Constellation Energy Corp

Three Months Ended September 30, 2026 Compared to Three Months Ended September 30, 2025. The variance in Net income (loss) attributable to common shareholders was favorable by $905 million primarily due to:

•Addition of Calpine operations acquired in January 2026, inclusive of the impacts of purchase accounting. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information; and

•Favorable net adjustments to deferred income taxes due to changes in forecasted apportionment.

The favorable items were partially offset by:

•Unfavorable decommissioning-related activities; and

•Lower Nuclear PTC revenues in 2026. See Note 6 — Government Assistance of the Combined Notes to Consolidated Financial Statements for additional information.

Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025. The variance in Net income (loss) attributable to common shareholders was favorable by $2,051 million primarily due to:

•Addition of Calpine operations acquired in January 2026, inclusive of the impacts of purchase accounting. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information;

•Favorable net market and portfolio conditions primarily driven by higher capacity revenues;

•Lower net unrealized loss on equity investments;

•Favorable net adjustments to deferred income taxes due to changes in forecasted apportionment; and

•Favorable decommissioning-related activities primarily driven by the 2026 nuclear ARO updates. See Note 9 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information.

The favorable items were partially offset by:

•Unfavorable Calpine merger and integration costs;

•Unfavorable interest expense primarily driven by increased long-term debt outstanding; and

•Unfavorable impacts from nuclear outages.

Operating revenues. Our six reportable segments are Mid-Atlantic, Midwest, New York, ERCOT, Other Power Regions, and Calpine. See Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information on these reportable segments.

With the exception of Calpine's natural gas sales, which are included in the Calpine segment, wholesale and retail sales of natural gas, as well as sales of other energy-related products and sustainable solutions and other miscellaneous business activities that are not significant to overall results of operations, are reported under Other and not allocated to a segment.

For the three and nine months ended September 30, 2026 compared to 2025, Operating revenues were as follows:

(a)% Change in unrealized gains (losses) is not a meaningful measure.

Sales and Supply Sources. Our sales and supply volumes (GWhs) by segment are summarized below:

(a)Includes the proportionate share of output where we have an undivided ownership interest in jointly-owned generating plants.

Nuclear Fleet Capacity Factor. The following table presents nuclear fleet operating data for our plants that reflects our ownership percentage for stations operated by us and excludes Salem and STP, which are operated by PSEG and STPNOC, respectively. The nuclear fleet capacity factor presented in the table is defined as the ratio of the actual output of a unit (or combination of units) over a period of time to its output if the unit had operated at net monthly mean capacity for that time period. We consider capacity factor to be a useful measure to analyze the nuclear fleet performance between periods. We have included the analysis below as a complement to the financial information provided in accordance with GAAP. However, these measures are not a presentation defined under GAAP and may not be comparable to other companies’ presentations or be more useful than the GAAP information provided elsewhere in this report.

Equivalent Forced Outage Factor (Natural Gas, Oil, and Pumped-storage Hydro). As a result of our expanded fleet following the acquisition of Calpine in January 2026, we now consider EFOF to be a key operational metric beginning in 2026. EFOF represents the percentage for which a generating unit is not available due to forced outages and forced deratings in a given period. We consider EFOF to be a useful measure in analyzing the reliability and performance of our natural gas, oil, and pumped-storage hydro fleet. The EFOF for the three and nine months ended September 30, 2026 was 5.9%. This operational metric is being included as a complement to the financial information provided in accordance with GAAP. However, as an operational metric, it may not be calculated or presented in a manner comparable to similar metrics used by other companies.

Electricity Prices. As a producer and supplier of electricity, the price of electricity has a significant impact on our operating revenues and purchased power cost. We report the sale and purchase of electricity in the spot market on a net hourly basis in either Operating revenues or Purchased power and fuel expense based on our net hourly position. We assess the net position by ISO/RTO across segments and, where applicable, by segment within the ISO/RTO. The price of electricity is impacted by several variables, including but not limited to, the price of fuels, generation resources in the geographic region, weather, ongoing competition, emerging technologies, as well as macroeconomic and regulatory factors. The following table presents an average day-ahead around-the-clock reference price ($/MWh) for the periods presented for zones/hubs in each ISO/RTO where we have significant activity. This does not reflect prices we ultimately realized.

