Constellation Energy (CEG) 10-K risk factor changes: FY2023 vs FY2022

- the renewal of [removed: permits and] operating licenses,

- the safe, secure and effective operation of our nuclear facilities and the ability to effectively manage the associated decommissioning obligations, [added: and]

[removed: -] [added: Also,] the ability of energy transmission and distribution companies to maintain the reliability, resiliency and safety of their energy delivery [removed: systems, which] [added: systems] could affect our ability to deliver energy to our customers and affect our operating [removed: costs, and][added: costs.]

- physical and [removed: cyber security] [added: cybersecurity] risks for us as an owner-operator of generation facilities and as a participant in commodities trading.

- [removed: challenges to achieving the benefits of separation, including the need to] replicate certain services provided by Exelon [removed: (e.g.] [added: (e.g.,] information technology), which will require additional resources and expense, [added: and]

- performance by Exelon and us under the transaction agreements, including indemnification responsibilities tied to the allocation of businesses and [removed: liabilities, and][added: liabilities.]

We are exposed to price volatility associated with both the wholesale and retail power markets and the procurement of [removed: nuclear,] [added: nuclear fuel,] natural gas and oil.

Cost [added: and Availability] of Fuel. We depend on nuclear fuel, natural gas and oil to operate most of our generating facilities.

As of December 31, [removed: 2022,] [added: 2023,] approximately [removed: 38%, 13%,] [added: 37%, 12%,] and [removed: 19%] [added: 17%] of our available credit facilities were with European, Canadian and Asian banks, respectively.

See ITEM 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – Liquidity and Capital Resources – Credit Matters and Cash Requirements – Security Ratings [added: and Note 16 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements] for additional information regarding the potential impacts of credit downgrades on our cash flows.

The impacts of significant economic downturns [removed: (i.e.] [added: (i.e.,] recession) could lead to decreased volumes delivered and increased expense for uncollectible customer balances.

The impacts of significant economic downturns on our retail customers, such as less demand for products and services provided by [removed: commercial and industrial] [added: C&I] customers, could result in an increase in the number of uncollectible customer balances and related expense.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK [added: and Note 16 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements] for additional information on our credit risk.

These conditions, which cannot be accurately predicted, could cause us to seek additional [removed: capacity] [added: replacement supply] at a time when [removed: markets are weak.][added: supply is constrained.]

[removed: By comparison, the estimated impact reduced our overall Net loss by approximately $50 million for the year ended December 31, 2022, see Note 3 — Regulatory Matters and] [added: See] Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.

Long-lived [removed: assets] [added: assets, goodwill,] and other assets could become impaired.

An impairment would require us to reduce the carrying value of the long-lived asset [added: and goodwill] to fair value through a non-cash charge to expense by the amount of the impairment.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – Critical Accounting Policies and Estimates, Note [added: 1 — Basis of Presentation, Note] 8 — Property, Plant, and [removed: Equipment and] [added: Equipment,] Note 12 — Asset [removed: Impairments] [added: Impairments, and Note 13 — Intangible Assets] of the Combined Notes to Consolidated Financial Statements for additional information on long-lived asset impairments.

We could incur substantial costs in the event of non-performance by [removed: third-parties] [added: third parties] under indemnification agreements.

[removed: In the spot markets, we are exposed to risk as a result of default sharing] mechanisms that exist within certain markets, primarily RTOs and ISOs.

In addition, our retail sales subject us to credit risk through competitive electricity and natural gas supply activities to serve [removed: commercial and industrial] [added: C&I] companies, governmental entities and residential customers.

See Note [removed: 3] [added: 19] — [removed: Regulatory Matters] [added: Commitments and Contingencies] of the Combined Notes to Consolidated Financial Statements for additional information on the February 2021 extreme cold weather event and Texas-based generating asset outages.

Our consolidated financial statements are significantly affected by our sales and purchases of commodities at market-based rates, as opposed to cost-based or other similarly regulated [removed: rates] [added: rates,] and federal and state regulatory and legislative developments related to emissions, climate change, capacity market mitigation, energy price information, resilience, fuel diversity and RPS.

[removed: Spent Nuclear Fuel Storage. The approval of a national repository for the storage of SNF and the timing of that facility opening,] will significantly affect the costs associated with storage of SNF and the ultimate amounts received from the DOE to reimburse us for these costs.

In addition, conditions could be imposed as part of the license renewal process that could adversely affect operations, require a substantial [added: increase in capital expenditures, result in increased operating costs or render the project uneconomic.]

[removed: Similar] effects could result from a change in the Federal Power Act or the applicable regulations due to events at hydroelectric facilities owned by others, as well as those owned by us.

[removed: The] [added: Our] material [removed: ones] [added: legal proceedings, claims and litigation] are summarized in Note 3 — Regulatory Matters and Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements.

We primarily operate in the [removed: Midwest and] [added: Midwest,] East Coast of the United States, [added: and Texas] areas that have historically been prone to various types of severe weather events, and as such we have well-developed response and recovery programs based on these historical events.

In either event, we could lose revenue and incur increased purchased power [added: costs] and fuel expense to meet supply commitments.

[removed: Further, our] [added: Spent Nuclear Fuel Storage. Our] nuclear operations produce various types of nuclear waste materials, including SNF.

The approval of a national repository for the storage of SNF and the timing of that facility opening, [removed: will significantly affect the costs associated with storage of SNF and the ultimate amounts received from the DOE to reimburse us for these costs.]

If we are required to arrange for the safe and permanent disposal of [removed: spent fuel] [added: SNF] beyond current expectations, this could lead to substantial expense or capital expenditures.

As required by the Price-Anderson Act, we carry the maximum available amount of nuclear liability insurance, [removed: $450] [added: $500] million for each operating site.

In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay claims exceeding the [removed: $13.7] [added: $16.2] billion limit for a single incident.

[removed: While we, through PECO,] [added: We] have recourse to collect additional amounts from [removed: PECO] [added: utility] customers [added: through PECO] (subject to certain limitations and [removed: thresholds), we have no recourse to collect additional amounts from utility customers] [added: thresholds)] for [removed: any of our other nuclear] [added: former PECO] units [removed: if there is a shortfall of funds necessary] [added: and through CenterPoint Energy Houston Electric and AEP Texas] for [removed: decommissioning.][added: STP units.]

If circumstances changed such that there was an inability to continue to make contributions to the trust funds of the former PECO [added: or STP] units based on amounts collected from [removed: PECO] [added: utility] customers, or if we no longer had recourse to collect additional amounts from [removed: PECO] [added: the respective utility] customers if there was a shortfall of funds for decommissioning, the adequacy of the trust funds related to [removed: the former PECO] [added: these] units could be negatively affected.

Any changes to the [removed: PECO] [added: utilities'] regulatory agreements could impact our ability to offset decommissioning-related activities [added: for these units] within the Consolidated [removed: Statement] [added: Statements] of Operations and Comprehensive Income, and the impact to our consolidated financial statements could be material.

For the year ended December 31, 2021, a pre-tax charge of $193 million was recorded in the Consolidated [removed: Statements] [added: Statement] of Operations and Comprehensive Income for decommissioning-related activities that were not offset for the Byron units due to contractual offset being temporarily suspended.

We are subject to [added: evolving] physical security and cybersecurity risks.

Threat [removed: sources] [added: actors] continue to seek to exploit potential vulnerabilities in the [removed: electric generation and natural gas industry] [added: energy sector] associated with protection of sensitive and confidential information, grid infrastructure and other energy infrastructures.

In addition, we have a material goodwill balance as of December 31, 2023.

We assess goodwill for impairment at least annually or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of the reporting units below their carrying amount.

Changes in significant assumptions, including discount rates, energy prices, projected operating costs, and cash flows could potentially result in future impairments of goodwill.

In the spot markets, we are exposed to risk as a result of default sharing

The PTC benefiting existing nuclear plants included in the IRA (starting January 1, 2024) continues to be the subject of additional guidance issued from the U.S. Treasury and IRS, which may negatively impact the amount of benefits we ultimately receive with respect to some of our units.

Similar

See "NRC actions could negatively affect the operations and profitability of our nuclear generating fleet" above for additional information on the storage of SNF.

We do not procure the fuel for the sites we do not operate.

The operator's nuclear fuel procurement plan could impact our results of operations.

See Note 7 — Early Plant Retirements and Note 10 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information.

Security incidents such as ransomware attacks are becoming increasingly prevalent and severe, as well as increasingly difficult to detect.

In addition, geopolitical issues, to include conflicts in the Ukraine and the Middle East, as well as tensions between the U.S. and China, may motivate cyber attacks which could impact the U.S. energy sector and our Company via supply chain disruptions or direct targeting.

Security breaches can also occur as a result of non-technical issues, including intentional or inadvertent actions by our employees, third-party service providers or their personnel or other parties.

Our customers depend on the

continuous availability of our commercial and generation operations.

A failure, interruption, or breach of our operational or information security systems, or those of our third-party service providers, as a result of cyber-attacks or information security breaches could disrupt our business, result in the disclosure or misuse of confidential or proprietary information, damage our reputation, cause loss of customers or revenue, increase our costs, result in litigation and/or regulatory action, and/or cause other losses, any of which might have a materially adverse impact on our business operations and our financial position or results of operations.

Operational harm could be in the form of impact to the operation of the generation fleet and/or reliability of the bulk electric system.

Impacts to confidential or proprietary information could include inappropriate release of certain types of information, including critical infrastructure, sensitive customer, vendor and employee, trading, export control or other confidential information.

We currently utilize a mix of third-party managed service providers to host and support our information technology, customer support, and generation operations.

As an example, our data centers are hosted in vendor-managed co-location facilities.

Consequently, we may be subject to short- and long-term interruptions, delays and outages in service and availability due to third-party cybersecurity incidents that are outside of our direct control.

We expect that in the future we may experience interruptions, delays and outages in service and availability from time to time due to a variety of factors, including infrastructure changes, human or software errors, website hosting disruptions and capacity constraints.

Coordinated physical and or cyber attacks that disrupt multiple key electric assets of unaffiliated parties responsible for real-time planning and management of the bulk electric system which could impact our ability to provide generation potentially resulting in localized and regional blackouts affecting third parties and the public, many of which will have no direct commercial relationship with the Company.

We also cannot anticipate, detect, repel, or implement fully effective preventative measures against all cyber threats, particularly because the techniques used are constantly evolving.

For example, as Artificial Intelligence (AI) continues to evolve, threat actors could use AI to develop malicious code and sophisticated phishing attempts.

As threats continue to evolve, we may be required to expend additional resources to continue to enhance our information security measures and/or to investigate and remediate information security vulnerabilities.

While we have not experienced a material breach or disruption to our network or information systems or our operations to date, future attacks may negatively impact our business, reputation, or financial results.

There can be no assurance that such insurance will be available on commercially reasonable terms, in the future.

We are continuously evolving our cybersecurity strategy and technical controls to prepare for, identify, protect, detect, respond, and recover our technology systems, information and operations from such attacks.

See ITEM 1C.

CYBERSECURITY for more information.

Such initiatives could involve significant risks and uncertainties, including distraction of

provides to us.

- limitations on future capital-raising or strategic transactions during the two-year period following the distribution arising from the need to protect the tax-free treatment of the distribution.

Our results were negatively affected by the impacts of COVID-19 in 2020 and future pandemics or other significant health issues could also adversely affect our results.

COVID-19 has previously disrupted economic activity in our markets and negatively affected our results of operations.

The estimated impact of COVID-19 to our Net income was approximately $170 million for the year ended December 31, 2020 and was not material for the years ended December 31, 2021 and 2022.

Any future widespread pandemic or other local or global health issue could adversely affect customer demand and our ability to operate our generation assets.

Any regulatory action relating to the timing and availability of a repository for SNF could adversely affect our ability to decommission fully our nuclear units.

increase in capital expenditures, result in increased operating costs or render the project uneconomic.

We cannot predict whether in the future a fee for SNF disposal may be reestablished or to what extent.

We make contributions to certain trust funds of the former PECO units based on amounts being collected by PECO from its customers and remitted to us.

We face physical security and cybersecurity risks.

We expect these attacks and disruptions to continue to occur in the future and we are constantly managing efforts to infiltrate and compromise our physical assets and information technology systems and data.

business partners and interconnected entities in RTOs and ISOs, or regulators could impact the operation of the generation fleet and/or reliability of the transmission and distribution system or result in the theft or inappropriate release of certain types of information, including critical infrastructure information, sensitive customer, vendor and employee data, trading or other confidential data.

The risk of these system-related events and security breaches occurring continues to intensify, and while we have not directly experienced a material breach or disruption to our network or information systems or our operations to-date, such attacks continue to increase in sophistication and frequency, and we may be unable to prevent all such attacks in the future.

Furthermore, in the future, such insurance may not be available on commercially reasonable terms, or at all.

We may not achieve some or all the expected benefits of the separation, and the separation may materially adversely affect our business.

We may not be able to achieve the full strategic and financial benefits expected to result from the separation, or such benefits may be delayed or not occur at all.

If we fail to achieve some or all the benefits expected to result from the separation, or if such benefits are delayed, it could have a material adverse effect on our competitive position, business, financial condition, results of operations and cash flows.

We may not be able to engage in desirable strategic transactions or capital-raising following the separation.

Under current U.S. federal income tax law, a spin-off that otherwise qualifies for tax-free treatment can be rendered taxable to the parent corporation and its shareholders as a result of certain post-spin-off transactions, including certain acquisitions of shares or assets of the spun-off corporation.

To preserve the tax-free treatment of the distribution, and in addition to potential tax indemnity obligations, we agreed to certain limitations or prohibitions in the tax matters agreement that may prohibit us, for the two-year period following the distribution and except in specific circumstances, from, among other things:

- entering into any transaction pursuant to which all or a portion of the shares of our stock, or substantially all of our assets, would be acquired, whether by merger or otherwise;

- issuing equity securities beyond certain thresholds;

- repurchasing shares of our stock other than in certain open-market transactions.

