[DUK] Duke Energy: Q3 2026 Earnings Test Rate Recovery Against Rising Costs

Duke Energy is a regulated electric and natural gas utility headquartered in Charlotte, North Carolina, serving about 8.7 million retail electric customers across six states in the Southeast and Midwest[1]. Duke Energy Q3 2026 earnings are scheduled for 2026-11-05 and will cover the Third quarter 2026 (three months ended September 30, 2026)[2]. In the latest disclosed period, the second quarter of 2026, the company reported GAAP EPS of $1.38 and adjusted EPS of $1.43, against $1.25 on both measures a year earlier; adjusted Electric Utilities and Infrastructure segment income was $1,310 million versus $1,194 million; and first-half adjusted EPS was $3.36 versus $3.00[3]. With the second-quarter results, management reaffirmed 2026 adjusted EPS guidance of $6.55 to $6.80 and a long-term adjusted EPS growth rate of 5% to 7% a year through 2030 off the 2025 midpoint of $6.30, and said it had confidence in earning in the top half of that range beginning in 2028[3]. The company does not give quarterly guidance; Drillr's compilation of 9 analysts puts consensus third-quarter EPS at $1.863 (range $1.814 to $1.893), 6 analysts put consensus third-quarter revenue at $8,908.7 million (range $8,788.6 million to $9,008.8 million), and 13 analysts put full-year EPS consensus at $6.717[4].

Three things matter most in this report. The first is whether rates and riders already in effect can keep outrunning costs: in the first half, rate cases added $0.24 a share and riders added $0.22, while depreciation, interest and O&M together subtracted $0.35[3], and the new rates requested by the two North Carolina utilities would take effect no earlier than January 2027[5], so the third-quarter driver breakdown will show whether that gap is narrowing or widening. The second is whether data-center signings can speed up again: cumulative electric service agreements rose only from about 7.6 gigawatts at the end of the first quarter to 7.8 gigawatts[6][7], management still plans to convert the full 15.4-gigawatt late-stage pipeline into signed agreements by the first half of 2027[7], and weather-normalized retail sales grew 1.3% year over year in the second quarter[3], so third-quarter signings and volumes will test the basis for future investment and the current contribution from sales respectively. The third is whether funding pressure rises ahead of rate recovery: first-half capital spending in the electric and gas segments totaled $8,024 million while operating cash flow was $4,272 million[5], and third-quarter interest drag, cash flow and the pace of capital spending will show whether that funding gap remains manageable.

Company Background and Business Structure

Duke Energy operates through six main subsidiaries: Duke Energy Carolinas (DEC), Duke Energy Progress (DEP), Duke Energy Florida, Duke Energy Indiana, Duke Energy Ohio and Piedmont Natural Gas[1]. Its electric service territory covers about 90,000 square miles and an estimated 27 million people across six states, and beyond retail service it sells power wholesale to municipalities, electric cooperatives and other load-serving entities[1]. DEC and DEP, the two Carolinas utilities, are combining: the South Carolina Public Service Commission issued its final order approving the combination on June 3, 2026[5], and the company says the combination is expected to save customers $2.3 billion through 2040[6].

The company reports two segments, and electricity is by far the larger one. In 2025 the Electric Utilities and Infrastructure segment had revenue of $29,357 million and segment income of $5,337 million, including residential revenue of $13,756 million, commercial $8,337 million, industrial $3,423 million and wholesale $2,402 million[1]. The Gas Utilities and Infrastructure segment had 2025 revenue of $3,003 million and segment income of $559 million, while the Other segment, which mainly carries holding-company debt interest, lost $985 million[1]. Group earnings therefore depend almost entirely on how state commissions set electric rates, and the gas business is roughly one-tenth the size of the electric business.

Duke Energy builds and operates a large generating fleet, and nuclear power is the baseload for the two Carolinas utilities. At the end of 2025, DEC had 20,901 MW of capacity, including the Oconee, McGuire and Catawba nuclear stations, and DEP had 14,068 MW, including the Brunswick, Harris and Robinson nuclear stations, for a combined total of roughly 35,000 MW[1]. These assets form the core of the rate base, and new gas units and transmission and distribution investment enter rates through the same regulatory process.

