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Duke Energy
Duke Energy
Duke Energy
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Duke Energy Corporation is an American electric power and natural gas holding company headquartered in Charlotte, North Carolina. The company serves over 7 million customers in the eastern United States. In 2024 it ranked as the 141st largest company in the United States – its highest-ever placement on the Fortune 500 list.[2]

Key Information

Overview

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Duke Energy is based in Charlotte, North Carolina. It owns 58,200 megawatts of base-load and peak generation in the United States, which it distributes to its 7.2 million customers. It has approximately 29,000 employees.[3] Duke Energy's service territory covers 104,000 square miles (270,000 km2) with 250,200 miles (402,700 km) of distribution lines.[4] Almost all of Duke Energy's Midwest generation comes from coal, natural gas, or oil, while half of its Carolinas generation comes from its nuclear power plants. During 2006, Duke Energy generated 148,798,332 megawatt-hours of electrical energy.

Duke Energy Renewable Services (DERS), a subsidiary of Duke Energy, specializes in the development, ownership, and operation of various generation facilities throughout the United States. This segment of the company operates 1,700 megawatts of generation. 240 megawatts of wind generation were under construction and 1,500 additional megawatts of wind generation were in planning stages.[5] On September 9, 2008, DERS updated its projections for future wind power capacity. By the end of 2008, it would have over 500 MW of nameplate capacity of wind power online, and an additional 5,000 MW in development.[6]

Subsidiaries

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  • Duke Energy Carolinas (formerly Duke Power)
  • Duke Energy Ohio (formerly Cincinnati Gas & Electric Company, via Cinergy)
  • Duke Energy Kentucky (formerly Union Light, Heat & Power, via Cinergy)
  • Duke Energy Indiana (formerly Public Service Indiana, via Cinergy)
  • Duke Energy Florida (formerly Florida Power Corporation, via Progress Energy)
  • Duke Energy Progress (formerly Carolina Power and Light, via Progress Energy)
  • Duke Energy Renewables
  • Duke Energy Retail
  • Duke Energy International
  • Duke Energy Sustainable Solutions
  • Duke Energy One
  • Piedmont Natural Gas

History

[edit]
550 South Tryon, former Duke headquarters in Charlotte, 2010

The company began in 1900 as the Catawba Power Company when Walker Gill Wylie and his brother financed the building of a hydroelectric power station at India Hook Shoals along the Catawba River near India Hook, South Carolina. When Wylie needed additional funding to further his ambitious plan for construction of a series of hydroelectric power plants, Wylie convinced James B. Duke and his partner James Blaney to invest in the Southern Power Company, founded in 1905.

In 1917 James Blaney was the founder of the Wateree Power Company that was formed as a holding company for several utilities that had been founded and/or owned by Duke, and Blaney his associates, and in 1924 the name was changed to Duke Power. In 1927, most of the subsidiary companies, including Southern Power Company, Catawba Power Company, Great Falls Power Company, and Western Carolina Power Company were merged into Duke Power, although Southern Public Utilities, 100% owned by Duke Power, maintained a legally separate existence for the retail marketing of Duke-generated power to residential and commercial customers.[7] Southern Public Utilities also operated transit systems, which Duke eventually converted from streetcars to buses.

In 1973, through its subsidiary, the Eastover Mining Company, Duke Power engaged in a lengthy contract dispute with the workers at the Brookside coal mine in Harlan County, Kentucky.[8] For thirteen months, workers picketed the company for improved medical benefits and the right to representation by the United Mine Workers of America, while Duke Power insisted on a no-strike clause in the miner's eventual labor contract. The strike culminated in the shooting and death of twenty-two year old miner, Lawrence D. Jones, by a foreman at the Duke Power-owned mine.[9] Five days later, Duke Power would reach an agreement with the striking miners which included recognition of the new UMWA local, the rehiring of workers dismissed during the strike, and dropping charges related to the action.[10]

In 1988, Nantahala Power & Light Co., which served southwestern North Carolina, was purchased by Duke from Alcoa. For many years, it was operated as a separate division of Duke Power, operating under the Duke Power Nantahala Area brand. All former Nantahala operations now operate as Duke Energy Carolinas, although the former Nantahala hydroelectric dams operating in the area are operated as the Nantahala Region for regulatory and permitting purposes. The purchase of Nantahala gave Duke Power, and subsequently Duke Energy, its first and only interconnection with the TVA.

In 1990, Duke sold its remaining transit operations. Duke Power merged with PanEnergy, a natural gas company, in 1997 to form Duke Energy.[11] The Duke Power name continued as the electric utility business of Duke Energy until the Cinergy merger.

Duke Energy Field Services near Palestine, Texas. The facilities include refineries and oil wells throughout the region.

With the purchase of Cinergy Corporation announced in 2005 and completed on April 3, 2006, Duke Energy Corporation's customer base grew to include the Midwestern United States as well. The company operates nuclear power plants, coal-fired plants, conventional hydroelectric plants, natural-gas turbines to handle peak demand, and pumped hydro storage. During 2006, Duke Energy also acquired Chatham, Ontario-based Union Gas, which is regulated under the Ontario Energy Board Act (1998).

On January 3, 2007, Duke Energy spun off its gas business to form Spectra Energy. Duke Energy shareholders received 1 share of Spectra Energy for each 2 shares of Duke Energy. After the spin-off, Duke Energy now receives the majority of its revenue from its electric operations in portions of North Carolina, South Carolina, Kentucky, Ohio, and Indiana. The spinoff to Spectra also included Union Gas, which Duke Energy acquired the previous year.[12][13]

In 2011, Duke Energy worked with Charlotte's business leader community to help build Charlotte into a smart city. The group called the initiative "Envision Charlotte". At the time, the group decided on a goal to reduce energy use in the "urban core of the city by 20 percent". To do so, the group focused on making energy consumption changes to commercial buildings larger than 10,000 square feet.[14]

On July 3, 2012, Duke Energy merged with Progress Energy Inc with the Duke Energy name retained along with the Charlotte, North Carolina, headquarters.[15][16]

Duke announced on June 18, 2013, that CEO Jim Rogers was retiring and Lynn Good would become the new CEO. Rogers has been CEO and Chairman since 2006, while Good was Chief Financial Officer of Duke since 2009, having joined Duke in the 2006 Cinergy merger. Rogers' retirement was part of an agreement to end an investigation into Duke's Progress Energy acquisition in 2012.[17]

In 2016, Duke Energy purchased Piedmont Natural Gas for $4.9 billion to become its wholly owned subsidiary.[18] Duke Energy completed selling its remaining power operations in Central and South America for $1.2 billion months afterwards.[19] At one point Duke Energy had more than 4,300 megawatts of electric generation in Latin America.[20] It operated eight hydroelectric power plants in Brazil with an installed capacity of 2,307 megawatts.[21]

The company expects to spend $13 billion upgrading the North Carolina grid from 2017.[22]

In 2018, Jessee Pound of CNBC wrote that Duke was one of many larger American companies which "paid an effective federal tax rate of 0% or less", which the Institute on Taxation and Economic Policy claimed was a result of Donald Trump´s Tax Cuts and Jobs Act of 2017.[23] A response from Duke to a similar claim from the Institute of Policy Studies 2024 stated: "Duke Energy has a deferred tax balance – this does not mean Duke Energy is not paying these taxes, it means that our taxes are due in future years, and we will pay them."[24]

On December 3, 2022, an attack was carried out on two Duke Energy substations located in Moore County, North Carolina.[25] Damage from the attack left up to 40,000 residents without electrical power for several days, with officials closing schools and declaring a state of emergency. No suspect was ever identified, but the Federal Bureau of Investigation supported local investigators in case the incident met the definition of domestic terrorism under the Patriot Act.[26]

Proposed nuclear plant

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Main article: William States Lee III Nuclear Generating Station

On March 16, 2006, Duke Power announced that a Cherokee County, South Carolina site had been selected for a potential new nuclear power plant. The site is jointly owned by Duke Power and Southern Company. Duke planned to develop the site for two Westinghouse Electric Company AP1000 (advanced passive) pressurized water reactors. Each reactor would have been capable of producing approximately 1,117 megawatts. (See Nuclear Power 2010 Program.)

On December 14, 2007, Duke Power submitted a Combined Construction and Operating License to the Nuclear Regulatory Commission, with an announcement that it will spend $160 million in 2008 on the plant with a total cost of $5 billion to $6 billion.[27] The plant was approved in 2016.[28]

In August 2017, Duke decided to seek permission from the North Carolina Utility Commission to cancel the project due to the bankruptcy of Westinghouse and "other market activity", although they retained the option of restarting the project at some point in the future if circumstances change.[29]

This site would have been adjacent to the old site, which was never completed and abandoned in the early 1980s, and used by James Cameron as a film set for the 1989 movie The Abyss.

In 2018, Duke Energy announced that they had decided not to include new nuclear power in their long-range plans.[30]

Headquarters buildings

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Former Church Street headquarters being demolished

J.A. Jones designed the first headquarters building, known as the Power Building, which was completed in 1927 at 440 South Church. It was five stories and 503,000 square feet (46,700 m2). The Electric Center at 526 South Church Street opened in 1975 with an addition in 1988.[31][32] State Farm Insurance sold the Power Building in 2004 for $8 million to The Dilweg Cos., who anticipated significant development. Novare Group bought 5.13 acres (20,800 m2) at 408 South Church Street for $17 million from The Dilweg Cos. in a deal announced March 27, 2006.[32] The Power Building was demolished February 24, 2007.[33]

Duke Energy Center at 550 South Tryon Street was announced as the company's headquarters in 2009.[34] The company announced May 17, 2021 that the headquarters will move in 2023 to Duke Energy Plaza, across the street from the current headquarters. Childress Klein is developing the new building, which will allow Duke to sell its Church Street and College Street buildings, and end its lease at 400 South Tryon.[35][36] Previously named Charlotte Metro Tower,[36] the 40-story building will be purchased when completed for up to $675 million by Childress Klein and CGA Capital, in the largest real estate deal in the city's history, announced in December 2019.[37]

Finances

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For the fiscal year 2017, Duke Energy reported earnings of US$3.059 billion, with an annual revenue of US$23.565 billion, an increase of 3.6% over the previous fiscal cycle. Duke Energy's shares traded at over $79 per share, and its market capitalization was valued at over US$58.8 billion in November 2018.[38]

Year Revenue
in million US$ 		Net income
in million US$ 		Total Assets
in million US$ 		Employees
2005 6,906 1,812 54,723
2006 10,607 1,863 68,700
2007 12,720 1,500 49,686
2008 13,207 1,362 53,077
2009 12,731 1,075 57,040
2010 14,272 1,320 59,090
2011 14,529 1,706 62,526
2012 17,912 1,768 113,856
2013 22,756 2,665 114,779 27,948
2014 22,509 1,883 120,557 28,344
2015 22,371 2,816 121,156 29,188
2016 22,743 2,152 132,761 28,798
2017 23,565 3,059 137,914 29,060
2018 24,521 2,666 145,392 30,083
2019 25,079 3,707 158,838 28,793
2020 23,868 1,270 162,388 27,535
2021 25,097 3,802 169,587 27,605
2022 28,768 2,444 178,086 27,859
2023 29,060 2,735 176,893 27,037

Environmental record

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In 1999, the United States Environmental Protection Agency commenced an enforcement action against Duke Energy for making modifications to very old and deteriorating coal-burning power plants without getting permits under the Clean Air Act. Duke asserted that a "modification" under the Clean Air Act did not require a permit. Environmental groups asserted that Duke was using loopholes in the law to increase emissions. Initially, Duke prevailed at the trial court level, but in 2006 the case was argued before the Supreme Court (Environmental Defense v. Duke Energy Corp. (05-848)). The Court unanimously ruled on April 2, 2007, that the modifications allowed the power plants to operate for more hours, increasing emissions, so Clean Air Act permits were needed.[39]

In 2002, researchers at the University of Massachusetts Amherst identified Duke Energy as the 46th-largest corporate producer of air pollution in the United States, with roughly 36 million pounds of toxic chemicals released annually into the air.[40] Major pollutants included sulfuric and hydrochloric acid, chromium compounds, and hydrogen fluoride.[41] The Political Economy Research Institute ranks Duke Energy 13th among corporations emitting airborne pollutants in the United States. The ranking is based on the quantity (80 million pounds in 2005) and toxicity of the emissions.[42] This change reflects the purchase of fossil fuel-heavy Cinergy, which occurred in 2005.