The tax matters agreement prohibits us from taking or failing to take any other action that would prevent the distribution and certain related transactions from qualifying as a transaction that is generally tax-free for U.S. federal income tax purposes under Sections 355 and 368(a)(1)(D) of the IRC.

These restrictions may limit our ability to pursue certain equity issuances, strategic transactions, repurchases or other transactions that we may believe to be in the best interests of our shareholders or that might increase the value of our business.

We are a supplier of [removed: clean] [added: carbon-free] energy.

Through our integrated business operations, we sell electricity, natural gas, and other [removed: energy related] [added: energy-related] products and sustainable solutions to various types of customers, including distribution utilities, municipalities, cooperatives, and commercial, industrial, governmental, and residential customers in competitive markets across multiple geographic regions.

The following Management’s Discussion and Analysis of Financial Condition and Results of Operations summarizes results for the year ended December 31, [removed: 2022] [added: 2023] compared to the year ended December 31, [removed: 2021.][added: 2022.]

[removed: For discussion of the year ended December 31, 2021] compared to the year ended December 31, [removed: 2020,] [added: 2021,] refer to ITEM 7.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS in the [removed: 2021] [added: 2022] Form 10-K, which was filed with the SEC on February [removed: 25, 2022.][added: 16, 2023.]

We are announcing our capital allocation strategy for [removed: 2023 and] 2024 [added: and 2025] supporting our core principles outlined in our Strategy and Outlook discussion.

We will [removed: double] [added: increase] the [removed: annual] [added: quarterly] dividend [removed: in 2023 from $0.5640 per share] [added: by 25%] to [removed: $1.1280] [added: $0.3525] per share [added: starting in 2024,] while targeting growth of 10% annually.

We are allocating capital towards our best-in-class generation fleet by committing [removed: $1.5 billion] [added: $875 million] of growth capital expenditures over the next [removed: three] [added: two] years, including nuclear [removed: uprates,] [added: uprates and license renewals,] wind [removed: repowering] [added: repowering,] and [removed: hydrogen.][added: hydrogen with policy support.]

In our commitment to return value to shareholders, we have also [removed: authorized a] [added: approved an increase to our previously announced $1 billion] share buyback [removed: program] [added: program, authorizing the repurchase] of [removed: $1.0 billion.][added: up to an additional $1 billion of company stock.]

Significant [removed: 2022] Transactions and Developments

We incurred separation costs of [removed: $140] [added: $101] million and [removed: $49] [added: $140] million for the [removed: twelve months] [added: years] ended December 31, [removed: 2022] [added: 2023] and [removed: 2021,] [added: 2022,] respectively, which are primarily recorded in Operating and maintenance expense.

We are closely monitoring developments of the Russia and Ukraine conflict including United [removed: States sanctions against Russian energy exports, the potential for sanctions on] [added: States, United Kingdom, European Union, and Canadian sanctions, and pending legislation that may impact exports and imports of] Russian nuclear fuel [removed: supply,] [added: supply] and enrichment activities, as well as [removed: yet undefined action by] [added: the potential for] Russia to limit energy deliveries.

We are taking this affirmative action by working with our diverse set of suppliers to ensure we can secure the nuclear fuel needed to continue to operate our nuclear fleet long-term and provide the necessary fuel to bridge potential Russian supply disruption through 2028, which is the date multiple suppliers are expected to have incremental [added: additional] capacity online.

[removed: See] [added: (c)See] Note 16 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements [added: for additional information on mark-to-market gains] and [removed: ITEM 7A.][added: losses.]

The AROs associated with decommissioning our nuclear units were [removed: $12.5] [added: $13.9] billion at December 31, [removed: 2022.][added: 2023.]

Probabilities assigned to cost levels include an assessment of the likelihood of costs 20% higher (high-cost scenario) or 15% lower (low-cost scenario) than the [removed: base cost] [added: base-cost] scenario.

The [removed: assumed] plant shutdown timing scenarios [removed: include the following] [added: consider] four alternatives: (1) the probability of [added: early plant retirement, (2) the probability of] operating through the original 40-year nuclear license term, [removed: (2)] [added: (3)] the probability of operating through an initial 20-year license renewal term, [removed: (3)] [added: and (4)] the probability of a second, 20-year license renewal [removed: term, and (4) the probability of early plant retirement for certain sites due to changing market conditions and regulatory environments.][added: term.]

Discount Rates. The probability-weighted estimated future cash flows for the various assumed scenarios are discounted using [added: our specific] credit-adjusted, risk-free rates (CARFR) [removed: applicable to the various businesses in which each of] [added: or a AAA-rated U.S. company proxy CARFR for] the [removed: nuclear] units [removed: originally operated.][added: that maintain the ability to collect decommissioning costs from utility customers (former PECO and STP units).]

Any decrease in the estimated undiscounted future cash flows relating to the ARO are treated as a modification of an existing ARO cost layer and, therefore, are measured using the average historical CARFR rates used in creating the initial ARO cost [removed: layers.]

If all our future nominal cash flows associated with the ARO were to be discounted at the current prevailing CARFR, the obligation would decrease from approximately [removed: $12.5] [added: $13.9] billion to approximately [removed: $10.5] [added: $11.3] billion.

| Change in the CARFR applied to the annual ARO update | | | Increase (Decrease) to ARO as of December 31, [removed: 2022] [added: 2023] | | |

| [removed: 2021] [added: 2022] CARFR rather than the [removed: 2022] [added: 2023] CARFR | | | $ | [removed: 3,470] [added: 520] | |

| [removed: 2022] [added: 2023] CARFR increased by 50 basis points | | | [removed: (570)] [added: (290)] | | |

| [removed: 2022] [added: 2023] CARFR decreased by 50 basis points | | | [removed: 710] [added: 350] | | |

| Change in ARO Assumption | | | Increase (Decrease) to ARO as of December 31, [removed: 2022] [added: 2023] | | |

| Uniform increase in escalation rates of 50 basis points | | | $ | [removed: 1,780] [added: 1,860] | |

| Increase the estimated costs to decommission the nuclear plants by 10 percent | | | [removed: 720] [added: 770] | | |

| Shorten each unit's [removed: probability weighted] [added: probability-weighted] operating life assumption by 10 percent(b) | | | [removed: 280] [added: 220] | | |

| Extend the estimated date for DOE acceptance of SNF to 2040 | | | [removed: (70)] [added: (80)] | | |

Unamortized energy contract assets and liabilities represent the remaining unamortized balances of non-derivative energy contracts [added: and fuel contracts] that we have acquired.

Amortization of the unamortized energy [added: and fuel] contract assets and liabilities are recorded through Operating revenues or Purchased power and fuel expense, depending on the nature of the underlying contract.

The cash flows from our generating units are generally evaluated at a regional portfolio level (asset group) given the interdependency of cash flows generated from the customer supply and [removed: risk management activities within each region.]

In certain cases, our generating assets may be evaluated on an individual basis where those assets are contracted on a long-term basis with a third-party and operations are independent of other generating assets (typically contracted [removed: renewables).][added: renewable generation).]

The determination of fair value is driven by both internal assumptions that include significant unobservable [removed: inputs (Level 3),] [added: inputs,] such as revenue and generation forecasts, projected capital, maintenance expenditures, and discount rates, as well as information from various public, financial and industry sources.

Depreciable Lives of Property, [removed: Plant] [added: Plant,] and Equipment

[removed: While some of these contracts are considered derivative financial instruments under the authoritative guidance, certain of these qualifying transactions have been designated as] NPNS [removed: transactions, and] [added: transactions] are not required to be recorded at fair value, but rather on an accrual basis of accounting.

We consider [removed: nonperformance] [added: non-performance] risk, including credit risk in the valuation of derivative contracts, and both historical and current market data in our assessment of [removed: nonperformance] [added: non-performance] risk.

The impacts of [removed: nonperformance] [added: non-performance] and credit risk to date have generally not been material to the consolidated financial statements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK and Note [added: 16 — Derivative Financial Instruments and Note] 18 — Fair Value of Financial Assets and Liabilities [removed: and Note 16 — Derivative Financial Instruments] of the Combined Notes to Consolidated Financial Statements for additional information regarding derivative instruments.

[removed: We sponsor] [added: The majority of our current employees participate in] defined benefit pension and OPEB plans [removed: for most current employees.][added: we sponsor.]

For discussion of the year ended December 31, 2022

See Note 20 — Shareholders' Equity of the Combined Notes to the Consolidated Financial Statements for additional information on completed and authorized share buybacks.

Share Repurchase Program

On February 16, 2023, our Board of Directors announced a share repurchase program with a $1 billion authority without expiration.

Repurchases under this program commenced in March 2023.

On December 12, 2023, the Board of Directors approved an increase to our previously announced $1 billion share repurchase program, authorizing the repurchase of up to an additional $1 billion of our outstanding common stock.

During 2023, we repurchased from the open market 10.6 million shares of our common stock for a total cost, inclusive of taxes and transaction costs, of $1 billion.

Acquisition of Joint Ownership in South Texas Project

On November 1, 2023, we completed the acquisition of NRG South Texas LP (renamed and converted as Constellation South Texas, LLC), which owns a 44% undivided ownership interest in the jointly owned STP, a 2,645 MW, dual-unit nuclear plant located in Bay City, Texas.

The net cash paid was $1.65 billion, after certain purchase price adjustments.

This acquisition is complementary to and aligned strategically with our existing clean energy business operations.

The STP operating results are included in the ERCOT operating segment.

See Note 5 — Segment Information additional information on our reportable segments.

Revenue Recognized for Illinois ZECs Delivered in Prior Planning Years

Our Clinton and Quad Cities units contract with certain utilities in Illinois which requires delivery of all ZECs produced during each planning year (June 1 to May 31), with total compensation limited by an annual cap for each planning year designed to limit the cost of ZECs to each utility's customers.

ZECs delivered that, if paid, would result in the annual cap being exceeded may be paid in subsequent years at the vintage year price as long as the payments would not exceed the annual cap in the year paid.

In each planning year since the program commenced on June 1, 2017, we delivered ZECs to the utilities in excess of the annual compensation cap.

The ZEC price and annual compensation cap effective for each planning year are administratively determined by the IPA.

In 2023, we recognized $218 million of revenue as a receivable for ZECs delivered in prior planning years, with payment expected in the third quarter of 2024.

As of December 31, 2023, this receivable is included within Customer accounts receivable, net in the Consolidated Balance Sheets.

See Note 4 — Revenue from Contracts with Customers of the Combined Notes to the Consolidated Financial Statements for additional information on this acquisition.

layers.

Purchase Accounting

In accordance with authoritative guidance, the assets acquired and liabilities assumed in an acquired business are recorded at their estimated fair values on the date of acquisition.

Determining the fair value of assets acquired and liabilities assumed requires management’s judgment, often utilizes independent valuation experts and involves the use of significant estimates and assumptions with respect to the timing and amounts of future cash inflows and outflows, discount rates, market prices and asset lives, among other items.

Changes to these estimates and assumptions could result in material changes to the fair value of assets and liabilities as of acquisition date.

The judgments made in the determination of the estimated fair value assigned to the assets acquired and liabilities assumed, as well as the estimated useful life of each asset and the duration of each liability, could significantly impact the financial statements in periods after acquisition, such as through depreciation and amortization expense.

Authoritative guidance provides that the allocation of the purchase price may be modified up to one year after the acquisition date as more information is obtained about the fair value of assets acquired and liabilities assumed.

The difference between the purchase price amount and the net fair value of assets acquired and liabilities assumed is recognized as goodwill on the balance sheet if the purchase price exceeds the estimated net fair value or as a bargain purchase gain on the income statement if the purchase price is less than the estimated net fair value.

Goodwill is assigned to reporting units that are expected to benefit from the acquisition.

Goodwill is not amortized, instead it is subject to an impairment assessment at least annually to consider whether the

reporting unit fair value is more likely than not less than the carrying amount.

Goodwill

We are required to perform an assessment for impairment of goodwill at least annually or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of the reporting units below their carrying amount.

A reporting unit is an operating segment or one level below an operating segment (known as a component) and is the level at which goodwill is tested for impairment.

Our operating segments and reporting units are Mid-Atlantic, Midwest, New York, ERCOT, and Other Power Regions.

Goodwill is primarily reported within our ERCOT segment.

Entities assessing goodwill for impairment have the option of first performing a qualitative assessment to determine whether a quantitative assessment is necessary.

As part of the qualitative assessment, we evaluate, among other things, management’s best estimate of projected operating and capital cash flows for the reporting units and changes in certain market conditions, including the discount rate.

Significant assumptions used in these fair value analyses include discount and growth rates, energy prices, and projected operating and capital cash flows.

We expect to incur incremental costs of approximately $80 million in 2023.

PJM Performance Bonuses

On December 23, 2022, and continuing through the morning of December 25, 2022, winter storm Elliott blanketed the entirety of PJM’s footprint with record low temperatures and extreme weather conditions.

A significant portion of PJM's fossil generation fleet failed to perform as reserves were called.

PJM’s initial estimate of non-performance charges ranges from $1 billion to $2 billion and, in accordance with its tariff, funds collected from those charges are redistributed to generating resources that performed above expectations during the event.

PJM released preliminary invoices to generators subject to non-performance charges and bonuses on February 10, 2023.

PJM indicated that these preliminary invoices are informational and subject to change for items that could have a material impact to the final amounts billed to non-performing generators, pending PJM’s

completion of their internal processes and data quality assurance reviews.

Leveraging preliminary data from PJM and applying significant judgments and assumptions, we recognized an estimated benefit of $109 million (pre-tax) for performance bonuses (net of non-performance charges), primarily driven by the overperformance of our nuclear fleet.

The ultimate impact to our consolidated financial statements may be affected by several factors, including final non-performance charges billed, the impacts of generator defaults, and related litigation and disputes.

It is reasonably possible that the ultimate benefit could differ significantly once these uncertainties are resolved, which could have a material impact on our financial statements.

Hedging Strategy

We are exposed to commodity price risk associated with the unhedged portion of our electricity portfolio.