Two transactions in 2026 changed the group's ownership structure and business perimeter. On March 3, 2026, an affiliate of Brookfield completed the first closing, acquiring 9.2% of Florida Progress, the holding company of Duke Energy Florida, for about $2.8 billion, and committed to invest a further $200 million by the end of 2026, $500 million by June 30, 2027, $1.5 billion by the end of 2027 and $1 billion by June 30, 2028[8]; the full arrangement corresponds to $6 billion of investment and an eventual indirect stake of about 19.7%[1]. On March 31, the company sold Piedmont's Tennessee gas business to Spire for $2.48 billion, using about $800 million to repay Piedmont debt and about $1.5 billion, net of tax, for its capital plan[9].

Financial History and Current Position

In full-year 2025, both revenue and earnings were dominated by the electric segment. Consolidated operating revenue was $32,237 million, net income available to common stockholders was $4,912 million, and adjusted EPS was $6.31, up from $5.90 in 2024[1]. On the cost side, electric-segment fuel and purchased power cost $8,138 million, while group operation, maintenance and other expense was $6,698 million, depreciation and amortization $6,324 million and interest expense $3,634 million[1].

Both investment and debt are rising quickly. Capital investment expenditures were $14,002 million in 2025, including $12,553 million in the electric segment and $1,114 million in the gas segment; at year-end, long-term debt including current maturities was $86,865 million, of which $7,123 million matures in 2026[1]. The 10-K projects capital and investment expenditures of $17,750 million in 2026, $19,500 million in 2027 and $21,200 million in 2028[1], and the five-year capital plan totals $103 billion, which the company describes as the industry's largest regulated capital plan[9].

First-quarter 2026 growth came mainly from rate recovery and cold weather. First-quarter GAAP EPS was $1.97 and adjusted EPS was $1.93, against $1.76 on both measures a year earlier; adjusted electric segment income was $1,404 million versus $1,276 million, and adjusted gas segment income was $361 million versus $349 million[10]. The difference between GAAP and adjusted results came from legal and regulatory settlements (−$0.19 a share) and gains on asset sales (+$0.22 a share)[10].

The second quarter extended the growth, though it is a smaller quarter than the first. Second-quarter adjusted EPS was $1.43, adjusted electric segment income was $1,310 million, gas segment income was $10 million (versus $6 million a year earlier), and the Other segment's loss narrowed from $228 million to $204 million; first-half adjusted EPS of $3.36 was $0.36 above the prior-year $3.00[3].

Cash flow and funding sources show investment spending well ahead of operating cash inflows. First-half 2026 operating cash flow was $4,272 million, electric segment capital spending was $7,463 million (up about 30% from $5,724 million), and gas segment capital spending was $561 million (versus $548 million)[5]; Drillr financial data put prior-year first-half operating cash flow at about $5.04 billion. At March 31, the company held $2.1 billion of cash and had $8.0 billion available under its $10 billion master credit facility, which was extended to March 2031[11]. In March 2026 it signed an at-the-market equity program of up to $6 billion that runs through September 2028[5], has priced $600 million so far this year, and raised the quarterly dividend 2% in July[7].

Operating Model

Duke Energy's revenue is set jointly by regulator-approved rates and sales volumes. Electric revenue roughly equals each state's retail sales multiplied by approved rates, plus wholesale revenue, rider revenue and fuel and purchased-power costs passed through at cost; approved rates in turn equal the revenue requirement divided by forecast sales, where the revenue requirement covers O&M, depreciation, taxes, fuel and the rate base multiplied by the weighted return on capital. In 2025 the electric segment's $8,138 million of fuel and purchased power was passed through at cost, lifting revenue without directly determining profit[1].

