Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Management’s Report on Internal Control Over Financial Reporting

The management of Constellation Energy Corporation (CEG Parent) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

CEG Parent’s management assessed the effectiveness of CEG Parent’s internal control over financial reporting as of December 31, 2023. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, CEG Parent’s management concluded that, as of December 31, 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, 2023, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.

February 27, 2024

Management’s Report on Internal Control Over Financial Reporting

The management of Constellation Energy Generation, LLC (Constellation) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

Constellation’s management assessed the effectiveness of Constellation’s internal control over financial reporting as of December 31, 2023. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, Constellation’s management concluded that, as of December 31, 2023, Constellation’s internal control over financial reporting was effective.

February 27, 2024

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of Constellation Energy Corporation

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(1)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(1)(ii), of Constellation Energy Corporation and its subsidiaries (the “Company”) (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control - Integrated 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, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 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, 2023, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.

Basis for Opinions

The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 8. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Critical Audit Matters

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Nuclear Decommissioning Asset Retirement Obligations (ARO) Assessment

As described in Notes 1 and 10 to the consolidated financial statements, the Company has a legal obligation to decommission its nuclear power plants following the permanent cessation of operations. 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. Management updates its ARO annually, unless circumstances warrant more frequent updates, based on its review of updated cost studies and its annual evaluation of cost escalation factors and probabilities assigned to various scenarios. As of December 31, 2023, the nuclear decommissioning ARO was $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 (i) the significant judgment by management when 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.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s development of the inputs, assumptions, and discounted cash flow model used in management’s ARO assessment. These procedures also included, among others (i) testing management’s process for estimating the decommissioning obligations by evaluating the appropriateness of the discounted cash flow model; (ii) testing the completeness and accuracy of data used by management; and (iii) evaluating the reasonableness of management’s significant assumptions related to decommissioning cost studies. Professionals with specialized skill and knowledge were used to assist in evaluating the results of decommissioning cost studies.

/s/ PricewaterhouseCoopers LLP

Baltimore, Maryland

February 27, 2024

We have served as the Company's auditor since 2022.

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Member of Constellation Energy Generation, LLC

Opinion on the Financial Statements

We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(2)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(2)(ii), of Constellation Energy Generation, LLC and its subsidiaries (the “Company”) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023 in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

Nuclear Decommissioning Asset Retirement Obligations (ARO) Assessment

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s development of the inputs, assumptions, and discounted cash flow model used in management’s ARO assessment. These procedures also included, among others; (i) testing management’s process for estimating the decommissioning obligations by evaluating the appropriateness of the discounted cash flow model; (ii) testing the completeness and accuracy of data used by management; and (iii) evaluating the reasonableness of management’s significant assumptions related to decommissioning cost studies. Professionals with specialized skill and knowledge were used to assist in evaluating the results of decommissioning cost studies.

/s/ PricewaterhouseCoopers LLP

Baltimore, Maryland

February 27, 2024

We have served as the Company's auditor since 2001.

Constellation Energy Corporation and Subsidiary Companies

Consolidated Statements of Operations and Comprehensive Income


	For the Years Ended December 31,
(In millions, except per share data)	2023		2022		2021
Operating revenues
Operating revenues	$	24,918	$	24,280	$	18,461
Operating revenues from affiliates	—		160		1,188
Total operating revenues	24,918		24,440		19,649
Operating expenses
Purchased power and fuel	16,001		17,457		12,157
Purchased power and fuel from affiliates	—		5		6
Operating and maintenance	5,685		4,797		3,934
Operating and maintenance from affiliates	—		44		621
Depreciation and amortization	1,096		1,091		3,003
Taxes other than income taxes	553		552		475
Total operating expenses	23,335		23,946		20,196
Gain (loss) on sales of assets and businesses	27		1		201
Operating income (loss)	1,610		495		(346)
Other income and (deductions)
Interest expense, net	(431)		(250)		(282)
Interest expense to affiliates	—		(1)		(15)
Other, net	1,268		(786)		795
Total other income and (deductions)	837		(1,037)		498
Income (loss) before income taxes	2,447		(542)		152
Income tax (benefit) expense	859		(388)		225
Equity in income (losses) of unconsolidated affiliates	(11)		(13)		(10)
Net income (loss)	1,577		(167)		(83)
Net income (loss) attributable to noncontrolling interests	(46)		(7)		122
Net income (loss) attributable to common shareholders	$	1,623	$	(160)	$	(205)
Comprehensive income (loss), net of income taxes
Net income (loss)	$	1,577	$	(167)	$	(83)
Other comprehensive income (loss), net of income taxes
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	(4)		(6)		—
Actuarial loss reclassified to periodic cost	25		101		—
Pension and non-pension postretirement benefit plans valuation adjustment	(453)		186		—
Unrealized gain (loss) on cash flow hedges	(1)		(1)		(1)

Unrealized gain (loss) on foreign currency translation	2		(3)		—
Other comprehensive income (loss), net of income taxes	(431)		277		(1)
Comprehensive income (loss)	$	1,146	$	110	$	(84)
Comprehensive income (loss) attributable to noncontrolling interests	(46)		(7)		122
Comprehensive income (loss) attributable to common shareholders	$	1,192	$	117	$	(206)

Average shares of common stock outstanding:
Basic	323		328		—
Assumed exercise and/or distributions of stock-based awards	1		1		—
Diluted	324		329		—

Earnings per average common share
Basic	$	5.02	$	(0.49)	$	—
Diluted	$	5.01	$	(0.49)	$	—

Constellation Energy Corporation and Subsidiary Companies

Consolidated Statements of Cash Flows


	For the Years Ended December 31,
(In millions)	2023		2022		2021
Cash flows from operating activities
Net income (loss)	$	1,577	$	(167)	$	(83)
Adjustments to reconcile net income (loss) to net cash flows provided by (used in) operating activities
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization	2,514		2,427		4,540



Deferred income taxes and amortization of ITC	251		(643)		(205)
Net fair value changes related to derivatives	996		986		(568)
Net realized and unrealized (gains) losses on NDT funds	(476)		794		(586)
Net realized and unrealized (gains) losses on equity investments	(307)		13		160
Other non-cash operating activities	18		248		(261)
Changes in assets and liabilities:
Accounts receivable	396		(868)		(616)
Receivables from and payables to affiliates, net	—		20		14
Inventories	60		(228)		(68)
Accounts payable and accrued expenses	(1,330)		1,142		346
Option premiums received (paid), net	26		(177)		(338)
Collateral received (posted), net	(1,491)		(351)		(130)
Income taxes	325		162		256
Pension and non-pension postretirement benefit contributions	(54)		(237)		(259)
Other assets and liabilities	(7,806)		(5,474)		(3,540)
Net cash flows provided by (used in) operating activities	(5,301)		(2,353)		(1,338)
Cash flows from investing activities
Capital expenditures	(2,422)		(1,689)		(1,329)
Proceeds from NDT fund sales	5,822		4,050		6,532
Investment in NDT funds	(6,050)		(4,271)		(6,673)
Collection of DPP, net	7,340		4,964		3,902

Proceeds from sales of assets and businesses	24		52		878
Acquisitions of assets and businesses	(1,690)		(29)		(30)
Other investing activities	7		27		2
Net cash flows provided by (used in) investing activities	3,031		3,104		3,282
Cash flows from financing activities
Change in short-term borrowings	146		257		362
Proceeds from short-term borrowings with maturities greater than 90 days	539		—		880
Repayments of short-term borrowings with maturities greater than 90 days	(200)		(1,180)		—
Issuance of long-term debt	3,195		14		152
Retirement of long-term debt	(168)		(1,162)		(105)

Retirement of long-term debt to affiliate	—		(258)		—
Change in money pool with Exelon	—		—		(285)
Acquisition of CENG noncontrolling interest	—		—		(885)
Distributions to Exelon	—		—		(1,832)
Contributions from Exelon	—		1,750		64
Dividends paid on common stock	(366)		(185)		—




Repurchases of common stock	(992)		—		—
Other financing activities	42		(35)		(46)
Net cash flows provided by (used in) financing activities	2,196		(799)		(1,695)
Increase (decrease) in cash, restricted cash, and cash equivalents	(74)		(48)		249
Cash, restricted cash, and cash equivalents at beginning of period	528		576		327
Cash, restricted cash, and cash equivalents at end of period	$	454	$	528	$	576