We enter into non-derivative and derivative contracts, including options, swaps, and forward and futures contracts, all with credit-approved counterparties, to hedge this anticipated exposure.

For merchant revenues not already hedged via comprehensive state programs, such as the CMC in Illinois, we typically utilize a three-year ratable sales plan to align our hedging strategy with our financial objectives.

The prompt three-year merchant revenues are hedged on an approximate rolling 90%/60%/30% basis.

We may also enter into transactions that are outside of this ratable hedging program.

As of December 31, 2022, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York, and ERCOT reportable segments is 94%-97% and 75%-78% for 2023 and 2024, respectively.

We have been and will continue to be proactive in using hedging strategies to mitigate commodity price risk.

We procure natural gas through long-term and short-term contracts and spot-market purchases.

Nuclear fuel assemblies are obtained predominantly through long-term uranium concentrate supply contracts, contracted conversion services, contracted enrichment services, or a combination thereof, and contracted fuel fabrication services.

The supply markets for uranium concentrates and certain nuclear fuel services are subject to price fluctuations and availability restrictions.

Approximately 60% of our uranium concentrate requirements from 2023 through 2027 are supplied by three suppliers.

In the event of non-performance by these or other suppliers, we believe that replacement uranium concentrate can be obtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements.

Geopolitical developments, including the Russia and Ukraine conflict and United States sanctions against Russia, have the potential to impact delivery from multiple suppliers in the international uranium processing industry.

Non-performance by these counterparties could have a material adverse impact on our consolidated financial statements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for additional information.

NPNS. As part of our energy marketing business, we enter contracts to buy and sell energy to meet the requirements of our customers.

These contracts include short-term and long-term commitments to purchase and sell energy and energy-related products in the retail and wholesale markets with the intent and ability to deliver or take delivery.

Contracts that qualify for NPNS are those for which physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period, and the contract is not financially settled on a net basis.

Revenues and expenses on contracts that qualify as NPNS are recognized when the underlying physical transaction is completed.

| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |

| Discount rate(a) | | | 5.52 | | % | 5.50 | | % | 0.5 | | % | | | | (345) | | | | | | (61) | | | | | | (406) | | |

| | | | 5.52 | | % | 5.50 | | % | (0.5) | | % | | | | 391 | | | | | | 69 | | | | | | 460 | | |

For personal injury claims, we are self-insured to the extent that losses are within policy deductibles or exceed the amount of insurance maintained.

commodities in non-regulated markets (wholesale and retail) and the provision of other energy-related non-regulated products and services.

| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |

| | | | 2022 | | | | | | 2021 | | | | | | | | |

| | | | | | | Twelve Months Ended December 31, | | | | | | | | |

We manage these risks through risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of risk [removed: exposures.]

After the separation on February 1, 2022, reporting on risk management issues is to the Executive [removed: Committee, the Risk Management Committees of our generation and customer-facing businesses,] [added: Committee] and the Audit and Risk Committee of the Board of Directors.

Commodity price risk is associated with price movements resulting from changes in supply and demand, fuel costs, market liquidity, weather conditions, governmental, [removed: regulatory] [added: regulatory,] and environmental policies, and other factors.

To reduce commodity price risk caused by market fluctuations, we enter [removed: into] non-derivative contracts as well as derivative contracts, including swaps, futures, forwards, and options, with approved counterparties to hedge anticipated exposures.

We expect the settlement of the majority of our economic hedges will occur during [removed: 2023] [added: 2024] through [removed: 2025.][added: 2026.]

In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on [removed: our] owned and contracted generation positions [removed: which] [added: that] have not been hedged.

The forecasted market price risk exposure for our entire economic hedge portfolio associated with a $5/MWh reduction in the annual average around-the-clock energy price based on December 31, [removed: 2022] [added: 2023] market conditions and hedged position [removed: would be a decrease] [added: results] in [removed: pre-tax] [added: an immaterial impact to] net income [removed: of approximately $8 million and $215 million] [added: (loss)] for [removed: 2023] [added: 2024] and [removed: 2024,] [added: 2025,] respectively.

[removed: See] Note 16 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.

Approximately [removed: 60%] [added: 55%] of our uranium concentrate requirements from [removed: 2023] [added: 2024] through [removed: 2027] [added: 2028] are supplied by three suppliers.

To-date, we have not experienced any counterparty credit risk associated with these suppliers stemming from the [removed: Russian] [added: Russia] and Ukraine conflict.

In the event of non-performance by these or other suppliers, we believe that replacement uranium [removed: concentrates] [added: concentrate] can be obtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements.

Geopolitical developments, including the Russia and Ukraine conflict and United [removed: States] [added: States, United Kingdom, European Union, and Canadian] sanctions against Russia, have the potential to impact delivery from multiple suppliers in the international uranium [added: processing] industry.

Non-performance by these counterparties could have a material adverse impact [removed: in] [added: on] our consolidated financial statements.

To-date, we have not experienced any delivery or non-performance issues from our suppliers, nor any degradation in the [removed: quality of fuel we have received, and we are closely monitoring developments from the conflict.]

The following table provides detail on changes in our commodity mark-to-market net asset or liability balance sheet position from December 31, [removed: 2020] [added: 2021] to December 31, [removed: 2022.][added: 2023.]

See Note 16 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on the balance sheet classification of the mark-to-market energy contract net assets (liabilities) recorded as of December 31, [removed: 2022] [added: 2023] and [removed: 2021.][added: 2022.]

| Total change in fair value [removed: during 2021] of contracts recorded in result of operations | | | [removed: 797] [added: (2,530)] | | | | | | [added: (647)] | | | | | | | | | | | | [added: | | |]

| Reclassification to realized at settlement of contracts recorded in results of operations | | | [removed: (228)] [added: 1,561] | | | | | | [added: (380)] | | | | | | | | | | | | [added: | | |]

| Changes in allocated collateral | | | [removed: 96] [added: 1,502] | | | | | | [added: 386] | | | | | | | | | | | | [added: | | |]

| Net option premium paid [added: (received)] | | | [removed: 338] [added: (26)] | | | | | | [added: 177] | | | | | | | | | | | | [added: | | |]

| Option premium amortization | | | [removed: (125)] [added: (183)] | | | | | | [added: (293)] | | | | | | | | | | | | [added: | | |]

| Upfront payments and amortizations(b) | | | [removed: 15] [added: (249)] | | | | | | [added: 167] | | | | | | | | | | | | [added: | | |]

| Foreign [removed: Currency Translation] [added: currency translation] | | | [removed: 14] [added: (13)] | | | | | | [added: 14] | | | | | | | | | | | | [added: | | |]

| [removed: Balance] [added: Ending balance] as of December [removed: 31, 2022] [added: 31(a)] | | | $ | [removed: 1,046] [added: 1,108] | | [removed: (a)] | | | [added: $] | [added: 1,046] | | | | | | | | | | | [added: | | |]

(b)Includes derivative contracts acquired or sold through upfront payments or receipts of cash, excluding option [removed: premiums,] [added: premiums] and the associated amortizations.

| | | | [removed: 2023] [added: 2024] | | | | | | [removed: 2024] [added: 2025] | | | | | | [removed: 2025] [added: 2026] | | | | | | [removed: 2026] [added: 2027] | | | | | | [removed: 2027] [added: 2028] | | | | | | [removed: 2028] [added: 2029] and Beyond | | | | | | | | |

| Actively quoted prices (Level 1) | | | $ | [removed: 264] [added: 103] | | | | | $ | [removed: 169] [added: 90] | | | | | $ | [removed: 128] [added: 46] | | | | | $ | [removed: 68] [added: 9] | | | | | $ | [removed: 33] [added: (8)] | | | | | $ | — | | | | | $ | [removed: 662] [added: 240] | |

| Prices provided by external sources (Level 2) | | | [removed: 238] [added: (276)] | | | | | | [removed: 4] [added: 186] | | | | | | [removed: (83)] [added: 91] | | | | | | [removed: 6] [added: (1)] | | | | | | [removed: —] [added: (1)] | | | | | | — | | | | | | [removed: 165] [added: (1)] | | |

| Prices based on model or other valuation methods (Level 3) | | | [removed: 284] [added: 712] | | | | | | [removed: (107)] [added: 133] | | | | | | [removed: 83] [added: (9)] | | | | | | [removed: 38] [added: 9] | | | | | | [removed: 7] [added: 1] | | | | | | [removed: (86)] [added: 23] | | | | | | [removed: 219] [added: 869] | | |

(b)Amounts are shown net of collateral paid/(received) from counterparties (and offset against mark-to-market assets and liabilities) of [removed: $898] [added: $2,400] million at December 31, [removed: 2022.][added: 2023.]

As part of the normal course of business, we routinely enter into [removed: physical] [added: physically] or [removed: financial] [added: financially settled] contracts for the [removed: sale and] purchase [added: and sale] of [added: capacity,] electricity, [removed: natural gas,] [added: fuels, emissions allowances,] and other [removed: commodities.][added: energy-related products.]

We participate in [removed: all, or some,] [added: all] of the [removed: established,] [added: established] wholesale spot energy markets that are administered by PJM, ISO-NE, NYISO, CAISO, MISO, SPP, AESO, [removed: OIESO,] and ERCOT.

The credit policies of the RTOs and ISOs may, under certain circumstances, [added: require that losses arising from the default of one member on spot energy market transactions be shared by the remaining participants.]

Non-performance or non-payment by a major [removed: counterparty] [added: member of an RTO/ISO] could result in a material adverse impact on our consolidated financial statements.

We enter into commodity transactions on NYMEX, ICE, NASDAQ, NGX, and the Nodal exchange [removed: ("the Exchanges").][added: (each an Exchange and, collectively, Exchanges).]

A hypothetical 50 basis point increase in the interest rates associated with unhedged variable-rate debt (excluding Commercial Paper) and fixed-to-floating swaps would not [removed: result] [added: have resulted] in a material decrease in our pre-tax income for the year ended December 31, [removed: 2022.][added: 2023.]

A hypothetical 25 basis points increase in interest rates and 10% decrease in equity prices would [removed: result] [added: have resulted] in a [removed: $759] [added: $885] million reduction in the fair value of [removed: the] [added: our NDT] trust assets as of December 31, [removed: 2022.][added: 2023.]

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF [removed: OPERATIONS] [added: OPERATIONS, and Note 10 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements] for additional information.

exposures.

Beginning in 2024, our nuclear fleet is eligible for the nuclear PTC provided by the IRA, an important tool in managing commodity price risk for each nuclear unit not already receiving state support.

The nuclear PTC provides increasing levels of support as unit revenues decline below levels established in the IRA and is further adjusted annually for inflation over the duration of the program.

In locations and periods where our load serving activities do not naturally offset existing generation portfolio risk, remaining commodity price exposure is managed through portfolio hedging activities.

Portfolio hedging activities are generally concentrated in the prompt three years, when customer demand and market liquidity enable effective price risk mitigation.

During this prompt three-year period, we seek to mitigate price risk associated with our load serving contracts, non-nuclear generation, and any residual price risk for our nuclear generation that the nuclear PTC and state programs may not fully mitigate.

We also enter transactions that further optimize the economic benefits of our overall portfolio.

The forecasted market price risk exposure is the risk of a change in the value of unhedged positions.

quality of fuel we have received, and we are closely monitoring developments from the conflict.

| | | | 2023 | | | | | | 2022 | | | | | | | | | | | | | | |

| Beginning balance as of January 1(a) | | | $ | 1,046 | | | | | $ | 1,622 | | | | | | | | | | | | | |

| Total | | | $ | 539 | | | | | $ | 409 | | | | | $ | 128 | | | | | $ | 17 | | | | | $ | (8) | | | | | $ | 23 | | | | | $ | 1,108 | |

See

Our employee benefit plan trusts also hold investments in equity and debt securities.

See ITEM 7.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates for sensitivity analysis of key assumptions in the valuation of our Pension and OPEB obligations.

For merchant generation sales

not already hedged via comprehensive state programs, such as the CMC in Illinois, we typically utilize a three-year ratable sales plan to align our hedging strategy with our financial objectives.

The prompt three-year merchant sales are hedged on an approximate rolling 90%/60%/30% basis.

We may also enter transactions that are outside of this ratable hedging program.

As of December 31, 2022, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York, and ERCOT reportable segments is 94%-97% and 75%-78% for 2023 and 2024, respectively.

The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation.

Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted generation based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products and options.

Equivalent sales represent all hedging products, which include economic hedges, CMC payments, and certain non-derivative contracts.

A portion of our hedging strategy may be accomplished with fuel products based on assumed correlations between power and fuel prices, which routinely change in the market.

Power price sensitivities are derived by adjusting power price assumptions while keeping all other price inputs constant.

We actively manage our portfolio to mitigate market price risk exposure for our unhedged position.

Actual results could differ depending on the specific timing of, and markets affected by, price changes, as well as future changes in our portfolio.

The following table detailing our trading and non-trading marketing activities is included to address the recommended disclosures by the energy industry’s Committee of Chief Risk Officers (CCRO).

| | | | | | | | | | | | | | | | | | | | | |

| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |

| | | | Mark-to-Market Energy Contract Net Assets | | | | | | | | | | | | | | | | | |

| Balance as of December 31, 2020 | | | $ | 729 | | (a) | | | | | | | | | | | | | | |

| Balance as of December 31, 2021 | | | $ | 1,622 | | (a) | | | | | | | | | | | | | | |

| Total change in fair value during 2022 of contracts recorded in result of operations | | | (647) | | | | | | | | | | | | | | | | | |

| Reclassification to realized at settlement of contracts recorded in results of operations | | | (380) | | | | | | | | | | | | | | | | | |

| Changes in allocated collateral | | | 386 | | | | | | | | | | | | | | | | | |

| Net option premium paid | | | 177 | | | | | | | | | | | | | | | | | |

| Option premium amortization | | | (293) | | | | | | | | | | | | | | | | | |

| Upfront payments and amortizations(b) | | | 167 | | | | | | | | | | | | | | | | | |

__________

The table provides two fundamental pieces of information.