Earnings are essentially rate base multiplied by the allowed return on equity and the equity ratio, minus regulatory lag. Depreciation and interest start as soon as new assets enter service, while rates only begin recovering them after the next rate case or rider adjustment. First-half 2026 adjusted EPS rose $0.36, with rate cases contributing $0.24, riders and other retail margin $0.22, volume $0.11, wholesale $0.05 and weather $0.02, partly offset by depreciation and amortization of −$0.17, interest of −$0.09 and O&M of −$0.09[3].

The regulatory process sets the lag between investment and earnings. In November 2025 DEC requested about $1,002 million of additional revenue over two years and a 10.95% return on equity, and in June 2026 it cut the request to about $622 million and 10.48%[12]; the July settlement uses a 9.8% allowed return on equity and 53% equity, with earnings sharing allowing up to 10.3%[7], and DEP has asked for its Year 1 rates to take effect no later than January 1, 2027[5]. The lag on data-center load is longer: customers have started vertical construction, with energy use expected to begin in the second half of 2027 or 2028 and to ramp to full contracted load by the early 2030s[7].

The cash model rests on capital spending that keeps exceeding operating cash flow, with the gap filled by outside funding. Management's funding sources include Brookfield's staged payments for the Florida minority stake[8], net proceeds from the Tennessee gas sale[9], new debt and at-the-market equity; management says the company is on track for a 14.5% FFO-to-debt ratio in 2026 and a 15% long-term target as further Florida minority-interest proceeds arrive[7].

Industry and Competitive Position

Duke Energy's competitive position rests first on scale and its exclusive regulated service. The company generates, transmits, distributes and sells electricity within its service territory[1], describes its five-year, $103 billion capital plan as the industry's largest regulated capital plan[9], and is currently investing more than $1 billion a month in infrastructure[7]. In this model revenue growth depends mainly on whether regulators let new investment into rates, not on winning customers in a market.

Load growth in its territory is Duke Energy's main point of difference. The company has signed 7.8 gigawatts of electric service agreements with data-center customers and plans to convert the full 15.4-gigawatt late-stage pipeline into signed agreements by the first half of 2027, and every agreement includes minimum-take provisions[7]. To meet that load, it plans to add 15 gigawatts of new capacity by 2031, has about 5 gigawatts of gas capacity under construction and another 2.5 gigawatts in advanced development, and has raised its gas-turbine order from GE Vernova to 26 units, with the first delivered in July 2026[7].

Cost control is the company's other argument under rate pressure. Management says Duke Energy ranks third among electric industry peers for low non-generation O&M per customer and has launched the Customer Protection Plus Commitment, which requires large energy users to cover the full cost of serving their facilities[7]. These statements come from the company's earnings call, and the available material gives no specific peer cost figures, so they can only be treated as the company's own account of its advantages.

The available comparison has clear limits. Management has kept its 5% to 7% long-term EPS growth rate[3] and says it typically updates long-term guidance in the fourth quarter, changing it out of cycle only for a material change[7]; the company has also not disclosed how its data-center agreements are split by state. How far load growth can translate into earnings growth above guidance therefore cannot be compared line by line with peers on the current material.

Core Debates

With new North Carolina rates not effective until 2027, can already-approved rates and riders keep outrunning rising depreciation and interest in the third quarter?

This question decides whether first-half growth carries into the second half. Duke Energy earns the investment returns regulators allow, so the larger its capital spending, the sooner depreciation and interest rise, while recovery waits for rate cases. First-half 2026 adjusted EPS was $3.36, up $0.36 year over year[3], and full-year 2025 EPS of $6.31 minus first-half 2025 EPS of $3.00 implies $3.31 in the second half of 2025[1][3]; the $6.675 midpoint of full-year guidance only requires the second half of 2026 to roughly match that. Drillr's compiled consensus puts third-quarter EPS at $1.863, above $1.499 for the fourth quarter[4], so the third-quarter result will largely show how much of the first-half growth can carry forward.

