Carolinas Settled, Guidance at the Top End, and Not One New Data-Center Contract

Results vs. Consensus

Q3 2026 Scorecard

Consensus providers ranged from $1.86 to $1.88 on earnings, so the beat runs from 5.9% to 7.0% depending on the provider, and revenue estimates clustered tightly at $8.90 billion to $8.91 billion. This is the sixth consecutive quarter in which Duke has beaten the published estimate. The more useful comparison is with the second quarter, when the beat was 10.0% with weather a headwind. This quarter's beat is smaller and weather is a $0.08 tailwind, which is the opposite mix.

Year-over-Year Comparison

The income statement repeats the shape of the second quarter with larger numbers. Operating income rose 17.7% on 6.6% more revenue, and the reason is the same Florida accounting entry seen from both sides: storm recovery revenue at Duke Energy Florida fell $341 million and segment operations and maintenance fell $379 million, "primarily due to lower storm amortization at Duke Energy Florida." Strip that wash out and the operating line grew on rate cases and volume, then gave a large share back below it. Pretax income rose $319 million, but tax took $123 million of it and minority interests another $52 million, so net income to common rose $144 million.

Sequential Comparison

The sequential jump is the summer, as the CEO forecast in August when he called the third quarter "our largest quarter still ahead of us." Two lines barely moved. Depreciation was flat at $1,709 million and interest rose only 1.0%, because both track the asset base rather than the weather. The line that did move is the minority interest: $85 million against $53 million in the second quarter, a 60% sequential increase. Progress Energy, the parent of Florida Progress, reports the Brookfield share on its own line: $36 million in the quarter, against $34 million for the whole first half. Most of the increase therefore went to the existing minority holder in Duke Energy Indiana, whose segment income doubled from the second quarter. The Brookfield share is the part that roughly doubles over the next fourteen months as the stake rises toward 19.7%.

The Earnings Bridge

The bridge carries $0.49 of gross positive drivers and $0.31 of negatives. Rate cases and riders contributed $0.25, which is the regulated machine working as designed. Weather and volume contributed $0.18 together, the largest load contribution under our coverage. The negative that deserves the most attention sits in the "Other" line: the release footnote breaks the Electric segment's $(0.17) into $(0.08) for the timing of production tax credits, $(0.07) for minority interest and $(0.02) for property taxes. The nine-month footnote lists no production tax credit timing at all, which suggests the third quarter returned a benefit booked earlier in the year rather than losing one. The minority interest line has no such offset. It is a permanent and growing claim.

Segment Performance

Electric Utilities and Infrastructure

Electric earned $1,817 million, up $159 million, on revenue of $8,747 million. Operating income rose $420 million, and $340 million of it survived to pretax income after a $70 million rise in interest expense and lower other income. Tax then took $130 million more than a year ago, as the segment's effective rate rose to 17.2% from 13.5%, and minority interests took $51 million more. The segment kept $159 million of a $420 million operating gain, or 38%.

"Electric Utilities and Infrastructure increased $0.20 as the growth engine of the company continues to produce strong results. Rate cases and riders, along with higher sales volumes and hot summer weather, fueled the growth in the quarter. These drivers were partially offset by higher depreciation and interest expense associated with our growing asset base and the minority interest at Duke Energy Florida." — Brian Savoy, EVP and CFO

That is the first time in our coverage that management has named the minority interest in its own spoken bridge. It is progress on a point we raised in August, when the line appeared nowhere in the commentary. The production tax credit timing item, at $(0.08) the largest single negative in the segment, was still not mentioned.

Third-quarter figures for Progress, Ohio and Indiana are nine-month results less the six-month results filed in August. Florida's figure is before the 9.19% minority interest. Every utility grew in the quarter, which answers half of a concern we raised in August, when Carolinas and Indiana both earned less in the first half than a year earlier. Indiana turned the most: $249 million against $167 million, on Step 2 rates from the 2024 case and a nine-month decline of $86 million in operations and maintenance that the 10-Q attributes to lower rider amortization and plant maintenance. Carolinas recovered in the quarter but is still up only 0.6% over nine months on $850 million more revenue, and its quarterly tax rate rose to 14.4% from 6.9%.

Assessment: The segment delivered the mechanics of regulated growth: rates up, riders up, volume up. What is changing is how much of each operating dollar reaches Duke's shareholders. Tax normalisation and minority interests took $181 million of the segment's pretax gain this quarter. Both claims grow from here, and the segment's 9.6% income growth will be harder to repeat once the excess deferred tax amortization is fully behind it and Brookfield owns nearly a fifth of Florida.

Gas Utilities and Infrastructure

Gas lost $19 million against $26 million, its seasonal summer loss, helped by an $11 million decline in operations and maintenance after the Tennessee sale. Piedmont throughput rose 8.1%, while average Piedmont customers fell 17.0% to 996,464, the Tennessee disposal seen in the customer count. Piedmont settled its South Carolina rate case at a 9.8% return and a 53% equity ratio, with new rates from October. The CFO flagged the segment's next quarter in advance.

"We also expect lower quarterly results in the gas segment as we enter the first winter heating season following the Piedmont Tennessee sale." — Brian Savoy, EVP and CFO

Assessment: Immaterial to the quarter and material to the fourth-quarter arithmetic, which is where it belongs in the guidance discussion below. The annual goodwill test at August 31 found fair value above carrying value at every tested reporting unit, so the Duke Energy Ohio gas goodwill question we have carried since May closed without a charge for this year.

Other

The holding company segment lost $247 million against $225 million, a $0.03 drag, on higher captive insurance losses and lower returns on investments that fund employee benefit obligations. Parent interest expense was $329 million against $332 million, almost unchanged even though the parent issued $2 billion of remarketable notes inside the equity units in August. The proceeds paid down short-term debt and are expected to redeem $500 million of 3.25% junior subordinated debentures due 2082.