First, the table provides the source of fair value used in determining the carrying amount of our total mark-to-market net assets (liabilities), net of allocated collateral.

Second, the table shows the maturity, by year, of our commodity contract net assets (liabilities), net of allocated collateral, giving an indication of when these mark-to-market amounts will settle and either generate or require cash.

| Total | | | $ | 786 | | | | | $ | 66 | | | | | $ | 128 | | | | | $ | 112 | | | | | $ | 40 | | | | | $ | (86) | | | | | $ | 1,046 | |

The following tables provide information on our credit exposure for all derivative instruments, NPNS, and payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of December 31, 2022.

The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties and an indication of the duration of a company’s credit risk by credit rating of the counterparties.

The figures in the table below exclude credit risk exposure from individual retail customers, uranium procurement contracts, and exposure through RTOs, ISOs, and commodity exchanges, which are discussed below.

| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |

| Rating as of December 31, 2022 | | | Total Exposure Before Credit Collateral | | | | | | Credit Collateral(a) | | | | | | Net Exposure | | | | | | Number of Counterparties Greater than 10% of Net Exposure | | | | | | Net Exposure of Counterparties Greater than 10% of Net Exposure | | |

| Investment grade | | | $ | 1,304 | | | | | $ | 135 | | | | | $ | 1,169 | | | | | — | | | | | | $ | — | |

| Non-investment grade | | | 110 | | | | | | 88 | | | | | | 22 | | | | | | — | | | | | | — | | |

| No external ratings | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

| Internally rated—investment grade | | | 106 | | | | | | — | | | | | | 106 | | | | | | — | | | | | | — | | |

| Internally rated—non-investment grade | | | 374 | | | | | | 40 | | | | | | 334 | | | | | | — | | | | | | — | | |

Our generation fleet of nuclear, hydro, wind, [removed: natural gas,] and solar generation facilities has the generating capacity to power the equivalent of [removed: 15] [added: 16] million homes, producing [removed: 11] [added: about 10] percent of the carbon-free energy in the United States.

Constellation’s fleet is helping to accelerate the nation’s transition to a carbon-free future with more than [removed: 32,355] [added: 33,094] megawatts of capacity and an annual output that is nearly 90 percent carbon-free.

We employ approximately [removed: 13,370] [added: 13,871] people, and do business in 48 states, the District of Columbia, Canada, and the United Kingdom.

Collectively, the combined fleet is nearly 90% carbon-free (based on generation output of electricity) and is the [removed: fourth] [added: third] largest generation portfolio in the U.S. in terms of total generation with meaningful geographic [removed: diversity.][added: diversity, according to the 2023 Ceres Benchmarking Air Emissions of the 100 Largest Electric Power Producers in the United States.]

At December 31, [removed: 2022,] [added: 2023,] our [added: owned] generating resources [added: total capacity of 33,094 MWs] consisted of the following:

[removed: | Owned generation assets(a) | | | | | |][added: Owned Assets]

The following map illustrates the locations of our owned generation facilities as of December 31, [removed: 2022:][added: 2023:]

The Company's Generation Fleet [removed: Map(a)][added: Map(a)(b)]

[removed: ][added: ]

[removed:  Nuclear  Wind][added: ]

[removed:  Gas/Other  Solar][added: ]

[removed:  Hydro][added: ]

We have five reportable segments, as described in the table below, representing the different [removed: geographical areas] [added: geographic regions] in which our owned generating resources are located and our customer-facing activities are conducted.

| Segment | | | | | | Net Generation Capacity (MWs)(a) | | | | | | % of Net Generation Capacity | | | | | | [removed: Geographical Area] [added: Geographic Regions] | | |

| Mid-Atlantic | | | | | | [removed: 10,495] [added: 10,393] | | | | | | 32 | | % | | | | Eastern half of PJM, which includes New Jersey, Maryland, Virginia, West Virginia, Delaware, the District of Columbia, and parts of Pennsylvania and North Carolina | | |

| Midwest | | | | | | [removed: 11,892] [added: 11,605] | | | | | | [removed: 37] [added: 35] | | % | | | | Western half of PJM and the United States footprint of MISO, excluding MISO’s Southern Region | | |

| New York | | | | | | 3,093 | | | | | | [removed: 10] [added: 9] | | % | | | | NYISO | | |

| ERCOT | | | | | | [removed: 3,610] [added: 4,734] | | | | | | [removed: 11] [added: 14] | | % | | | | Electric Reliability Council of Texas | | |

| Other Power Regions | | | | | | [removed: 3,265] [added: 3,269] | | | | | | 10 | | % | | | | New England, South, West, and Canada | | |

| Total | | | | | | [removed: 32,355] [added: 33,094] | | | | | | 100 | | % | | | | | | |

(a)Net generation capacity is stated at proportionate ownership share as of December 31, [removed: 2022.][added: 2023.]

The following table shows [added: our total owned] sources of electric supply [removed: in] [added: of 202,474] GWhs [added: and 200,962 GWhs] for [removed: 2022] [added: 2023] and [removed: 2021:][added: 2022, respectively:]

(a)Includes the proportionate share of output where we have an undivided ownership interest in jointly-owned generating [removed: plants and includes the total output of plans that are fully consolidated.][added: plants.]

[removed: (c)Includes] [added: (b)Includes] wind, hydroelectric, [removed: solar,] and [removed: in 2021, biomass] [added: solar] generating assets.

See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information regarding the [removed: sale] [added: acquisition] of [removed: our biomass facility.][added: STP.]

Our nuclear fleet is the nation’s largest, with current generating capacity of approximately [removed: 21 gigawatts;] [added: 22 GWs;] it produced [removed: 173 terawatt hours] [added: 174 TWhs] of zero-emissions electricity during [removed: 2022] [added: 2023] – enough to power [removed: 15.4] [added: 16] million homes and avoid more than 123 million metric tons of carbon emissions according to the EPA GHG Equivalencies Calculator.

We have ownership interests in [removed: 13] [added: 14] nuclear generating stations currently in service, consisting of [removed: 23] [added: 25] units.

As of December 31, [removed: 2022,] [added: 2023,] we wholly own all our nuclear generating stations, except for undivided ownership interests in [removed: four] [added: five] jointly owned nuclear stations: Quad Cities (75% ownership), Peach Bottom (50% ownership), Salem (42.59% ownership), [removed: and] Nine Mile Point Unit 2 (82% ownership), [removed: which] [added: and STP 44% ownership), that] are [removed: consolidated] [added: included] in our consolidated financial statements relative to our proportionate ownership interest in each unit.

See Note 2 — Mergers, Acquisitions, and Dispositions [removed: and Note 22 — Variable Interest Entities] of the Combined Notes to Consolidated [added: Financial Statements for additional information on these dispositions.]

[added: See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated] Financial Statements for additional information regarding the acquisition of EDF's equity interest in CENG and the CENG consolidation.

We operate all of these nuclear generating stations, except for the [removed: two] units at [removed: Salem,] [added: Salem and STP,] which are operated by PSEG Nuclear, LLC (an indirect, wholly owned subsidiary of [removed: PSEG),] [added: PSEG)] and [removed: we have consistently operated our nuclear plants at best-in-class levels.][added: STPNOC, respectively.]

During [added: 2023,] 2022, [removed: 2021,] and [removed: 2020,] [added: 2021,] our nuclear generating facilities achieved capacity factors(a) of [added: 94.4%,] 94.8%, [removed: 94.5%,] and [removed: 95.4%,] [added: 94.5%,] respectively, at ownership percentage.

In [removed: 2022,] [added: 2023,] we achieved an average refueling outage duration of 21 days for units we operate.

We achieved an average refueling outage duration of [added: 21 and] 22 days in [removed: both 2021] [added: 2022] and [removed: 2020,] [added: 2021, respectively,] against industry averages of [removed: 32] [added: 40] and [removed: 34] [added: 32] days, respectively.

In [added: 2023,] 2022, [removed: 2021,] and [removed: 2020,] [added: 2021,] electric supply (in GWhs) generated from our nuclear generating facilities was [removed: 64%,] 65%, [added: 64%,] and [removed: 62%,] [added: 65%,] respectively, of our total electric [removed: supply, which also includes natural gas, oil, and renewable generation and electric supply purchased for resale.][added: supply.]

Peach Bottom has previously received a second 20-year license renewal from the [removed: NRC, for a total 80-year term,] [added: NRC] for Units 2 and [removed: 3.][added: 3, for a total 80-year term.]

See Note 3 — Regulatory Matters [added: and Note 8 — Property, Plant, and Equipment] of the Combined Notes to Consolidated Financial Statements for additional information.

(a)Capacity factor is defined as the ratio of the actual output of a [removed: plant] [added: unit (or combination of units)] over a period of time to its output if the [removed: plant] [added: unit] had operated at [removed: full average annual] [added: net monthly] mean capacity for that time period.

| Nine Mile [removed: Point] [added: Point(b)] | | | 1 | | | | | | 1969 | | | | | | 2029 | | |

| [removed: Ginna] [added: Ginna(b)] | | | 1 | | | | | | 1970 | | | | | | 2029 | | |

In addition to the owned generating resources above, at December 31, 2023 we have contracted generation with a total capacity of 4,103 MWs, which represents electric supply procured under unit-specific agreements.


_________

In addition to the owned generation above, we also had purchased power from the spot energy markets that are administered by the RTOs/ISOs and bilateral transactions of 67,215 GWhs and 70,682 GWhs for the years ended December 31, 2023 and 2022, respectively.

On November 1, 2023.

we acquired NRG South Texas LP, which owns a 44% undivided ownership interest in the jointly owned STP.

We have consistently operated our nuclear plants at best-in-class levels.

STPNOC has received 20-year operating license renewals for STP Units 1 and 2.

| STP | | | 1 | | | | | | 1988 | | | | | | 2047 | | |

| | | | 2 | | | | | | 1989 | | | | | | 2048 | | |

We expect that the license expiration dates will be restored to 2053 and 2054, respectively.

Beginning in the third quarter of 2022, we updated Dresden depreciation provisions consistent with the license renewal as described above.

Beginning in 2023, Dispatch Match reflects a change to remove the Conowingo run-of-river hydroelectric operational performance.

Prior year Dispatch Match for 2022 and 2021 was previously reported as 98.4% and 72.4%, respectively.

Beginning in 2023, Renewable Energy Capture reflects a change to include the Conowingo run-of-river hydroelectric operational performance.

Prior year Renewable Energy Capture for 2022 and 2021 was previously reported as 95.8% and 95.7%, respectively.

| ERCOT | | | | | | 7 | | | | | | 2025 - 2035 | | | | | | 981 | | |

| Total | | | | | | 34 | | | | | | | | | | | | 4,103 | | |

| Capacity Expiring (MW) | | | | | | 101 | | | | | | 501 | | | | | | 398 | | | | | | 5 | | | | | | 58 | | | | | | 3,040 | | | | | | 4,103 | | |

We are one of the nation’s largest energy suppliers.


In addition to our high customer renewal rates, we have produced consistently high new win rates for C&I

In 2023 we rolled out our Hourly Carbon-Free Energy (CFE) platform and closed two landmark transactions with Microsoft and Commonwealth Edison.

Achieving 100% carbon-free power is a key sustainability goal for many organizations.

As customers make the transition to 100% carbon-free power, many are looking to bridge the gap between their real-time electricity demand and available sources of carbon-free power.

Our Hourly CFE platform and associated products match carbon-free generation every hour with a customer’s load, along with appropriate tracking and retirement of hourly attributes in the applicable registry.

Beginning in 2024, our nuclear fleet is eligible for the nuclear PTC provided by the IRA, an important tool in managing commodity price risk for each nuclear unit not already receiving state support.

The nuclear PTC provides increasing levels of support as unit revenues decline below levels established in the IRA and is further adjusted annually for inflation over the duration of the program.

In locations and periods where our load serving activities do not naturally offset existing generation portfolio risk, remaining commodity price exposure is managed through portfolio hedging activities.

Portfolio hedging activities are generally concentrated in the prompt three years, when customer demand and market liquidity enable effective price risk mitigation.

During this prompt three-year period, we seek to mitigate price risk associated with our load serving contracts, non-nuclear generation, and any residual price risk for our nuclear generation that the nuclear PTC and state programs may not fully mitigate.

We also enter transactions that further optimize the economic benefits of our overall portfolio.

We do not anticipate difficulty in obtaining the necessary uranium concentrates or conversion, enrichment, or fabrication services to meet the nuclear fuel requirements of our nuclear fleet.

See ITEM 2.

The NRC may modify, suspend, or revoke operating licenses and impose violations and/or

- Prior to the end of 2022, successfully delivered on our commitment to provide 100% of our C&I customers with customer-specific information on their GHG impact for facilities contracting for power or gas supply from Constellation, that include hourly carbon-free energy matching.

increasingly stringent policies that require the reduction of GHG emissions over time.

This federal support builds on actions taken by states to recognize that existing nuclear generation facilities are essential to meeting policy objectives to reduce GHG emissions, with 10 states introducing bills in 2023 to add nuclear energy to clean energy targets and four of those states, including Connecticut, Michigan, North Carolina and Tennessee, finalizing such legislation.

In addition, nuclear energy generation supports jobs and regional economies, and helps to ensure reliability and security of the electrical grid.

For these reasons, the International Energy Agency concluded in a 2022 report, “Nuclear Power and Secure Energy Transitions,” that extending the lifetimes of existing nuclear plants is an indispensable part of a cost-effective path to net zero by 2050.

| | | | | | |

| --- | --- | --- | --- | --- | --- |

| Type of Capacity | | | MWs | | |

| Nuclear | | | 20,895 | | |

| Natural gas and oil | | | 8,807 | | |

| Renewable(b) | | | 2,653 | | |

| Owned generation assets | | | 32,355 | | |

| Contracted generation(c) | | | 3,883 | | |

| Total generating resources | | | 36,238 | | |

(c)Electric supply procured under unit-specific agreements.