In early 2008, Duke Energy announced a plan to build the new, 800-megawatt Cliffside Unit 6 coal plant 55 miles (89 km) west of Charlotte, North Carolina. The plan has been strongly opposed by environmental groups such as Rising Tide North America, Rainforest Action Network, the community-based Canary Coalition as well as the Southern Environmental Law Center, which has threatened to sue Duke if it does not halt construction plans. On April 1, activists locked themselves to machinery at the Cliffside construction area as part of Fossil Fools Day.

Duke Energy has been "one of the most vocal advocates"[citation needed] for a "cap-and-trade" system to combat global CO2 emissions,[43] "and the company's CEO, Jim Rogers, thinks the company will profit from cap-and-trade".[citation needed] The company left the National Association of Manufacturers in part over differences on climate policy.[43][44]

In a joint venture with the French-based global energy firm AREVA, under the nominal name of ADAGE, Duke Energy has planned a "Green" biomass burning facility in Mason County, Washington and is negotiating with forestland owners to secure the 600,000 tons of wood debris it needs yearly to fuel its $250 million biomass plant. The joint venture between electric power company Duke Energy and global nuclear services giant AREVA was created to build wood waste-to-energy power plants around the country.

ADAGE president Reed Wills announced the first Northwest outpost will be in the struggling timber town of Shelton, Washington.

The following pollutants are provided by DUKE-AREVA-ADAGE in their application for permit to the Department of Environmental Protection for a similar type of plant in Florida.

  • 248 tons per year – particulate matter
  • 288 tons per year – particulate matter 10
  • 233 tons per year – particulate matter 2.5
  • 249 tons per year – NOx (nitrogen oxides)
  • 246 tons per year – SO2 (sulfur dioxide)
  • 248 tons per year – CO (carbon monoxide)
  • 40 tons per year – H2SO4 – (sulfuric acid mist)
  • 63 tons per year – VOC (volatile organic compounds)
  • 29 tons per year – F (fluorides)[45]

Generating facilities

[edit]
  • This list is partially complete due to the July 3, 2012, merger with Progress Energy.

Biomass fired

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  • Shelton Biomass Facility (proposed)

Nuclear

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Coal-fired

[edit]

Hydroelectric

[edit]

Conventional hydro

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Following is a list of Duke Energy's thirty conventional hydroelectric facilities, in order of average electric production.[46] All properties are 100% owned by Duke, and all but Markland are located in North Carolina and South Carolina (Markland is located in southern Indiana).[47]

Pumped-storage hydro

[edit]

Oil and gas-fired

[edit]
  • Anclote Station
  • Asheville Combustion Turbines
  • Bartow Combined Cycle Station
  • Buck Steam Station
  • Buzzard Roost Station
  • Cayuga Combustion Turbine Station
  • Cliffside Steam Station
  • Connersville Peaking Station
  • Dan River Steam Station
  • Darlington County Electric Plant
  • Henry County Peaking Station
  • Hines Energy Complex
  • H.F. Lee Energy Complex
  • Lee Steam Station
  • W.S. Lee Steam Station
  • Lincoln Combustion Turbine Station
  • Madison Peaking Station
  • Miami-Wabash Peaking Station
  • Mill Creek Combustion Turbine Station
  • Noblesville Station
  • Rockingham Station
  • Smith Energy Complex
  • Sutton Combined Cycle Plant
  • Wabash River Repowering Station
  • Wheatland Peaking Station
  • Woodsdale Station

Solar farms

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Citing the falling cost of building solar farms, Duke Energy announced plans in 2017 to launch three new such projects in Kentucky. Two will be in Kenton County and one will be in Grant County. Together the three plants will create more than 6.7 MW of power.[48] These join several other solar farms including:

  • Davidson County Solar Farm
  • Martins Creek Solar Farm 1 MW (Murphy, NC)
  • Culberson Solar Farm 1 MW (Murphy, NC)
  • Osceola Solar Facility 4 MW (St.Petersburg, Fla)[49]

Additionally, Duke Energy added 451 MW of solar capacity to North Carolina's grid in 2017.[50]

  • Hamilton Solar Power Plant 74.9 MW (Jasper, FL)
  • Columbia Solar Power Plant 74.9 MW (Fort White, FL) (opening in 2020)[51]
  • Live Oak Solar Power Plant ? MW (Live Oak, FL)

In 2020 Duke Energy began commercial operations of several farms in Texas, operating alongside its Farm from 2010.[52][53][54]

  • Blue Wing Solar Project (San Antonio, TX)
  • Lapetus Solar Project 100 MW (Andrews County, TX)
  • Holstein Solar Project 200 MW (Nolan County, TX)
  • Rambler Solar Project 200 MW (Tom Green County, TX)

Wind farms

[edit]

Electric vehicles

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Duke Energy announced in October 2018 that it would install 530 electric car charging stations around Florida. Ten percent of the stations will go into low income communities.[56]

Awards

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Duke Energy has been chosen as one of The 50 Best Employers In America by Business Insider[57]

In 2002, Duke Energy was awarded the Ig Nobel Prize in Economics for "adapting the mathematical concept of imaginary numbers for use in the business world".[58]

Criticism

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In December 2000, Cinergy Corp agreed to pay $1.4B to settle allegations that its coal plants illegally polluted the air.[59] Duke Energy completed its acquisition of Cinergy Corp in 2006.[60]

In July 2004, Duke Energy agreed to pay $208M to settle allegations that it had engaged in price gouging in California during the energy crisis of 2000 and 2001.[61]

In December 2009, Duke Energy agreed to spend approximately $93M to resolve violations of the Clean Air Act. Duke became obligated to make investments that were expected to reduce sulfur dioxide emissions by 86%.[62]

On February 14, 2011, Greenpeace launched a campaign in which Phil Radford called on Duke Energy to abandon mountaintop removal coal, produce a third of its energy from renewable sources by 2020, and abandon coal altogether by 2030."[63]

In May 2011, Duke agreed to pay $30M to resolve allegations that changes made to the company pension plan disproportionately harmed employees over 40, costing many of them up to half of their accrued benefits.[64]

In December 2011, the non-partisan organization Public Campaign criticized Duke Energy for spending $17.47 million on lobbying. It also criticized Duke for not paying any taxes from 2008 to 2010 and receiving $216 million in tax rebates,[65] in spite of turning a $5.4 billion profit and extensively raising executive compensations.[66]

In 2012, Greenpeace protested Duke's lobbying of the Democratic Party, including its funding of the 2012 Democratic National Convention.[67]

In July 2012, Duke Energy was criticized for paying former Progress Energy CEO Bill Johnson $44.7 million in compensation, including a $10 million severance, for something close to 20 minutes on the job as Duke's CEO.[68]

In 2012, Duke Energy sued Citrus County, Florida claiming its tax bill was too high. The county hired an outside appraiser who found that there were a lot of unreported and underreported items and the tax claim was actually too low.[69]

In May 2013, university students launched a campaign for Brown University to divest fossil fuels, specifically referring to Duke Energy and other coal plant operators.[70]

On February 2, 2014, the massive Dan River coal-ash spill led to a grand jury investigation into Duke Energy. The initial investigation was overseen by Governor Pat McCrory, who was accused of intervening on Duke's behalf as he had been a Duke Energy employee for 28 years. Prosecutors went looking for any cash or items of value that might have been given to Governor McCrory and members of his administration in exchange for cheap settlements.[71][72] Duke Energy was prosecuted, pled guilty to nine charges of criminal negligence,[73] and agreed to pay $102 million in fines and restitutions.[74] Duke Energy was also ordered to close all of its 32 ash ponds in the state of North Carolina by 2029.[75]

In September 2016, the Government Pension Fund of Norway, then worth $900 billion, excluded Duke Energy and its subsidiaries from the fund, citing "risk of severe environmental damage".[76]

During 2018 Duke Energy along with 90 additional Fortune 500 companies "paid an effective federal tax rate of 0% or less" as a result of Donald Trump´s Tax Cuts and Jobs Act of 2017.[23]

In August 2020, environmental watchdog EWG released a report accusing Duke Energy of charging Indiana ratepayers for $12 billion worth of failed projects.[77] This was the direct consequence of a controversial bill passed in Indiana earlier that year.[78] Projects included two natural gas pipelines and two retired nuclear power plants.

In 2021, investigative reporting by the Orlando Sun Sentinel revealed that Duke Energy, FPL (Nextera Energy), and TECO Energy put forth more than $3 million to promote "ghost" spoiler candidates in key Florida legislature races. The scheme involved former senator Frank Artiles and was effective in costing the Democrats at least one election.[79]

In January 2021, Duke Energy agreed to a settlement, which the company proposed, to absorb $1.1 billion worth of coal-ash pond closure and cleanup costs, in North Carolina, between 2015 and 2030.[80] The parties involved also waived all rights to challenge the "reasonableness and prudence" of Duke Energy's coal ash management practices and costs before March 2020.[81] Duke estimates the costs to be between $8 and $9 billion, the settlement reduces the cost on the ratepayer by 60%.[81]

In August 2021, Indiana city officials from Bloomington, Carmel, and West Lafayette, and other lawmakers sent a letter to Duke Energy deploring its progress towards renewables and asking it to stop overcharging low-income homes for electricity.[82]

December 2022 rolling blackouts

[edit]

In December 2022, a major winter storm impacted much of the United States. On December 24, 2022, Christmas Eve, Duke Energy implemented rolling blackouts for the first time in their history, due to unprecedented energy demand.[83] The rolling blackouts came without warning and lasted hours.[citation needed] In addition to facility failures, Duke reported failures related to the software that regulated the controlled blackouts.[84] The Federal Energy Regulatory Commission initiated an investigation in response to the blackouts.[85]

See also

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References

[edit]
[edit]
Revisions and contributorsEdit on WikipediaRead on Wikipedia

Duke Energy

View on Grokipedia
from Grokipedia
Duke Energy Corporation is an American energy holding company headquartered in , that generates, transmits, distributes, and sells and , serving approximately 8.6 million electric customers and 1.7 million customers across , , , , , , and . The company operates about 54,800 megawatts of energy capacity, drawing from a mix of , nuclear, , renewables, and energy storage facilities, positioning it as one of the largest electric utilities in the United States by customer base and generation assets. Founded in the early 1900s as the Catawba Power Company and evolving through key mergers—including the 1997 combination with PanEnergy to form and the 2012 acquisition of Progress Energy, which made it the nation's largest utility by customers—Duke Energy has expanded from regional hydroelectric origins to a diversified national player in power production and delivery. Its infrastructure supports industrial growth, including recent demands from data centers, while maintaining a focus on reliability amid rising needs. Duke Energy's operations have drawn both acclaim for infrastructure investments and scrutiny over environmental impacts, including reliance on for near-term capacity expansions to meet surging demand and ongoing litigation alleging contributions to through emissions. The company has committed to reducing carbon emissions but faces criticism from advocacy groups for insufficient renewable scaling and proposed policy shifts that could elevate customer costs for shareholder-protected risks. Despite these tensions, Duke Energy remains pivotal in balancing affordable, reliable power with regulatory pressures in a transitioning .