Capacity Prices. We participate in capacity auctions in each ISO/RTO where we have qualifying generating assets. We also incur capacity costs associated with load served, which are factored into customer sales prices. Capacity prices have a material impact on our operating revenues and purchased power and fuel expense. We report capacity on a net monthly basis in either Operating revenues or Purchased power and fuel expense. We assess the net position by ISO/RTO across segments and, where applicable, by segment within the ISO/RTO. The following table presents the average capacity prices ($/MW Day) for each ISO/RTO in which we have significant activity. Prices reflect the weighted average prices for the various auction periods within the three and nine months ended September 30, 2026 and 2025.

We also enter into bilateral capacity contracts at negotiated contract prices. These contracts primarily relate to resource adequacy in CAISO and have a material impact on our operating revenues. Negotiated contract prices from these bilateral contracts are not included in the table below.

(a)We did not have significant activity at this zone for the three months ended September 30, 2025.

ZEC Prices. We are compensated through state programs for the emissions-free attributes of our nuclear generation. The following table includes the average ZEC reference prices ($/MWh) for each state and associated segment in which state programs have been enacted. Gross prices reflect the weighted average price for the various delivery periods within the three and nine months ended September 30, 2026 and 2025 and may not necessarily reflect prices we ultimately realized as a result of interaction with the nuclear PTC discussed below.

(a)See ITEM 1. BUSINESS, Environmental Matters and Regulation of our 2025 Form 10-K for additional information on the plants receiving payments through state programs.

(b)The New Jersey ZEC program concluded in May 2025.

Illinois CMC Price. The price received (paid) for each CMC is determined by the IPA monthly by subtracting energy and capacity index prices from the bid price, which resulted in $33.43 per MWh for the period June 2024 through May 2025, $33.50 per MWh for the period June 2025 through May 2026, and $34.50 per MWh for the period June 2026 through May 2027. If the monthly CMC price per MWh calculation results in a net positive value, ComEd will multiply that value by the delivered quantity and pay the total to us. If the CMC price per MWh calculation results in a net negative value, we will multiply this value by the delivered quantity and pay the net value to ComEd. The average CMC prices per MWh were ($26.54) and ($17.11) for the three months ended September 30, 2026 and 2025, respectively, and ($19.54) and ($6.53) for the nine months ended September 30, 2026 and 2025, respectively. The average CMC prices may not necessarily reflect prices we ultimately realized as a result of interaction with the nuclear PTC discussed below.

Nuclear PTC. Beginning in 2024, our nuclear units are eligible for a PTC extending through 2032. The nuclear PTC provides a transferable credit up to $15 per MWh and is subject to phase-out when annual gross receipts are between $26.00 per MWh and $44.75 per MWh for 2025 and 2026. Both the amount of the PTC and the gross receipts thresholds adjust for inflation annually through the duration of the program based on the GDP price deflator for the preceding calendar year.

Many of the state-sponsored programs (e.g., ZECs and CMCs) providing compensation for the emissions-free attributes of generation from certain of our nuclear units include contractual or other provisions that require us to refund that compensation up to the amount of the nuclear PTC received or pass through the entirety of the nuclear PTC received. See Note 6 — Government Assistance of the Combined Notes to Consolidated Financial Statements for additional information on the nuclear PTC.

The following table summarizes the impacts to Operating revenues related to the benefits of nuclear PTC and state-sponsored programs subject to refund or pass through as described above for the three and nine months ended September 30, 2026 compared to 2025:

(a)Our estimate required the exercise of judgment in determining the amount of nuclear PTC expected for each of our nuclear units. Refer to Note 6 — Government Assistance of the Combined Notes to Consolidated Financial Statements for additional information.

(b)Includes only state-sponsored programs that have contractual or other provisions that require us to refund that compensation up to the amount of the nuclear PTC received or pass through the entirety of the nuclear PTC received.