Owned Assets(b)

| | | | | | | | | | | | |

| --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |

| | | | Source of Electric Supply | | | | | | | | |

| | | | 2022 | | | | | | 2021 | | |

| Nuclear(a)(b) | | | 173,350 | | | | | | 172,990 | | |

| Purchases — non-trading portfolio | | | 70,682 | | | | | | 67,605 | | |

| Natural gas and oil | | | 21,563 | | | | | | 19,960 | | |

| Renewable(c) | | | 6,049 | | | | | | 6,577 | | |

| Total Supply | | | 271,644 | | | | | | 267,132 | | |

(b)2021 values have been revised from those previously reported to correctly reflect our 82% undivided ownership interest in Nine Mile Point Unit 2.

We are currently seeking license renewals for our Clinton and Dresden units.

Clinton depreciation provisions are based on an estimated useful life through 2047.

Dresden Units 2 and 3 depreciation provisions are based on an estimated useful life through 2049 and 2051, respectively, in anticipation of the license renewals.

Peach Bottom Units 2 and 3 depreciation provisions are based on an estimated useful life through 2053 and 2054 respectively, in anticipation of the license expiration dates being restored.

Much of this output was dispatched to support our wholesale and retail power customer-facing activities.

| New York | | | | | | 4 | | | | | | 2023 | | | | | | 26 | | |

| ERCOT | | | | | | 6 | | | | | | 2026 - 2035 | | | | | | 841 | | |

| Total | | | | | | 31 | | | | | | | | | | | | 3,883 | | |

| Capacity Expiring (MW) | | | | | | 140 | | | | | | 101 | | | | | | 490 | | | | | | 398 | | | | | | 5 | | | | | | 2,749 | | | | | | 3,883 | | |


In


For merchant generation sales not already hedged via comprehensive state programs, such as the CMC program in Illinois, we typically utilize a three-year ratable sales plan to align our hedging strategy with our financial objectives.

The prompt three-year merchant sales are hedged on an approximate rolling 90%/60%/30% basis, providing cash flow stability while still allowing commercial opportunities to generate value for the Company.

We may also enter transactions that are outside of this ratable hedging program.

We are exposed to commodity price risk for the portions of our electricity portfolio that are unhedged.

As of December 31, 2022, the

percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York, and ERCOT reportable segments is 94%-97% and 75%-78% for 2023 and 2024, respectively.

Similarly, the scale and scope of the portfolio provides risk-mitigating technology, product, and geographical diversification.

For information regarding material lawsuits and proceedings, see Note 3 — Regulatory Matters and Note 19 — Commitments [removed: and Contingencies of the Combined Notes to Consolidated Financial Statements.]

and Contingencies of the Combined Notes to Consolidated Financial Statements.

For the Fiscal Year Ended December 31, [removed: 2022][added: 2023]

The estimated aggregate market value of the voting and non-voting common equity held by nonaffiliates of each registrant as of June 30, [removed: 2022] [added: 2023] was as follows:

The number of shares outstanding of each registrant’s common stock as of January 31, [removed: 2023] [added: 2024] was as follows:

| Constellation Energy Corporation Common Stock, without par value | | | [removed: 327,131,082] [added: 316,666,538] | | |

Portions of the Registrants’ Definitive Proxy Statement relating to the [removed: 2023] [added: 2024] Annual Meeting of Shareholders are incorporated by reference into Part III of this report.

The Registrants expect to file the Definitive Proxy Statement with the Securities and Exchange Commission within 120 days after December 31, [removed: 2022.][added: 2023.]

| [GLOSSARY OF TERMS AND [removed: ABBREVIATIONS](#i0f667b69a013404da82f8d403a978330_13)] [added: ABBREVIATIONS](#id92a3771fd574010a55cfb2a228a2bce_10)] | | | | | | [removed: [1](#i0f667b69a013404da82f8d403a978330_13)] [added: [1](#id92a3771fd574010a55cfb2a228a2bce_10)] | | |

| [FILING [removed: FORMAT](#i0f667b69a013404da82f8d403a978330_16)] [added: FORMAT](#id92a3771fd574010a55cfb2a228a2bce_13)] | | | | | | [removed: [6](#i0f667b69a013404da82f8d403a978330_16)] [added: [5](#id92a3771fd574010a55cfb2a228a2bce_13)] | | |

| [CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING [removed: INFORMATION](#i0f667b69a013404da82f8d403a978330_19)] [added: INFORMATION](#id92a3771fd574010a55cfb2a228a2bce_16)] | | | | | | [removed: [6](#i0f667b69a013404da82f8d403a978330_19)] [added: [5](#id92a3771fd574010a55cfb2a228a2bce_16)] | | |

| [WHERE TO FIND MORE [removed: INFORMATION](#i0f667b69a013404da82f8d403a978330_22)] [added: INFORMATION](#id92a3771fd574010a55cfb2a228a2bce_19)] | | | | | | [removed: [6](#i0f667b69a013404da82f8d403a978330_22)] [added: [5](#id92a3771fd574010a55cfb2a228a2bce_19)] | | |

| [ITEM [removed: 1.](#i0f667b69a013404da82f8d403a978330_28)] [added: 1.](#id92a3771fd574010a55cfb2a228a2bce_25)] | | | [removed: [BUSINESS](#i0f667b69a013404da82f8d403a978330_28)] [added: [BUSINESS](#id92a3771fd574010a55cfb2a228a2bce_25)] | | | [removed: [7](#i0f667b69a013404da82f8d403a978330_28)] [added: [6](#id92a3771fd574010a55cfb2a228a2bce_25)] | | |

| | | | [Constellations Strategy and [removed: Outlook](#i0f667b69a013404da82f8d403a978330_34)] [added: Outlook](#id92a3771fd574010a55cfb2a228a2bce_31)] | | | [removed: [19](#i0f667b69a013404da82f8d403a978330_34)] [added: [17](#id92a3771fd574010a55cfb2a228a2bce_31)] | | |

| | | | [Environmental Matters and [removed: Regulation](#i0f667b69a013404da82f8d403a978330_40)] [added: Regulation](#id92a3771fd574010a55cfb2a228a2bce_37)] | | | [removed: [23](#i0f667b69a013404da82f8d403a978330_40)] [added: [22](#id92a3771fd574010a55cfb2a228a2bce_37)] | | |

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| [ITEM [removed: 1B.](#i0f667b69a013404da82f8d403a978330_46)] [added: 1B.](#id92a3771fd574010a55cfb2a228a2bce_43)] | | | [UNRESOLVED STAFF [removed: COMMENTS](#i0f667b69a013404da82f8d403a978330_46)] [added: COMMENTS](#id92a3771fd574010a55cfb2a228a2bce_43)] | | | [removed: [43](#i0f667b69a013404da82f8d403a978330_46)] [added: [28](#id92a3771fd574010a55cfb2a228a2bce_43)] | | |

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| [ITEM [removed: 3.](#i0f667b69a013404da82f8d403a978330_52)] [added: 3.](#id92a3771fd574010a55cfb2a228a2bce_49)] | | | [LEGAL [removed: PROCEEDINGS](#i0f667b69a013404da82f8d403a978330_52)] [added: PROCEEDINGS](#id92a3771fd574010a55cfb2a228a2bce_49)] | | | [removed: [46](#i0f667b69a013404da82f8d403a978330_52)] [added: [32](#id92a3771fd574010a55cfb2a228a2bce_49)] | | |

| [ITEM [removed: 4.](#i0f667b69a013404da82f8d403a978330_55)] [added: 4.](#id92a3771fd574010a55cfb2a228a2bce_52)] | | | [MINE SAFETY [removed: DISCLOSURES](#i0f667b69a013404da82f8d403a978330_55)] [added: DISCLOSURES](#id92a3771fd574010a55cfb2a228a2bce_52)] | | | [removed: [46](#i0f667b69a013404da82f8d403a978330_55)] [added: [46](#id92a3771fd574010a55cfb2a228a2bce_52)] | | |

| [ITEM [removed: 5.](#i0f667b69a013404da82f8d403a978330_61)] [added: 5.](#id92a3771fd574010a55cfb2a228a2bce_58)] | | | [MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY [removed: SECURITIES](#i0f667b69a013404da82f8d403a978330_61)] [added: SECURITIES](#id92a3771fd574010a55cfb2a228a2bce_58)] | | | [removed: [46](#i0f667b69a013404da82f8d403a978330_61)] [added: [46](#id92a3771fd574010a55cfb2a228a2bce_58)] | | |

| [ITEM [removed: 6.](#i0f667b69a013404da82f8d403a978330_64)] [added: 6.](#id92a3771fd574010a55cfb2a228a2bce_61)] | | | [removed: [RESERVED](#i0f667b69a013404da82f8d403a978330_64)] [added: [RESERVED](#id92a3771fd574010a55cfb2a228a2bce_61)] | | | [removed: [48](#i0f667b69a013404da82f8d403a978330_64)] [added: [48](#id92a3771fd574010a55cfb2a228a2bce_61)] | | |

| [ITEM [removed: 7.](#i0f667b69a013404da82f8d403a978330_67)] [added: 7.](#id92a3771fd574010a55cfb2a228a2bce_64)] | | | [MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF [removed: OPERATIONS](#i0f667b69a013404da82f8d403a978330_67)] [added: OPERATIONS](#id92a3771fd574010a55cfb2a228a2bce_64)] | | | [removed: [49](#i0f667b69a013404da82f8d403a978330_67)] [added: [48](#id92a3771fd574010a55cfb2a228a2bce_64)] | | |

| | | | [Executive [removed: Overview](#i0f667b69a013404da82f8d403a978330_70)] [added: Overview](#id92a3771fd574010a55cfb2a228a2bce_67)] | | | [removed: [49](#i0f667b69a013404da82f8d403a978330_70)] [added: [48](#id92a3771fd574010a55cfb2a228a2bce_67)] | | |

| | | | [Significant [removed: 202](#i0f667b69a013404da82f8d403a978330_73)[2](#i0f667b69a013404da82f8d403a978330_73) [Transactions] [added: Transactions] and [removed: Developments](#i0f667b69a013404da82f8d403a978330_73)] [added: Developments](#id92a3771fd574010a55cfb2a228a2bce_70)] | | | [removed: [49](#i0f667b69a013404da82f8d403a978330_73)] [added: [49](#id92a3771fd574010a55cfb2a228a2bce_70)] | | |

| | | | [Other Key Business [removed: Drivers](#i0f667b69a013404da82f8d403a978330_76)] [added: Drivers](#id92a3771fd574010a55cfb2a228a2bce_73)] | | | [removed: [50](#i0f667b69a013404da82f8d403a978330_76)] [added: [50](#id92a3771fd574010a55cfb2a228a2bce_73)] | | |

| | | | [Critical Accounting Policies and [removed: Estimates](#i0f667b69a013404da82f8d403a978330_79)] [added: Estimates](#id92a3771fd574010a55cfb2a228a2bce_76)] | | | [removed: [51](#i0f667b69a013404da82f8d403a978330_79)] [added: [50](#id92a3771fd574010a55cfb2a228a2bce_76)] | | |

| | | | [Financial Results of [removed: Operations](#i0f667b69a013404da82f8d403a978330_82)] [added: Operations](#id92a3771fd574010a55cfb2a228a2bce_79)] | | | [removed: [58](#i0f667b69a013404da82f8d403a978330_82)] [added: [58](#id92a3771fd574010a55cfb2a228a2bce_79)] | | |

| | | | [Liquidity and Capital [removed: Resources](#i0f667b69a013404da82f8d403a978330_85)] [added: Resources](#id92a3771fd574010a55cfb2a228a2bce_82)] | | | [removed: [68](#i0f667b69a013404da82f8d403a978330_85)] [added: [67](#id92a3771fd574010a55cfb2a228a2bce_82)] | | |

| [ITEM [removed: 7A.](#i0f667b69a013404da82f8d403a978330_91)] [added: 7A.](#id92a3771fd574010a55cfb2a228a2bce_85)] | | | [QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET [removed: RISK](#i0f667b69a013404da82f8d403a978330_91)] [added: RISK](#id92a3771fd574010a55cfb2a228a2bce_85)] | | | [removed: [77](#i0f667b69a013404da82f8d403a978330_91)] [added: [76](#id92a3771fd574010a55cfb2a228a2bce_85)] | | |

| [ITEM [removed: 8.](#i0f667b69a013404da82f8d403a978330_94)] [added: 8.](#id92a3771fd574010a55cfb2a228a2bce_88)] | | | [FINANCIAL STATEMENTS AND SUPPLEMENTARY [removed: DATA](#i0f667b69a013404da82f8d403a978330_94)] [added: DATA](#id92a3771fd574010a55cfb2a228a2bce_88)] | | | [removed: [83](#i0f667b69a013404da82f8d403a978330_94)] [added: [81](#id92a3771fd574010a55cfb2a228a2bce_88)] | | |

| | | | [Constellation Energy [removed: Corporation](#i0f667b69a013404da82f8d403a978330_115)] [added: Corporation](#id92a3771fd574010a55cfb2a228a2bce_103)] | | | [removed: [87](#i0f667b69a013404da82f8d403a978330_115)] [added: [86](#id92a3771fd574010a55cfb2a228a2bce_103)] | | |

| | | | [Constellation Energy Generation, [removed: LLC](#i0f667b69a013404da82f8d403a978330_130)] [added: LLC](#id92a3771fd574010a55cfb2a228a2bce_118)] | | | [removed: [93](#i0f667b69a013404da82f8d403a978330_130)] [added: [91](#id92a3771fd574010a55cfb2a228a2bce_118)] | | |

| | | | [Combined Notes to Consolidated Financial [removed: Statements](#i0f667b69a013404da82f8d403a978330_145)] [added: Statements](#id92a3771fd574010a55cfb2a228a2bce_133)] | | | [removed: [98](#i0f667b69a013404da82f8d403a978330_145)] [added: [96](#id92a3771fd574010a55cfb2a228a2bce_133)] | | |