Current evidence shows rate recovery still outrunning costs, but the margin narrowed in the second quarter. Second-quarter adjusted EPS of $1.43 was $0.18 above the prior year; rate cases contributed $0.10, riders $0.08, volume $0.08 and wholesale $0.04, while depreciation subtracted $0.09, interest $0.04 and weather $0.02[3]. In the first quarter, rate cases and riders contributed $0.14 and $0.13 respectively, with depreciation again at −$0.09[10], so the combined rate-recovery contribution fell from $0.27 to $0.18 in the second quarter. Drillr financial data put third-quarter 2025 adjusted EPS at $1.81, which is the year-ago base for this quarter.

The financial transmission runs from rate mechanisms through electric segment income to EPS. Rates and riders already in effect raise electric segment revenue and offset higher depreciation, interest and O&M, which lifted second-quarter adjusted electric segment income by about 9.7% to $1,310 million[3]. The new North Carolina rates are still under review: on July 17, 2026, DEC filed a comprehensive settlement with the North Carolina Public Staff and other parties, DEP recorded a $22 million charge consistent with the same framework[5], and DEP filed its own comprehensive settlement on August 5[13]. An alternative reading is that part of the first-half growth came from cold first-quarter weather (+$0.04 a share)[10] and from lower holding-company financing costs after the asset sales, which improved the Other segment (+$0.03 a share)[7], and neither repeats every quarter; management also said only that full-year results would land within the guidance range and did not raise guidance[3].

What remains unresolved is whether riders and rates in other states can keep covering growing depreciation and interest before new North Carolina rates take effect. The third-quarter report should answer three questions: whether adjusted EPS beats the $1.81 year-ago base and approaches or exceeds the $1.863 consensus[4]; whether rate cases and riders together still contribute more than $0.15 a share and whether depreciation drag widens beyond $0.12; and whether commission orders in the two North Carolina cases arrive around mid-November 2026 as management indicated[7], and whether full-year guidance narrows to the top half of the range. If third-quarter EPS falls year over year and the full-year target leans more on the fourth quarter, regulatory lag is getting worse; if the commission changes the settled return on equity or delays the new rates, returns at the two North Carolina utilities will be lower from 2027.

Signed data-center power agreements rose only from 7.6 to 7.8 gigawatts last quarter; can signings accelerate in the third quarter while existing customers keep using more power?

Data-center load is the main basis for Duke Energy's investment scale over the next few years, but its contribution to current earnings is still small. Signed agreements have already lifted the Carolinas load forecast to the high-load case, and if all projected agreements are signed, the current five-year capital plan has $5 billion to $10 billion of upside for additional generation and transmission, concentrated in Indiana and Florida[7]. Because these customers are expected to start using power only in the second half of 2027 or 2028[7], third-quarter earnings still depend on volumes from existing residential and commercial customers.

Signings slowed sharply in the second quarter while volumes from existing customers improved. In the first quarter the company signed 2.7 gigawatts, bringing the total to about 7.6 gigawatts, nearly two-thirds of it under construction[6]; by the second-quarter call the total was 7.8 gigawatts, an increase of only about 0.2 gigawatts, and management acknowledged that large-customer negotiations are complex and can take longer than expected while still planning to reach 15.4 gigawatts in the first half of 2027[7]. Second-quarter retail sales rose 0.3% year over year and 1.3% on a weather-normalized basis, with residential up 2.1%, commercial up 1.7% and industrial down 0.5%, retail customers grew 1.4%, and volume added $0.08 to EPS[3]; in the first quarter weather-normalized retail sales fell 0.5% and volume added $0.03[10].

This debate has two transmission chains. In the short chain, customer growth and higher commercial usage lift weather-normalized retail sales, which turn into the volume contribution to EPS; in the long chain, data-center agreements with minimum-take provisions raise the Carolinas load forecast, which leads to new generation and transmission investment, a larger rate base and future revenue[7]. An alternative reading is that slower signings reflect pressure over cost allocation from the North Carolina Attorney General and environmental groups and stricter contract terms[14][15], and that recent volume growth comes mainly from residential customer growth with little connection to data centers.