Supplemental cash flow information
Increase (decrease) in capital expenditures not paid	$	16	$	(23)	$	96
Increase (decrease) in DPP	8,097		5,166		3,652
Increase (decrease) in PP&E related to ARO update	501		343		618

See the Combined Notes to Consolidated Financial Statements

Constellation Energy Corporation and Subsidiary Companies

Consolidated Balance Sheets


	December 31,
(In millions)	2023		2022
ASSETS
Current assets
Cash and cash equivalents	$	368	$	422
Restricted cash and cash equivalents	86		106
Accounts receivable
Customer accounts receivable (net of allowance for credit losses of $56 and $46 as of December 31, 2023 and 2022, respectively)	1,934		2,585


Other accounts receivable (net of allowance for credit losses of $5 as of December 31, 2023 and 2022)	917		731


Mark-to-market derivative assets	1,179		2,368



Inventories, net
Natural gas, oil, and emission allowances	284		429
Materials and supplies	1,216		1,076


Renewable energy credits	660		617

Other	1,655		1,026
Total current assets	8,299		9,360
Property, plant, and equipment (net of accumulated depreciation and amortization of $17,423 and $16,726 as of December 31, 2023 and 2022, respectively)	22,116		19,822
Deferred debits and other assets

Nuclear decommissioning trust funds	16,398		14,114
Investments	563		202
Goodwill	425		47
Mark-to-market derivative assets	995		1,261




Deferred income taxes	52		44
Other	1,910		2,059
Total deferred debits and other assets	20,343		17,727
Total assets(a)	$	50,758	$	46,909

See the Combined Notes to Consolidated Financial Statements

Constellation Energy Corporation and Subsidiary Companies

Consolidated Balance Sheets


	December 31,
(In millions)	2023		2022
LIABILITIES AND EQUITY
Current liabilities
Short-term borrowings	$	1,644	$	1,159
Long-term debt due within one year	121		143

Accounts payable and accrued expenses	2,612		3,734



Mark-to-market derivative liabilities	632		1,558

Renewable energy credit obligation	972		901

Other	338		344
Total current liabilities	6,319		7,839
Long-term debt	7,496		4,466


Deferred credits and other liabilities
Deferred income taxes and unamortized ITCs	3,209		3,031
Asset retirement obligations	14,118		12,699
Pension obligations	1,070		605
Non-pension postretirement benefit obligations	732		609
Spent nuclear fuel obligation	1,296		1,230



Payables related to Regulatory Agreement Units	3,688		2,897
Mark-to-market derivative liabilities	419		983


Other	1,125		1,178
Total deferred credits and other liabilities	25,657		23,232
Total liabilities(a)	39,472		35,537
Commitments and contingencies (Note 19)

Shareholders' equity

Common stock (No par value, 1,000 shares authorized, 317 shares and 327 shares outstanding as of December 31, 2023 and 2022, respectively)	12,355		13,274
Retained earnings (deficit)	761		(496)
Accumulated other comprehensive income (loss), net	(2,191)		(1,760)
Total shareholders' equity	10,925		11,018
Noncontrolling interests	361		354
Total equity	11,286		11,372
Total liabilities and shareholders' equity	$	50,758	$	46,909

(a)Our consolidated assets include $3,355 million and $2,641 million at December 31, 2023 and 2022, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Our consolidated liabilities include $990 million and $1,041 million at December 31, 2023 and 2022, respectively, of certain VIEs for which the VIE creditors do not have recourse to us. See Note 22–Variable Interest Entities for additional information.

See the Combined Notes to Consolidated Financial Statements

Constellation Energy Corporation and Subsidiary Companies

Consolidated Statements of Changes in Equity


	Shareholder's Equity							Noncontrolling Interests		Predecessor Member's Equity (a)		Total Equity
(In millions, shares in thousands)	Issued Shares	Common Stock		Retained Earnings (Deficit)		Accumulated Other Comprehensive Income (Loss), net
Balance, December 31, 2020	—	$	—	$	—	$	(30)	$	2,277	$	12,429	$	14,676
Net income (loss)	—	—		—		—		122		(205)		(83)

Changes in equity of noncontrolling interest	—	—		—		—		(37)		—		(37)
Acquisition of CENG noncontrolling Interest	—	—		—		—		(1,965)		1,080		(885)
Deferred tax adjustment related to acquisition of CENG noncontrolling interest	—	—		—		—		—		(288)		(288)
Distribution to member	—	—		—		—		—		(1,832)		(1,832)
Contributions from member	—	—		—		—		—		64		64
Acquisition of noncontrolling interest	—	—		—		—		(2)		2		—
Other comprehensive income (loss), net of income taxes	—	—		—		(1)		—		—		(1)
Balance, December 31, 2021	—	$	—	$	—	$	(31)	$	395	$	11,250	$	11,614
Net income from January 1, 2022 to January 31, 2022	—	—		—		—		—		151		151
Separation-related adjustments	—	—		—		(2,006)		7		1,802		(197)
Changes in equity of noncontrolling interests from January 1, 2022 to January 31, 2022	—	—		—		—		(7)		—		(7)
Consummation of separation	326,664	13,203		—		—		—		(13,203)		—
Net loss from February 1, 2022 to December 31, 2022	—	—		(311)		—		(7)		—		(318)
Employee incentive plans	466	71		—		—		—		—		71
Changes in equity of noncontrolling interest	—	—		—		—		(34)		—		(34)
Common stock dividends (0.1410/common share)	—	—		(185)		—		—		—		(185)


Other comprehensive income (loss) , net of income taxes	—	—		—		277		—		—		277
Balance, December 31, 2022	327,130	$	13,274	$	(496)	$	(1,760)	$	354	$	—	$	11,372
Net income (loss)	—	—		1,623		—		(46)		—		1,577
Employee incentive plans	902	81		—		—		—		—		81
Changes in equity of noncontrolling interest	—	—		—		—		53		—		53
Common stock dividends ($0.2820/common share)	—	—		(366)		—		—		—		(366)


Common stock repurchased	(10,560)	(1,000)		—		—		—		—		(1,000)
Other comprehensive income (loss) , net of income taxes	—	—		—		(431)		—		—		(431)
Balance, December 31, 2023	317,472	$	12,355	$	761	$	(2,191)	$	361	$	—	$	11,286

(a)Represents Constellation’s predecessor member's equity prior to the separation transaction. Upon completion of the separation, the predecessor member's equity was transferred to CEG Parent’s Common stock. See Note 1 — Basis of Presentation for additional information on the separation.

See the Combined Notes to Consolidated Financial Statements

Constellation Energy Generation, LLC and Subsidiary Companies

Consolidated Statements of Operations and Comprehensive Income


	For the Years Ended December 31,
(In millions)	2023		2022		2021
Operating revenues
Operating revenues	$	24,918	$	24,280	$	18,461
Operating revenues from affiliates	—		160		1,188
Total operating revenues	24,918		24,440		19,649
Operating expenses
Purchased power and fuel	16,001		17,457		12,157
Purchased power and fuel from affiliates	—		5		6
Operating and maintenance	5,685		4,797		3,934
Operating and maintenance from affiliates	—		44		621
Depreciation and amortization	1,096		1,091		3,003
Taxes other than income taxes	553		552		475
Total operating expenses	23,335		23,946		20,196
Gain (loss) on sales of assets and businesses	27		1		201
Operating income (loss)	1,610		495		(346)
Other income and (deductions)
Interest expense, net	(431)		(250)		(282)
Interest expense to affiliates	—		(1)		(15)
Other, net	1,268		(786)		795
Total other income and (deductions)	837		(1,037)		498
Income (loss) before income taxes	2,447		(542)		152
Income tax (benefit) expense	859		(388)		225
Equity in income (losses) of unconsolidated affiliates	(11)		(13)		(10)
Net income (loss)	1,577		(167)		(83)
Net income (loss) attributable to noncontrolling interests	(46)		(7)		122
Net income (loss) attributable to membership interest	$	1,623	$	(160)	$	(205)
Comprehensive income (loss), net of income taxes
Net income (loss)	$	1,577	$	(167)	$	(83)
Other comprehensive income (loss), net of income taxes
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	(4)		(6)		—
Actuarial loss reclassified to periodic benefit cost	25		101		—
Pension and non-pension postretirement benefit plans valuation adjustment	(453)		186		—
Unrealized gain (loss) on cash flow hedges	(1)		(1)		(1)