| | | | [2. Mergers, Acquisitions, and [removed: Dispositions](#i0f667b69a013404da82f8d403a978330_154)] [added: Dispositions](#id92a3771fd574010a55cfb2a228a2bce_142)] | | | [removed: [105](#i0f667b69a013404da82f8d403a978330_154)] [added: [103](#id92a3771fd574010a55cfb2a228a2bce_142)] | | |

| | | | [3. Regulatory [removed: Matters](#i0f667b69a013404da82f8d403a978330_160)] [added: Matters](#id92a3771fd574010a55cfb2a228a2bce_148)] | | | [removed: [106](#i0f667b69a013404da82f8d403a978330_160)] [added: [106](#id92a3771fd574010a55cfb2a228a2bce_148)] | | |

| | | | [4. Revenue from Contracts with [removed: Customers](#i0f667b69a013404da82f8d403a978330_166)] [added: Customers](#id92a3771fd574010a55cfb2a228a2bce_154)] | | | [removed: [112](#i0f667b69a013404da82f8d403a978330_166)] [added: [108](#id92a3771fd574010a55cfb2a228a2bce_154)] | | |

| | | | [8. Property, Plant, and [removed: Equipment](#i0f667b69a013404da82f8d403a978330_193)] [added: Equipment](#id92a3771fd574010a55cfb2a228a2bce_181)] | | | [removed: [121](#i0f667b69a013404da82f8d403a978330_193)] [added: [117](#id92a3771fd574010a55cfb2a228a2bce_181)] | | |

| | | | [10. Asset Retirement [removed: Obligations](#i0f667b69a013404da82f8d403a978330_208)] [added: Obligations](#id92a3771fd574010a55cfb2a228a2bce_196)] | | | [removed: [122](#i0f667b69a013404da82f8d403a978330_208)] [added: [118](#id92a3771fd574010a55cfb2a228a2bce_196)] | | |

| | | | [16. Derivative Financial [removed: Instruments](#i0f667b69a013404da82f8d403a978330_250)] [added: Instruments](#id92a3771fd574010a55cfb2a228a2bce_238)] | | | [removed: [143](#i0f667b69a013404da82f8d403a978330_250)] [added: [140](#id92a3771fd574010a55cfb2a228a2bce_238)] | | |

| | | | [17. Debt and Credit [removed: Agreements](#i0f667b69a013404da82f8d403a978330_256)] [added: Agreements](#id92a3771fd574010a55cfb2a228a2bce_244)] | | | [removed: [148](#i0f667b69a013404da82f8d403a978330_256)] [added: [144](#id92a3771fd574010a55cfb2a228a2bce_244)] | | |

| | | | [18. Fair Value of Financial Assets and [removed: Liabilities](#i0f667b69a013404da82f8d403a978330_265)] [added: Liabilities](#id92a3771fd574010a55cfb2a228a2bce_253)] | | | [removed: [154](#i0f667b69a013404da82f8d403a978330_265)] [added: [149](#id92a3771fd574010a55cfb2a228a2bce_253)] | | |

| Constellation Energy Corporation | | | $29,396,464,132 | | |

| [PART I](#id92a3771fd574010a55cfb2a228a2bce_22) | | | | | | | | |

| | | | [General](#id92a3771fd574010a55cfb2a228a2bce_28) | | | [6](#id92a3771fd574010a55cfb2a228a2bce_28) | | |

| | | | [Employees](#id92a3771fd574010a55cfb2a228a2bce_34) | | | [19](#id92a3771fd574010a55cfb2a228a2bce_34) | | |

| [ITEM 1C.](#id92a3771fd574010a55cfb2a228a2bce_1837) | | | [CYBERSECURITY](#id92a3771fd574010a55cfb2a228a2bce_1837) | | | [28](#id92a3771fd574010a55cfb2a228a2bce_1837) | | |

| [PART II](#id92a3771fd574010a55cfb2a228a2bce_55) | | | | | | | | |

| | | | [Management's Report on Internal Control Over Financial Reporting](#id92a3771fd574010a55cfb2a228a2bce_91) | | | [81](#id92a3771fd574010a55cfb2a228a2bce_91) | | |

| | | | [Report of Independent Registered Public Accounting Firm](#id92a3771fd574010a55cfb2a228a2bce_94) | | | [82](#id92a3771fd574010a55cfb2a228a2bce_94) | | |

| | | | [1. Basis of Presentation](#id92a3771fd574010a55cfb2a228a2bce_136) | | | [96](#id92a3771fd574010a55cfb2a228a2bce_136) | | |

| | | | [5. Segment Information](#id92a3771fd574010a55cfb2a228a2bce_163) | | | [111](#id92a3771fd574010a55cfb2a228a2bce_163) | | |

| | | | [6. Accounts Receivable](#id92a3771fd574010a55cfb2a228a2bce_169) | | | [114](#id92a3771fd574010a55cfb2a228a2bce_169) | | |

| | | | [7. Early Plant Retirements](#id92a3771fd574010a55cfb2a228a2bce_175) | | | [115](#id92a3771fd574010a55cfb2a228a2bce_175) | | |

| | | | [9. Jointly Owned Electric Plant](#id92a3771fd574010a55cfb2a228a2bce_190) | | | [118](#id92a3771fd574010a55cfb2a228a2bce_190) | | |

| | | | [11. Leases](#id92a3771fd574010a55cfb2a228a2bce_202) | | | [124](#id92a3771fd574010a55cfb2a228a2bce_202) | | |

| | | | [12. Asset Impairments](#id92a3771fd574010a55cfb2a228a2bce_211) | | | [125](#id92a3771fd574010a55cfb2a228a2bce_211) | | |

| | | | [13. Intangible Assets](#id92a3771fd574010a55cfb2a228a2bce_217) | | | [126](#id92a3771fd574010a55cfb2a228a2bce_217) | | |

| | | | [14. Income Taxes](#id92a3771fd574010a55cfb2a228a2bce_223) | | | [127](#id92a3771fd574010a55cfb2a228a2bce_223) | | |

| | | | [15. Retirement Benefits](#id92a3771fd574010a55cfb2a228a2bce_232) | | | [130](#id92a3771fd574010a55cfb2a228a2bce_232) | | |

| | | | [20. Shareholders' Equity](#id92a3771fd574010a55cfb2a228a2bce_265) | | | [162](#id92a3771fd574010a55cfb2a228a2bce_265) | | |

| | | | [21. Stock-Based Compensation Plans](#id92a3771fd574010a55cfb2a228a2bce_271) | | | [163](#id92a3771fd574010a55cfb2a228a2bce_271) | | |

| [PART III](#id92a3771fd574010a55cfb2a228a2bce_319) | | | | | | | | |

| [PART IV](#id92a3771fd574010a55cfb2a228a2bce_337) | | | | | | | | |

| [SIGNATURES](#id92a3771fd574010a55cfb2a228a2bce_358) | | | | | | [185](#id92a3771fd574010a55cfb2a228a2bce_358) | | |

| | | | [Constellation Energy Corporation](#id92a3771fd574010a55cfb2a228a2bce_358) | | | [185](#id92a3771fd574010a55cfb2a228a2bce_358) | | |

| *Continental Wind* | | | | | | Continental Wind LLC | | |

| *STP* | | | | | | South Texas Project nuclear generating station | | |

| *West Medway II* | | | | | | West Medway Generating Station II | | |

| *AEP Texas* | | | | | | American Electric Power Texas | | |

| *CO2* | | | | | | Carbon Dioxide | | |

| *EMA* | | | | | | Employee Matters Agreement | | |

| *Exchange Act* | | | | | | Securities Exchange Act of 1934. as amended | | |

| *GW* | | | | | | Gigawatt | | |

| *Mystic COS* | | | | | | Mystic Cost of Service Agreement | | |

| *OCI* | | | | | | Other Comprehensive Income | | |

| *SPDES* | | | | | | State Pollutant Discharge Elimination System | | |

| *STPNOC* | | | | | | STP Nuclear Operating Company | | |

| *TMA* | | | | | | Tax Matters Agreement | | |

| *TSA* | | | | | | Transition Services Agreement | | |

| *VEBA* | | | | | | Voluntary Employees' Beneficiary Associations | | |

Neither Registrant makes any representation as to information relating to the other Registrant.

| Constellation Energy Corporation | | | $18,711,601,222 | | |

| | | | | | | | | |

| --- | --- | --- | --- | --- | --- | --- | --- | --- |

| [PART I](#i0f667b69a013404da82f8d403a978330_25) | | | | | | | | |

| | | | [General](#i0f667b69a013404da82f8d403a978330_31) | | | [7](#i0f667b69a013404da82f8d403a978330_31) | | |

| | | | [Employees](#i0f667b69a013404da82f8d403a978330_37) | | | [21](#i0f667b69a013404da82f8d403a978330_37) | | |

| [PART II](#i0f667b69a013404da82f8d403a978330_58) | | | | | | | | |

| | | | [1. Basis of Presentation](#i0f667b69a013404da82f8d403a978330_148) | | | [98](#i0f667b69a013404da82f8d403a978330_148) | | |

| | | | [5. Segment Information](#i0f667b69a013404da82f8d403a978330_175) | | | [114](#i0f667b69a013404da82f8d403a978330_175) | | |

| | | | [6. Accounts Receivable](#i0f667b69a013404da82f8d403a978330_181) | | | [117](#i0f667b69a013404da82f8d403a978330_181) | | |

| | | | [7. Early Plant Retirements](#i0f667b69a013404da82f8d403a978330_187) | | | [119](#i0f667b69a013404da82f8d403a978330_187) | | |

| | | | [9. Jointly Owned Electric Utility Plant](#i0f667b69a013404da82f8d403a978330_202) | | | [122](#i0f667b69a013404da82f8d403a978330_202) | | |

| | | | [11. Leases](#i0f667b69a013404da82f8d403a978330_214) | | | [127](#i0f667b69a013404da82f8d403a978330_214) | | |

| | | | [12. Asset Impairments](#i0f667b69a013404da82f8d403a978330_223) | | | [129](#i0f667b69a013404da82f8d403a978330_223) | | |

| | | | [13. Intangible Assets](#i0f667b69a013404da82f8d403a978330_229) | | | [130](#i0f667b69a013404da82f8d403a978330_229) | | |

| | | | [14. Income Taxes](#i0f667b69a013404da82f8d403a978330_235) | | | [131](#i0f667b69a013404da82f8d403a978330_235) | | |

| | | | [15. Retirement Benefits](#i0f667b69a013404da82f8d403a978330_244) | | | [135](#i0f667b69a013404da82f8d403a978330_244) | | |

| | | | [20. Stock-Based Compensation Plans](#i0f667b69a013404da82f8d403a978330_283) | | | [168](#i0f667b69a013404da82f8d403a978330_283) | | |

| | | | [21. Changes in Accumulated Other Comprehensive Income](#i0f667b69a013404da82f8d403a978330_289) | | | [170](#i0f667b69a013404da82f8d403a978330_289) | | |

| [PART III](#i0f667b69a013404da82f8d403a978330_331) | | | | | | | | |

| [PART IV](#i0f667b69a013404da82f8d403a978330_349) | | | | | | | | |

| [SIGNATURES](#i0f667b69a013404da82f8d403a978330_370) | | | | | | [190](#i0f667b69a013404da82f8d403a978330_370) | | |

| | | | [Constellation Energy Corporation](#i0f667b69a013404da82f8d403a978330_370) | | | [190](#i0f667b69a013404da82f8d403a978330_370) | | |

| *SolGen* | | | | | | SolGen, LLC | | |

| *CPP* | | | | | | Clean Power Plan | | |

| *CTV* | | | | | | Constellation Technology Ventures | | |

| *ESG* | | | | | | Environmental, Social, and Governance | | |

| *FRR* | | | | | | Fixed Resource Requirement | | |

| *IRC* | | | | | | Internal Revenue Code | | |

| *MATS* | | | | | | U.S. EPA Mercury and Air Toxics Standards | | |

| *MOPR* | | | | | | Minimum Offer Price Rule | | |

| *MPSC* | | | | | | Missouri Public Service Commission | | |

| *NJBPU* | | | | | | New Jersey Board of Public Utilities | | |

| *NOSA* | | | | | | Nuclear Operating Services Agreement | | |

| *PA DEP* | | | | | | Pennsylvania Department of Environmental Protection | | |

| *PSDAR* | | | | | | Post-shutdown Decommissioning Activities Report | | |

| *RMC* | | | | | | Risk Management Committee | | |

| *RMP* | | | | | | Risk Management Policy | | |

| *SSA* | | | | | | Social Security Administration | | |

Risk Management and Strategy

Constellation has established programs and processes to manage material risks from cybersecurity threats including assessing and identifying existing cybersecurity risks, as well as continuously monitoring for developing risks.

Our cybersecurity risk management strategy is established at the executive level and is implemented through our cybersecurity program which deploys risk-based security controls and services to protect our customers, personnel, information and cyber assets.

The program aligns enterprise cyber and physical security controls with the National Institute of Standards & Technology (NIST) Cybersecurity Framework (CSF) and other industry standards such as the NERC and NRC cybersecurity standards.

Cybersecurity risk is assessed and reported in our enterprise risk management program, which utilizes the Three Lines Model adapted from the Institute of Internal Auditors, for risk management to assign clear risk responsibilities across the enterprise.

Through coordination with operational teams, we align on cybersecurity risk classification, categorization, likelihood, and potential impact to the company.

At the highest level, our program includes multi-layered oversight by the Board of Directors and Board Committees.

Our cybersecurity and physical security controls are implemented through policies and procedures which form the comprehensive framework we utilize for planning, performing, managing, assessing, innovating, and improving our security controls.

Our defense-in-depth strategy to protect our cyber assets and sensitive information reduces the potential severity and duration of a cybersecurity incident by leveraging security measures across various layers of the enterprise.

Cross-functional executive steering committees and peer groups, with business unit and technical stakeholder participation, are maintained to support oversight, security controls development, change management, implementation, evaluation, continuous improvement, and sustainment.

Our cybersecurity program is aligned to the five functions of the NIST Cybersecurity Framework – identify, detect, protect, respond, and recover.