What remains unresolved is whether the signing pace can support the 15.4-gigawatt timeline. Reaching 15.4 gigawatts by the first half of 2027 requires signing the remaining 7.6 gigawatts or so within about four quarters, about 1.9 gigawatts a quarter on average, so whether cumulative agreements reach about 9.7 gigawatts by the end of the third quarter and whether the timeline holds is the most direct test[7]; the third-quarter report should also show whether weather-normalized retail sales keep growing above 1%, whether industrial usage stops falling, and whether volume contributes at least $0.05 a share. If signings keep adding only a few tenths of a gigawatt a quarter, the investment upside from 2027 may shrink; if North Carolina's large-load rate arrangements are approved and signings accelerate, the view that load growth arrives on schedule gains support.

Capital spending now runs above $1 billion a month while first-half operating cash flow fell; will interest costs and funding needs rise faster than rate recovery in the third quarter?

The funding structure sets the cost of the lag between investing first and recovering later. Duke Energy is executing what it calls the industry's largest regulated capital plan, investing more than $1 billion a month[7]; interest directly reduces EPS, equity issuance dilutes it, and cash flow and the FFO-to-debt ratio bear on credit ratings and future borrowing costs.

First-half data show faster investment and lower cash inflows, though asset transactions have temporarily eased interest pressure. First-half 2026 electric segment capital spending was $7,463 million, up about 30%, and operating cash flow was $4,272 million[5], against about $5.04 billion a year earlier according to Drillr financial data; interest reduced EPS by $0.05 in the first quarter and $0.04 in the second[10][3]. The $2.8 billion first Brookfield closing in March[8] and the roughly $2.5 billion Tennessee gas sale[5] reduced holding-company borrowing, and the Other segment's second-quarter loss narrowed from $228 million to $204 million[3]; the company has priced $600 million of equity under its at-the-market program in 2026, and management says it will meet its 14.5% FFO-to-debt target[7].

The financial transmission runs from capital spending through debt and equity funding to EPS. At the end of 2025 long-term debt was $86,865 million, $7,123 million matures in 2026, and 2025 interest expense was $3,634 million[1]; interest and share dilution from new investment weigh on EPS first, while asset-sale proceeds and Brookfield's payments reduce holding-company borrowing. An alternative reading is that the first-half decline in operating cash flow may reflect the deferral of about $268 million of Winter Storm Fern restoration costs[5] and the timing of fuel-cost recovery rather than weaker operations; but the interest savings from asset sales are one-time, so interest drag may widen again in later quarters.

What remains unresolved is whether funding needs push up financing costs before new North Carolina rates take effect. The third-quarter report should show whether interest drag on EPS stays within $0.05, whether third-quarter operating cash flow recovers to about $3.6 billion, whether combined electric and gas capital spending for the first nine months exceeds $12.5 billion (it was $8,024 million in the first half[5]), and whether the company updates the $5 billion to $10 billion large-load investment upside[7]. If interest drag widens and cash flow keeps falling, outside funding needs and equity dilution will rise; if cash flow recovers and the FFO-to-debt target is met, the view that the funding plan is manageable gains support.

Risks and Falsifiers

Political and regulatory pressure over affordability is rising in several states. North Carolina Attorney General Jeff Jackson has proposed in Duke Energy's rate cases a separate rate class for data-center and large-load customers[14], and management acknowledges heightened focus on affordability in Indiana that adds uncertainty to upcoming rate and planning cases[7]. The exposed line is all electric segment revenue regulated by state commissions, $29,357 million in 2025[1], and the two North Carolina utilities' two-year revenue requests total about $1.23 billion[12][13]. If both North Carolina cases are approved as settled and Indiana's upcoming rate and planning cases end constructively, this risk weakens.

Extreme weather brings both restoration costs and volume swings. Winter Storm Fern restoration costs, including capital expenditures, are estimated at about $268 million, of which $177 million is at DEC and $91 million at DEP[5]; DEC removed Fern from its current North Carolina rate case to pursue future securitization[12], so recovery of those costs remains uncertain until approved. If the commission approves securitization of the Fern costs, this risk is resolved.