Corporate Profile

Company Overview and Core Operations

Duke Energy Corporation is a major player in the utilities sector and an and holding company headquartered in . As one of the largest energy companies in the United States, it operates regulated utilities that generate approximately 49,600 megawatts of electric power capacity and serve about 7.6 million retail electric customers across six states, including , , , , , and . Its utilities provide service to 1.7 million customers in , , , , and . The company's core operations center on the generation, transmission, distribution, and sale of electricity and natural gas as a large vertically integrated utility serving multi-state grids through its regulated utilities and infrastructure segments. Duke Energy's electric generation portfolio includes a mix of nuclear, natural gas, coal, hydroelectric, solar, and energy storage facilities, with over 110 generating sites supporting reliable power delivery. In addition to traditional fossil fuel and nuclear assets, it maintains a growing portfolio of renewable energy sources, including solar and wind projects, as part of efforts to modernize the grid and incorporate cleaner technologies. Duke Energy also engages in gas utilities and infrastructure operations, focusing on the distribution of to residential, commercial, and industrial customers, alongside investments in and expansion. The company emphasizes delivery, with ongoing capital expenditures directed toward continuous investments in transmission and distribution infrastructure maintenance, grid upgrades, enhanced reliability, and the integration of advanced technologies like to meet increasing demand and regulatory requirements for lower emissions. These operations are structured to ensure affordable, reliable service while transitioning toward a mix that balances baseload power from nuclear and with intermittent renewables, supporting shareholder returns through consistent dividend payments over 99 consecutive years.

Service Territories and Customer Demographics

Duke Energy's electric service territories span approximately 104,000 square miles across six states in the southeastern and midwestern : , , , , , and . The company's regulated utilities, including Duke Energy Carolinas, Duke Energy Progress, Duke Energy , Duke Energy , and Duke Energy and , deliver electricity to urban, suburban, and rural areas within these regions, encompassing major population centers such as Charlotte and Raleigh in , Columbia in , and Fort Myers in . As of 2025, Duke Energy serves 8.6 million electric customers, comprising residential, commercial, and industrial accounts. Residential customers form the largest segment, with notable growth of 2.4% in the and during the first quarter of 2024 compared to the prior year, driven by increases and development. For instance, Duke Energy alone reports over 1.5 million residential customers, alongside approximately 251,000 commercial and 3,100 industrial accounts. Duke Energy supplies 2.8 million customers across all categories in its 24,000-square-mile territory covering parts of North and . Industrial and commercial users, including facilities and large es, represent a smaller but energy-intensive portion, contributing to higher per-customer consumption relative to residential loads. Customer demographics reflect the diverse economic profiles of the served states, with a emphasis on growing suburban and urban in the Southeast. The territories support an estimated of around 24 million, though electric service focuses on retail delivery rather than universal coverage. services extend to 1.7 million additional customers in overlapping areas, primarily residential and commercial, but electric operations dominate the utility's footprint.

Subsidiaries and Organizational Structure

Duke Energy Corporation functions as a that conducts its core operations through a network of wholly owned subsidiaries, primarily regulated electric and natural gas utilities serving customers across the southeastern and . These subsidiaries handle electric generation, transmission, distribution, and sales, as well as distribution, under state-specific regulatory oversight. The structure emphasizes decentralized operations at the subsidiary level to comply with regional regulatory frameworks while centralizing strategic oversight, financing, and certain at the parent level. Key electric utility subsidiaries include Duke Energy Carolinas, LLC, serving approximately 2.7 million electric customers in North and South Carolina; Duke Energy Progress, LLC, providing service to 1.8 million customers primarily in the Carolinas with 13,800 megawatts of capacity; Duke Energy Florida, LLC, operating in Florida with ongoing capital expansions exceeding $87 billion planned through partnerships; Duke Energy Indiana, LLC; Duke Energy Ohio, LLC; and Duke Energy Kentucky, LLC. In August 2025, Duke Energy filed regulatory applications to merge Duke Energy Carolinas and Duke Energy Progress into a single entity, aiming to achieve operational efficiencies and customer savings exceeding $1 billion by 2038 without altering rates. For natural gas, Piedmont Natural Gas Company, Inc., operates distribution networks, though its Tennessee local distribution operations were announced for sale to Spire Inc. for $2.48 billion in July 2025, subject to regulatory approval. Additional subsidiaries support commercial renewables and infrastructure, such as Duke Energy Renewables, though these fall under non-regulated activities. The company's reporting structure is organized into two primary reportable segments: Electric Utilities and Infrastructure, encompassing regulated electric operations across subsidiaries; and Gas Utilities and Infrastructure, focused on distribution and related assets. This segmentation aligns with regulatory and operational distinctions, with consolidated financials reflecting intercompany eliminations. Leadership is centralized under President and Chief Executive Officer Harry K. Sideris, effective April 1, 2025, supported by executive vice presidents overseeing customer operations, operations, and subsidiary-specific roles, such as Kodwo Ghartey-Tagoe as EVP and CEO of Duke Energy Carolinas and the business.

Historical Development

Founding and Initial Expansion (1900s–1960s)

The origins of what became Duke Power Company, the predecessor to Duke Energy, began with the Catawba Power Company, incorporated in 1900 by Dr. W. Gill Wylie and associates to harness hydroelectric potential along the in . On April 30, 1904, the company's Catawba Hydro Station commenced operations, generating 3,300 kilowatts and marking the initial commercialization of electricity production in the Piedmont Carolinas region. Tobacco magnate , recognizing the economic value of reliable power for regional industries like textiles, invested heavily, partnering with his brother Benjamin N. Duke and engineer William States Lee. In June 1905, the Dukes incorporated the Southern Power Company as a holding entity to consolidate and expand hydroelectric assets, acquiring the Catawba facilities and initiating construction of additional dams such as those at Great Falls and Fishing Creek. This integrated system transmitted power over long distances to mills and communities, fueling industrialization; by 1907, Southern Power operated multiple plants supplying electricity to cotton mills in Charlotte and beyond, with transmission lines extending up to 100 miles. The company also developed the Piedmont & Northern Railway in 1911 to interconnect power users, enhancing grid reliability and stimulating in North and . On November 13, 1924, Southern Power reorganized and renamed itself Duke Power Company, with James B. Duke elected president, reflecting his dominant influence. Expansion continued into steam generation, exemplified by the 1925 Buck Steam Station on the , which added capacity to supplement hydro variability. Growth moderated during the and due to economic constraints and material shortages, limiting new builds after 1928 until 1938. Postwar demand surges from population and industrial booms prompted a shift toward coal-fired plants in the , with Duke Power constructing large facilities like the Dan River and Lee stations, elevating it to one of the nation's top utilities by the , serving over 500,000 customers across 20,000 square miles. This era laid the foundation for diversified generation, culminating in the 1963 commissioning of the experimental Parr Nuclear Station as an early foray into atomic power. In the 1960s, Duke Power launched the House Power Panel (HPP) program, part of the "Gold Medallion Home Program," to encourage all-electric homes. Active from 1960 to 1974, Duke installed, owned, and maintained main breaker panels (HPPs) for participating residential customers in North Carolina. Duke continued owning these panels post-program, with proactive replacements ending in 2023; North Carolina customers can still request reviews by contacting 800.777.9898. The process involves a field engineer site visit for inspection, ownership confirmation, condition assessment, and photos. Eligible Duke-owned HPPs receive no-cost replacement by an electrician, with temporary power interruption of about 3-4 hours. Post-replacement, a county or municipal inspector verifies compliance, requiring labeled circuits, an accessible panel, and visible yellow caution tape on ground rods (removable after). Ineligible panels due to non-ownership or unresolved code issues require customer action independently.

Mergers, Acquisitions, and Portfolio Shifts (1970s–2000s)

During the 1970s and 1980s, Duke Power Company, the predecessor to Duke Energy, pursued limited , prioritizing organic expansion and infrastructure development amid rising energy demand in the . The company focused on constructing nuclear facilities such as the (operational from 1981) and (from 1985), which represented significant capital investments rather than external acquisitions. No major divestitures occurred during this period, as Duke Power maintained a vertically integrated model centered on regulated , transmission, and distribution. The 1990s marked a strategic pivot driven by federal deregulation of natural gas markets and anticipation of electric utility restructuring, prompting Duke Power to diversify beyond electricity. In 1990, the company divested its remaining transit operations, streamlining focus on core energy assets. The pivotal event was the 1997 merger with PanEnergy Corp, a Houston-based natural gas transmission firm, completed on June 18 in a $7.7 billion all-stock transaction that formed Duke Energy Corporation. Under the terms, each PanEnergy share converted to 1.0444 shares of Duke Energy stock, tripling the company's revenues from approximately $5 billion to over $15 billion and integrating PanEnergy's second-largest U.S. natural gas pipeline system spanning 20,000 miles. This merger shifted Duke Energy's portfolio toward a broader energy model encompassing gas pipelines, trading, and international operations, positioning it as a multifaceted provider rather than a regional electric utility. In the late and early , Duke Energy accelerated acquisitions to capitalize on and global opportunities, acquiring merchant power plants and expanding internationally. Notable deals included the purchase of three California power plants from PG&E Corp. for $500 million around 2000, enhancing West Coast generation capacity. The company also pursued Latin American projects, such as stakes in generation facilities in and , though these later faced challenges from economic volatility. Portfolio shifts emphasized non-regulated segments like trading and independent power production, with Duke Energy entering merchant generation amid the era's competitive markets. However, by the mid-, rising s from volatile wholesale prices led to divestitures, including the 2006 sale of 6,300 MW of non-core power plants to LS Power for $1.5 billion to refocus on regulated utilities. The 2006 merger with Cinergy Corp, valued at around $12 billion, further consolidated Midwest operations, adding electric and gas assets in , , and while reinforcing regulated infrastructure dominance. These moves reflected a pragmatic response to market 's opportunities and pitfalls, balancing diversification with .