To protect our information and cyber assets, we implement practices for training and screening of personnel, access management, network defense, asset configuration management, vulnerability assessment (including penetration testing), third-party security, and privacy and information protection.

In addition, to detect cybersecurity events, we deploy security logging and monitoring, malicious code detection, and data loss protection tools.

If the company is the target of a cybersecurity attack, we have established processes for incident response and crisis management to detect and triage potential incidents and determine severity, contain, and eradicate a threat.

These processes also include steps to recover our systems and information through established and exercised system recovery plans and business continuity plans.

Our incident response process includes steps to notify regulatory and other governmental authorities of cybersecurity events as required by law, including providing notice to investors for material cybersecurity events.

As part of our process to continuously improve, we utilize internal functions such as our internal audit and risk functions to evaluate security controls and risk management practices.

We also engage third-party subject matter experts to independently assess our programs, processes and technical controls, as needed.

For our regulated cyber assets associated with critical infrastructure, such as those within the scope of NERC and the NRC, regulatory auditors and inspectors monitor our adherence to mandatory cybersecurity requirements on a regular frequency using a variety of compliance monitoring and enforcement mechanisms.

Board Governance and Management

Our Board is actively engaged in monitoring the performance of the Company's cybersecurity program and maintains oversight of the Company’s enterprise risk program, including with respect to commodity markets, market design, enterprise security (physical and cyber), operating risks, and financial performance.

While the full Board retains ultimate responsibility and oversight of the Company's cybersecurity risk management practices, the Nuclear Oversight Committee and the Audit and Risk Committee also have cybersecurity risk management as part of their charters.

The Nuclear Oversight Committee is tasked with overseeing compliance with policies and procedures to manage and mitigate cybersecurity risks associated with our nuclear assets.

The Audit and Risk Committee oversees policies and processes established by management to identify, assess, monitor, manage and control technology and cyber risks, among other risks.

Our Chief Information Officer (CIO) and Chief Information Security Officer (CISO) provide regular reports to the Board, or one or both of its designated Committees, regarding the security of our operational and information technology programs, systems, and risks.

We also report on the state of our cybersecurity program and provide key risk indicators to track performance.

Emergent matters or events are reported to the Board between scheduled meetings on an ad hoc basis through our incident response and crisis management protocols.

At the executive and management level, the Chief Administration Officer, via delegations to the Cyber and Physical Security organizations, is authorized to govern and functionally oversee our security controls and services on behalf of the enterprise.

Our cybersecurity organization, under the direction of the CISO who reports to the CIO, implements and provides governance and functional oversight for cybersecurity controls and services.

Our CIO has over 20 years of experience with information systems, including management roles in operational security, technical design and engineering, and platform architecture cybersecurity, governance and compliance, and business continuity.

Our CISO has over 20 years of experience in cybersecurity, governance and compliance, physical security and business continuity.

In addition, cybersecurity risk is assessed and tracked through the Company's enterprise risk management program.

Although the risks from cyber threats have not materially affected our business strategy, results of operations, or financial condition to date, we continue to closely monitor cyber risk.

Overall, our company has implemented tactical processes for assessing, identifying, and managing material risks from cybersecurity threats to the company including governance at the Board level and accountability in our executive management for the execution of our cyber risk management strategy and the controls designed to protect our operations.

See ITEM 1A.

RISK FACTORS for additional information regarding the Company’s cybersecurity risks.

| | | | | | |

| --- | --- | --- | --- | --- | --- |

The following table presents our interests in net electric generating capacity by station at December 31, [removed: 2022:][added: 2023:]

| Quad Cities | | | | | | Cordova, IL | | | | | | 2 | | | | | | 75 | | | | | | Uranium | | | | | | Base-load | | | | | | 1,403 | | | [removed: (f)] | | |

| Clinton | | | | | | Clinton, IL | | | | | | 1 | | | | | | | | | | | | Uranium | | | | | | Base-load | | | | | | [removed: 1,080] [added: 1,092] | | | | | |

| Michigan Wind 2 | | | | | | Sanilac Co., MI | | | | | | 50 | | | | | | 51 | | | [removed: (g)] [added: (f)] | | | Wind | | | | | | Intermittent | | | | | | 46 | | | [removed: (f)] | | |

| Beebe | | | | | | Gratiot Co., MI | | | | | | 34 | | | | | | 51 | | | [removed: (g)] [added: (f)] | | | Wind | | | | | | Intermittent | | | | | | 42 | | | [removed: (f)] | | |

| Michigan Wind 1 | | | | | | Huron Co., MI | | | | | | 46 | | | | | | 51 | | | [removed: (g)] [added: (f)] | | | Wind | | | | | | Intermittent | | | | | | 35 | | | [removed: (f)] | | |

| Harvest 2 | | | | | | Huron Co., MI | | | | | | 33 | | | | | | 51 | | | [removed: (g)] [added: (f)] | | | Wind | | | | | | Intermittent | | | | | | 30 | | | [removed: (f)] | | |

| Harvest | | | | | | Huron Co., MI | | | | | | 31 | | | | | | 51 | | | [removed: (g)] [added: (f)] | | | Wind | | | | | | Intermittent | | | | | | 26 | | | [removed: (f)] | | |

| Beebe 1B | | | | | | Gratiot Co., MI | | | | | | 21 | | | | | | 51 | | | [removed: (g)] [added: (f)] | | | Wind | | | | | | Intermittent | | | | | | 26 | | | [removed: (f)] | | |

| [removed: Blue Breezes] [added: CP Windfarm] | | | | | | Faribault Co., MN | | | | | | 2 | | | | | | [added: 51] | | | [added: (f)] | | | Wind | | | | | | Intermittent | | | | | | [removed: 3] [added: 2] | | | | | |

| Total Midwest | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | [removed: 11,892] [added: 11,605] | | | | | |

| Peach Bottom | | | | | | Delta, PA | | | | | | 2 | | | | | | 50 | | | | | | Uranium | | | | | | Base-load | | | | | | 1,324 | | | [removed: (f)] | | |

| Salem | | | | | | Lower Alloways Creek Township, NJ | | | | | | 2 | | | | | | 42.59 | | | | | | Uranium | | | | | | Base-load | | | | | | [removed: 993] [added: 995] | | | [removed: (f)] | | |

| Conowingo | | | | | | Darlington, MD | | | | | | 11 | | | | | | | | | | | | Hydroelectric | | | | | | Base-load | | | | | | [removed: 572] [added: 497] | | | | | |

| Criterion | | | | | | Oakland, MD | | | | | | 28 | | | | | | 51 | | | [removed: (g)] [added: (f)] | | | Wind | | | | | | Intermittent | | | | | | 36 | | | [removed: (f)] | | |

| Fourmile Ridge | | | | | | Garrett County, MD | | | | | | 16 | | | | | | 51 | | | [removed: (g)] [added: (f)] | | | Wind | | | | | | Intermittent | | | | | | 20 | | | [removed: (f)] | | |

| Solar Horizons | | | | | | Emmitsburg, MD | | | | | | 1 | | | | | | 51 | | | [removed: (g)] [added: (f)] | | | Solar | | | | | | Intermittent | | | | | | 8 | | | [removed: (f)] | | |

| Solar New Jersey 3 | | | | | | Middle Township, NJ | | | | | | 5 | | | | | | 51 | | | [removed: (g)] [added: (f)] | | | Solar | | | | | | Intermittent | | | | | | 1 | | | [removed: (f)] | | |

| Muddy Run | | | | | | Drumore, PA | | | | | | 8 | | | | | | | | | | | | Hydroelectric | | | | | | Intermediate | | | | | | [removed: 1,070] [added: 1,058] | | | | | |

| Eddystone 3, 4 | | | | | | Eddystone, PA | | | | | | 2 | | | | | | | | | | | | Oil/Gas | | | | | | Peaking | | | | | | 760 | | | [added: (i)] | | |

| Philadelphia Road | | | | | | Baltimore, MD | | | | | | 4 | | | | | | | | | | | | Oil | | | | | | Peaking | | | | | | [removed: 61] [added: 60] | | | | | |

| Total Mid-Atlantic | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | [removed: 10,495] [added: 10,393] | | | | | |

| Whitetail | | | | | | Webb County, TX | | | | | | 57 | | | | | | 51 | | | [removed: (g)] [added: (f)] | | | Wind | | | | | | Intermittent | | | | | | 47 | | | [removed: (f)] | | |

| Sendero | | | | | | Jim Hogg and Zapata County, TX | | | | | | 39 | | | | | | 51 | | | [removed: (g)] [added: (f)] | | | Wind | | | | | | Intermittent | | | | | | 40 | | | [removed: (f)] | | |

| Colorado Bend II | | | | | | Wharton, TX | | | | | | 3 | | | | | | | | | | | | Gas | | | | | | Intermediate | | | | | | [removed: 1,143] [added: 1,138] | | | | | |

| Wolf Hollow II | | | | | | Granbury, TX | | | | | | 3 | | | | | | | | | | | | Gas | | | | | | Intermediate | | | | | | [removed: 1,115] [added: 1,103] | | | | | |

| Handley 3 | | | | | | Fort Worth, TX | | | | | | 1 | | | | | | | | | | | | Gas | | | | | | Intermediate | | | | | | [removed: 395] [added: 375] | | | | | |

| Total ERCOT | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | [removed: 3,610] [added: 4,734] | | | | | |

| Nine Mile Point | | | | | | Scriba, NY | | | | | | 2 | | | | | | | | | [removed: (i)] [added: (g)] | | | Uranium | | | | | | Base-load | | | | | | 1,675 | | | [removed: (f)] | | |

| Bluestem | | | | | | Beaver County, OK | | | | | | 60 | | | | | | 51 | | | [removed: (g)(j)] [added: (f)(h)] | | | Wind | | | | | | Intermittent | | | | | | 101 | | | [removed: (f)] | | |

| Shooting Star | | | | | | Kiowa County, KS | | | | | | 65 | | | | | | 51 | | | [removed: (g)] [added: (f)] | | | Wind | | | | | | Intermittent | | | | | | 53 | | | [removed: (f)] | | |

| Sacramento PV Energy | | | | | | Sacramento, CA | | | | | | 4 | | | | | | 51 | | | [removed: (g)] [added: (f)] | | | Solar | | | | | | Intermittent | | | | | | 15 | | | [removed: (f)] | | |

| Bluegrass Ridge | | | | | | King City, MO | | | | | | 27 | | | | | | 51 | | | [removed: (g)] [added: (f)] | | | Wind | | | | | | Intermittent | | | | | | 29 | | | [removed: (f)] | | |

| Conception | | | | | | Barnard, MO | | | | | | 24 | | | | | | 51 | | | [removed: (g)] [added: (f)] | | | Wind | | | | | | Intermittent | | | | | | 26 | | | [removed: (f)] | | |

| Cow Branch | | | | | | Rock Port, MO | | | | | | 24 | | | | | | 51 | | | [removed: (g)] [added: (f)] | | | Wind | | | | | | Intermittent | | | | | | 26 | | | [removed: (f)] | | |

| Mountain Home | | | | | | Glenns Ferry, ID | | | | | | 20 | | | | | | 51 | | | [removed: (g)] [added: (f)] | | | Wind | | | | | | Intermittent | | | | | | 21 | | | [removed: (f)] | | |

| High Mesa | | | | | | Elmore Co., ID | | | | | | 19 | | | | | | 51 | | | [removed: (g)] [added: (f)] | | | Wind | | | | | | Intermittent | | | | | | 20 | | | [removed: (f)] | | |

| Echo 1 | | | | | | Echo, OR | | | | | | 21 | | | | | | 50.49 | | | [removed: (g)] [added: (f)] | | | Wind | | | | | | Intermittent | | | | | | 17 | | | [removed: (f)] | | |

| Cassia | | | | | | Buhl, ID | | | | | | 13 | | | | | | 51 | | | [removed: (g)] [added: (f)] | | | Wind | | | | | | Intermittent | | | | | | 14 | | | [removed: (f)] | | |

| Wildcat | | | | | | Lovington, NM | | | | | | 13 | | | | | | 51 | | | [removed: (g)] [added: (f)] | | | Wind | | | | | | Intermittent | | | | | | 14 | | | [removed: (f)] | | |

| South Texas Project | | | | | | Bay City, TX | | | | | | 2 | | | | | | 44 | | | | | | Uranium | | | | | | Base-load | | | | | | 1,161 | | | | | |

| Total | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 33,094 | | | | | |

(i)Eddystone stations 3 and 4 will be retiring in June 2025.

| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

| CP Windfarm | | | | | | Faribault Co., MN | | | | | | 2 | | | | | | 51 | | | (g) | | | Wind | | | | | | Intermittent | | | | | | 2 | | | (f) | | |

| Southeast Chicago | | | | | | Chicago, IL | | | | | | 8 | | | | | | | | | | | | Gas | | | | | | Peaking | | | | | | 296 | | | (h) | | |

| Salem | | | | | | Lower Alloways Creek Township, NJ | | | | | | 1 | | | | | | 42.59 | | | | | | Oil | | | | | | Peaking | | | | | | 16 | | | (f) | | |

| Total | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 32,355 | | | | | |

(h)We have deactivated the site and are evaluating for potential return of service or retirement beyond 2023.

Not Applicable.

Not Applicable

As of January 31, [removed: 2023] [added: 2024] there were [removed: 327,131,082] [added: 316,666,538] shares of common stock outstanding and approximately [removed: 75,145] [added: 70,439] record holders of common stock.

The performance graph below illustrates a [removed: one-year] [added: two-year] comparison of cumulative total returns based on an initial investment of $100 in CEG Parent common stock, as compared with the S&P 500 Stock Index and the Philadelphia Utility Sector Index, or UTY, for the [removed: year 2022.][added: period 2022 through 2023.]

[removed: ][added: ]

| Value of [removed: Investment in 2022] [added: Investment] | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | [added: | | |]

| CEG | | | $100 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $175 | | | [added: $240 | | |]

| S&P 500 | | | $100 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $86 | | | [added: $108 | | |]

| UTY | | | $100 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $107 | | | [added: $96 | | |]

As of January 31, [removed: 2023,] [added: 2024,] CEG Parent directly held the entire membership interest in Constellation.