The North Carolina commission may not fully accept the settlements, or may cut the return on equity or delay new rates under affordability pressure. The amounts at stake are DEC's two-year request of about $622 million and DEP's of about $610 million, North Carolina retail rate bases of about $26.5 billion and $17.9 billion as of the end of 2024, and about $4.4 billion and $3.9 billion of capital projects entering service during the two-year multi-year rate plans[12][13]. If both cases are approved on settlement terms around mid-November 2026[7], this risk is falsified.

Data-center projects may be delayed or cancelled, and if demand does not arrive after the load forecast was raised, new generation could sit idle and face disallowance. The company acknowledges in its 10-K that emerging large loads such as hyperscale data centers carry unique risks because of their high demand and rapid fluctuations[1]; the exposure is the $5 billion to $10 billion of potential investment beyond the five-year plan, about 5 gigawatts of gas capacity under construction and 26 contracted gas turbines[7]. If cumulative signed agreements reach 15.4 gigawatts in the first half of 2027 and customers begin taking power on schedule, this risk is falsified.

Higher interest rates or a credit downgrade would raise the cost of new debt, and rates can reflect those costs only in the next rate case. At the end of 2025 long-term debt was $86,865 million, $7,123 million matures in 2026, and 2025 interest expense was $3,634 million[1]. If the 2026 FFO-to-debt ratio reaches 14.5%[7] and third-quarter interest drag on EPS is no more than $0.05, this risk weakens.

What to Watch Next

• Rate recovery versus cost drag: compare third-quarter adjusted EPS with the $1.81 year-ago base and the $1.863 consensus[4], from a second-quarter base of $1.43 with rate cases at +$0.10, riders at +$0.08 and depreciation at −$0.09[3]. A combined rate and rider contribution above $0.15 supports continuation; a year-over-year EPS decline signals worsening regulatory lag.
• North Carolina rate cases: watch the timing of the DEC and DEP orders and whether they change the settlements, which include a 9.8% return on equity and 53% equity for DEC[7] and a DEP settlement filed August 5[13]. Approval on settlement terms around mid-November confirms the current view; a lower return or delayed rates falsifies it.
• Data-center signings and volumes: from 7.8 gigawatts signed and second-quarter weather-normalized sales growth of 1.3% with a $0.08 volume contribution[7][3], watch whether signings approach 9.7 gigawatts by quarter-end and whether volumes keep growing above 1%. Faster signings confirm; another quarter of only a few tenths of a gigawatt weakens the case.
• Capital spending and funding: from first-half operating cash flow of $4,272 million and capital spending of $8,024 million[5], with second-quarter interest drag of −$0.04[3], watch interest drag, third-quarter cash flow and nine-month capital spending. Interest drag within $0.05 and recovering cash flow mean the plan is manageable; wider drag and falling cash flow mean rising funding pressure.

Conclusion

Duke Energy's earnings run on a simple but slow mechanism: the company invests first in generation, transmission and distribution, then recovers depreciation, interest and an equity return through rates set by state commissions. That mechanism is still working, with first-half 2026 adjusted EPS of $3.36, up $0.36, and reaffirmed full-year guidance of $6.55 to $6.80[3]; but first-half capital spending of $8,024 million far exceeded operating cash flow of $4,272 million[5], new North Carolina rates will not take effect until 2027, and data-center signings added only about 0.2 gigawatts in the second quarter[7]. The central unresolved relationship is whether rates and riders already in effect can keep covering the depreciation, interest and financing costs of investing ahead before new rates and new load arrive.