Post-2010 Restructuring and Energy Transition Milestones

In July 2012, Duke Energy completed its merger with Progress Energy, forming one of the largest electric utilities in the United States by and customer base, with the combined entity serving approximately 7.1 million electric customers across six states. This restructuring integrated Progress's nuclear, coal, and assets, particularly in the and , but faced subsequent shareholder litigation over undisclosed leadership changes post-merger, resulting in a $146 million settlement in 2015. In October 2016, Duke Energy acquired Piedmont Natural Gas for approximately $6.7 billion in enterprise value, adding about 1 million natural gas customers primarily in the Carolinas and Tennessee, thereby diversifying its portfolio beyond electricity generation into regulated gas distribution. This move supported integrated energy services amid growing demand for natural gas as a bridge fuel, though in July 2025, Duke announced the divestiture of its Tennessee Piedmont operations to Spire Inc. for $2.48 billion, reflecting a strategic refocus on core electric utility assets. Duke Energy's energy transition efforts post-2010 have centered on reducing reliance on coal-fired generation while expanding , nuclear, and renewables to meet reliability needs and emissions targets. Since 2010, the company has retired over 7,500 megawatts (MW) of coal capacity across 51 to 56 units, including early closures like two Progress Energy Carolinas plants in October 2012 and units in by 2013 as part of environmental settlements. These retirements contributed to a 44% reduction in carbon emissions from baseline levels by 2022, driven by federal regulations like the Clean Air Act and economic shifts favoring lower-cost alternatives. Key milestones include the September 2019 announcement of a net-zero carbon emissions goal for electric generation by 2050, with an interim target of at least 50% reduction by 2030 from 2005 levels, emphasizing a balanced mix of dispatchable and sources. Renewable capacity grew rapidly, reaching 1 gigawatt (GW) of owned solar in 2019—enough to power about 2 million homes—and hitting a total of 10,000 MW across renewables by 2021, with nearly 1,800 MW added in 2021 alone through solar farms and projects. The company plans further additions, including 3,460 MW of solar in by 2031, alongside battery storage and onshore , but recent 2025 resource plans delay some retirements (e.g., at Marshall Steam Station until 2034) and add 9.7 GW of capacity by 2033 to address surging demand from and data centers, prioritizing grid stability over accelerated . This approach reflects empirical trade-offs: renewables' necessitates backup from reliable baseload sources like gas and nuclear, as intermittent generation alone cannot guarantee supply during peak loads without massive overbuild and storage investments.

Financial Performance

Revenue Generation and Profit Metrics

Duke Energy generates the majority of its revenue through regulated utility operations, where earnings are derived from sales of electricity and to retail customers under rate structures approved by state commissions. These rates are typically set based on the utility's cost of service, including operating expenses, capital investments, and an allowed , with additional revenue from regulatory riders covering specific costs such as fuel adjustments, storm recovery, and incentives. The Electric Utilities and Infrastructure segment, serving customers in the , , and the Midwest, accounts for approximately 92% of , driven by residential (about 40%), commercial (30%), and industrial (25%) sales, with the remainder from wholesale and other services. The Gas Utilities and Infrastructure segment contributes the balance, primarily from distribution in the Midwest and Southeast. In 2024, Duke Energy reported total operating of $30.36 billion, a 4.46% increase from $29.06 billion in 2023, reflecting higher retail sales volumes, rate base growth from capital investments, and favorable impacting . The Electric Utilities and segment generated $26.81 billion, up from $26.85 billion in 2023, while Gas Utilities added $2.32 billion. growth has been supported by regulatory approvals for rate increases and recovery of investments, though offset by higher operating costs including and maintenance. Profit metrics for 2024 showed attributable to common shareholders of $4.402 billion, a 60.95% rise from $2.735 billion in 2023, largely due to reduced impairment charges, higher allowed in key jurisdictions, and operational efficiencies, despite increased from ongoing grid modernization. Adjusted , a key non-GAAP metric excluding one-time items, reached levels supporting growth, with the company maintaining a regulated target around 9-10% across segments. Historical trends indicate steady profitability, with compounding at approximately 2-4% annually over the past decade, aligned with customer growth and capital deployment exceeding $10 billion yearly.
Fiscal YearTotal Revenue ($B)Net Income ($B)
202228.402.44
202329.062.735
202430.364.402

Capital Expenditures and Investment Strategies

Duke Energy's five-year capital expenditure plan, updated in August 2025 to $87 billion for the period through 2029, reflects a $14 billion increase from prior projections, driven primarily by surging electricity demand from data centers, industrial growth, and population increases across its service territories. This escalation, which includes an additional $4 billion allocated to Duke Energy Florida for grid modernization and capacity expansions, aims to support over 16 billion in total investments within the state alone by 2029. The company's 2024 capital spending reached approximately $12.28 billion, underscoring the scale of ongoing infrastructure commitments amid forecasts of record load growth. Investment strategies emphasize resilient grid enhancements and diversified generation capacity to meet reliability needs while transitioning toward lower-carbon sources. Key allocations include major upgrades to transmission and distribution systems, extensions of nuclear operations—such as the approval in March 2025 to prolong the McGuire Nuclear Station's lifespan—and evaluations for new nuclear reactors potentially operational by 2037 in the Carolinas. Natural gas additions, renewables like solar and wind, and battery storage are prioritized, with the 2025 Carolinas Resource Plan outlining roughly doubled solar capacity and over 1,100 MW of batteries by the early 2030s. Coal plant life extensions are also under consideration following shifts in federal policy, balancing short-term reliability against long-term decarbonization goals. Longer-term projections indicate $190 to $200 billion in total investments over the next decade, funded through a mix of internal cash flows, , equity issuances—targeting $6.5 billion between 2025 and 2029—and strategic partnerships, such as the August 2025 agreement with Brookfield to inject capital into Duke Energy via a minority stake sale. These approaches prioritize ratepayer affordability and shareholder returns, with CEO emphasizing infrastructure modernization to handle AI-driven electrification without compromising service stability.

Market Valuation and Shareholder Outcomes

As of October 24, 2025, Duke Energy Corporation's stood at approximately $99.05 billion, reflecting a 15.22% increase over the prior year amid steady stock price appreciation. The company's shares traded at $127.37 per share on that date, with a trailing price-to-earnings (P/E) of 19.90 and a forward P/E of 18.21, indicating a valuation aligned with regulated sector norms where stable cash flows from essential services support moderate multiples. Enterprise value reached $183.62 billion, yielding an EV/EBITDA multiple of about 11.98, which accounts for the capital-intensive nature of power generation and grid infrastructure investments. Shareholder outcomes have been characterized by consistent growth and total returns that prioritize income stability over high volatility. Duke Energy has raised its for 18 consecutive years, with the current trailing twelve-month payout at $4.26 per share, delivering a yield of 3.35% based on the October 24 closing . Quarterly dividends, such as the 106.5-cent payment declared for August 2025, underscore a policy of returning a significant portion of regulated to investors while funding capital expenditures. Over the past five years, total shareholder return (including dividends and appreciation) reached 72.8%, though one-year returns as of late 2025 hovered around 11.0%, trailing broader market gains due to interest rate sensitivity in the utilities sector.
MetricValue (as of Oct 2025)Source Notes
$99.05BReflects ~777 million at $127.37/share
Trailing P/E Ratio19.90Based on EPS of $6.15
(TTM)3.35%Annualized from $4.26 payout
5-Year TSR72.8%Includes reinvested dividends
These metrics highlight Duke Energy's appeal to income-focused investors, with returns driven by predictable regulatory-approved rate bases rather than aggressive growth, though elevated debt levels from infrastructure spending temper upside potential in rising rate environments.

Power Generation Portfolio

Nuclear Generation Assets

Duke Energy operates 11 nuclear reactors across six sites in and , comprising the largest regulated nuclear fleet in the United States with a combined generating capacity of approximately 10,700 megawatts. These pressurized reactors (PWRs) and reactors (BWRs) provide reliable baseload power, contributing over 50% of the company's in the and supporting low-carbon energy needs for millions of customers. The fleet has demonstrated high capacity factors, often exceeding 90%, due to rigorous maintenance and operational protocols overseen by the U.S. (NRC). The plants include in (three PWR units, 2,538 MW total capacity; commercial operation: Unit 1 in July 1973, Units 2 and 3 in 1974), in (two PWR units, 2,300 MW total; Unit 1 in December 1981, Unit 2 in June 1984), straddling , and (two PWR units, 2,310 MW total; Unit 1 in January 1985, Unit 2 in August 1986), in (one PWR unit, 964 MW; May 1987), and in (two BWR units, 1,870 MW total; Unit 2 in September 1975, Unit 1 in March 1977).
Plant NameLocationUnitsReactor TypeNet Capacity (MW)Commercial Operation Dates
Oconee County, SC3PWR2,5381973–1974
Mecklenburg County, NC2PWR2,3001981, 1984
York County, SC / Mecklenburg County, NC2PWR2,3101985, 1986
Shearon HarrisWake County, NC1PWR9641987
Brunswick Nuclear PlantBrunswick County, NC2BWR1,8701975, 1977
License renewals have extended operations for key facilities; for instance, Oconee's three units received NRC approval on March 31, , for an additional 20 years, pushing service through 2053–2054 and enabling continued output of over 2,500 MW to meet rising demand while minimizing costs. Safety records remain strong, with no major incidents reported, supported by investments in upgrades like digital instrumentation and emergency systems. These assets underscore Duke Energy's emphasis on nuclear as a dispatchable, zero-emission resource amid grid reliability challenges.

Fossil Fuel-Based Facilities

Duke Energy's fossil fuel-based facilities encompass coal-fired steam turbines, integrated gasification combined cycle (IGCC) units, and natural gas-fired combined-cycle and combustion turbine plants, which supply dispatchable power across its regulated utilities in , , , , , and . These assets, totaling several gigawatts in capacity, enable baseload and flexible generation to meet variable demand, with increasingly dominant following retirements initiated under environmental regulations since the . As of Q4 2024, Duke's regulated generation portfolio exceeds 55,000 MW in available capacity, where fossil fuels provide reliability amid rising loads from data centers and industrial growth, offsetting intermittency from renewables. The coal segment has contracted significantly, with over 4,000 MW retired in North Carolina alone since 2012, driven by compliance with federal emissions standards and economic shifts favoring cheaper gas. Notable active coal or dual-fuel plants include the Marshall Steam Station in Catawba County, North Carolina, a four-unit facility with 2,078 MW winter peak capacity that can cofire natural gas but primarily relies on coal for baseload output. The Edwardsport IGCC plant in Knox County, Indiana, operational since 2013, generates 798 MW by gasifying coal into syngas for turbine combustion, incorporating carbon capture readiness though utilization remains limited. Recent integrated resource plans propose delaying retirements at select coal units—such as those at three North Carolina sites—beyond prior 2035 targets, citing insufficient alternatives to handle projected demand surges exceeding 10 GW by 2035, a decision substantiated by load forecasts rather than regulatory easing alone. Natural gas facilities predominate in the fossil mix, offering higher efficiency (up to 60% in combined-cycle configurations) and lower emissions than . Key units include the W.S. Lee Station in , featuring a 750 MW combined-cycle plant that entered commercial service in 2018, contributing to grid stability in the . The Asheville Combined Cycle Station in , replaced retired 344 MW units in 2020 with efficient gas-fired capacity, backed by an $817 million investment to maintain local reliability. Duke's 2025 Carolinas plan envisions adding 9.7 GW of gas-fired capacity by 2033, including hydrogen-capable units like a proposed 1,360 MW facility in , to replace aging while accommodating peak needs and renewable integration. In , similar proposals evaluate retaining units over full gas conversions at sites like Cayuga, prioritizing cost-effective dispatch amid volatile fuel prices.
FacilityLocationCapacity (MW, Winter Peak)Primary FuelKey Notes
Marshall Steam, NC2,078 (dual-fuel capable)Four-unit baseload plant; operational with .
Edwardsport IGCC, IN798 (gasified)Advanced technology commissioned 2013; includes potential for capture.
W.S. Lee, SC750 (CC)Combined-cycle; online 2018 for efficient peaking.
Asheville CC, NC~600 (estimated post-conversion)Replaced in 2020; supports local demand.
These facilities underscore Duke's strategy of retaining flexible fossil assets for grid resilience, with operational data from federal filings confirming their role in averting shortages during high-demand periods.