For the three and nine months ended September 30, 2026 compared to 2025, changes in Operating revenues by segment were approximately as follows:

(a)% Change in unrealized gains or losses is not a meaningful measure.

(b)See Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on unrealized gains and losses.

Purchased power and fuel. See Operating revenues above for discussion of our reportable segments and hedging strategies and for supplemental statistical data, including sales and supply sources by segment, nuclear fleet capacity factor, EFOF, capacity prices, and electricity prices.

With the exception of Calpine's natural gas activity, which is included in the Calpine segment, wholesale and retail natural gas activity, energy-related activity in the United Kingdom, as well as other miscellaneous business activities that are not significant to overall results of operations are reported under Other and are not allocated to a segment.

For the three and nine months ended September 30, 2026 compared to 2025, Purchased power and fuel expense were as follows:

(a)% Change in unrealized losses (gains) is not a meaningful measure.

Natural Gas Prices. As an owner-operator of a large fleet of natural gas-fired generation facilities, the cost of our natural gas supply has a significant impact on our Purchased power and fuel expense. The following table summarizes the average daily reference price ($/MMBtu) for the periods presented in each geographic region where we have significant activity. This does not reflect prices we ultimately realized.

(a)Transcontinental Gas pipeline located in Mid-Atlantic region.

(b)Houston-area pipeline and industrial network located in ERCOT region.

(c)Pacific Gas & Electric Company virtual trading point located in West region.

(d)Algonquin Gas Transmission physical delivery point located in New England region.

For the three and nine months ended September 30, 2026 compared to 2025, changes in Purchased power and fuel expense by segment were approximately as follows:

(a)% Change in unrealized gains or losses is not a meaningful measure.

(b)See Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on unrealized gains and losses.

The changes in Operating and maintenance expense consisted of the following:

(a)Primarily reflects increased employee-related costs, including labor and other incentives, as well as higher contracting expense, driven in large part by the addition of Calpine's operations beginning in January 2026.

(b)Includes the co-owned Salem and STP generating units.

(c)Primarily includes administrative expenses such as information technology, regulatory fees, facilities and rentals, and insurance. The increase is driven primarily by the addition of Calpine's operations beginning in January 2026.

Depreciation and amortization expense increased by $213 million for the three months ended September 30, 2026 compared to the same period in 2025, and increased by $597 million for the nine months ended September 30, 2026 compared to the same period in 2025, primarily due to the additional depreciation and amortization associated with assets acquired from Calpine beginning in January 2026. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.

Interest expense, netincreased by $83 million for the three months ended September 30, 2026 compared to the same period in 2025, and increased by $355 million for the nine months ended September 30, 2026 compared to the same period in 2025, primarily due to a net increase in outstanding debt as a result of the debt assumed and related financing transactions following the acquisition of Calpine in January 2026. See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.

Other, net was unfavorable for the three and nine months ended September 30, 2026 compared to the same period in 2025, due to activity described in the table below:

(a)Includes net realized and net unrealized gains (losses) on NDT fund investments, the elimination of decommissioning-related activities, and the elimination of income taxes related to all NDT fund activity for the Regulatory Agreement Units. See Note 9 — Asset Retirement Obligations and Note 18 — Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements for additional information.

(b)Includes unrealized gains (losses) resulting from an equity investment in a publicly traded company. We record the fair value of this investment in Other deferred debits and other assets in the Consolidated Balance Sheets based on quoted market price of the stock.

Effective income tax rates were 18.2% and 33.4% for the three months ended September 30, 2026 and 2025, respectively, and 25.4% and 32.9% for the nine months ended September 30, 2026 and 2025, respectively. The decrease in effective tax rate for the three months ended was primarily driven by the long-term rate change and lower qualified NDT fund income in the third quarter of 2026 which is taxed at a higher rate. The decrease in effective tax rate for the nine months ended was primarily due to proportionally lower qualified NDT fund income in 2026 which is taxed at a higher rate as well as long-term rate change. See Note 10 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.