Unrealized gain (loss) on foreign currency translation	2		(3)		—


Other comprehensive income (loss), net of income taxes	(431)		277		(1)
Comprehensive income (loss)	1,146		110		(84)
Comprehensive income (loss) attributable to noncontrolling interests	(46)		(7)		122
Comprehensive income (loss) attributable to membership interest	$	1,192	$	117	$	(206)

See the Combined Notes to Consolidated Financial Statements

Constellation Energy Generation, LLC and Subsidiary Companies

Consolidated Statements of Cash Flows


	For the Years Ended December 31,
(In millions)	2023		2022		2021
Cash flows from operating activities
Net income (loss)	$	1,577	$	(167)	$	(83)
Adjustments to reconcile net income (loss) to net cash flows provided by (used in) operating activities
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization	2,514		2,427		4,540



Deferred income taxes and amortization of ITCs	251		(643)		(205)
Net fair value changes related to derivatives	996		986		(568)
Net realized and unrealized (gains) losses on NDT funds	(476)		794		(586)
Net realized and unrealized (gains) losses on equity investments	(307)		13		160
Other non-cash operating activities	(44)		199		(261)
Changes in assets and liabilities:
Accounts receivable	389		(855)		(616)
Receivables from and payables to affiliates, net	73		65		14
Inventories	60		(228)		(68)
Accounts payable and accrued expenses	(1,330)		1,112		346
Option premiums received (paid), net	26		(177)		(338)
Collateral received (posted), net	(1,491)		(351)		(130)
Income taxes	325		162		256
Pension and non-pension postretirement benefit contributions	(54)		(237)		(259)
Other assets and liabilities	(7,897)		(5,540)		(3,540)
Net cash flows provided by (used in) operating activities	(5,388)		(2,440)		(1,338)
Cash flows from investing activities
Capital expenditures	(2,422)		(1,689)		(1,329)
Proceeds from NDT fund sales	5,822		4,050		6,532
Investment in NDT funds	(6,050)		(4,271)		(6,673)
Collection of DPP, net	7,340		4,964		3,902

Proceeds from sales of assets and businesses	24		52		878
Acquisitions of assets and businesses	(1,690)		(29)		(30)



Other investing activities	7		27		2
Net cash flows provided by (used in) investing activities	3,031		3,104		3,282
Cash flows from financing activities
Change in short-term borrowings	146		257		362
Proceeds from short-term borrowings with maturities greater than 90 days	539		—		880
Repayments of short-term borrowings with maturities greater than 90 days	(200)		(1,180)		—
Issuance of long-term debt	3,195		14		152
Retirement of long-term debt	(168)		(1,162)		(105)

Retirement of long-term debt to affiliate	—		(258)		—
Change in money pool with Exelon	—		—		(285)
Acquisition of CENG noncontrolling interest	—		—		(885)
Distributions to Exelon	—		—		(1,832)
Distributions to member	(1,239)		(185)		—


Contributions from Exelon	—		1,750		64
Contributions from member	—		82		—


Other financing activities	23		(57)		(46)
Net cash flows provided by (used in) financing activities	2,296		(739)		(1,695)
Increase (decrease) in cash, restricted cash, and cash equivalents	(61)		(75)		249
Cash, restricted cash, and cash equivalents at beginning of period	501		576		327
Cash, restricted cash, and cash equivalents at end of period	$	440	$	501	$	576

Supplemental cash flow information
Increase (decrease) in capital expenditures not paid	$	16	$	(23)	$	96
Increase (decrease) in DPP	8,097		5,166		3,652
Increase (decrease) in PP&E related to ARO update	501		343		618

See the Combined Notes to Consolidated Financial Statements

Constellation Energy Generation, LLC and Subsidiary Companies

Consolidated Balance Sheets


	December 31,
(In millions)	2023		2022
ASSETS
Current assets
Cash and cash equivalents	$	366	403
Restricted cash and cash equivalents	74		98
Accounts receivable
Customer accounts receivable (net of allowance for credit losses of $56 and $46 as of December 31, 2023 and 2022, respectively)	1,934		2,585


Other accounts receivable (net of allowance for credit losses of $5 as of December 31, 2023 and 2022)	911		718


Mark-to-market derivative assets	1,179		2,368



Inventories, net
Natural gas, oil, and emission allowance	284		429
Materials and supplies	1,216		1,076



Renewable energy credits	660		617
Other	1,655		1,026
Total current assets	8,279		9,320
Property, plant, and equipment (net of accumulated depreciation and amortization of $17,423 and $16,726 as of December 31, 2023 and 2022, respectively)	22,116		19,822
Deferred debits and other assets

Nuclear decommissioning trust funds	16,398		14,114
Investments	563		202
Goodwill	425		47
Mark-to-market derivative assets	995		1,261




Deferred income taxes	52		44
Other	1,910		2,059
Total deferred debits and other assets	20,343		17,727
Total assets(a)	$	50,738	$	46,869

See the Combined Notes to Consolidated Financial Statements

Constellation Energy Generation, LLC and Subsidiary Companies

Consolidated Balance Sheets


	December 31,
(In millions)	2023		2022
LIABILITIES AND EQUITY
Current liabilities
Short-term borrowings	$	1,644	$	1,159
Long-term debt due within one year	121		143

Accounts payable and accrued expenses	2,486		3,679
Payables to affiliates	118		45



Mark-to-market derivative liabilities	632		1,558

Renewable energy credit obligation	972		901

Other	338		344
Total current liabilities	6,311		7,829
Long-term debt	7,496		4,466


Deferred credits and other liabilities
Deferred income taxes and unamortized ITCs	3,209		3,031
Asset retirement obligations	14,118		12,699
Pension obligations	1,070		605
Non-pension postretirement benefit obligations	732		609
Spent nuclear fuel obligation	1,296		1,230


Payables related to Regulatory Agreement Units	3,688		2,897
Mark-to-market derivative liabilities	419		983


Other	1,025		1,106
Total deferred credits and other liabilities	25,557		23,160
Total liabilities(a)	39,364		35,455
Commitments and contingencies (Note 19)

Equity
Member’s equity
Membership interest	11,537		12,408
Undistributed earnings	1,667		412
Accumulated other comprehensive income (loss), net	(2,191)		(1,760)
Total member’s equity	11,013		11,060
Noncontrolling interests	361		354
Total equity	11,374		11,414
Total liabilities and equity	$	50,738	$	46,869

(a)Our consolidated assets include $3,355 million and $2,641 million as of December 31, 2023 and 2022, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Our consolidated liabilities include $990 million and $1,041 million as of December 31, 2023 and 2022, respectively, of certain VIEs for which the VIE creditors do not have recourse to us. See Note 22–Variable Interest Entities for additional information.

See the Combined Notes to Consolidated Financial Statements

Constellation Energy Generation, LLC and Subsidiary Companies

Consolidated Statements of Changes in Equity


	Member’s Equity						Noncontrolling Interests		Total Equity
(In millions)	Membership Interest		Undistributed Earnings		Accumulated Other Comprehensive Income (Loss), net
Balance, December 31, 2020	$	9,624	$	2,805	$	(30)	$	2,277	$	14,676
Net (loss) income	—		(205)		—		122		(83)

Changes in equity of noncontrolling interests	—		—		—		(37)		(37)
Acquisition of CENG noncontrolling Interest	1,080		—		—		(1,965)		(885)
Deferred tax adjustment related to acquisition of CENG noncontrolling interest	(288)		—		—		—		(288)
Distribution to member	—		(1,832)		—		—		(1,832)
Contribution from member	64		—		—		—		64
Acquisition of noncontrolling interest	2		—		—		(2)		—
Other comprehensive income (loss), net of income taxes	—		—		(1)		—		(1)
Balance, December 31, 2021	$	10,482	$	768	$	(31)	$	395	$	11,614
Net (loss) income	—		(160)		—		(7)		(167)
Separation-related adjustments	1,844		(11)		(2,006)		7		(166)
Changes in equity of noncontrolling interests	—		—		—		(41)		(41)



Distribution to member	—		(185)		—		—		(185)
Contribution from member	82		—		—		—		82

Other comprehensive income (loss), net of income taxes	—		—		277		—		277
Balance, December 31, 2022	$	12,408	$	412	$	(1,760)	$	354	$	11,414
Net income (loss)	—		1,623		—		(46)		1,577


Changes in equity of noncontrolling interest	—		—		—		53		53



Distribution to member	(871)		(368)		—		—		(1,239)


Other comprehensive income (loss), net of income taxes	—		—		(431)		—		(431)
Balance, December 31, 2023	$	11,537	$	1,667	$	(2,191)	$	361	$	11,374

See the Combined Notes to Consolidated Financial Statements

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

1. Basis of Presentation

Description of Business

We are a producer of carbon-free energy and a supplier of energy products and services. Our generating capacity includes primarily nuclear, wind, solar, natural gas and hydroelectric assets. Through our integrated business operations, we sell electricity, natural gas, and other energy-related products and sustainable solutions to various types of customers, including distribution utilities, municipalities, cooperatives, and commercial, industrial, governmental, and residential customers in markets across multiple geographic regions. We have five reportable segments: Mid-Atlantic, Midwest, New York, ERCOT and Other Power Regions.