Assessment: The holding company line is where the funding strategy should be visible, and it is: flat parent interest while the group's debt grew. The accelerated Brookfield proceeds arriving in December should keep it that way through 2027.

Load and Operating KPIs

Weather-normal retail growth of 2.0% is the best print of the year, after 1.3% in the second quarter and 0.4% for the first half, and takes nine months to 1.0%. Residential grew 2.7% weather-normal on 1.6% more customers, so usage per household rose again. Industrial was flat weather-normal on 1.8% fewer industrial customers. On billed volumes Indiana stood out, with industrial sales up 8.3%. Actual volumes were far stronger than the normalised figures because the Carolinas were hot: cooling degree days at Duke Energy Carolinas ran 23.6% above last year and 17.8% above normal. The 10-Q adds that an August heat wave set a new summer peak demand record in the Carolinas.

Assessment: The load data finally supports the investment case, and the supply data shows what that load costs while the new plants are still being built. A peak-demand summer was served with 18.0% more coal, 8.9% more purchased power and 3.7% less nuclear. At Duke Energy Carolinas, nuclear output fell 5.7% and purchased power and interchange rose 59.2%. Those costs go to customers through fuel clauses, which is why fuel expense rose 19.6%. They also reach customers' bills in the same months that three commissions are weighing whether data centers will raise those bills.

Key Topics & Management Commentary

Overall Management Tone: Confident on the regulated core and procedural on everything that went wrong. Management narrated the Carolinas settlements, the guidance narrowing and the load acceleration in detail. Two regulatory rejections and a quarter without a new data-center contract reached the call only when analysts raised them, where they were described as feedback, a small project and complex negotiations. Against August, the tone was more assured on earnings and less specific on growth.

1. A Clean Beat in Which Weather Supplied 44% of the Growth

Adjusted EPS of $1.99 against $1.81 is a 9.9% increase and a 6.4% beat, and there were no special items in the quarter, so reported and adjusted earnings are the same number for the first time this year. The composition matters for anyone extrapolating it. Weather added $0.08 against the prior year, and volume added $0.10, partly because hot weather lifts usage beyond what the normalisation captures. Ex-weather, earnings grew 5.5%.

"Today, we announced adjusted earnings per share of $1.99 compared to $1.81 last year, building on the solid performance we've delivered throughout the year. Results were driven by growth at our electric utilities as we make critical infrastructure investments to meet growing customer demand in our service territories." — Harry Sideris, President and CEO

Nine months now stand at $5.35 against $4.81, an 11.2% increase, and 79.3% of the new guidance midpoint against 76.2% of the 2025 actual at the same point. Against normal weather, rather than against last year, the CFO put the year-to-date benefit at $0.22.

Assessment: A good quarter that confirms the algorithm without changing it. The 5.5% ex-weather growth rate is exactly what a 5% to 7% utility should print in a year before its contracted load arrives, and the headline 9.9% should not be annualised.

2. Guidance Narrowed to the Top End, and the Fourth Quarter Pays for It

The range moved to $6.70 to $6.80 from $6.55 to $6.80. The midpoint rose to $6.75 from $6.675, and management said it expects to finish "near the top end." The top of the range is 7.8% above 2025's $6.31 and 7.9% above the $6.30 midpoint from which the long-term growth rate is measured, so 2026 will land above the 5% to 7% band before any data-center load is billed.

"Overall, we are extremely pleased with our year-to-date performance and are well positioned to deliver full year results near the top end of our narrowed EPS guidance range." — Brian Savoy, EVP and CFO

The arithmetic of the fourth quarter is the part that was not discussed. With $5.35 banked, the range implies $1.35 to $1.45 for the quarter against $1.50 a year ago. Even the top of the range requires a 3.3% decline, and the midpoint a 6.7% decline. Management gave the reasons in pieces without adding them up: discretionary operations and maintenance funded by the weather benefit, a gas segment entering winter without Tennessee, and a December Brookfield closing that lifts the minority interest. The CEO also said an October hurricane "impacted our Florida and Carolinas customers."

Assessment: This is the policy the CFO pre-announced in August, now in numbers. Duke is banking the top end and spending the rest of the weather on its plants, which is sensible for a utility in a rate cycle and means the fourth quarter will print below last year. Investors who read the narrowing as momentum will be surprised in February. Investors who read it as a smoothed year will not.

3. Duke Energy Progress Settled on the Carolinas Template

On August 5 Duke Energy Progress, the North Carolina Public Staff and other intervenors filed a comprehensive settlement at a 9.8% return on equity and a 53% equity ratio, the same framework as Duke Energy Carolinas. The two-year revenue increase is $338 million, or 6.8%, against $729 million filed and $610 million in rebuttal. From the rebuttal figure, the reduction came from four places: the lower return ($93 million), an increase in production tax credit flow-back to customers to $120 million a year in 2027 and 2028 from $40 million ($80 million), extension of coal ash amortization to eight years from five ($28 million), and $71 million of other stipulated and multi-year plan adjustments. The multi-year plan carries $3.4 billion of North Carolina retail capital against $3.9 billion filed.

"Just after the second quarter call, we reached another comprehensive settlement with North Carolina Public Staff and other interveners, this time in our Duke Energy Progress rate case. We believe the DEC and DEP settlements support a balanced outcome with customer rates expected to remain below the national average. We expect orders on both cases by mid-November with rates effective in January of 2027." — Harry Sideris, President and CEO

Progress's allowed return did not fall, because its 2023 order had already set 9.8%. The settlement carries the same stay-out option to November 2028 as the Carolinas deal, conditional on full-cost-of-capital deferral for the Person County combined cycle and the Marshall turbines. The one-time charge was guided at approximately $30 million; Progress had already booked $22 million in the second quarter, and no further settlement charge appeared in the third.

Assessment: The last unresolved piece of the Carolinas binary resolved on the terms we assumed in August. Beyond holding the return at the 9.8% Progress already had, the largest concession is the tax credit flow-back ($80 million of the $272 million), which shifts customer benefit forward without changing rate base, and that is the cheapest kind of concession a utility can make. With both settlements in hand, roughly $471 million of combined year-one North Carolina increases should take effect in January 2027, subject to the orders.