Between the second-quarter report on August 4, 2026 and October 26, no sell-side research reports were found in the search, and the two independent outside views collected both come from opponents and both focus on data-center load and cost allocation. North Carolina environmental group NC WARN argued in a letter to the governor that Duke Energy has overstated its growth and is recruiting large-load customers to justify its spending; the same Utility Dive report said the company must raise about $10 billion of common equity from 2027 through 2030 to fund its plan and has already priced $600 million in at-the-market offerings[15]. North Carolina Attorney General Jeff Jackson said Duke Energy is onboarding an unprecedented number of data centers without a clear plan to protect ratepayers from higher rates and risk, and asked for a separate rate class for large-load customers, load-forecast updates every 90 days and a pause on new gas plants[14]. Both views bear on the data-center signing and capital-plan debates, but with different emphasis: NC WARN questions whether the demand is real, while the Attorney General focuses on who bears the cost once the load arrives; NC WARN is an advocacy group and the Attorney General is a party to the rate cases, so neither is a neutral assessor, and the $10 billion equity figure comes from press reporting rather than a company filing.

From here, the combination that would materially strengthen the current understanding is third-quarter adjusted EPS growth with rate and rider contributions still exceeding depreciation and interest drag, approval of both North Carolina cases on settlement terms around mid-November, clear progress in cumulative data-center agreements toward the 15.4-gigawatt target for the first half of 2027, and interest drag held within $0.05 a share alongside recovering operating cash flow. Conversely, if third-quarter EPS falls year over year, the commission changes the settlement terms, signings stall, interest drag widens and cash flow keeps trailing capital spending, the lag between investing ahead and recovering through rates would become the main pressure on EPS and the balance sheet.

Sources

[1] DUK FY2025 10-K filed 2026-02-26 · 2026-02-26 · 10-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001326160&type=10-K&dateb=&owner=include&count=40

[2] DUK earnings calendar updated 2026-10-25 · 2026-10-25 · Drillr earnings calendar

[3] DUK Q2 2026 8-K filed 2026-08-04 · 2026-08-04 · 8-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001326160&type=8-K&dateb=&owner=include&count=40

[4] Drillr analyst estimates DUK Q3 2026 retrieved 2026-10-23 · 2026-10-23 · Drillr analyst estimates · https://gateway.drillr.ai/mcp/private

[5] DUK Q2 2026 10-Q filed 2026-08-04 · 2026-08-04 · 10-Q · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001326160&type=10-Q&dateb=&owner=include&count=40

[6] DUK Q1 2026 earnings call 2026-05-05 · 2026-05-05 · earnings-call · https://gateway.drillr.ai/mcp/private

[7] DUK Q2 2026 earnings call 2026-08-04 · 2026-08-04 · earnings-call · https://gateway.drillr.ai/mcp/private

[8] DUK 8-K filed 2026-03-03 · 2026-03-03 · 8-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001326160&type=8-K&dateb=&owner=include&count=40

[9] DUK 8-K filed 2026-04-01 · 2026-04-01 · 8-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001326160&type=8-K&dateb=&owner=include&count=40

[10] DUK Q1 2026 8-K filed 2026-05-05 · 2026-05-05 · 8-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001326160&type=8-K&dateb=&owner=include&count=40

[11] DUK Q1 2026 10-Q filed 2026-05-05 · 2026-05-05 · 10-Q · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001326160&type=10-Q&dateb=&owner=include&count=40

[12] DUK 8-K filed 2026-07-06 · 2026-07-06 · 8-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001326160&type=8-K&dateb=&owner=include&count=40

[13] DUK 8-K filed 2026-08-05 · 2026-08-05 · 8-K · https://www.sec.gov/cgi-bin/browse-edgar?action=getcompany&CIK=0001326160&type=8-K&dateb=&owner=include&count=40

[14] NC Attorney General view on Duke Energy via WCTI 2026-09-14 · 2026-09-14 · 北卡罗来纳州总检察长办公室(WCTI 报道) · https://wcti12.com/news/local/jeff-jackson-pushes-new-duke-rate-class-so-data-centers-cover-their-share-not-residents

[15] NC WARN view on Duke Energy via Utility Dive 2026-08-06 · 2026-08-06 · NC WARN(Utility Dive 报道) · https://www.utilitydive.com/news/duke-energy-to-issue-10b-in-equity-to-capture-once-in-a-generation-gro/827039/