Our Board of Directors approved an updated dividend policy for [removed: 2023.][added: 2024.]

The [removed: 2023] [added: 2024] quarterly dividend will be [removed: $0.2820] [added: $0.3525] per share.

The following table sets forth Constellation’s quarterly cash dividends per share paid during [added: 2023 and] 2022.

| Fourth Quarter | | | | | | Third Quarter | | | | | | Second Quarter | | | | | | First Quarter | | | [added: | | | Fourth Quarter | | | | | | Third Quarter | | | | | | Second Quarter | | | | | | First Quarter | | |]

| $ | [added: 0.2820 | | | | | $ | 0.2820 | | | | | $ | 0.2820 | | | | | $ | 0.2820 | | | | | $ |] 0.1410 | | | | | $ | 0.1410 | | | | | $ | 0.1410 | | | | | $ | 0.1410 | |

First Quarter [removed: 2023] [added: 2024] Dividend

On February [removed: 15, 2023,] [added: 26, 2024,] our Board of Directors declared a regular quarterly dividend of [removed: $0.2820] [added: $0.3525] per share on our common stock for the first quarter of [removed: 2023.][added: 2024.]

The dividend is payable on [removed: Friday,] [added: Tuesday,] March [removed: 10, 2023,] [added: 19, 2024,] to shareholders of record as of 5 p.m.

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| | | | 2/1/22 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 12/31/22 | | | 12/31/23 | | |

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Eastern time on Friday, March 8, 2024.

Our Board of Directors considers share buybacks to be one of several ways we can provide value to our shareholders through our deployment of capital.

The first is to maintain strong investment grade metrics in addition to the pursuit of organic and inorganic growth consistent with our role as a leader in the clean energy transition.

Our deployment of capital can also include the repurchase of shares if they can be acquired at attractive prices and increases to our dividend, which currently targets a 10% annual growth rate.

We take into account the excise taxes imposed and other administrative costs when assessing our repurchase program.

We believe that our share buyback policy is in the best interests of our company and its shareholders and is also consistent with the interests of our other stakeholders.

On February 16, 2023, as part of our capital allocation plan, our Board of Directors announced a share repurchase program with a $1 billion authority without expiration.

Repurchases under this program commenced in March 2023.

Shares repurchased were made through open market transactions and purchases pursuant to a Rule 10b5-1 trading plan.

All repurchased shares were constructively retired and cancelled.

On December 12, 2023, our Board of Directors approved an increase to our previously announced $1 billion share repurchase program, authorizing the repurchase of up to an additional $1 billion of the Company’s outstanding common stock.

On November 9, 2023, we entered into a stock purchase plan for the purchase of shares of our common stock (November 2023 Stock Purchase Plan), designed to comply with Rule 10b5-1 under the Exchange Act.

Under its terms, the November 2023 Stock Purchase Plan would expire at the later of the completion of the maximum purchase amount of $250 million of shares of our common stock, or December 31, 2023.

During 2023, we repurchased from the open market approximately 10.6 million shares of our common stock for a total cost, inclusive of taxes and transaction costs, of $1 billion.

As of December 31, 2023, there was $1 billion of remaining authority to repurchase shares.

The following table provides information regarding our share repurchases under the program during the three months ended December 31, 2023.

All repurchases disclosed were made pursuant to the November 2023 Stock Purchase Plan:

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| Period | | | Total Number of Shares Purchased(a) | | | | | | Average Price Paid per Share(b) | | | | | | Approximate Dollar Value of Shares that May Yet Be Purchased Under the Programs(c) | | |

| October 1, 2023 to October 31, 2023 | | | — | | | | | | $ | — | | | | | $ | 244,000,000 | |

| November 1, 2023 to November 30, 2023 | | | 993,800 | | | | | | $ | 122.84 | | | | | $ | 121,000,000 | |

| December 1, 2023 to December 31, 2023(d) | | | 1,031,569 | | | | | | $ | 115.75 | | | | | $ | 1,000,000,000 | |

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| | | | 2/1 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 12/31 | | |

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Eastern time on Monday, February 27, 2023.

None.

Not Applicable.

Not Applicable

CEG Parent’s management assessed the effectiveness of CEG Parent’s internal control over financial reporting as of December 31, [removed: 2022.][added: 2023.]

Based on this assessment, CEG Parent’s management concluded that, as of December 31, [removed: 2022,] [added: 2023,] CEG Parent’s internal control over financial reporting was effective.

The effectiveness of CEG Parent’s internal control over financial reporting as of December 31, [removed: 2022,] [added: 2023,] has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.

Constellation’s management assessed the effectiveness of Constellation’s internal control over financial reporting as of December 31, [removed: 2022.][added: 2023.]

Based on this assessment, Constellation’s management concluded that, as of December 31, [removed: 2022,] [added: 2023,] Constellation’s internal control over financial reporting was effective.

We also have audited the Company's internal control over financial reporting as of December 31, [removed: 2022,] [added: 2023,] based on criteria established in [removed: *Internal] [added: Internal] Control - Integrated [removed: Framework*] [added: Framework] (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, [removed: 2022] [added: 2023] and [removed: 2021,] [added: 2022,] and the results of its operations and its cash flows for each of the three years in the period ended December 31, [removed: 2022] [added: 2023] in conformity with accounting principles generally accepted in the United States of America.

Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, [removed: 2022,] [added: 2023,] based on criteria established in *Internal Control - Integrated [removed: Framework* (2013)] [added: Framework (2013)*] issued by the COSO.

To estimate its decommissioning obligations management uses a [removed: probability-weighted,] [added: probability- weighted,] discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models, and discount rates.

As of December 31, [removed: 2022,] [added: 2023,] the nuclear decommissioning ARO was [removed: $12.5] [added: $13.9] billion.

The principal considerations for our determination that performing procedures relating to the Company’s nuclear decommissioning ARO assessment is a critical audit matter are [added: (i)] the significant judgment by management when estimating its decommissioning obligations; [removed: this in turn led to] [added: (ii)] a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating the reasonableness of management’s discounted cash flow model and significant assumptions related to decommissioning cost [removed: studies.][added: studies; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.]

These procedures also included, among [removed: others,] [added: others (i)] testing management’s process for estimating the decommissioning obligations by evaluating the appropriateness of the discounted cash flow [removed: model,] [added: model; (ii)] testing the completeness and accuracy of data used by [removed: management,] [added: management;] and [added: (iii)] evaluating the reasonableness of management’s significant assumptions related to decommissioning cost studies.

In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, [removed: 2022] [added: 2023] and [removed: 2021,] [added: 2022,] and the results of its operations and its cash flows for each of the three years in the period ended December 31, [removed: 2022] [added: 2023] in conformity with accounting principles generally accepted in the United States of America.

The principal considerations for our determination that performing procedures relating to the Company’s nuclear decommissioning ARO assessment is a critical audit matter are [added: (i)] the significant judgment by management when [added: estimating its decommissioning obligations; (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating the reasonableness of management’s discounted cash flow model and significant assumptions related to decommissioning cost studies; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.]

[added: These procedures also included, among others; (i) testing management’s process for] estimating [removed: its] [added: the] decommissioning [removed: obligations; this in turn led to a high degree] [added: obligations by evaluating the appropriateness] of [removed: auditor judgment, subjectivity,] [added: the discounted cash flow model; (ii) testing the completeness] and [removed: effort in performing procedures] [added: accuracy of data used by management;] and [added: (iii)] evaluating the reasonableness of management’s [removed: discounted cash flow model and] significant assumptions related to decommissioning cost studies.

| (In millions, except per share data) | | | [removed: 2022] [added: 2023] | | | | | | [removed: 2021] [added: 2022] | | | | | | [removed: 2020] [added: 2021] | | |

| Operating revenues | | | $ | [removed: 24,280] [added: 24,918] | | | | | $ | [removed: 18,461] [added: 24,280] | | | | | $ | [removed: 16,392] [added: 18,461] | |

| Operating revenues from affiliates | | | [removed: 160] [added: —] | | | | | | [removed: 1,188] [added: 160] | | | | | | [removed: 1,211] [added: 1,188] | | |

| Total operating revenues | | | [removed: 24,440] [added: 24,918] | | | | | | [removed: 19,649] [added: 24,440] | | | | | | [removed: 17,603] [added: 19,649] | | |

| Purchased power and fuel | | | [removed: 17,457] [added: 16,001] | | | | | | [removed: 12,157] [added: 17,457] | | | | | | [removed: 9,592] [added: 12,157] | | |

| Purchased power and fuel from affiliates | | | [removed: 5] [added: —] | | | | | | [removed: 6] [added: 5] | | | | | | [removed: (7)] [added: 6] | | |

| Operating and maintenance | | | [removed: 4,797] [added: 5,685] | | | | | | [removed: 3,934] [added: 4,797] | | | | | | [removed: 4,613] [added: 3,934] | | |

| Operating and maintenance from affiliates | | | [removed: 44] [added: —] | | | | | | [removed: 621] [added: 44] | | | | | | [removed: 555] [added: 621] | | |

| Depreciation and amortization | | | [removed: 1,091] [added: 1,096] | | | | | | [removed: 3,003] [added: 1,091] | | | | | | [removed: 2,123] [added: 3,003] | | |

| Taxes other than income taxes | | | [removed: 552] [added: 553] | | | | | | [removed: 475] [added: 552] | | | | | | [removed: 482] [added: 475] | | |

| Total operating expenses | | | [removed: 23,946] [added: 23,335] | | | | | | [removed: 20,196] [added: 23,946] | | | | | | [removed: 17,358] [added: 20,196] | | |

| Gain [added: (loss)] on sales of assets and businesses | | | [removed: 1] [added: 27] | | | | | | [removed: 201] [added: 1] | | | | | | [removed: 11] [added: 201] | | |

| Operating income (loss) | | | [removed: 495] [added: 1,610] | | | | | | [removed: (346)] [added: 495] | | | | | | [removed: 256] [added: (346)] | | |

| Interest expense, net | | | [removed: (250)] [added: (431)] | | | | | | [removed: (282)] [added: (250)] | | | | | | [removed: (328)] [added: (282)] | | |

| Interest expense to affiliates | | | [removed: (1)] [added: —] | | | | | | [removed: (15)] [added: (1)] | | | | | | [removed: (29)] [added: (15)] | | |

| Other, net | | | [removed: (786)] [added: 1,268] | | | | | | [removed: 795] [added: (786)] | | | | | | [removed: 937] [added: 795] | | |

| Total other income and (deductions) | | | [removed: (1,037)] [added: 837] | | | | | | [removed: 498] [added: (1,037)] | | | | | | [removed: 580] [added: 498] | | |

| [removed: (Loss) income] [added: Income (loss)] before income taxes | | | [removed: (542)] [added: 2,447] | | | | | | [removed: 152] [added: (542)] | | | | | | [removed: 836] [added: 152] | | |

| Equity in [removed: losses] [added: income (losses)] of unconsolidated affiliates | | | [removed: (13)] [added: (11)] | | | | | | [removed: (10)] [added: (13)] | | | | | | [removed: (8)] [added: (10)] | | |

| Net [removed: (loss) income] [added: income (loss)] | | | [removed: (167)] [added: 1,577] | | | | | | [removed: (83)] [added: (167)] | | | | | | [removed: 579] [added: (83)] | | |

| Net [removed: (loss)] income [added: (loss)] attributable to noncontrolling interests | | | [removed: (7)] [added: (46)] | | | | | | [removed: 122] [added: (7)] | | | | | | [removed: (10)] [added: 122] | | |

| Net [removed: (loss)] income [added: (loss)] attributable to common shareholders | | | $ | [removed: (160)] [added: 1,623] | | | | | $ | [removed: (205)] [added: (160)] | | | | | $ | [removed: 589] [added: (205)] | |

| Net [removed: (loss)] income [added: (loss)] | | | $ | [removed: (167)] [added: 1,577] | | | | | $ | [removed: (83)] [added: (167)] | | | | | $ | [removed: 579] [added: (83)] | |

| Prior service benefit reclassified to periodic benefit cost | | | [removed: (6)] [added: (4)] | | | | | | [removed: —] [added: (6)] | | | | | | — | | |

| Actuarial loss reclassified to periodic cost | | | [removed: 101] [added: 25] | | | | | | [removed: —] [added: 101] | | | | | | — | | |

February 27, 2024

February 27, 2024

To estimate its decommissioning obligations management uses a probability- weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models, and discount rates.

As of December 31, 2023, the nuclear decommissioning ARO was $13.9 billion.

February 27, 2024

| Income tax (benefit) expense | | | 859 | | | | | | (388) | | | | | | 225 | | |

| Acquisitions of assets and businesses | | | (1,690) | | | | | | (29) | | | | | | (30) | | |

| Repurchases of common stock | | | (992) | | | | | | — | | | | | | — | | |

| (In millions) | | | 2023 | | | | | | 2022 | | |

| Goodwill | | | 425 | | | | | | 47 | | |

| Other | | | 1,910 | | | | | | 2,059 | | |

| (In millions) | | | 2023 | | | | | | 2022 | | |

| Accounts payable and accrued expenses | | | 2,612 | | | | | | 3,734 | | |

| Employee incentive plans | | | 902 | | | | | | 81 | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | 81 | | |

| Common stock dividends ($0.2820/common share) | | | — | | | | | | — | | | | | | (366) | | | | | | — | | | | | | — | | | | | | — | | | | | | (366) | | |

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| Common stock repurchased | | | (10,560) | | | | | | (1,000) | | | | | | — | | | | | | — | | | | | | — | | | | | | — | | | | | | (1,000) | | |

| Balance, December 31, 2023 | | | 317,472 | | | | | | $ | 12,355 | | | | | $ | 761 | | | | | $ | (2,191) | | | | | $ | 361 | | | | | $ | — | | | | | $ | 11,286 | |

| Operating revenues | | | $ | 24,918 | | | | | $ | 24,280 | | | | | $ | 18,461 | |