4. A Large-Load Tariff Settlement in North Carolina

On October 6 the two Carolinas utilities, the Public Staff and several large customers filed a further settlement on large-load tariffs. It formalises cost-responsibility provisions for qualifying customers signing electric service agreements on or after June 1, 2026. Agreements signed before that date already carry similar protections.

"We also reached a settlement with Public Staff and several large customers around the proposed large load tariff in early October. We believe the settlement achieves a constructive outcome that balances the goals of protecting existing customers while supporting economic growth. We expect the commission to issue an order on the tariff along with the rate cases." — Harry Sideris, President and CEO

Assessment: This is the most important regulatory document of the quarter for the growth case, and it went the right way. North Carolina now has a negotiated framework for who pays for data-center capacity, which is exactly what Florida's commission said Duke's Florida filing lacked. The Carolinas agreements already signed carry equivalent protections, so the political risk to signed Carolinas load is lower than the headlines on the day suggested.

5. No New Data-Center Agreements, and a Correction to Our Own Arithmetic

Executed electric service agreements with data-center customers stayed at 7.8 gigawatts. Management did not state the figure in its prepared remarks; it came up when an analyst used it in a question. The late-stage pipeline remained 15.4 gigawatts for a third consecutive quarter, and the conversion target remains the first half of 2027. What the quarter produced instead was letters: "multiple projects executing preliminary agreements during the quarter and providing deposits to begin initial transmission system work."

"We remain confident in converting the full 15.4 gigawatt late-stage pipeline to ESAs by the first half of 2027. We are advancing negotiations with prospective large load customers with multiple projects executing preliminary agreements during the quarter and providing deposits to begin initial transmission system work." — Brian Savoy, EVP and CFO

We owe readers a correction here. In August we wrote that converting the pipeline by mid-2027 would need roughly 4 gigawatts a quarter. That treated the whole 15.4 gigawatts as unsigned. Management's May framing was that the pipeline is "inclusive of the ESAs we've signed," so the amount still to convert is 7.6 gigawatts, not 15.4. Measured correctly, the August requirement was 1.9 gigawatts a quarter. After a quarter of zero, it is 2.5 gigawatts a quarter for each of the next three. The 5.2 gigawatts already under construction remains on schedule to take energy from the second half of 2027.

Assessment: The correction makes the target more achievable and the miss more visible. Zero is not a slow number, it is no number, and it arrived in the quarter that produced the Florida rejection and the Smith denial. In August we said two more sub-gigawatt quarters would take us back to Hold. This was the first. The February call is the second.

6. Florida Rejected the Large-Load Tariff, and Management Called It Feedback

On November 3, two days before the call, the Florida Public Service Commission voted 5-0 to reject Duke Energy Florida's large-load tariff. The commission found the filing did not demonstrate compliance with Florida's 2026 large-load law, SB 484, which requires large-load customers to bear their full costs of service. Duke Energy Florida had argued its proposed contract terms were sufficient without a separate rate for large loads. Florida is one of the two states where management locates the $5 billion to $10 billion of capital upside.

"Yes, this week, Florida gave us feedback on our filed tariff. We have the same focus as our regulators as well as our stakeholders, customers and policymakers to make sure that these data centers are paying their fair share, providing benefits to the customers as well as maintaining reliability." — Harry Sideris, President and CEO

The company intends to adjust and refile, and said there is "no slowdown in what we're doing in Florida." Separately, Duke Energy Florida enters the final year of its current rate plan in 2027 with base rates held flat by battery tax credits, so new Florida base rates would not take effect before 2028.

Assessment: A unanimous rejection is not feedback, and the gap between the vote and the description is the clearest example this quarter of the disclosure pattern we have flagged since May. The substance is fixable: Florida wants a rate that isolates large-load cost, and Duke can write one. But Florida contracts cannot be signed on terms the commission has not approved, which makes a Florida contribution to the first-half 2027 conversion target harder than it looked in August.

7. North Carolina Denied the Smith Turbine on Doubts About the Load

On September 18 the North Carolina Utilities Commission denied Duke Energy Progress a certificate for a 255-megawatt simple-cycle combustion turbine at the Smith Energy Complex, estimated at $584 million, or about $2,290 per kilowatt. The order cited testimony calling that cost "staggering," and found that "much of the growth appears to be based upon anticipated data center customer additions" and that "any such anticipated load growth is insufficiently reliable for the Commission to act at this point." The denial was without prejudice, and the commission indicated a refiling should follow its ruling on the Carolinas resource plan, which the 10-Q expects by December 31, 2026. The vote was not unanimous; the order carried a dissent and two concurrences.

"Yes, so our Smith CPCN that we filed was denied by the commission. They had some questions. I think they were really focused on the IRP proceeding and validating the load requirements in there. We still feel very confident that that's a good project. It's a small project." — Harry Sideris, President and CEO

Against that, the commission determined the need for the 1,365-megawatt Anderson County combined cycle on September 28 and approved construction monitoring for the first Person County unit. Duke prefiled for two combined-cycle units totalling nearly 2,800 megawatts at a Davie-Davidson site in October, with full applications expected early next year.

Assessment: The project is small. The reasoning is not. A commission in Duke's most constructive jurisdiction has now written that the data-center load behind a generation request is too uncertain to act on, and that sentence will be quoted back at every gas filing that follows, including the 2,800 megawatts at Davie-Davidson. The approvals for Anderson and Person County show the commission will still build for load it believes in. The task for Duke is to convert pipeline into signed agreements before it asks for the next plant.