Basis of Presentation

On February 21, 2021, the Board of Directors of Exelon authorized management to pursue a plan to separate its competitive generation and customer-facing energy businesses, conducted through Constellation Energy Generation, LLC (“Constellation”, formerly Exelon Generation Company, LLC) and its subsidiaries, into an independent, publicly-traded company. CEG Parent, a direct, wholly owned subsidiary of Exelon, was newly formed for the purpose of separation and had not engaged in any business activities nor had any assets or liabilities prior to the separation. On February 1, 2022, the separation was completed and CEG Parent holds all the interests in Constellation previously held by Exelon.

As an individual registrant, Constellation has historically filed consolidated financial statements to reflect its financial position and operating results as a stand-alone, wholly owned subsidiary of Exelon. The accompanying Consolidated Financial Statements have been prepared in accordance with GAAP for annual financial statements and in accordance with the instructions to Form 10-K and Regulation S-X promulgated by the SEC. The Consolidated Financial Statements include the accounts of our subsidiaries and all intercompany transactions have been eliminated. CEG Parent's prior period financial statements have been adjusted to reflect the balances of Constellation in accordance with applicable guidance. Amounts disclosed relate to CEG Parent and Constellation unless specifically noted as relating to CEG Parent only. Unless otherwise indicated or the context otherwise requires, references herein to the terms “we,” “us,” and “our” refer collectively to CEG Parent and Constellation.

We own 100% of our significant consolidated subsidiaries, either directly or indirectly, except for certain consolidated VIEs, including CRP, of which we hold a 51% interest. The remaining interests in the consolidated VIEs are included in noncontrolling interests on the Consolidated Balance Sheets. See Note 22 — Variable Interest Entities for additional information on consolidated VIEs.

We consolidate the accounts of entities in which we have a controlling financial interest, after the elimination of intercompany transactions. Where we do not have a controlling financial interest in an entity, proportionate consolidation, equity method accounting or accounting for investments in equity securities with or without readily determinable fair value is applied. We apply proportionate consolidation when we have an undivided interest in an asset and are proportionately liable for our share of each liability associated with the asset. We proportionately consolidate our undivided ownership interest in jointly owned electric plants. Under proportionate consolidation, we separately record our proportionate share of the assets, liabilities, revenues and expenses related to the undivided interest in the asset. See Note 9 — Jointly Owned Electric Plant for additional information on application of proportionate consolidation. We apply equity method accounting when we have a significant influence over an investee through an ownership in equity, which generally approximates a 20% to 50% voting interest.

We apply equity method accounting to certain investments and joint ventures. Under equity method accounting, we report our interest in the entity as an investment and our percentage share of the earnings from the entity as single line items in our consolidated financial statements. We use accounting for investments in equity securities with or without readily determinable fair values if we lack a significant influence, which generally results when we hold less than 20% of the common stock of an entity. Under accounting for investments in equity securities with readily determinable fair values, the investments are reported based on quoted prices in active markets and realized and unrealized gains and losses are included in earnings. Under accounting for investments in equity securities without readily determinable fair values, the investments are reported at cost adjusted for changes

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 1 — Basis of Presentation

from observable transactions for identical or similar investments of the same issuer, less impairment, and changes in measurement are reported in earnings.

Separation from Exelon

On February 1, 2022, Exelon completed the separation through a pro-rata distribution of all of the outstanding shares of our common stock, no par value, on the basis of one such share for every three shares of Exelon common stock held on January 20, 2022, the record date of the distribution. We are an independent, publicly traded company listed on the Nasdaq Stock Market under the symbol “CEG”, and regular-way trading began on February 2, 2022. Exelon no longer retains any ownership interest in CEG Parent or Constellation.

Prior to completion of the separation, our financial statements include certain transactions with affiliates of Exelon, which are disclosed as related party transactions. After February 1, 2022, all transactions with Exelon or its affiliates are no longer related party transactions.

In order to govern the ongoing relationships with Exelon after the separation, and to facilitate an orderly transition, we entered into several agreements with Exelon, including the following:

Separation Agreement – sets forth the principal actions to be taken in connection with the separation, including the transfer of assets and assumption of liabilities and establishes certain rights and obligations between us following the distribution
Transition Services Agreement (TSA) – governs all matters relating to the provision of services between us and Exelon on a transitional basis, in addition to providing us with certain services for an expected period of two-years, provided that certain services may be longer than the term and services may be extended with approval from both parties; the services include support for information technology, accounting, finance, human resources, security, and various other administrative and operational services
Employee Matters Agreement (EMA) – addresses certain employment, compensation and benefits matters, including the allocation of employees between us and Exelon and the allocation and treatment of certain assets and liabilities relating to our employees and former employees
Tax Matters Agreement (TMA) - governs the respective rights, responsibilities, and obligations between us and Exelon with respect to all tax matters (excluding employee-related taxes covered under EMA), in addition to certain restrictions which generally prohibit us from taking or failing to take any action in the two-year period following the distribution that would prevent the distribution from qualifying as tax-free for U.S. federal income tax purposes, including limitations on our ability to pursue certain equity issuances, strategic transactions, repurchases or other transactions

Pursuant to the Separation Agreement, we received a cash contribution of $1.75 billion from Exelon on January 31, 2022, the proceeds of which were used to settle $258 million of an intercompany loan from Exelon and $200 million of short-term debt outstanding prior to separation, in addition to a $192 million contribution to our pension plans. We also entered into two new five-year credit facility agreements providing $4.5 billion of capacity. See Note 17 — Debt and Credit Agreements for additional information on these facility agreements.

The amounts Exelon billed us for services pursuant to the TSA were $151 million and $266 million for the years ended December 31, 2023 and 2022, respectively. The amounts we billed Exelon for services pursuant to the TSA were $14 million and $43 million for the years ended December 31, 2023 and 2022, respectively.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Areas in which significant estimates have been made include, but are not limited to, the accounting for nuclear decommissioning costs and other AROs, pension and OPEB plans, inventory reserves, allowance for credit losses, long-lived asset valuations and impairment assessments, derivative instruments, goodwill, unamortized energy contracts, fixed asset depreciation, environmental costs and other loss contingencies, taxes and unbilled energy revenues. Actual results could differ from those estimates.

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 1 — Basis of Presentation

Revenues

Operating Revenues. Our operating revenues generally consist of revenues from contracts with customers involving competitive sales of power, natural gas, and other energy-related products and sustainable solutions. We recognize revenue from contracts with customers to depict the transfer of goods or services to customers in an amount that we expect to be entitled to in exchange for those goods or services. At the end of each reporting period, we accrue an estimate for the unbilled amount of power and natural gas delivered or services provided to customers.

Commodity Derivatives. Derivative instruments are generally recorded at fair value with subsequent changes in fair value recognized as realized and unrealized revenue or expense. The classification of revenue or expense is based on the intent of the transaction. See Note 16 — Derivative Financial Instruments for additional information.

Taxes Directly Imposed on Revenue-Producing Transactions. We collect certain taxes from customers such as sales and gross receipts taxes, along with other taxes, surcharges and fees, that are levied by state or local governments on the sale or distribution of electricity and natural gas and any taxable energy-related products and services. Some of these taxes are imposed on the customer, but paid by us, while others are imposed on us. Where these taxes are imposed on the customer, such as sales taxes, they are reported on a net basis in revenues. However, where these taxes are imposed on us, such as gross receipts taxes, they are reported on a gross basis in expense. Accordingly, revenues are recognized for the taxes collected from customers along with an offsetting expense in Taxes other than income taxes in the Consolidated Statements of Operations and Comprehensive Income. See Note 23 — Supplemental Financial Information for the taxes that are presented on a gross basis.