Renewable and Hydroelectric Resources

Duke Energy's resources primarily consist of solar photovoltaic installations and hydroelectric facilities, with emerging plans for additional capacity within its regulated utilities. As of 2025, the company's regulated portfolio includes approximately 4,000 megawatts (MW) of solar capacity serving customers across its six-state territory, alongside a hydroelectric fleet of about 3,800 MW, making it the second-largest investor-owned hydroelectric operator in the United States. These resources contribute to a diversified mix but represent a modest portion of Duke's total capacity of roughly 50,200 MW, which remains dominated by nuclear, , and facilities. Hydroelectric assets form a cornerstone of Duke's renewable portfolio, emphasizing run-of-river, , and pumped-storage systems primarily in the . The Bad Creek Pumped Storage Facility in provides 1,520 MW of capacity, enabling and peak-load balancing by pumping water to an upper during off-peak hours and generating during demand surges. The Yadkin-Pee Dee Hydroelectric Project on the includes the Tillery Development (81.25 MW) and Blewett Falls Development (24.13 MW), supporting baseload and flexible generation. Duke manages these assets through operations that prioritize reliable power flow, flood control, and environmental compliance, though output varies with seasonal precipitation and water availability. In 2018, the company divested five smaller Nantahala-area stations totaling 18.7 MW to Northbrook Energy, streamlining its focus on larger-scale hydro operations. Solar development has accelerated in regulated markets, particularly in Florida and the Carolinas, driven by state incentives and integrated resource plans. In Florida, Duke Energy Florida operates over 25 utility-scale solar sites producing nearly 1,500 MW as of early 2025, including recent completions like the Clean Energy Connection projects adding hundreds of MW. North Carolina approvals in 2024 support an additional 3,460 MW of solar by 2031, bringing totals to 6,700 MW in that region, often paired with battery storage for grid stability. In 2023, Duke sold its commercial renewables business—including 3,400 MW of non-regulated solar, wind, and storage—to Brookfield Renewable for $2.8 billion, refocusing on utility-owned assets to align with ratepayer-funded expansions. Wind resources remain limited in Duke's current regulated fleet, with historical emphasis on commercial projects now divested. plans include up to 1,200 MW of land-based by 2033, starting with 300 MW targeted for earlier deployment in the , contingent on transmission upgrades and economic viability assessments in integrated resource plans. These initiatives reflect Duke's strategy to incrementally integrate intermittency-prone renewables while relying on dispatchable hydro and storage to mitigate reliability risks.

Energy Storage and Emerging Technologies

Duke Energy operates over 2,400 megawatts (MW) of pumped-storage hydroelectric facilities, primarily at sites like the Bad Creek facility in , where upgrades completed in 2025 extended operations for another 50 years and enhanced capacity to support regional load growth. The company plans to expand total capacity to more than 6,000 MW by 2035, integrating pumped hydro with battery systems to balance intermittent renewables and grid demands. As of 2025, Duke Energy has approximately 90 MW of grid-tied battery energy storage systems (BESS) in operation across three states, with 65 MW under construction, including the largest such system in that entered commercial operation in March 2023. In its 2025 Carolinas Resource Plan, filed October 1, 2025, the company targets 5,600 MW of battery storage by 2034—an increase of 2,900 MW from prior projections—to address and integrate solar resources, following regulatory approval for 1,100 MW of additional BESS alongside pumped hydro expansions. In , Duke Energy Florida completed nearly 34 MW of innovative BESS projects in 2022, co-located with solar to provide grid stability and defer transmission upgrades. Duke Energy is piloting alternative storage technologies beyond lithium-ion batteries, including a 5 MW sodium-sulfur system at the historic Suwannee site in , operational as of May 2025, capable of storing energy for up to eight hours to test longer-duration discharge for grid resilience. In , Duke Energy announced plans in October 2023 to develop the nation's first integrated system for producing, storing, and combusting 100% in a at its sites, leveraging excess renewables for to enable low-emission peaking power. The company is advancing hydrogen-capable natural gas turbines, including two units planned adjacent to existing facilities in , as part of a broader outlined in its August 2023 updated Carbon Plan to reduce emissions while maintaining reliability. In June 2025, Duke Energy progressed a 1.4-gigawatt combined-cycle plant in designed for hydrogen blending, supported by agreements with Amazon, , , and to explore risk-sharing for carbon-free options like advanced nuclear and . Duke Energy is also evaluating carbon capture, utilization, and storage (CCUS) through pilot studies and DOE front-end engineering design, though without committed large-scale funding as of 2025, focusing instead on integration with existing fossil assets for emissions mitigation. Additionally, in January 2025, the company joined an industry consortium seeking DOE grants to accelerate small modular reactors and other advanced nuclear technologies, aiming to deploy them for baseload power amid rising demands.

Infrastructure and Grid Operations

Transmission and Distribution Systems

Duke Energy's transmission system comprises over 19,000 miles of high-voltage lines that transport electricity from generation facilities to substations, operating at voltages up to 525,000 volts, including 345 kV lines capable of spanning long distances such as river crossings. These lines connect to numerous substations, with configurations such as dual 525 kV and multiple 230 kV connections at key facilities, enabling efficient bulk power transfer across the company's service territories in the Carolinas, Florida, Midwest, and beyond. The system supports integration with regional grids, adhering to planning criteria that maintain voltage levels within specified limits during normal and contingency conditions to ensure stability. Distribution networks step down voltage from transmission levels—typically at 230 kV or below—to deliver power to end-users, serving approximately 8.6 million electric customers as of 2025. Subsidiary operations, such as Duke Energy Florida, cover 13,000 square miles with targeted infrastructure including undergrounding projects to mitigate outage risks from , while broader efforts incorporate self-healing technology that automatically isolates faults and reroutes power, reducing restoration times during events like Hurricanes Helene and Milton in 2024. Reliability metrics in 2024 reflected weather-related challenges, with unadjusted SAIDI elevated due to exclusions for major storms, yet investments in grid hardening—such as 600 miles of transmission upgrades—enhanced resiliency. Ongoing investments prioritize grid modernization, including advanced monitoring for voltage management and expansion of resilient to accommodate growing and distributed resources. Duke Energy has committed to significant capital outlays for transmission and distribution enhancements as part of broader plans exceeding $100 billion over the past decade, focusing on , threat resistance, and integration of renewables without compromising reliability standards. These efforts align with regional transmission , incorporating self-build requirements for interconnections that limit ground potential rise and ensure equipment safety.

Demand Response and Load Management

Duke Energy implements (DR) programs to incentivize customers to curtail electricity usage during periods, typically triggered by , thereby alleviating grid stress and deferring infrastructure investments. These initiatives, including automated load control and voluntary participation, have been expanded across service territories, with seeing enhanced financial incentives in August 2025 to address record usage levels. Load management complements DR by employing direct controls, such as cycling units, to shave peaks without customer intervention, supporting overall reliability amid growing demands. For commercial and industrial customers, Duke offers tailored DR options like Automation in , providing incentives for pre-qualified reductions during high-demand events, and EnergyWise Business, which targets heavy power users in summer and winter peaks. In , the SavingsOnDemand program delivers annual rewards for scaling back at least 100 kW during grid emergencies, with capacity credits of $24 per kW paid monthly. These programs shift non-essential loads away from critical hours, historically reducing system peaks by integrating participant commitments into operational planning. Residential efforts focus on behavioral and time-based incentives, including Time-of-Use (TOU) rates that lower costs for off-peak consumption and the Power Manager program, which installs devices to intermittently cycle HVAC systems during alerts, yielding bill credits for participants. Duke's subsidiary launched a Behavioral Managed EV Charging Program in 2024, encouraging off-peak charging to mitigate EV-induced peaks over four years. Customer alerts, such as those issued on June 23, 2025, in the , further promote voluntary reductions from 3-8 p.m., helping avert outages. Effectiveness is evidenced by post-event acknowledgments, as in June 2025 when customer participation managed hot-weather peaks, alongside studies assessing winter reduction potentials through expanded strategies like advanced metering. While DR avoids immediate capacity additions, outcomes depend on enrollment and response reliability, with Duke integrating these into broader grid optimization tools for and flexible load accommodation.

Integration of Distributed Energy Resources

Duke Energy integrates distributed energy resources (DERs), such as rooftop solar photovoltaic systems, battery storage, and electric vehicles (EVs), through a combination of incentive programs, advanced planning frameworks, and grid management technologies to accommodate growing customer adoption while maintaining system reliability. The company's Integrated System and Operations Planning (ISOP), implemented since in high-DER regions like the , forecasts DER penetration—including solar, storage, and EVs—and incorporates these into annual integrated resource plans via granular modeling and non-traditional solutions screening, such as community microgrids. This approach evaluates DER contributions to resource valuation and optimizes investments across , transmission, and distribution to minimize costs amid rapid DER growth. A key initiative is the PowerPair pilot program, launched in April 2024, which provides residential customers incentives up to $9,000 for pairing approved rooftop solar installations with battery energy storage systems, aiming to reduce and enhance grid resilience by enabling behind-the-meter storage to dispatch during high-load periods. The program targets integration by promoting paired systems that support two-way power flows and demand shifting, with eligibility limited to new installations in Duke's service territories. Complementing this, Duke Energy One offers solutions for commercial and industrial customers, selecting on-site DER mixes like solar and storage to provide backup during outages and improve overall reliability. Technological advancements facilitate DER accommodation, including a patented Advanced Power Distribution Platform announced in August 2024, which simulates grid operations down to individual customer loads, transformers, and DERs to predict overloads and automate responses like power rerouting or EV charging shifts to off-peak hours (9 p.m. to 6 a.m.). This tool supports over 1.5 million projected EVs by the end of the decade by modeling their integration alongside renewables, reducing costs and enabling cleaner energy optimization. Duke also participates in the , promoting OpenFMB standards for interoperable DER communication to simplify grid interactions with distributed intelligent nodes. Challenges arise from DER scale-up, particularly in , where solar installations are projected to increase sixfold by 2035, straining distribution transformers—exacerbated by EVs, where five vehicles equate to the load of one new traditional customer—and risking accelerated equipment aging without mitigation. To address this, deploys the moDERnize for real-time DER monitoring, forecasting, and control; "Flipping the Circuit" techniques to optimize voltage and expand hosting capacity; and the NOSC for autonomous smart charging that balances EV loads. An NREL-commissioned study for 's systems, with phases completed in 2020 and 2022, found that solar penetration up to 35% could elevate curtailment in low-demand seasons, though battery storage mitigates this, supporting up to 80% carbon-free generation with nuclear baseload. These efforts underscore 's focus on empirical grid modeling to balance DER benefits against operational risks like variability and localized overloads.