8. The Storm Accounting Again Carried the Expense Line

Consolidated operations and maintenance fell $389 million, or 22.1%, to $1,373 million. As in the second quarter, the mechanism is the end of the 2024 hurricane cost recovery at Duke Energy Florida: segment operations and maintenance fell $379 million "primarily due to lower storm amortization," and storm recovery revenue fell $341 million. The earnings bridge, which measures the line net of recoverable costs, shows nothing for Electric and $0.01 for Gas. Nine months stand at $(0.08), almost unchanged from the $(0.09) at June.

"As we close out 2026, we're reinvesting some weather benefits to further strengthen the system as we exercise O&M agility to deliver consistent, sustainable growth year after year." — Brian Savoy, EVP and CFO

The first-quarter Winter Storm Fern costs have a regulatory path now. The 10-Q shows $171 million at Duke Energy Carolinas and $75 million at Duke Energy Progress deferred as regulatory assets, and the July and August storm stipulations net eligible Fern restoration costs against the Hurricane Helene over-securitization amount, subject to the rate-case orders.

Assessment: The flat full-year operations and maintenance promise from May is now met by a wide margin on the income statement and essentially unchanged on the basis that reaches earnings. Neither the release narrative nor the call used the words storm amortization. The reinvestment the CFO described will appear in the fourth quarter, which is where the implied decline in earnings comes from.

9. Load Growth Is Arriving Before the Data Centers Do

Third-quarter weather-normal demand rose 2.0%, and management called it the strongest quarterly growth since 2022. It came from households and commercial customers, not from data centers, which have not yet begun taking energy. Management repeated its 3% to 4% load growth outlook for the rest of the five-year plan.

"Load growth has accelerated through 2026. Third quarter demand increased 2%, our strongest quarterly growth since 2022. Residential customer growth is steady at nearly 2%, outpacing the national average, while manufacturing -- advanced manufacturing loads are beginning to come online and ramp." — Brian Savoy, EVP and CFO

Assessment: This is the most underappreciated number of the quarter. A utility growing load 2% before a single contracted data center is energised is a utility whose rate base need does not depend on hyperscalers. That matters more after this week than before it. It also gives Duke a better argument at the commission than the data-center pipeline does, which is the lesson of the Smith order.

10. The Equity Plan Is Now Explicit: $10 Billion, a Third Done

In August, the CFO told the second-quarter call there was "no large block equity planned in our 5-year plan." Six days later, Duke priced 40 million equity units for $2 billion, each a forward contract to buy common stock on August 1, 2029 paired with remarketable senior notes. Holders receive 7.75% a year, of which 4.85% is interest and 2.90% contract adjustment payments; Duke elected to defer the $159 million contract adjustment obligation. Settlement will deliver 13.2 million to 16.5 million shares, between 1.7% and 2.1% of today's count, depending on the price between $121.18 and $151.47.

"We're supporting our growth capital plan with $10 billion of equity and have already addressed 1/3 of our expected needs. We priced $825 million of equity through our ATM program year-to-date with settlement expected in December of 2027. In August, we issued $2 billion of mandatory convertible equity units, and we expect to issue $125 million annually through our dividend reinvestment plan beginning in 2027. Together, these actions limit near-term dilution and preserve future share price appreciation upside." — Brian Savoy, EVP and CFO

At-the-market forwards rose to $825 million from $600 million, and the third-quarter tranches priced at $120.05 and $119.71, the lowest of the year and below the equity units' $121.18 reference price. Brookfield, meanwhile, plans to accelerate $1 billion of its Florida investment from 2028 into December, lifting the December closing to $1.2 billion from $200 million, with the remaining $2 billion in 2027.

Assessment: A mandatory convertible is not a block of common stock, and the instrument is well designed: it defers dilution to 2029 and caps it. But "no large block equity" followed within a week by $2 billion of mandatory equity is a credibility cost, and the $10 billion total puts a number on what the funding pillar was always going to need. The plan is still less dilutive than issuing common at 19 times earnings. It is not the near-equity-free plan the August language suggested.

11. Below the Line: Minority Interest, Tax Credits and the Tax Rate

Minority interests cost $0.07 and production tax credit timing $0.08, together $0.15 against a total increase of $0.18, and the adjusted effective tax rate rose to 15.5% from 10.8%. The release attributes the tax increase to "a decrease in the amortization of excess deferred income taxes." Interest expense rose $65 million, or 7.2%, and the 10-Q adds that part of the Electric increase reflects "higher accrued financing costs associated with deferred nuclear PTC liabilities."

"... in the rising interest rate environment, those deals look better every day, bringing in $8.5 billion to delever Holdco when interest rates are moving against us is a great thing." — Brian Savoy, EVP and CFO

Assessment: The minority interest is the price of the Brookfield funding, and the CFO's case that it is accretive, because the stake sold at "near a 30 P/E," is arithmetically sound. The tax rate is the harder headwind: excess deferred tax amortization is a declining benefit by construction, and the nine-month adjusted rate is now 13.0% against 11.3% a year ago. Neither item threatens the algorithm. Minority interest and tax credit timing together took $0.15, almost as much as the $0.16 that rate cases contributed, which is why a quarter with $0.25 of rate and rider growth produced only 5.5% growth before weather.

12. Cash Coverage Improved in the Quarter, and Leverage Rose Again

Third-quarter operating cash flow of $3,617 million covered 83.6% of $4,326 million of capital expenditure, up from 66.5% in the second quarter but against 105.2% a year earlier. For nine months, $7,889 million of operating cash covered 62.8% of $12,566 million of capital expenditure, against 87.8%. Capital expenditure is up 27.2% for the nine months and operating cash down 9.0%. The CFO said Duke invests "about $1.5 billion a month right now," rising to about $2 billion a month in 2027.

The $1,046 million other-assets drag we flagged in August grew to $1,312 million for nine months, and the 10-Q now explains it: "higher deferred fuel and purchased power costs as well as storm restoration costs due to severe winter weather." Those are recoverable balances. North Carolina approved recovery of $809 million of first-quarter fuel costs over 19 months from June. Debt to total capitalisation rose to 61.7% from 61.6% at June, as debt grew $1,551 million in the quarter against $679 million of equity.