Leases

We recognize a ROU asset and lease liability for operating leases with a term of greater than one year. Operating lease ROU assets are included in Other deferred debits and other assets and operating lease liabilities are included in Other current liabilities and Other deferred credits and other liabilities on the Consolidated Balance Sheets. The ROU asset is measured as the sum of (1) the present value of all remaining fixed and in-substance fixed payments using the rate implicit in the lease whenever that is readily determinable or our incremental borrowing rate, (2) any lease payments made at or before the commencement date (less any lease incentives received) and (3) any initial direct costs incurred. The lease liability is measured the same as the ROU asset, but excludes any payments made before the commencement date and initial direct costs incurred. Lease terms include options to extend or terminate the lease if it is reasonably certain they will be exercised. We include non-lease components for most asset classes, which are service-related costs that are not integral to the use of the asset, in the measurement of the ROU asset and lease liability.

Expense for operating leases and leases with a term of one year or less is recognized on a straight-line basis over the term of the lease, unless another systematic and rational basis is more representative of the derivation of benefit from use of the leased property. Variable lease payments are recognized in the period in which the related obligation is incurred and consist primarily of payments for purchases of electricity under contracted generation that are based on the electricity produced by those generating assets. Operating lease expense and variable lease payments are recorded to Purchased power and fuel expense for contracted generation or Operating and maintenance expense for all other lease agreements in the Consolidated Statements of Operations and Comprehensive Income.

Income from operating leases, including subleases, is recognized on a straight-line basis over the term of the lease, unless another systematic and rational basis is more representative of the pattern in which income is earned over the term of the lease. Variable lease payments are recognized in the period in which the related obligation is performed and consist primarily of payments received from sales of electricity under contracted generation that are based on the electricity produced by those generating assets. Operating lease income and variable lease payments are recorded to Operating revenues in the Consolidated Statements of Operations and Comprehensive Income.

Our operating leases consist primarily of contracted generation, real estate including office buildings, and vehicles and equipment. We generally account for contracted generation in which the generating asset is not renewable as a lease if the customer has dispatch rights and obtains substantially all the economic benefits. We

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 1 — Basis of Presentation

generally do not account for contracted generation in which the generating asset is renewable as a lease if the customer does not design the generating asset. We account for land right arrangements that provide for exclusive use as leases while shared use land arrangements are generally not leases.

See Note 11 — Leases for additional information.

Income Taxes

Deferred federal and state income taxes are recorded on temporary differences between the book and tax basis of assets and liabilities and for tax benefits carried forward. ITCs have been deferred in the Consolidated Balance Sheets and are recognized in book income over the life of the related property. We account for uncertain income tax positions using a benefit recognition model with a two-step approach; a more-likely-than-not recognition criterion; and a measurement approach that measures the position as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. If it is not more-likely-than-not that the benefit of the tax position will be sustained on its technical merits, no benefit is recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. We recognize accrued interest related to unrecognized tax benefits in Interest expense, net or Other, net (interest income) and recognize penalties related to unrecognized tax benefits in Other, net in the Consolidated Statements of Operations and Comprehensive Income.

Cash and Cash Equivalents

We consider investments purchased with an original maturity of three months or less to be cash equivalents.

Restricted Cash and Cash Equivalents

Restricted cash and cash equivalents represent funds that are restricted to satisfy designated current liabilities. As of December 31, 2023 and 2022, restricted cash and cash equivalents primarily represented the payment of medical, dental, vision, and long-term disability benefits and project-specific nonrecourse financing structures for debt service and financing of operations of the underlying entities. See Note 17 — Debt and Credit Agreements and Note 23 — Supplemental Financial Information for additional information.

Allowance for Credit Losses on Accounts Receivables

The allowance for credit losses reflects our best estimate of losses on the customers' accounts receivable balances based on historical experience, current information, and reasonable and supportable forecasts.

The allowance for credit losses for our retail customers is based on accounts receivable aging historical experience coupled with specific identification through a credit monitoring process, which considers current conditions and forward-looking information such as industry trends, macroeconomic factors, changes in the regulatory environment, external credit ratings, publicly available news, payment status, payment history, and the exercise of collateral calls. The allowance for credit losses for our wholesale customers is developed using a credit monitoring process, like that used for retail customers. When a wholesale customer’s risk characteristics are no longer aligned with the pooled population, we use specific identification to develop an allowance for credit losses. Adjustments to the allowance for credit losses are recorded in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income.

We have certain non-customer receivables in Current Assets and Other deferred debits and other assets which primarily are with governmental agencies. As such, the allowance for credit losses related to these receivables is not material. We monitor these balances and will record an allowance if there are indicators of a decline in credit quality.

Variable Interest Entities

We account for our investments in and arrangements with VIEs based on the following specific requirements:

qualitative assessment of factors determinant in whether we have a controlling financial interest,
ongoing reconsideration of this assessment, and

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 1 — Basis of Presentation

where we consolidate a VIE (as primary beneficiary), disclosure of (1) the assets of the consolidated VIE, if they can be used to only settle specific obligations of the consolidated VIE, and (2) the liabilities of a consolidated VIE for which creditors do not have recourse to the general credit of the primary beneficiary.

See Note 22 — Variable Interest Entities for additional information.

Inventories

Inventory is recorded at the lower of weighted average cost or net realizable value. Provisions are recorded for excess and obsolete inventory. Natural gas, oil, materials and supplies, and emissions allowances are generally included in inventory when purchased. Natural gas, oil, and emissions allowances are expensed to Purchased power and fuel expense when consumed. Materials and supplies generally include items utilized within our generating plants and are expensed to Operating and maintenance or capitalized to Property, plant and equipment, as appropriate, when installed or used.

Debt and Equity Security Investments

Debt and Equity Investments within NDT funds. We have debt and equity securities held in our NDT funds which are measured and recorded at fair value. Realized and unrealized gains and losses, net of trust level taxes, on our NDT funds associated with the Regulatory Agreement Units are offset in Noncurrent payables related to Regulatory Agreement Units. Realized and unrealized gains and losses, net of trust level taxes, on our NDT funds associated with the Non-Regulatory Agreement Units are included in Other, net in the Consolidated Statements of Operations and Comprehensive Income. For equity securities without readily determinable fair values, we have elected to use the measurement alternative to measure these investments, defined as cost adjusted for changes from observable transactions for identical or similar investments of the same issuer, less impairment. Our NDT funds are classified as current or noncurrent assets, depending on the timing of the decommissioning activities and income taxes on trust earnings. See Note 18 — Fair Value of Financial Assets and Liabilities and Note 10 — Asset Retirement Obligations for additional information.

Equity Security Investments with Readily Determinable Fair Values. We have certain equity securities with readily determinable fair values. Realized and unrealized gains and losses are included in Other, net in the Consolidated Statements of Operations and Comprehensive Income. See Note 18 — Fair Value of Financial Assets and Liabilities for additional information.

Equity Security Investments without Readily Determinable Fair Values. We have certain equity securities without readily determinable fair values. We have elected to use the measurement alternative to measure these investments, defined as cost adjusted for changes from observable transactions for identical or similar investments of the same issuer, less impairment. Changes in measurement are reported in Other, net in the Consolidated Statements of Operations and Comprehensive Income. See Note 18 — Fair Value of Financial Assets for additional information.

Property, Plant and Equipment

Property, plant and equipment is recorded at acquired cost. Acquired cost includes construction-related direct labor and material costs. When appropriate, acquired cost also includes capitalized interest. Costs associated with nuclear outages and planned major maintenance activities, are expensed to Operating and maintenance expense or capitalized to Property, plant, and equipment based on the nature of the activities in the period incurred. The cost of repairs and maintenance and minor replacements of property is charged to Operating and maintenance expense as incurred.

Upon retirement, the cost of property is generally charged to accumulated depreciation in accordance with the composite and group methods of depreciation. Upon replacement of an asset, the costs to remove the asset, net of salvage, are capitalized to gross plant when incurred as part of the cost of the newly installed asset and recorded to depreciation expense over the life of the new asset. Removal costs, net of salvage, incurred for property that will not be replaced is charged to Operating and maintenance expense as incurred. Certain assets follow the unitary method of depreciation and recognize gains and losses in the period of replacement or retirement. These gains and losses are recorded in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income.