Regulatory Framework

Interactions with Federal Agencies

Duke Energy's nuclear operations are subject to oversight by the U.S. (NRC), which has approved subsequent license renewals for key facilities, such as the in , extending operations for Units 1, 2, and 3 by an additional 20 years each, effective March 2025, based on compliance with safety standards under the Atomic Energy Act. In April 2025, Duke submitted an application to the NRC for a similar 20-year renewal for the H.B. Robinson Nuclear Plant, demonstrating ongoing adherence to federal nuclear safety protocols amid evaluations of long-term plant viability. The company's plants have consistently met NRC requirements, including performance in security drills, though historical actions, such as a 2000 white finding at Oconee for significance determination, highlight periodic scrutiny of operational risks. Interactions with the (FERC) focus on transmission, interconnection, and hydroelectric relicensing. In March 2025, FERC approved Duke's compliance filing with Order 2023, revising generator interconnection procedures to address queue backlogs and enhance grid reliability. Duke received a 30-year FERC license renewal for the Keowee-Toxaway Hydroelectric Project in August 2016, enabling continued operations under federal standards for environmental and operational impacts. Disputes have arisen, including a 2023-2024 case where FERC rejected an Affected System Operator Agreement between Duke Energy Progress and American Beech Solar for interconnection, leading to appellate review in the D.C. Circuit, which upheld FERC's authority over such transmission-related pacts. The Environmental Protection Agency (EPA) has enforced compliance through settlements addressing and Clean Air Act violations. In May 2015, Duke subsidiaries pleaded guilty to nine criminal counts related to unauthorized coal ash discharges into waterways, resulting in a $102 million penalty and mitigation measures. A September 2015 Clean Air Act settlement required $975,000 in civil penalties and $4.4 million in environmental projects for pollution controls at coal plants. Additional resolutions include a 2016 $1 million fine for a oil spill violation in . These actions reflect federal emphasis on emission and discharge limits, with Duke admitting liability in criminal contexts but contesting broader claims in civil suits, such as a 2007 case on permit modifications under the Clean Air Act's prevention of significant deterioration provisions. Duke collaborates with the Department of Energy (DOE) on grid modernization and innovation funding. In August 2024, DOE awarded $57 million for a 40-mile transmission line rebuild in to bolster reliability for 14,000 customers. The DOE issued an emergency order in June 2025 allowing temporary exceedance of emission limits at Carolinas plants during high-demand periods, prioritizing reliability. Duke joined a 2025 public-private consortium seeking DOE grants for Generation III+ development, underscoring federal support for advanced nuclear amid goals. Earlier efforts include a DOE-funded Demonstration Project to optimize distributed resources.

State Utility Commission Dynamics

Duke Energy's subsidiaries interact with state utility commissions primarily through rate case proceedings, integrated resource plan (IRP) approvals, and petitions for investments, where commissions assess cost recovery against service reliability and affordability. These dynamics reflect tensions between the utility's capital-intensive needs for grid hardening—driven by aging and weather vulnerabilities—and consumer advocates' demands for restrained rate hikes, often amid advocacy from environmental groups for accelerated decarbonization. In states like and , commissions have balanced approvals for reliability-focused expenditures with periodic rate reductions tied to fuel cost fluctuations, while in and , judicial appeals have scrutinized commission decisions on cost justification and local mandates. In North Carolina, the North Carolina Utilities Commission (NCUC) has adjudicated Duke Energy Carolinas and Duke Energy Progress rate cases, approving a 5% base rate increase for Duke Energy Carolinas in December 2023 while mandating low-income affordability programs. The NCUC approved Duke Energy Progress's request to reduce residential rates by 4.5% effective January 2025, citing lower fuel costs, yielding average monthly savings of about $5 for typical customers. In November 2024, the NCUC endorsed elements of Duke's Carolinas IRP but faced criticism from groups like the Environmental Defense Fund for permitting delayed coal retirements, multiple new natural gas plants, and slower offshore wind deployment, potentially undermining the state's 70% emissions reduction target by 2032 despite feasible solar acceleration. Duke sought NCUC approval in August 2025 to merge its Carolinas subsidiaries, projecting over $1 billion in customer savings through operational efficiencies, with parallel filings in South Carolina. Florida's Public Service Commission (FPSC) approved Duke Energy Florida's multiyear rate settlement in August 2024 without modification, authorizing a $203 million increase in 2025 and $59 million in 2026 to fund grid resilience and solar expansion. The FPSC also greenlit a 2025 rate decrease in November 2024, driven by fuel clause adjustments, and in June 2025 approved centers in four counties via a rate adjustment mechanism. The Florida upheld FPSC's 2022 storm-protection plan approvals for Duke in November 2024, affirming recovery of hardening costs post-hurricanes despite challenges from consumer advocates. These decisions prioritize infrastructure recovery amid frequent severe weather, with the FPSC facilitating alternative rate plans for accelerated clean energy procurement. In , the Indiana Utility Regulatory Commission (IURC) has navigated disputes over Duke Energy Indiana's (IGCC) plant, culminating in 2015 settlements resolving $3.3 billion cost overrun claims with consumer and environmental groups. The in December 2024 interpreted state law to uphold IURC approval of Duke's energy plans if overall cost-justified, rejecting per-project mandates. In 2024, the court sided with Duke and the IURC against Carmel city's underground wiring ordinances, deeming them unreasonable impositions on utility expenses that would pass to ratepayers. Recent IURC orders, such as 2025 approval of environmental cost recovery, continue to enable rate recovery for compliance investments amid appeals from groups like Citizens Action Coalition challenging standing and prudence. Ohio's Public Utilities Commission (PUCO) has approved Duke Energy Ohio settlements, including a 2022 natural gas distribution rate case resolving infrastructure upgrade costs, but faced Ohio Supreme Court scrutiny in June 2025 when it permitted appeals of a 2023 gas rate plan approval, alleging improper ratemaking. Duke's June 2022 gas rate filing sought recovery for pipeline replacements serving 340,000 customers, reflecting ongoing proceedings to mitigate supply risks via auction-based procurement. These interactions highlight judicial oversight constraining PUCO discretion on rate impacts. Across jurisdictions, commissions like the Commission exhibit similar patterns, approving Duke Kentucky's filings for reliability investments while environmental intervenors advocate stricter emissions timelines, often resulting in modified plans that prioritize for grid stability over rapid fossil retirements. Such dynamics underscore commissions' role in enforcing least-cost principles, occasionally overriding activist pressures through evidentiary hearings and cost-benefit analyses. Duke Energy has incurred substantial compliance costs associated with environmental regulations, particularly those mandating coal ash remediation and emissions controls at its fossil fuel facilities. These costs, often in the hundreds of millions annually, stem from federal and state requirements under the Clean Air Act and coal combustion residuals rules, including groundwater monitoring, pond closures, and pollution abatement projects. For instance, in Indiana, Duke Energy sought recovery of $88 million in historical coal cleanup expenditures from 2019 to 2023, alongside $238 million in projected future spending through 2028, though an appeals court ruled in August 2025 that retroactive rate hikes for pre-filing costs were impermissible. In South Carolina, the utility has pursued regulatory asset treatment to defer and amortize post-2020 coal ash compliance costs, enabling partial customer rate recovery while earning a return on invested capital. Phase 3 of Duke's environmental compliance plans in Indiana alone projected $113 million in capital expenditures for scrubber installations and related upgrades, excluding ongoing operation and maintenance. Regulatory disputes over cost recovery frequently arise, with commissions adjusting allowances to balance utility investments against customer impacts. In a July 2024 South Carolina rate case, the Public Service Commission approved new tariffs but reduced recovery for certain North Carolina-mandated environmental costs, reflecting ongoing tensions between state-specific rules and interstate operations. has proposed merging its Carolinas and Progress subsidiaries to streamline duplicative regulatory filings, projecting over $1 billion in customer savings from reduced compliance administrative burdens by 2025. Such efforts highlight how fragmented state oversight amplifies overhead, with coal initiatives—driven by spills like the 2014 Dan River incident—comprising a core driver of expenditures exceeding $5 billion utility-wide since 2015. Legal proceedings against Duke Energy predominantly involve environmental enforcement, resulting in penalties totaling over $2.4 billion since 2000 for air pollution and residuals violations, per aggregated enforcement records. Major settlements include a $102 million fine in 2015 for Clean Air Act breaches tied to unauthorized modifications at 13 North Carolina plants, alongside commitments to install $1.1 billion in pollution controls without admitting liability. The 2014 Dan River coal ash spill prompted a $6 million state penalty in 2016 and a separate $3 million federal cleanup mandate, addressing 39,000 tons of material discharged into waterways. In North Carolina, a 2021 coal ash accord shifted $1.1 billion in remediation costs away from ratepayers, while a 2023 DEQ settlement imposed $20 million in fines and accelerated groundwater remediation at four sites. Other actions encompass Clean Air Act litigation resolved in 2015 after 15 years, yielding emissions reductions without further penalties, and a $1.75 million fine in 2025 for violations at the Indiana Gallagher plant, paired with $85 million in upgrades. proceedings in 2018 exacted a $3.5 million for allegations, with mandated compliance reporting. State-level fines, such as $25 million in 2015 for groundwater contamination at the Sutton plant, underscore recurring coal ash liabilities, often mitigated through negotiated remediation rather than full admissions of fault. These cases typically conclude in settlements emphasizing injunctive relief over , reflecting regulators' focus on amid high-stakes .

Environmental Record

Duke Energy's Scope 1 greenhouse gas emissions, predominantly carbon dioxide (CO₂) from fossil fuel-based electricity generation, totaled approximately 138 million metric tons in 2005, serving as the company's baseline for reduction targets. By 2023, these emissions had declined to 72 million metric tons, reflecting a 48% reduction driven by the retirement of coal-fired capacity, increased utilization of natural gas combined-cycle plants, and expansions in nuclear and renewable generation. This downward trajectory aligns with broader industry shifts under regulatory pressures, including Clean Air Act amendments, though absolute emissions remain substantial due to Duke's large service territory spanning multiple states with high electricity demand. Parallel reductions occurred in criteria pollutants: (SO₂) emissions fell 98% and nitrogen oxides (NOₓ) decreased by over 90% from 2005 levels through 2023, primarily via installation of systems, units, and coal unit retirements exceeding 10 GW since 2010. Year-over-year declines, such as the drop from 2022 to 2023 attributed to lower dispatch and moderated demand, underscore operational adjustments amid fluctuating fuel prices and weather patterns. These trends, verified through EPA compliance reporting and Duke's integrated resource plans, demonstrate causal links between fleet modernization and emission cuts, though challenges persist from intermittent renewable integration and gas dependency.
YearCO₂ Emissions (million metric tons)Key Driver
2005~138Baseline; heavy reliance
2022~80 (implied from 44% reduction)Ongoing retirements and gas shift
202372Reduced fossil generation
Emissions intensity, measured as CO₂ per megawatt-hour, has similarly trended downward, supporting Duke's commitments like a 50% CO₂ cut by 2030 from levels, though actual progress depends on regulatory stability and technology costs rather than aspirational goals alone. Historical data from EPA settlements further quantify localized impacts, such as over 2 million tons each of SO₂ and NOₓ avoided through plant-specific upgrades.

Regulatory Compliance and Penalties

Duke Energy has incurred significant penalties for environmental non-compliance, particularly concerning coal ash management and emissions from coal-fired plants, reflecting challenges in maintaining aging infrastructure under federal and state regulations like the Clean Water Act and Clean Air Act. In response to violations, the company has entered settlements mandating remediation, such as basin closures and pollution controls, though recurring issues have prompted ongoing enforcement actions by agencies including the EPA and Department of Environmental Quality (DEQ). A landmark case involved the 2014 Dan River coal ash spill, where 39,000 tons of ash and 27 million gallons of wastewater entered the river due to a pipe failure at a Duke facility in Eden, North Carolina, violating Clean Water Act discharge permits. Duke agreed to a $6 million penalty in 2016 to resolve state claims, following an initial $6.8 million fine it contested; the settlement supported river restoration without admitting liability. Broader coal ash groundwater contamination at multiple sites led to a 2015 $25.1 million fine from North Carolina regulators for unpermitted discharges affecting drinking water sources. In 2015, Duke subsidiaries pleaded guilty to nine Clean Water Act felonies for illegal discharges of coal ash pollutants into waterways across , resulting in a $102 million penalty that included $68 million in criminal fines and $34 million for mitigation projects like wetland restoration. This stemmed from systemic failures in systems at 13 facilities. Separately, a 2009 Clean Air Act settlement required $93 million in pollution controls and a civil penalty to address New Source Review violations at plants in the Midwest and Southeast, projected to cut sulfur dioxide emissions by over 110,000 tons annually. More recent actions include a March 2025 EPA settlement for Clean Air Act violations at the Gallagher Station in , imposing a $1.75 million for excess particulate matter and opacity emissions from 2018 to 2022, alongside required upgrades to electrostatic precipitators. In 2015, another EPA agreement for the Allen Steam Station in yielded a $975,000 penalty and unit retirements to curb oxides and , reducing annual emissions by about 2,300 tons. A 2020 DEQ settlement totaled around $20 million, with $7 million in penalties for historical groundwater impacts at 14 ash sites and $10-15 million for accelerated closures. Smaller fines, such as $156,000 in 2015 for surface water at the Cape Fear plant and $84,000 in 2018 for leaks at three facilities, highlight persistent and lapses. These penalties, totaling hundreds of millions since the early 2000s, underscore Duke's transition from dependency amid stricter post-2010 regulations, with compliance efforts including full excavation of unlined ash ponds ordered by in 2019—estimated at $5.6 billion in costs passed partly to ratepayers. Federal trackers attribute over $2.4 billion in environmental penalties to Duke since 2000, predominantly for air and water violations, though the company maintains these reflect legacy operations rather than willful disregard.