"We remain on track to achieve our 14.5% FFO-to-debt target for 2026." — Brian Savoy, EVP and CFO

Assessment: The cash picture is better than it looked in August. The working-capital drag is regulatory receivables with an approved recovery path, not lost cash. The leverage picture is not better. The ratio has risen in both quarters since the March asset proceeds, and the accelerated Brookfield money in December is what keeps the 14.5% target credible, a target that still appears in no filed document.

13. Indiana: A Rate Plan Filing Weeks Away

Indiana's 2026 affordability law requires Duke Energy Indiana to file its first multi-year rate plan between November 15 and December 15, 2026. The utility's quarter was strong: net income of $249 million against $167 million, on Step 2 rates, lower operations and maintenance and industrial sales up 8.3%. Wholesale sales fell 32.5% as contracts expired. The Cayuga combined-cycle certificate is under appeal at the Indiana Supreme Court, which heard oral argument in September.

"Turning to Indiana. We have provided notice of our intent to file our first multiyear rate plan later this year. We share the goals of Indiana customers, regulators and policymakers to keep bills as low as possible, maintain reliability while supporting growth in the state." — Harry Sideris, President and CEO

Assessment: Indiana's numbers improved just before the filing that will test them. The Carolinas set a 9.8% precedent, and Indiana's last order granted 9.75%. On structure, the CEO moved from August's "may be something that we're going to revisit" to "we're open to that" on a generation company. Indiana is the other half of the capital upside, and nothing about its tariff or its contracts was quantified.

14. Nuclear: Availability Lower, Posture Unchanged

The fleet capacity factor was 94% against 98%, and nuclear output fell 3.7% for the quarter and 4.2% for nine months, the second consecutive quarter of lower availability. Neither the release nor the call addressed it. On new reactors the answer was the same refusal as in August, now set against federal announcements involving Korean and Japanese partners and the planned restart at V.C. Summer.

"But our position is still the same. We're not going to go forward with anything until we have the protections for our customers and investors until we have clarity in the supply chain and the executability of these projects as well as being able to protect our balance sheet." — Harry Sideris, President and CEO

Assessment: The discipline on new nuclear remains a credit to management, and it looks better after a week in which the market punished capital spending tied to data centers. The availability decline is a smaller issue in dollars and a larger one in timing, because every lost nuclear megawatt-hour this year was replaced by coal and purchased power in customer fuel bills during a rate case.

Guidance & Outlook

Implied fourth-quarter ramp. Nine-month adjusted EPS is $5.35. The new range therefore implies $1.35 to $1.45 for the fourth quarter, with a $1.40 midpoint, against $1.50 in the fourth quarter of 2025. "Near the top end" implies roughly $1.43 to $1.45, a decline of 3% to 5%. The drivers management named are weather reinvestment in operations and maintenance, a smaller gas segment in its first winter without Tennessee, and the December Brookfield closing. An October hurricane is a further cost the quarter will carry.

Street at. The single-source consensus for 2026 entered the print at $6.72, three cents below the new $6.75 midpoint and eight cents below the top. That gap will close quickly, and the debate moves to 2027. Management's 2027 list is new rates in North Carolina, a flat Florida, 3% to 4% load growth and higher allowance for funds used during construction, against "a return to normal weather, higher depreciation and higher interest expense."

Guidance style. Third consecutive quarter of banking outperformance rather than spending it on the top of the range. The low end moved; the high end did not, although the nine-month run-rate and the CFO's $0.22 of year-to-date weather would have supported a raise. The long-term growth rate is again deferred to the February call, which the CEO said will include "more details on our updated financial plan."

What is not in the guide. No 2027 range, no number on the North Carolina orders' contribution, no quantification of the Florida refiling's timetable, and no updated capital plan. The February roll-forward is where the $5 billion to $10 billion either enters the five-year plan or does not, and where the CFO's step-up to about $2 billion a month of investment becomes a published capital number.

Analyst Q&A Highlights

What the Florida Rejection Means for the Florida Opportunity

The call opened on the Florida commission's vote two days earlier, which the question itself framed as a delay. Management described the decision as feedback, committed to refiling, and said work with Florida customers on load and commercial terms continues. It did not give a refiling date or say whether Florida agreements can be signed before a tariff is approved.

Q: "So let me just start on Florida. I know you guys continue to kind of highlight the additional capital opportunities to serve large loads. I guess, can you talk about how this week's PSC decision to delay the tariff and any impact to the opportunity set? I guess, what's the path forward there? Or can you continue to move forward as planned without the tariff in place?"
— Shahriar Pourreza, Wells Fargo

A: "We're making adjustments to our tariff and plan on refiling that. In the meantime, we're continuing to talk to our customers and continuing to advance the process there on what we're going to need to build for them and the commercial terms that we're going to need to have. So no slowdown in what we're doing in Florida. We'll have to refile the tariff, but we feel confident that we'll be able to reach agreement with the feedback that we received."
— Harry Sideris, President and CEO

Assessment: The answer was confident and contained no date. "No slowdown" refers to engineering and negotiation work, not to signed contracts, and the distinction matters because only signed contracts move capital into the plan. The refiling date is the first Florida milestone to watch.

Whether the Carolinas Framework Survives a Rate-Case Stay-Out

A question on the North Carolina settlements asked whether the 2029 outlook assumes the earnings sharing mechanism and the rest of the framework continue if the plant-cost deferrals let Duke delay its next case. Management confirmed that it does, and the CFO added that the stay-out option was built on revenue from large loads arriving from 2027.

Q: "And if the plant cost deferrals let you delay the next North Carolina rate case, I mean, does your outlook assume kind of a similar earnings sharing? Just the overall framework, maybe is the right way to say it, that still applies in '29, just as you think about the outlook here, if you can elaborate a little bit?"
— Julien Dumoulin-Smith, Jefferies

A: "With the revenue acceleration from the large load customers coming online in 2027 that ramp into 2028 and 2029, it really sets the stage that would create the opportunity for the stay-out. And that was part of the underpinning the negotiation, and we're excited to see that come to fruition."
— Brian Savoy, EVP and CFO

Assessment: The most revealing answer of the call. The stay-out to late 2028, which protects customers from another increase, depends on contracted large-load revenue arriving on schedule. The data-center pipeline is therefore not only the upside case. It is part of how the Carolinas settlements were made to work.