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 1 — Basis of Presentation

Capitalized Software. Certain costs, such as design, coding, and testing incurred during the application development stage of software projects that are internally developed or purchased for operational use are capitalized in Property, plant and equipment in the Consolidated Balance Sheets. Similar costs incurred for cloud-based solutions treated as service arrangements are capitalized in Other current assets and Deferred debits and other assets in the Consolidated Balance Sheets. Such capitalized amounts are amortized ratably over the expected lives of the projects when they become operational, generally not to exceed five years.

Capitalized Interest. During construction, we capitalize the costs of debt funds. Most projects will use a debt rate calculated using the general corporate debt pool. In some cases, projects are specifically financed and use a project specific debt rate, which is excluded from the general corporate debt pool. Capitalization of debt funds is recorded as a charge to construction work in progress and as a non-cash credit to interest expense. See Note 8 — Property, Plant, and Equipment, Note 9 — Jointly Owned Electric Plant and Note 23 — Supplemental Financial Information for additional information.

Nuclear Fuel

The cost of nuclear fuel is capitalized in Property, plant and equipment and charged to Purchased power and fuel using the unit-of-production method. Any potential future SNF disposal fees will also be expensed through Purchased power and fuel expense. Additionally, certain on-site SNF storage costs are being reimbursed by the DOE since a DOE (or government-owned) long-term storage facility has not been completed. See Note 19 — Commitments and Contingencies for additional information regarding the cost of SNF storage and disposal.

Depreciation and Amortization

Except for the amortization of nuclear fuel, depreciation, inclusive of ARC, is generally recorded over the estimated service lives of property, plant and equipment on a straight-line basis using the group, composite or unitary methods of depreciation. Two methods of depreciating multiple asset groups exist: the group method and the composite method. The group method is typically for groups of assets that are largely homogenous and have approximately the same useful lives. The composite method is used when the assets are heterogeneous and have different lives. Under both methods, a reporting entity depreciates the assets over the average life of the assets in the group. The estimated service lives are based on a combination of depreciation studies, historical retirements, site licenses and management estimates of operating costs and expected future energy market conditions. See Note 7 — Early Plant Retirements for additional information on the impacts of early plant retirements, Note 8 — Property, Plant, and Equipment for additional information regarding depreciation, and Note 23 — Supplemental Financial Information for additional information regarding nuclear fuel.

Asset Retirement Obligations

We estimate and recognize a liability for our legal obligation to perform asset retirement activities even though the timing and/or methods of settlement may be conditional on future events. We generally update our nuclear decommissioning ARO annually, unless circumstances warrant more frequent updates, based on our annual evaluation of cost escalation factors and probabilities assigned to the multiple outcome scenarios within our probability-weighted discounted cash flow models. Our multiple outcome scenarios are generally based on decommissioning cost studies which are updated, on a rotational basis, for each of our nuclear units at least every five years, unless circumstances warrant more frequent updates. AROs are accreted throughout each year to reflect the time value of money for these present value obligations through a charge to Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income for Non-Regulatory Agreement Units and through an offsetting decrease in noncurrent payables related to Regulatory Agreement Units. See Note 10 — Asset Retirement Obligations for additional information.

Accounting Implications of the Regulatory Agreement Units

Based on the requirements of the ICC, PAPUC, and PUCT that dictate our obligations related to the shortfall or excess of NDT funds necessary for decommissioning the former ComEd, former PECO, and STP units, decommissioning-related activities net of applicable taxes, including realized and unrealized gains and losses on the NDT funds, depreciation of the ARC, and accretion of the decommissioning obligation are generally offset in the Consolidated Statements of Operations and Comprehensive Income and are recorded as noncurrent payables in the Consolidated Balance Sheets (within Payables related to Regulatory Agreement Units). See Note 10 — Asset Retirement Obligations for additional information.

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 1 — Basis of Presentation

Asset Impairments

Long-Lived Assets. We regularly monitor and evaluate the carrying value of long-lived assets or asset groups for recoverability whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators of impairment may include a deteriorating business climate, including, but not limited to, declines in energy prices, condition of the asset, or plans to dispose of a long-lived asset significantly before the end of its useful life. We determine if long-lived assets or asset groups are potentially impaired by comparing the undiscounted expected future cash flows to the carrying value when indicators of impairment exist. When the undiscounted cash flow analysis indicates a long-lived asset or asset group may not be recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. Generally, pre-tax impairment losses are recorded in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. See Note 12 — Asset Impairments for additional information.

Goodwill. Goodwill represents the excess of the purchase price paid over the estimated fair value of the net assets acquired and liabilities assumed in the acquisition of a business. Goodwill is not amortized, but is tested for impairment at least annually or in an interim basis if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. See Note 2 — Mergers, Acquisitions, and Dispositions and Note 13 — Intangible Assets for additional information.

Equity Method Investments. We regularly monitor and evaluate equity method investments to determine whether they are impaired. An impairment is recorded when the investment has experienced a decline in value that is other-than-temporary in nature. Additionally, if the entity in which we hold an investment recognizes an impairment loss, we would record their proportionate share of that impairment loss and evaluate the investment for an other-than-temporary decline in value. These impairment losses are recorded in Equity in (losses) earnings of unconsolidated affiliates in the Consolidated Statements of Operations and Comprehensive Income.

Equity Security Investments. Equity investments with readily determinable fair values are measured and recorded at fair value with any changes in fair value recorded in Other, net in the Consolidated Statements of Operations and Comprehensive Income. Investments in equity securities without readily determinable fair values are qualitatively assessed for impairment each reporting period. If it is determined that the equity security is impaired, an impairment loss will be recognized in Other, net in the Consolidated Statements of Operations and Comprehensive Income to the amount by which the security’s carrying amount exceeds its fair value.

Derivative Financial Instruments

All derivatives are recognized on the balance sheet at their fair value unless they qualify for certain exceptions, including NPNS. For derivatives intended to serve as economic hedges, changes in fair value are recognized in earnings each period. Amounts classified in earnings are included in Operating revenues, Purchased power and fuel, or Interest expense in the Consolidated Statements of Operations and Comprehensive Income based on the activity the transaction is economically hedging. While most of the derivatives serve as economic hedges, there are also derivatives entered into for proprietary trading purposes, subject to our RMP, and changes in the fair value of those derivatives are recorded in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income. Cash inflows and outflows related to derivative instruments are included as a component of operating, investing, or financing cash flows in the Consolidated Statements of Cash Flows, depending on the nature of each transaction.

As part of the energy marketing business, we enter into 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 energy markets with the intent and ability to deliver or take delivery of the underlying physical commodity. NPNS are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period and will not be financially settled. Revenues and expenses on derivative contracts that qualify, and are designated, as NPNS are recognized when the underlying physical transaction is completed. While these contracts are considered derivative financial instruments, they are not required to be recorded at fair value. See Note 16 — Derivative Financial Instruments for additional information.

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 1 — Basis of Presentation

Retirement Benefits

Prior to separation, Exelon sponsored defined benefit pension plans and OPEB plans as described in Note 15 — Retirement Benefits. The plan obligations and costs of providing benefits under these plans were measured as of December 31, 2021. We accounted for our participation in Exelon’s pension and OPEB plans by applying multi-employer accounting. Exelon allocated costs related to its pension and OPEB plans to its subsidiaries based on both active and retired employee participation in each plan. We included the service cost and non-service cost components in Operating and maintenance expense and Property, plant, and equipment, net in the consolidated financial statements.

Effective upon separation, we sponsor defined benefit pension and OPEB plans as described in Note 15 — Retirement Benefits. The plan obligations and costs of providing benefits under these plans were measured upon separation as of February 1, 2022 and remeasured as of December 31, 2023 and 2022. The measurements involved various factors, assumptions, and accounting elections. The impact of assumption changes or experience different from that assumed on pension and OPEB obligations is recognized over time rather than immediately recognized in the Consolidated Statements of Operations and Comprehensive Income. Gains or losses more than the greater of ten percent of the PBO or the MRV of plan assets are amortized over the expected average remaining service period of plan participants. Gains or losses more than the greater of ten percent of the APBO or the MRV of plan assets are amortized over the average future remaining lifetime of the current inactive population for the OPEB plans.

We report the pension and OPEB service cost and non-service cost (credit) components of net periodic benefit costs (credits) for all plans separately in our Consolidated Statements of Operations and Comprehensive Income. Effective February 1, 2022, the service cost component continues to be included in Operating and maintenance expense and Property, plant, and equipment, net (where criteria for capitalization of direct labor has been met) while the non-service cost (credit) components are included in Other, net, in accordance with single employer plan accounting.