Carbon Reduction Commitments Versus Actual Outcomes

Duke Energy committed in 2019 to achieving net-zero carbon emissions from electric generation by 2050, with an interim target of at least 50% reduction in CO₂ emissions by 2030 relative to 2005 baseline levels. The company also set a goal to limit coal-fired generation to less than 5% of its total mix by 2030 and fully retire coal assets by 2035, subject to regulatory approval, while expanding renewables and energy efficiency to support these targets. In 2022, Duke Energy established additional interim milestones, including an 80% reduction by 2040 from the same 2005 baseline. Actual CO₂ emissions from Duke Energy's electric generation have declined substantially since the 2005 baseline, reaching a 48% reduction by 2023 through plant retirements, fuel switching to , and increased renewable integration. This progress aligns closely with the 50% reduction target for 2030, as emissions intensity and absolute output both decreased amid a 20% rise in sales over the period, driven by programs avoiding an estimated 24 million MWh of energy use. emissions fell 97% and nitrogen oxides 90% over the same timeframe, reflecting compliance with Clean Air Act standards and installations. Despite historical reductions, Duke Energy's 2025 North Carolina carbon plan projects a temporary emissions uptick, with CO₂ output climbing through the mid-2030s due to surging demand from centers and before peaking at approximately 60 million short tons in 2036 and then declining toward net-zero. This trajectory relies on as a bridge fuel, which accounted for about 50% of generation in recent years, potentially offsetting renewable gains if load growth exceeds projections. In November 2024, the Utilities Commission granted Duke Energy a from a state-mandated 70% reduction by 2030—stricter than the company's voluntary 50% goal—citing reliability needs amid rapid demand increases, allowing flexibility in retirement timelines. Projections indicate Duke Energy could exceed its 2030 target if current trends hold, but sustained progress toward 2050 net-zero hinges on regulatory approvals for nuclear life extensions, offshore development, and battery storage, as fossil fuels remain dominant in the near term. Independent analyses, such as NREL's 2022 integration study, affirm feasibility through high renewable penetration but highlight integration challenges like , underscoring that actual outcomes will depend on grid-scale carbon-free dispatch rather than commitments alone.

Reliability and Service Delivery

Historical Outage Statistics and Causes

Duke Energy assesses service reliability using industry-standard metrics such as the System Average Interruption Duration Index (SAIDI), which measures average outage duration in minutes per customer annually; the , which counts average interruptions per customer; and the , derived as SAIDI divided by SAIFI. These indices exclude major events like hurricanes per IEEE standards to evaluate baseline performance, though unadjusted figures reveal weather impacts. For real-time monitoring of current outages, Duke Energy provides an official power outage map at https://outagemap.duke-energy.com/ []. As of a recent update, the map reported only 2 customers without power in Mecklenburg County, North Carolina (out of 563,372 tracked customers, 0.00% affected), with overall county outages minimal at 21 customers primarily from other providers. In Duke Energy , adjusted SAIDI improved to 70.9 minutes in 2023, a 17% reduction from , attributed to storm hardening investments yielding the subsidiary's best reliability in over a . Unadjusted SAIDI for 2023 fell 39% below the prior year despite moderate weather exclusions, while 2024's unadjusted SAIDI surged due to significant hurricane activity. For Duke Energy Progress in , recent metrics include SAIDI of 141 minutes and of 1.19 system-wide, with localized variations like 100.2 minutes SAIDI and 1.02 in select areas. Major outages predominantly stem from severe weather, including hurricanes that damage poles, lines, and substations via high winds, flooding, and debris. Hurricane Helene in September 2024 caused 1.7 million customer outages across the Carolinas, with multiday disruptions from historic flooding and downed trees blocking access. Similar impacts occurred from Hurricanes Milton and Debby in 2024, where self-healing grid technology mitigated some durations but could not prevent widespread failures from equipment overload and vegetation contact. Vegetation encroachment and animal intrusions account for notable non-weather causes; trees felled by storms or overgrown lines frequently short circuits, as in a May 2025 event affecting thousands. Snakes and squirrels routinely trigger substation faults, exemplified by multiple 2025 incidents in impacting over 10,000 customers each via equipment contact. Equipment failures and human-related accidents, such as vehicle collisions with poles, contribute smaller shares but underscore aging vulnerabilities. Storms and tree-related issues constitute the majority of outages, with investments in trimming and undergrounding aimed at mitigation.

Investments in Resilience and Upgrades

Duke Energy's five-year capital plan, spanning 2024 to 2029, totals $83 billion, with significant portions directed toward grid modernization and resilience enhancements to mitigate outages from and support growing demand. In , investments have expanded to over $16 billion through 2029, including storm hardening measures such as undergrounding overhead lines, elevating substations, and reinforcing feeder backbones to withstand hurricanes. These efforts are tracked via the company's annual Plan reports to the Public Service Commission, which detail project costs and progress under the Storm Plan Cost Recovery Clause. A core component involves deploying self-healing grid technology, which uses sensors and to detect faults and reroute power, thereby isolating issues and restoring service to unaffected areas within seconds. By September 2025, this technology served approximately 80% of Duke Energy Florida's customers, including 90% in Pinellas County, where it prevented 95,000 outages and saved 81 million customer minutes of interruption in 2024 alone. Similar implementations in and other regions have reduced outage impacts during storms, with expansions planned to cover more of the service territory. Infrastructure upgrades also encompass replacing wooden poles with steel variants, installing flood barriers at substations, and enhancing transmission lines for greater capacity and durability. In the Pinellas County Reliability Program, Duke Energy constructed new lines, upgraded equipment, and integrated self-healing systems to boost overall grid capacity and reduce vulnerability to disruptions. Federally, the U.S. Department of Energy awarded Duke Energy $57 million in cost-share funding on August 6, 2024, for a project to integrate clean energy resources, harden , and improve resilience against events. State-level support includes Department of Environmental Quality grants exceeding $20 million for seven resiliency projects, one involving Duke's Area upgrades, announced April 29, 2025. These investments have yielded measurable reductions in outage durations; for instance, Duke Energy Florida's hardening efforts contributed to saving 313 million customer minutes during 2024 storms by enabling faster restorations. In , a proposed $74.8 million rate adjustment in June 2025 funds ongoing grid reliability upgrades. Overall, such measures prioritize empirical risk reduction over unproven alternatives, focusing on physical and automated response to causal factors like high winds and flooding prevalent in Duke's operational regions.

Performance During Major Weather Events

Duke Energy has demonstrated varying performance in restoring power following major hurricanes impacting its service territories in the and , often achieving rapid restorations for the majority of affected customers through prepositioned crews and grid hardening investments, though prolonged outages have occurred in areas with severe flooding or infrastructure damage. During in 2018, the company experienced approximately 1.7 million outages across the , restoring power to over 1.5 million customers within days despite widespread flooding that delayed access to some sites; full restoration efforts earned the Edison Electric Institute's Emergency Recovery Award for operations in hazardous conditions. In , which struck in September 2022, Duke Energy Florida reported over 1 million outages, restoring power to more than 650,000 customers within the initial days using a workforce of 10,000 personnel, with self-healing grid technology automatically mitigating an additional 160,000 outages during the storm. Restoration for all viable customers was completed by early , though debris and flooding extended timelines in coastal zones. Hurricane Helene in September 2024 caused extensive outages exceeding 2 million across Duke's territories, with the company restoring power to over 2.16 million customers, including 90% of those capable in the by early and approximately 800,000 in ; estimated restoration times were set for most areas within 3-5 days post-landfall, aided by mobilized resources despite unprecedented inland flooding. Challenges persisted in western regions with damaged poles and lines, where multi-day outages were anticipated due to topographic barriers. During Winter Storm Uri in February 2021, Duke Energy Carolinas faced outages affecting hundreds of thousands amid regional grid strains, primarily from frozen equipment and demand surges, but avoided the widespread blackouts seen in ; restoration focused on de-icing and fuel supply stabilization, with lessons incorporated into subsequent emergency protocols. In more recent events, such as severe storms in April 2025 across and , the company restored 96% of 69,000 outages within 36 hours, highlighting improvements in response efficiency. Overall, Duke's metrics show median restoration times under 48 hours for 90% of customers in hurricane scenarios, bolstered by technologies like self-healing reclosers that prevented tens of thousands of additional outages in events like and .

Controversies and Stakeholder Critiques

Resource Planning Disputes

In June 2021, the Public Service Commission rejected integrated resource plans (IRPs) submitted by Duke Energy Carolinas and Duke Energy Progress in a 4-2 vote, citing flawed assumptions that favored over solar and battery storage. The commission identified overly optimistic residential demand growth forecasts (1% annual increase through 2035, exceeding flat trends from 2010-2019), artificial caps on solar additions (500 MW per year), dismissal of storage viability, and inadequate risk assessment for gas supply constraints, including pipeline uncertainties. It directed Duke to resubmit revised plans incorporating lower load growth scenarios, solar costs at $38/MWh, National Renewable Energy Laboratory benchmarks for storage, expanded solar capacity to at least 750 MW annually, and explicit modeling of gas risks. In , disputes intensified around Duke's 2023 Combined Carbon Plan and Integrated Resource Plan (CPIRP), which proposed up to five new combined-cycle alongside delayed coal retirements, drawing criticism from environmental groups for insufficient progress toward the state's 70% carbon reduction target from 2005 levels by 2030. Stakeholders including NC WARN argued the plan exaggerated renewable costs while understating gas expenses and future demand, projecting over 50 new gas-fired units by 2035 and only 14% renewables despite national averages exceeding 20%, potentially locking in billions in customer-funded fossil infrastructure amid viable solar-plus-storage alternatives. The Utilities Commission held evidentiary hearings in July 2024 on plan costs and emissions impacts, where expert testimony highlighted risks of over-reliance on intermittent renewables without adequate firm capacity. Duke defended its gas-heavy portfolios as essential for grid reliability amid surging demand—projected to grow eight times faster than historical norms due to electrification and data centers—while a July settlement reduced proposed gas additions but retained significant commitments. In November , the commission approved the CPIRP with modifications, directing Duke to explore accelerated solar, offshore wind, and demand-side options but permitting flexibility on the 2030 target amid federal compliance pressures, such as potential retrofits or retirements by 2031 at sites like Belews Creek. Critics like the and contended the order enabled stalling on decarbonization to prioritize gas, potentially conflicting with net-zero goals by 2050, though Duke cited modeling showing only one low-gas portfolio met emissions mandates without reliability gaps. Duke's October 2025 Carolinas Resource Plan update escalated tensions by emphasizing nuclear restarts, additional gas, and extensions while omitting onshore , prompting Josh Stein's prior (overridden by ) of easing interim carbon mandates due to gas price volatility risks. These conflicts reflect broader stakeholder divides: utilities and regulators prioritizing dispatchable capacity for load growth versus advocates urging cost-minimizing renewables, with empirical modeling disputes often hinging on valuations and assumptions.