What the Next Capital Plan Looks Like

Asked what the $5 billion to $10 billion of upside is worth in rate base, the CFO did not size it and instead described the base plan rising on its own. Monthly capital deployment of about $1.5 billion steps to about $2 billion in 2027, and adding 2031 to the window brings in a larger build year than the 2026 it replaces.

Q: "Maybe just on the roll-forward, you kind of highlighted this $5 billion to $7 billion -- the $5 billion to $10 billion of additional capital in Florida and Indiana. Can you just kind of talk to what that is worth from like an earnings base increase or a rate base increase perspective as we think about the roll-forward?"
— Nicholas Campanella, Barclays

A: "As you pointed out, I mean, we're in the throes of building our next roll of the plan. And bottom line, capital is increasing, right? We're investing about $1.5 billion a month right now, and that's going to step up to about $2 billion a month with a beginning as we get into 2027. And there's a ton of projects and execution underpinning that capital deployment. And the $5 billion to $10 billion we highlighted for the large load projects, that's in the overlapping period."
— Brian Savoy, EVP and CFO

Assessment: Two billion dollars a month is $24 billion a year, against a current plan that averages $20.6 billion. That is a material increase to the February plan before any data-center upside, and it carries a funding question the same answer did not address. Higher capital at a constant growth rate means more equity, more Brookfield-style transactions, or more leverage.

Whether the Election Changes the Large-Load Opportunity

A question on the previous day's election results asked whether attitudes toward large-load customers were shifting in Duke's states or nearby. The answer was general: Duke works with both parties and sees no change in policymakers' goals. On the same day, the equity market sold data-center stocks on fears of construction pauses after the results.

Q: "And then maybe just on the election updates over the last 24 hours. I'm just wondering how you'd frame it impacting the states that you operate in, understanding there haven't been any major changes in governorship in most states, but just if the attitudes are changing towards large load customers in some of the adjacent states outside your territory, is there any anecdotal pieces that you could offer as it relates to your late-stage pipeline?"
— Nicholas Campanella, Barclays

A: "So we have a track record of that working with both sides of the aisle to be able to accomplish that. We don't see any changes in that focus or any changes in our ability to work with those that were recently elected. I think they share the same thing that they want to grow the states; they want to bring jobs. And they all agree that we're a vital part of that."
— Harry Sideris, President and CEO

Assessment: A reasonable answer to a question that cannot yet be answered with evidence. The risk is not that governors oppose growth. It is that commissions, as Florida's and North Carolina's did this quarter, require stricter proof that data-center customers pay their own way before they approve the plants and tariffs that serve them. That proof is what Duke has to produce.

The Smith Denial and the Next Gas Filing

The question asked about refiling the denied turbine certificate and whether the denial carries lessons for the larger Davie-Davidson combined-cycle filing. Management called Smith a small project, tied the denial to the resource plan proceeding, and said it is confident in the Davie-Davidson filing. It did not address the order's finding on data-center load.

Q: "As you think about the gas build, can you just talk a little bit about the plan to refile the CPCN for the Smith CT? And then just as you think about preparing the filing for the Davie-Davidson combined cycles, any lessons learned or concerns that you'd have about securing approvals there?"
— Carly Davenport, Goldman Sachs

A: "So we feel confident after the IRP filing that -- IRP decision that we will be able to reevaluate what we need to do there. We've had the CPCN, the out-of-state CPCN for Anderson County was approved. So we still feel like there's support for these projects in the gas build in the Carolinas, and we feel confident that the Davie-Davidson CPCN that we filed early next year will be successful."
— Harry Sideris, President and CEO

Assessment: The question asked for lessons and the answer offered none. The order's lesson is specific: load supported by unsigned data-center demand did not meet the bar. The resource plan order expected by year end is now the gating document for both the Smith refiling and the 2,800 megawatts behind it.

How Much of the Weather Is Being Spent

The question asked the CFO to quantify the weather benefit being reinvested in operations and maintenance. He declined to give the amount, then gave the bounds: $0.22 of weather year-to-date, part kept to reach the top of the range, and "a modest amount" spent to reduce risk in future years.

Q: "Just, I guess, maybe for Brian, you mentioned about reinvesting some of the weather benefits through O&M. Just any chance you could quantify maybe how much you pulled forward or how much gets derisked into '27?"
— Anthony Crowdell, Mizuho

A: "Anthony, we're not going to disclose that amount. But you can kind of get there through -- we've got $0.22 of weather year-to-date. We're not going to invest all of that back into the system because some of it is really helping us position for the top end of the range. So -- but you could think a modest amount of that $0.22, we'll be investing to derisk future years."
— Brian Savoy, EVP and CFO

Assessment: The bounds do the work the number would have done. If the year lands near $6.80 with $0.22 of weather, the underlying 2026 is roughly $6.58 to $6.65 depending on how much is reinvested. That is the base from which 2027 growth should be judged, and it is why we do not move our 2027 estimate with the higher 2026 range.

What Is Holding Up the Remaining 7.6 Gigawatts

The question used management's own figures to ask what gates the 7.6 gigawatts of pipeline that remain unsigned. The answer named no gate. It described complex contracts, many letter agreements, and a policy of counting nothing until an agreement is executed, and listed elections and tariff proceedings among the reasons negotiations are taking longer.