Renewable Energy Credits

RECs are included in Renewable energy credits in the Consolidated Balance Sheets. Purchased RECs are recorded at cost on the date they are purchased and internally generated RECs are recognized at a zero-cost basis when generated. The cost of RECs purchased on a stand-alone basis is based on the transaction price, while the cost of RECs acquired through PPAs represents the difference between the total contract price and the market price of energy at contract inception. Generally, revenue for RECs that are sold to a counterparty under a contract that specifically identifies a power plant are recognized at a point in time when the power is produced. This includes both bundled and unbundled REC sales. Otherwise, the revenue is recognized upon physical transfer of the REC to the customer.

2. Mergers, Acquisitions, and Dispositions

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.

The current renewed NRC licenses for the STP units expire in 2047 and 2048, and the NRC licensed operator is STP Nuclear Operating Company (STPNOC), acting on behalf of the joint owners. Other owners include City Public Service Board of San Antonio (CPS, 40%) and the City of Austin, Texas (Austin Energy, 16%). This acquisition is complementary to and aligned strategically with our existing clean energy business operations.

As part of the transaction, we acquired ownership of two decommissioning trust funds established to provide funding for decontamination and decommissioning of STP. The trust funds have been funded with amounts collected from predecessor utilities. We maintain the ability to collect additional funds from utility customers in the event of a shortfall and are required to return any excess funds to utility customers upon completion of decommissioning. As such, our accounting for the future decommissioning of our interest in STP will mirror that of our existing Regulatory Agreement Units. See Note 1 — Basis of Presentation and Note 10 — Asset Retirement Obligations for additional information on our accounting policy for Regulatory Agreement Units.

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 2 — Mergers, Acquisitions, and Dispositions

The acquisition was accounted for using the acquisition method of accounting in accordance with authoritative guidance, which requires, among other things, the assets acquired and liabilities assumed to be recognized at their respective fair value as of the acquisition date. The excess of the purchase price over fair value of our proportionate share of the assets acquired and liabilities assumed was recorded to goodwill. The goodwill recognized is primarily driven by the opportunity for continued operations through 80 years and the value of STP’s carbon-free energy that is not fully reflected by the markets. The goodwill amount has been assigned entirely to the ERCOT operating segment. See Note 13 — Intangible Assets for additional information. The total amount of goodwill is expected to be deductible for tax purposes over the amortization period.

The fair values of STP’s assets and liabilities were determined based on significant estimates and assumptions that are judgmental in nature, including projected future cash flows (including timing), discount rates reflecting risk inherent in the future cash flows and future power and fuel market prices. Accounting guidance provides that the allocation of the purchase price may be modified up to one year from the date of the acquisition to the extent that additional information is obtained about the facts and circumstances that existed as of the acquisition date. Any changes could result in a change in the amount of goodwill recorded.

The following table summarizes the acquisition-date fair value of the consideration transferred and the assets and liabilities assumed for the STP acquisition:


Cash paid for purchase price	$	1,654

Identifiable assets acquired and liabilities assumed
Property, plant, and equipment	1,254
Nuclear decommissioning trust funds	869
Inventories, net	47
Other long-term assets	40
Other current assets	11

Total assets	2,221

Asset retirement obligations	429
Payables related to Regulatory Agreement Units	376
Deferred income taxes and unamortized investment tax credits	65
Accounts payable and accrued expenses	45
Pension and OPEB obligations	25
Other long-term liabilities	5



Total liabilities	945
Total net identifiable assets, at fair value	1,276

Goodwill	$	378

For the year ended December 31, 2023, we incurred immaterial merger and integration-related costs which are included within Operating and maintenance expense in our Consolidated Statements of Operations and Comprehensive Income.

The operating revenues and results of operations for STP have been included in the Consolidated Statements of Operations and Comprehensive Income from the date of acquisition and were not material for the year ended December 31, 2023. The pro forma effects of this acquisition are not significant to our reported results for any periods presented. Accordingly, no pro forma financial statements have been presented herein.

On July 28, 2023 NRG accepted service of a lawsuit filed by the City of San Antonio, Texas, acting by and through CPS, in the 130th District Court of Matagorda County, Texas against NRG and certain of its subsidiaries, claiming the existence of a right of first refusal that applies to the transaction contemplated between us and NRG. On July 31, 2023 we intervened in the lawsuit and Austin Energy also intervened in the lawsuit claiming a similar right of first refusal. Per the terms of the Equity Purchase Agreement, NRG made representations that no right of first refusal applied to the transaction contemplated between us.

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 2 — Mergers, Acquisitions, and Dispositions

Separately, on July 31, 2023, San Antonio and Austin filed motions to dismiss and (in the alternative) immediately stay proceedings and petitions to intervene on the application for June 12, 2023 license transfer application that was filed with the NRC. These motions and petitions remain pending before the NRC. Notwithstanding this, the NRC issued approval of the license transfer application on October 30, 2023. However, the NRC staff’s approval of the license transfer is subject to the Commission’s authority to rescind, modify, or condition the approved transfer based on the outcome of any post-effectiveness hearing or motions on the license transfer application. On February 20, 2024, we (along with San Antonio, Austin and NRG) jointly filed a motion to stay of the issuance of a decision by the NRC on the pending petition and motions. The motion requested that the NRC stay any decision so that the parties can attempt to finalize a settlement agreement that would result in the withdrawal of San Antonio’s pending petition and motions.

The ongoing legal proceedings did not prohibit NRG and CEG from consummating the transaction, and Constellation is working with all parties to reach a resolution to the matter. We cannot reasonably predict the outcome of the lawsuit or NRC litigation; however, we do not expect it to have a material impact to our consolidated financial statements.

CENG Put Option

Prior to August 6, 2021, we owned a 50.01% membership interest in CENG, a joint venture with EDF, which wholly owned the Calvert Cliffs and Ginna nuclear stations and Nine Mile Point Unit 1, in addition to an 82% undivided ownership interest in Nine Mile Point Unit 2. CENG is 100% consolidated in our financial statements.

On April 1, 2014, we entered into various agreements with EDF including a Nuclear Operating Services Agreement, an amended LLC Operating Agreement, an Employee Matters Agreement, and a Put Option Agreement, among others. Under the amended LLC Operating Agreement, CENG made a $400 million special distribution to EDF and committed to make preferred distributions to us until we had received aggregate distributions of $400 million plus a return of 8.50% per annum.

Under the terms of the Put Option Agreement, EDF had the option to sell its 49.99% equity interest in CENG exercisable beginning on January 1, 2016 and thereafter until June 30, 2022. On November 20, 2019, we received notice of EDF’s intention to exercise the put option, and the put automatically exercised on January 19, 2020 at the end of the sixty-day advance notice period. The transaction required approval by FERC and the NYPSC, which approvals were received on July 30, 2020 and April 15, 2021, respectively. On August 6, 2021, we entered into a settlement agreement pursuant to which we purchased EDF's equity interest in CENG for a net purchase price of $885 million, which included, among other things, an adjustment for EDF's share of the outstanding balance of the preferred distribution payable to us by CENG. The difference between the net purchase price and EDF's noncontrolling interest as of August 6, 2021 was recorded to Membership interest in the Consolidated Balance Sheet. As a result of the transaction, we also recorded deferred tax liabilities of $288 million in Membership interest in the Consolidated Balance Sheet. See Note 14 — Income Taxes for additional information.

The following table summarizes the effects of the changes in our ownership interest in CENG in Member's Equity:


	For the Year Ended December 31, 2021
Net loss attributable to membership interest	$	(205)
Pre-tax increase in membership interest for purchase of EDF's 49.99% equity interest(a)	1,080
Decrease in membership interest due to deferred tax liabilities resulting from purchase of EDF's equity interest(a)	(288)
Change from net loss attributable to membership interest and transfers from noncontrolling interest	$	587

(a)Represents non-cash activity in the consolidated financial statements.

