CONSTELLATION ENERGY GENERATION LLC

Three Months Ended September 30, 2025 Compared to Three Months Ended September 30, 2024. The variance in Net income (loss) attributable to common shareholders was unfavorable by ($270) million primarily due to:

•Lower Nuclear PTC revenues in 2025. See Note 6 — Government Assistance of the Combined Notes to Consolidated Financial Statements for additional information; and

•Unfavorable net unrealized losses on economic hedges.

The unfavorable items were partially offset by:

•Favorable market and portfolio conditions primarily driven by higher capacity revenues and generation-to-load optimization; and

•Higher net unrealized gains on equity investments.

Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024. The variance in Net income (loss) attributable to common shareholders was unfavorable by ($1,010) million primarily due to:

•Lower Nuclear PTC revenues in 2025. See Note 6 — Government Assistance of the Combined Notes to Consolidated Financial Statements for additional information;

•Unfavorable net unrealized losses on economic hedges; and

•Higher net unrealized losses on equity investments.

The unfavorable items were partially offset by:

•Favorable market and portfolio conditions primarily driven by higher capacity revenues and generation-to-load optimization;

•Favorable net ZEC revenues, including the impacts of higher revenue recognized for ZECs delivered under the Illinois ZEC program in prior planning years; and

•Favorable net realized and unrealized NDT fund investment activity.

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

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 region.

For the three and nine months ended September 30, 2025 compared to 2024, Operating revenues were as follows:

Sales and Supply Sources. Our sales and supply volumes (GWhs) by region 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.

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 within each region, depending on our net hourly position. The price of electricity is impacted by several variables, including but not limited to, the price of fuels, generation resources in the 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 each of our major regions and does not necessarily reflect prices we ultimately realized.

(a)Reflects New England, which comprises the majority of the activity in the Other region.

Capacity Prices. We participate in capacity auctions in each of our major regions, except ERCOT which does not have a capacity market. 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 within each region in either Operating revenues or Purchased power and fuel expense, depending on our net monthly position. The following table presents the average capacity prices ($/MW Day) for each of our major regions. Prices reflect the weighted average prices for the various auction periods within the three and nine months ended September 30, 2025 and 2024.

ZEC Prices. We are compensated through state programs for the carbon-free attributes of our nuclear generation. The following table includes the average ZEC reference prices ($/MWh) for each of our major regions 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, 2025 and 2024 and may not necessarily reflect prices we ultimately realize as a result of interaction with the nuclear PTC discussed below.

(a)See ITEM 1. BUSINESS, Environmental Matters of our 2024 Form 10-K for additional information on the plants receiving payments through state programs.

(b)The New Jersey ZEC program ended 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 $32.50 per MWh for the period June 2023 through May 2024, $33.43 per MWh for the period June 2024 through May 2025 and $33.50 per MWh for the period June 2025 through May 2026. 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 ($17.11) and $5.54 for the three months ended September 30, 2025 and 2024, respectively, and ($6.53) and $7.73 for the nine months ended September 30, 2025 and 2024, respectively. The average CMC prices may not necessarily reflect prices we ultimately realize 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 $25.00 per MWh and $43.75 per MWh and $26.00 per MWh and $44.75 per MWh for 2024 and 2025, respectively. 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, 2025 compared to 2024:

(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, 2025 compared to 2024, changes in Operating revenues by region were approximately as follows:

(b)See Note 11 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on mark-to-market 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 region, nuclear fleet capacity factor, capacity prices, and electricity prices.

Wholesale and retail natural gas activity, 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 region.

For the three and nine months ended September 30, 2025 compared to 2024, Purchased power and fuel expense were as follows:

For the three and nine months ended September 30, 2025 compared to 2024, changes in Purchased power and fuel expense by region were approximately as follows:

(b)See Note 11 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on mark-to-market gains and losses.

Effective income tax rates were 33.4% and 27.3% for the three months ended September 30, 2025 and 2024, respectively and 32.9% and 21.0% for the nine months ended September 30, 2025 and 2024, respectively. The change in effective tax rate for 2025 is primarily due to the decrease in nuclear PTCs generated, which are not taxable, as well as higher qualified NDT fund income which is taxed at a higher rate. See Note 9 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.