Q: "You guys talked about this maybe remaining 7.6 gigawatts of the 15.4 gigawatts pipeline. You signed 7.8 gigawatts, I guess what are the gating items to move that 7.6 gigawatts into, I guess, what you've signed? Is it generation? Is it transmission? Just what is needed to maybe move that into the signed contract bucket?"
— Anthony Crowdell, Mizuho

A: "So we're continuing to have those discussions. They're going very well, but it's taking longer because of the complexities. And obviously, with a dynamic environment, I think everybody is experiencing this, whether it's elections, whether it's tariff proceedings, all those things come into play. But we're making progress on those, and we feel very confident that we'll be able to sign the rest of those between now and the first half of next year."
— Harry Sideris, President and CEO

Assessment: This exchange confirms two things. The pipeline figure includes the signed agreements, which corrects our August arithmetic. And management now cites tariff proceedings among the reasons for delay, which links the Florida rejection directly to the conversion timetable. "Taking longer" was the August explanation too.

Why Brookfield Is Paying Early

The question asked why the Florida minority proceeds were accelerated and how the holding-company interest saved compares with the equity requirement. The CFO said the acceleration was always a contractual option for Brookfield and is accretive to Duke, because the stake was sold at close to 30 times earnings and the proceeds retire holding-company debt as rates rise.

Q: "I just wanted to get a sense to, when we think about the acceleration of the Florida minority sale proceeds from 2028 into 2026, just, I guess, the rationale for that? And then how should we balance kind of the avoided holding company interest with -- alongside the kind of the equity requirements? Is it just primarily timing? Or is there something else to deal with?"
— Nicholas Amicucci, Evercore ISI

A: "Yes, Nick, I think we always contemplated this was a possibility because Brookfield had the optionality to accelerate their investment tranches. And so it's been in our planning assumptions that it could happen. And if it did, it's net-net accretive to us."
— Brian Savoy, EVP and CFO

Assessment: The arithmetic supports the claim. Selling earnings at about 30 times to retire debt is accretive when the stock trades at 19 times. The cost is that the minority interest line, which took $0.07 this quarter, most of it from the 9.19% Brookfield stake, steps up a year early. Investors should expect the 2027 bridge to show a larger minority interest drag and a smaller holding-company interest line.

What They're NOT Saying

1. Zero new data-center agreements: the 7.8 gigawatt figure did not appear in the prepared remarks and reached the call only inside an analyst's question. A quarter with no additions to the metric management made the center of the growth case was presented as "multiple projects executing preliminary agreements."
2. The Smith order's reasoning: the denial was not in the prepared remarks. When asked, management called it "a small project" and tied it to the resource plan. The order's finding that data-center-driven load growth is "insufficiently reliable for the Commission to act" was not addressed, though it applies to every gas filing that relies on the same forecast.
3. The vote count in Florida: a unanimous 5-0 rejection under a statute requiring large loads to bear their full cost was described as "feedback." No refiling date was given.
4. The fourth quarter: the new range implies $1.35 to $1.45 against $1.50 a year ago. Nobody on the call stated that the fourth quarter will decline, though management listed every reason it will.
5. Storm amortization, for a second quarter: the $379 million segment decline in operations and maintenance and the $341 million fall in Florida storm recovery revenue were disclosed only in the 10-Q. The words did not appear on the call.
6. Production tax credit timing: at $(0.08), the largest single negative in the Electric bridge was in the release footnote and absent from the commentary.
7. South Carolina's rate stabilisation denial: the South Carolina commission rejected Duke Energy Progress's first electric rate stabilisation adjustment in July, and the utility appealed to the state Supreme Court, which agreed in September to review it. The call did not mention it.
8. The deferred contract adjustment payments: Duke elected at issuance to defer the $159 million contract adjustment obligation on the equity units, accruing at 7.75%. That is in the 10-Q, not on the call.
9. Funds from operations to debt: the 14.5% target was repeated for a third consecutive quarter and appears in neither the release nor the 10-Q, with no published reconciliation.
10. Nuclear availability: capacity factor fell to 94% from 98%, the second consecutive quarter below the prior year, with coal output up 18.0%. Neither the release narrative nor the call addressed it.

Market Reaction

• Pre-print setup: DUK closed at $129.59 on November 4, up 10.6% year to date against 12.3% for the S&P 500, up 4.7% over twelve months and up 12.0% over the trailing thirty days. The stock rose 2.4% on the eve of the print. The 52-week closing range entering the print was $113.23 to $133.46, and the low was set on September 24, six days after the Smith denial.
• Reaction session: Duke reports before the open, so November 5 was the reaction day. The stock opened at $131.98, up 1.8%, reached $132.99 in the first half hour, and closed at $130.08, up 0.4%. Volume was 8.5 million shares against a 3.9 million thirty-day average, 2.2 times normal.
• Relative move: the S&P 500 fell 4.4% on the same session, its worst day since April 2025, as AI-linked equities sold off on fears that the midterm results would bring pauses to data-center construction. DUK outperformed the index by about 470 basis points.
• Peers: the utility sector fund fell 0.7%. Southern rose 0.2%, Dominion and NextEra each fell 0.2%, American Electric Power fell 1.9% and Sempra fell 3.7%.
• Since the August upgrade: DUK is up 4.7% from the $124.27 second-quarter reaction close, against a 4.9% decline in the S&P 500, after trading as low as $113.23 in late September.

The session tells a clear story about how the market classifies Duke. On a day when investors sold almost anything connected to data-center construction, Duke traded up on a print that contained no new data-center contracts and two regulatory setbacks to its data-center plans. The stock was priced as a regulated rate-base compounder with a 3.3% yield and a guidance range at the top end, and the data-center option was treated as an option rather than the core. That is consistent with how we framed the upgrade in August: the multiple was never paying for unsigned gigawatts.

The intraday shape adds a caution, and it points at the call rather than the market. The stock traded above $132 for most of the hour from the 10:00 start of the call, then fell from $132.64 at 11:05 to $130.62 by 11:35. The index was steady to slightly higher over that half hour, after most of its decline had already happened. The stock then drifted to a $129.80 low and closed at $130.08. A 2.2 times normal volume session that gave back most of a 2.6% gain once investors had heard about Florida, Smith and a quarter without contracts is not an unqualified endorsement. The three-month path matters more: from $124.27 to a $113.23 low after the equity units and the Smith denial, then a 14.4% recovery into the print as the settlements and the guidance came into view.

