Constellation Energy Corp

Three Months Ended September 30, 2024 Compared to Three Months Ended September 30, 2023. The variance in Net income (loss) attributable to common shareholders was favorable by $469 million primarily due to:

•Favorable nuclear PTCs related to the IRA beginning in 2024;

•Favorable net realized and unrealized NDT activity;

•Favorable market and portfolio conditions primarily driven by higher realized margins on load contracts and generation-to-load optimization; and

•Favorable mark-to-market activity and other fair value adjustments.

The favorable items were partially offset by:

•Higher labor (inclusive of incentives), contracting, and materials;

•Lower unrealized gains resulting from an investment that became a publicly traded company in the second quarter of 2023; and

•Unfavorable impacts of nuclear outages.

Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023. The variance in Net income (loss) attributable to common shareholders was favorable by $1,237 million primarily due to:

•Favorable mark-to-market activity and other fair value adjustments;

•Favorable market and portfolio conditions primarily driven by higher realized margins on load contracts and generation-to-load optimization;

•Favorable nuclear PTCs related to the IRA beginning in 2024;

•Favorable net realized and unrealized NDT activity; and

•Favorable impacts of nuclear outages.

The favorable items were partially offset by:

•Lower unrealized gains resulting from an investment that became a publicly traded company in the second quarter of 2023;

•Higher labor (inclusive of incentives), contracting, and materials;

•Lower revenue recognized for ZECs delivered under the Illinois ZEC program in prior planning years; and

•Higher Interest expense.

Operating revenues. Our five reportable segments are Mid-Atlantic, Midwest, New York, ERCOT, and Other Power Regions. See Note 4 —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, 2024 compared to 2023, Operating revenues were as follows:

Sales and Supply Sources. Our sales and supply sources by region are summarized below:

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

(b)2023 values have been revised from those previously reported to reflect gross generation inclusive of behind the meter consumption.

Nuclear Fleet Capacity Factor. The following table presents nuclear fleet operating data for our plants that, reflects ownership percentage of 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 plant over a period of time to its output if the plant had operated at its 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.

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 (a base credit of $3 per MWh with a five times multiplier provided certain prevailing wage requirements are met) and is subject to phase-out when annual gross receipts are between $25.00 per MWh and $43.75 per MWh. We have determined that we will meet the annual prevailing wage requirements at all our nuclear units and are eligible for the five times multiplier. Both the amount of the PTC and the gross receipts thresholds adjust for inflation after 2024 through the duration of the program based on the GDP price deflator for the preceding calendar year. The benefits of the PTC may be realized through a credit against our federal income taxes or transferred via sale to an unrelated party.

Many of the state-sponsored programs (i.e., 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 5 — Government Assistance of the Combined Notes to Consolidated Financial Statements for additional information on the nuclear PTC.

ZEC Prices. We are compensated through state programs for the carbon-free attributes of our nuclear generation. Gross revenues from ZEC programs are a significant contributor to our total operating revenues. 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, 2024 and 2023 and may not necessarily reflect prices we ultimately realize as a result of interaction with the nuclear PTC discussed above.

(a)See ITEM 1. BUSINESS, Environmental Matters of our 2023 Form 10-K for additional information on the plants receiving payments through state programs.

(b)The ZEC price is expected to be $10.00/MWh for each delivery period and is subject to an annual update once full year generation is known. Following the latest annual update in August 2024, the ZEC price for the delivery period beginning June 2023 through May 2024 was calculated to be $9.95.

Illinois CMC Price. The price received (paid) for each CMC is determined by the IPA monthly and is based on the accepted CMC bid, less the sum of (a) monthly weighted average PJM Busbar price, (b) ComEd zone capacity price and (c) any federal tax credit or subsidy received and is subject to a customer protection cap ($30.30 per MWh for initial delivery period June 2022 through May 2023, $32.50 per MWh for the period June 2023 through May 2024, and $33.43 per MWh for the period June 2024 through May 2025). 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 $5.54 and $2.12 for the three months ended September 30, 2024 and 2023, respectively, and $7.73 and $3.54 for the nine months ended September 30, 2024 and 2023, respectively. The average CMC prices may not necessarily reflect prices we ultimately realize as a result of interaction with the nuclear PTC discussed above.

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 significant 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, 2024 and 2023.

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.

For the three and nine months ended September 30, 2024 compared to 2023, changes in Operating revenues by region were approximately as follows:

(b)See Note 10 — 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, 2024 compared to 2023, Purchased power and fuel expense were as follows:

For the three and nine months ended September 30, 2024 compared to 2023, changes in Purchased power and fuel expense by region were approximately as follows:

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(b)See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on mark-to-market 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.

Other, net was favorable for the three months ended September 30, 2024 compared to the same period in 2023 and unfavorable for the nine months ended September 30, 2024 compared to the same period in 2023, 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 7 — Nuclear Decommissioning and Note 16 — Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements for additional information.

(b)The non-service credit (cost) components are included in Other, net, in accordance with single employer plan accounting. See Note 9 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information.

Effective income tax rates were 27.3% and 22.9% for the three months ended September 30, 2024 and 2023, respectively, and 21.0% and 29.4% for the nine months ended September 30, 2024 and 2023, respectively. The change in effective tax rate for the three months ended September 30, 2024 and 2023 is primarily due to tax effect of realized gains from qualified fund decommissioning activity, partially offset by nuclear PTC being inclusive in book income, which is not taxable. For the nine months ended September 30, 2024 and 2023, the change is primarily due to PTC being inclusive in book income, which is not taxable. See Note 8 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.