Rate Structures and Affordability Concerns

Duke Energy's residential rate structures primarily consist of a fixed customer charge covering basic facilities and metering costs, combined with a volumetric energy charge applied to kilowatt-hours (kWh) consumed, often structured in tiers or flat rates varying by state and season. For example, in North Carolina, residential schedules under Duke Energy Carolinas include a basic facilities charge of approximately $14 per month and energy rates around 10-12 cents per kWh, subject to adjustment riders for fuel costs, renewable energy incentives, and storm recovery. Commercial and industrial rates add demand charges based on maximum kilowatt (kW) usage during peak periods, alongside energy charges, to reflect infrastructure strain from higher loads; for instance, Duke Energy Progress South Carolina's 2025 rate review proposed average commercial increases of 12.8% incorporating such elements. Time-of-use (TOU) options exist for eligible customers, offering lower off-peak rates to encourage load shifting, though adoption remains limited. Recent rate cases have driven structural adjustments amid infrastructure investments and demand growth, with fixed charges facing scrutiny for disproportionately burdening low-usage households. In , Duke Energy Carolinas' 2025 rate case sought increases averaging 5.4% for commercial customers, following an 8.7% residential hike effective August 1, 2024, adding $12.06 monthly to a typical 1,000 kWh bill. North Carolina's 2023 rate cases for Duke Energy Carolinas and resulted in approved increases, prompting to in February 2024, citing excessive returns on equity exceeding 10% and inadequate affordability safeguards. Proposals to raise fixed charges, such as a 2019 South Carolina request to triple the monthly fee from $8.29 to $28, were rejected by regulators due to equity concerns, though incremental hikes persist in multi-year plans. Affordability challenges have intensified with cumulative hikes outpacing inflation, particularly for low-income and fixed-income customers, as evidenced by consumer complaints to state commissions and advocacy critiques. In , Energy's 2024 rate case approved a $19.16 monthly residential increase despite initial requests for 16.2% hikes and 29.9% fixed charge expansions, exacerbating bills already among the state's highest. Groups like the Southern Environmental Law Center noted that 2023 approvals boosted profits while adopting some low-income programs, yet fixed charge expansions in proposals continue to penalize conservation efforts by low-usage households. mitigates impacts through programs like the federally funded Low-Income Home Energy Assistance Program (LIHEAP), providing one-time payments, and state-specific initiatives such as 's Customer Assistance Program offering up to $42 monthly credits for eligible households. Projections indicate moderated bill impacts from the 2025 Carolinas Integrated Resource Plan, averaging 2.1% annual increases over the next decade—below —despite eightfold demand growth from and centers, attributing restraint to efficient resource additions like gas and renewables. However, stakeholders including Upstate Forever warn that even these trajectories strain vulnerable customers amid broader cost pressures from grid hardening and decarbonization. Regulatory oversight via public service commissions balances recovery of capital expenditures with consumer protections, though appeals and hearings reflect ongoing tensions over prudent versus excessive spending.

Political and Environmental Advocacy Conflicts

Duke Energy has expended substantial resources on political and campaign contributions, registering $6.4 million in federal expenditures in 2024 and $4.77 million through mid-2025, primarily advocating for policies supporting reliability, regulatory stability, and affordability. Its political action committee raised $618,933 in individual contributions during the 2024 cycle, directing funds to candidates across party lines in states like and where it operates. Critics, including Republican leaders, have accused the company of wielding through these donations—totaling millions annually—and , potentially prioritizing corporate interests over protections in rate cases and market . Such concerns escalated in cases like a 2019 lawsuit by NTE Energy alleging Duke monopolized wholesale power markets in , stifling competitors via political leverage. Environmental advocacy conflicts have centered on disputes over Duke's energy transition strategies, with activist groups frequently challenging its carbon reduction plans before regulators like the North Carolina Utilities Commission. In September 2024, organizations including the Southern Environmental Law Center and urged rejection of Duke's proposed Carbon Plan, arguing it violated state laws by delaying coal retirements, over-relying on infrastructure, and underutilizing cost-saving efficiency measures and renewables to meet a 70% emissions cut from 2005 levels by 2030—though subsequent legislation relaxed interim targets. Similar opposition arose in 2022 against Duke's policy changes, which over 17 solar firms and 54 nonprofits claimed would hinder rooftop solar adoption by reducing incentives for . Litigation has amplified these tensions, exemplified by the Town of Carrboro's December 2024 lawsuit accusing of orchestrating a decades-long campaign since the to downplay risks, thereby postponing cleaner transitions and exacerbating local damages from events like Hurricane Helene in 2024. coalitions intervened in 2024 proceedings to demand greater protections for frontline communities, criticizing 's plans for perpetuating pollution burdens despite internal awareness of emissions impacts. has countered that such suits threaten established state regulatory frameworks, emphasizing balanced approaches incorporating nuclear and gas for grid reliability amid activist pushes for accelerated renewables that overlook and cost risks. analyses have graded 's clean energy efforts a "D" as of 2023, citing insufficient prioritization of efficiency and storage over fossil extensions, though the utility maintains its plans align with empirical load growth and feasibility constraints.

Strategic Outlook and Innovations

Long-Term Resource Plans (e.g., 2025 Carolinas Plan)

Duke Energy Carolinas and Progress Energy Carolinas, operating in North and , develop long-term resource plans as required by state regulators to forecast , evaluate options, and propose a mix ensuring grid reliability over a 15-year horizon. These plans integrate load growth projections, technology assessments, and economic analyses, prioritizing dispatchable capacity to maintain stability amid variable renewables and rising from , data centers, and industrial expansion. The 2025 Carolinas Resource Plan, filed with the Utilities Commission and Public Service Commission on October 1, 2025, addresses demand growth forecasted at eight times the average rate of the prior 15 years, equivalent to adding power for over 1 million new homes by 2040. This acceleration stems from economic factors, including $19 billion in investments creating 25,000 jobs in 2025 alone, alongside AI-driven loads and resurgence. Key proposals emphasize a balanced portfolio: 4,000 MW of new solar capacity by 2034 to meet ongoing procurement targets; battery storage expanded to 5,600 MW by 2034, doubling prior commitments for intermittency support; and additions comprising five combined-cycle units and seven combustion turbines at specified sites like Lincoln and counties. Nuclear development advances through studies for large light-water reactors and small modular reactors, targeting operational status by 2037 at sites including Belews Creek in and William States III in , to provide carbon-free baseload power. retirements proceed orderly per prior approvals, but 2-4 year extensions for dual-fuel units at plants like Allen and Riverbend are considered to bridge near-term reliability gaps amid and uncertainties.
Resource TypeProposed Capacity/AdditionTimeline/Notes
Solar4,000 MWBy 2034; aligns with 1,700 MW 2025 target
Battery Storage5,600 MWBy 2034; up 2,900 MW from 2023 plan
Natural Gas5 combined-cycle units + 7 combustion turbinesPhased additions through 2030s
Nuclear (New)Light-water reactors/SMRs (studies)In-service target: 2037; sites: Belews Creek, W.S. Lee
Coal Extensions2-4 years for select dual-fuel unitsTo ensure reliability during transitions
Pumped HydroDeferred developmentFrom 2034 to 2040
Wind power expansion is minimal, deferred to the 2040s due to higher costs and transmission challenges relative to alternatives. The plan leverages existing assets, federal tax credits, and customer efficiency programs to cap annual bill impacts at 2.1%, below projected , while hearings commence in 2026 for final regulatory orders by December 31, 2026. This approach responds to the removal of North Carolina's interim carbon reduction mandate, shifting emphasis to cost-effective, reliable resources over accelerated decarbonization to avoid supply shortfalls.

Adoption of AI and Advanced Analytics

Duke Energy initiated its adoption of artificial intelligence (AI) and advanced analytics in 2017, beginning with predictive models applied to weather-normalized meter data to identify slow meters and potential energy theft. That same year, the company established the MADLab (Machine Learning, Artificial Intelligence, and Deep Learning Lab) as a cross-functional team of data scientists, engineers, and developers, which expanded to nearly 30 members and delivered projects including image analytics for drone inspections, neural networks for asset optimization, and natural language processing for customer service enhancements, yielding annual savings in the millions of dollars. In renewable energy operations, Duke Energy deployed the IdentiFlight system at its Top of the World Windpower Project in starting in 2021, utilizing cameras and AI algorithms to detect bald and golden eagles in flight, automatically curtailing nearby blades to prevent collisions; an independent 2020 study documented an 82% reduction in eagle fatalities. For grid management, the company partnered with Awesense to integrate data from 7.2 million sources—including GIS, AMI meters, , and line sensors—creating a of the distribution grid and resolving 97% of 500,000 issues via validation algorithms, thereby enabling near-real-time analytics and improved across departments. In 2022, Duke Energy expanded its Intelligent Grid Services through a collaboration with , developing custom applications on AWS cloud infrastructure to enhance grid responsiveness and support clean energy transitions with advanced data processing. By 2024, Duke Energy had formalized AI governance with guardrails for ethical deployment and advanced over 50 generative AI use cases across field operations, , and IT functions, reducing manual workloads, accelerating , and optimizing asset performance—such as extracting an additional 1% efficiency from generation plants and transmission lines. These efforts collectively support , , and operational resilience amid rising loads, with the company's 55 gigawatts of generation capacity and 11 nuclear reactors serving as foundational assets for scaling analytics-driven innovations.

Contributions to Economic Growth and Load Forecasting

Duke Energy's economic development initiatives, including the Site Readiness Program, have facilitated site evaluations and preparations that attract major projects, resulting in significant job creation and capital inflows across its service territories. In Ohio and Kentucky, the program has supported 5,400 new jobs and $2 billion in capital investments since 2010, with 5,973 jobs and $3.98 billion added since 2020 alone. In 2024, company efforts secured 78 projects across six states, yielding over 16,000 new jobs and $26 billion in capital investments. These programs enhance community competitiveness by addressing infrastructure needs, thereby drawing energy-intensive industries and fostering local economic expansion. The company's substantial capital expenditures further amplify these contributions, with $195 billion allocated for energy modernization from 2025 to 2034, generating an estimated $369.5 billion in total economic output and $211 billion in GDP impact over the period. This supports an average of 168,120 jobs annually, comprising 80,180 direct, 39,520 indirect, and 48,420 induced positions, alongside $131 billion in and $18.5 billion in state and local taxes. Such expenditures, focused on grid upgrades and generation capacity, underpin sustained growth by enabling reliable power for expanding sectors like and centers. Duke Energy's load practices integrate econometric models, weather data, and emerging demand drivers like and large-load customers, informing integrated plans to match supply with growth. Recent forecasts reflect accelerated demand, projecting 1.5-2% annual load growth in 2026 rising to 3-4% through 2029, driven by AI data centers and industrial resurgence—eight times higher than prior estimates in some regions. In the 2025 Carolinas Plan, the company anticipates unprecedented energy needs over the next decade, prompting additions like 1,700 MW of solar and battery storage in 2025 to avert shortages. Accurate mitigates risks of underinvestment, ensuring infrastructure scales with economic activity and supports seamless expansion without reliability disruptions.

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