Street Perspective

Debate: Does the Political Turn Against Data Centers Break Duke's Growth Leg?

Bull view: the bull camp argues that the market has confused data-center equities with the utilities that serve them. Duke's executed agreements carry minimum demand charges, credit support and termination payments, North Carolina has just settled a large-load tariff that writes those protections into regulation, and 5.2 gigawatts of contracted load is already under construction. On this reading, tougher commissions raise the bar for unsigned projects and protect the value of signed ones.

Bear view: the skeptics point to one quarter that produced a 5-0 rejection in Florida, a North Carolina order calling data-center load "insufficiently reliable," and an election that put construction pauses on the table, all while executed agreements did not move. They argue the $5 billion to $10 billion of upside and the 2028 move to the top half of the range both depend on signatures that the political environment just made harder to get.

Our take: both are right about different gigawatts. The 7.8 gigawatts signed, and the 5.2 gigawatts under construction, look safe and are worth the growth rate management guides to. The remaining 7.6 gigawatts and the capital upside behind them are now more uncertain than in August, and nothing in the current price depends on them. The February call will show whether the pipeline converts; we treat it as the decisive data point.

Debate: Is the Top-End 2026 a Sign of Momentum or of Weather?

Bull view: a growing consensus view holds that Duke has beaten every quarter, narrowed to the top end, and is growing weather-normal load 2% before data centers arrive. With North Carolina rates stepping up in January and allowance for funds used during construction rising with the gas build, 2027 should extend the run.

Bear view: the bear camp counters that $0.22 of the year came from weather, that the fourth quarter is guided down, and that 2027 starts with a return to normal weather, a larger minority interest, a rising tax rate and interest costs climbing with the balance sheet. On their arithmetic, the underlying 2026 is closer to $6.60 than $6.80, and 2027 growth from there is ordinary.

Our take: the bears have the better of the arithmetic and the bulls the better of the direction. The weather-adjusted base is lower than the headline, which is why our 2027 estimate does not move. But a 2.0% weather-normal load quarter and two settled Carolinas cases make the 5% to 7% algorithm more secure than it was in August, even if the 2027 print will not look like 2026.

Debate: Can the Funding Plan Keep Pace with a Capital Plan Heading to $2 Billion a Month?

Bull view: some desks argue that Duke's funding has been unusually efficient: $8.5 billion of asset proceeds at premium valuations, Brookfield paying early, a mandatory equity structure that defers dilution to 2029, and forward equity sold before the stock's autumn recovery was in view. Every dollar of the plan is being financed below the cost of a straight common issue.

Bear view: the bear camp notes that nine-month operating cash covered 62.8% of capital spending, leverage has risen for two quarters, the equity plan is now $10 billion, and the CFO's $2 billion a month implies annual spending about 16% above the current plan's average. Each step up in spending needs funding, and Duke has fewer non-core assets left to sell.

Our take: the bears are right that the funding question gets harder from here, and the August language understated the equity component. But the near-term mechanics are sound, the working-capital drag is recoverable fuel and storm cost, and Brookfield's early payment arrives just as leverage needs it. We would treat a February plan that raises capital without a matching funding plan as the real risk, not the units already priced.

Model Framework & Valuation

The table revises the framework set out in August. Where an assumption is unchanged, the reason is stated.

Valuation. At the November 5 close of $130.08 the stock trades at 19.3 times the new $6.75 guidance midpoint, 19.2 times our $6.78 and 18.4 times our 2027 estimate of $7.08, with a 3.3% dividend yield. In August it traded at 18.6 times the then-midpoint. Our framework of $138, on 19.5 times $7.08, is unchanged. From $130.08 that is a 6.1% price return, or roughly 9.4% with the yield.

The case for Outperform is now relative more than absolute. Since the upgrade the stock is up 4.7% while the S&P 500 is down 4.9%, and the reaction session showed what Duke is in a market that is repricing AI capital spending: a regulated compounder with settled rates in its largest jurisdiction, 2% load growth before any contracted data center is energised, and a 3.3% yield. That profile should continue to beat an index whose leadership is concentrated in the stocks that fell 4.4% on the day. It is not a case that depends on the 7.6 gigawatts.

What would take us to Hold. We keep the August triggers as written and do not net them against anything. First, a second sub-gigawatt quarter: if executed agreements on the February call have not grown by at least a gigawatt from 7.8, we move to Hold regardless of what the capital plan shows. Second, North Carolina orders that materially modify either settlement. Third, the stock reaching 19.5 times the 2027 estimate, which is our $138 framework, without a higher growth algorithm. On the 2027 basis the stock is at 18.4 times today. On the 2026 midpoint it is at 19.3 times, close to that level, and we flag the different bases so the trigger is not read twice.

Thesis Scorecard Post-Earnings

The scorecard grades the standing thesis pillar for pillar against the version carried after the second quarter. Status tags in the right-hand column are the ones carried in the thesis of record.

Overall: mixed, and modestly weakened on balance. The regulated core strengthened: the last Carolinas case settled on our assumed terms, guidance moved to the top end, and load grew at its fastest rate in four years. The growth option weakened on three fronts in a single quarter, the funding plan moved toward equity, and the disclosure pattern we have flagged since May held for a third quarter. Four status tags moved, three of them in the wrong direction.

Action: hold the position and wait for February. We maintain Outperform with conviction lowered to 6 out of 10 and an unchanged twelve-month framework of $138 on 19.5 times a 2027 estimate of $7.08, against $130.08. The rating rests on a regulated earnings stream that the market is now paying for as a defensive compounder, not on the data-center pipeline. The February call is the second test of the contracting trigger we set in August. A second quarter without a gigawatt of new agreements takes the rating to Hold.