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 2 — Mergers, Acquisitions, and Dispositions

Agreement for Sale of Our Biomass Facility

On April 28, 2021, we entered into a purchase agreement with ReGenerate Energy Holdings, LLC ("ReGenerate"), under which ReGenerate agreed to purchase our interest in the Albany Green Energy biomass facility. As a result, in the second quarter of 2021, we recorded a pre-tax impairment charge of $140 million in Operating and maintenance expense in the Consolidated Statement of Operations and Comprehensive Income. Completion of the transaction was subject to the satisfaction of various customary closing conditions that were satisfied in the second quarter of 2021. The sale was completed on June 30, 2021 for a net purchase price of $36 million.

Agreement for Sale of Our Solar Business

On December 8, 2020, we entered into an agreement with an affiliate of Brookfield Renewable, for the sale of a significant portion of our solar business, including 360 MWs of generation in operation or under construction across more than 600 sites across the United States. We retained certain solar assets not included in this agreement, primarily Antelope Valley.

Completion of the transaction contemplated by the sale agreement was subject to the satisfaction of several closing conditions that were satisfied in the first quarter of 2021. The sale was completed on March 31, 2021 for a purchase price of $810 million. We received cash proceeds of $675 million, net of $125 million long-term debt assumed by the buyer and certain working capital and other post-closing adjustments. We recognized a pre-tax gain of $68 million which is included in Gain on sales of assets and businesses in the Consolidated Statement of Operations and Comprehensive Income.

3. Regulatory Matters

The following matters below discuss the status of our material regulatory and legislative proceedings.

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. In accordance with PJM's tariff, funds collected from non-performance charges are redistributed as bonuses to generating resources that overperformed during the event, including our nuclear fleet. Complaints were filed at FERC by underperforming generators alleging, among other things, that PJM’s tariff is unjust and unreasonable, and that PJM violated its tariff or otherwise acted negligently in operating the system during that period, seeking to reduce or eliminate any penalty. In 2023, a proposed settlement was filed with FERC, and FERC subsequently approved the settlement as uncontested. We recognized $120 million and $109 million for bonuses (pre-tax), net of non-performance charges, in 2023 and 2022, respectively, associated with this event, primarily driven by the overperformance of our nuclear fleet. Remaining amounts on our balance sheet as of December 31, 2023 associated with this event are not material.

New England Regulatory Matters

Mystic Units 8 and 9 Cost of Service Agreement. On December 20, 2018, FERC issued an order accepting a cost of service agreement for Mystic Units 8 and 9 for the period between June 1, 2022 to May 31, 2024. The agreement is intended to preserve the two units for the two-year period while allowing the Mystic units to recover their costs of operating, including a substantial portion of the costs associated with the adjacent EMT we acquired in October 2018.

In 2020, FERC issued several orders that, together, affirmed the recovery of key elements of Mystic's cost of service compensation, including recovery of costs associated with the operation of EMT. Several parties appealed the orders to the U.S. Court of Appeals for the D.C. Circuit. On August 23, 2022, the court issued its opinion and remanded several issues back to FERC, including the amount of the EMT’s fixed costs that can be recovered via the Mystic COS.

On March 28, 2023, FERC issued an order on remand from the D.C. Circuit’s August 2022 decision (FERC Remand Order). Among other things, the FERC Remand Order affirmed that 91% of EMT’s fixed costs will be

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 3 — Regulatory Matters

recovered via the Mystic COS, subject to the reinstatement of a margin sharing mechanism on forward sales of vapor.

The Mystic COS requires an annual process whereby we identify and support our projected costs under the agreement and/or true-up previous projections to the actual costs incurred. The first annual process resulted in a filing at FERC on September 15, 2021 and included our projection of capital expenditures to be recovered under the Mystic COS between June 1, 2022 and December 31, 2022. On April 28, 2022, FERC issued an order setting for settlement and/or hearing the issue of whether our projected 2022 capital expenditures can be recovered. A settlement was filed at FERC in March 2023 and was approved by FERC on August 1, 2023. The settlement reduces the recovery we receive for capital projects over the term of the Mystic COS. The settlement also eliminates the potential that we would need to return EMT capital expenditures that were recovered via COS if EMT continues operating after the Mystic COS terminates. The approval of this offer of settlement does not have a material financial statement impact. On September 15, 2022, we made our second annual filing at FERC. On December 5, 2023, FERC issued an order setting for settlement/hearing certain components of the second annual filing, including the issue of Mystic’s recovery of historical rate base costs. We cannot reasonably predict the outcome of the settlement and/or hearing.

See Note 7 — Early Plant Retirements and Note 12 — Asset Impairments for additional information on the impacts of our August 2020 decision to retire Mystic Units 8 and 9 upon expiration of the cost of service agreement.

Federal Regulatory Matters

Inflation Reduction Act of 2022. On August 16, 2022, President Biden signed into law the IRA, which, among other things, includes federal tax credits, certain of which are transferable or fully refundable, for a number of clean energy technologies including existing nuclear plants. The nuclear PTC recognizes the contributions of carbon-free nuclear power by providing a federal tax credit of up to $15/MWh, subject to phase-out, beginning in 2024 and continuing through 2032. The nuclear PTC includes adjustments for inflation. With the nuclear PTC policy support, we expect that many of our nuclear assets will operate through the end of the nuclear PTC period. Further, the IRA includes a 15% book-minimum tax on applicable corporations that we do not expect to have a material impact to our consolidated financial statements. The U.S. Department of Treasury has begun the process of issuing guidance on the relevant tax provisions included in the legislation but has not yet addressed the nuclear PTC.

Operating License Renewals

Conowingo Hydroelectric Project. In 2012, we submitted an application to FERC for a new license for the Conowingo Hydroelectric Project (Conowingo). In connection with our efforts to obtain a water quality certification pursuant to Section 401 of the Clean Water Act (401 Certification) from MDE for Conowingo, we had been working with MDE and other stakeholders to resolve water quality licensing issues, including: (1) water quality, (2) fish habitat, and (3) sediment.

In 2019, we and MDE filed with FERC a Joint Offer of Settlement (Offer of Settlement) that would resolve all outstanding issues relating to the 401 Certification. FERC subsequently issued a new 50-year license for Conowingo, effective March 1, 2021. Several environmental groups appealed FERC’s ruling to the U.S. Court of Appeals for the D.C. Circuit. The court of appeals issued a decision vacating FERC’s decision to grant Conowingo its license renewal and sending the matter back to FERC for further proceedings. Upon issuance of the mandate from the U.S. Court of Appeals for the D.C. Circuit, we began operating under an annual license, which renews automatically, containing the same terms as the license that was in effect prior to the 2021 FERC order.

MDE informed us that as a result of the U.S. Court of Appeals decision, they would be resuming their administrative reconsideration of the 401 Certification. In response to the procedure outlined by the MDE, supplemental briefs on the 401 Certification were filed by the Lower Susquehanna Riverkeeper Association and Waterkeepers Chesapeake (jointly) and us. In addition, we filed a supplemental reply brief. We are unable to further predict the outcome of this proceeding at this time. Depreciation provisions continue to assume operation through 2071 given our expectation that a 50-year license will be issued.

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 3 — Regulatory Matters

Peach Bottom Units 2 and 3. On March 6, 2020, the NRC approved a second 20-year license renewal for Peach Bottom Units 2 and 3. As a result, Peach Bottom Units 2 and 3 were granted the authority to operate through 2053 and 2054, respectively.

Notwithstanding its 2020 approval, on February 24, 2022, the NRC took action to modify Peach Bottom's subsequently renewed licenses in response to a request for hearing that the NRC had not previously adjudicated. In its February 2022 decision, the NRC reversed itself and concluded that the previous environmental review required by the National Environmental Policy Act (NEPA) for the Peach Bottom subsequently renewed licenses was incomplete because it did not adequately address environmental impacts resulting from renewing the units’ licenses for an additional 20 years. As a result, the NRC has undertaken a rulemaking to modify its regulations and guidance to specifically address environmental impacts during the period of subsequent license renewal. In addition, the NRC modified the expiration dates for the Peach Bottom licenses from 2053 and 2054 to 2033 and 2034, respectively, pending the completion of the updated NEPA analysis. We expect that the license expiration dates will be restored to 2053 and 2054, respectively, once the NRC's reevaluation of environmental impacts resulting from subsequent license renewal is complete. In September 2023, the NRC announced that its schedule to complete the rulemaking has delayed by several months and now intends to be complete by August 2024. This delay does not alter our expectation that the license expiration dates for Peach Bottom will be restored. Depreciation provisions and ARO assumed retirement dates continue to assume Peach Bottom Units 2 and 3 will operate through 2053 and 2054, respectively, given our expectation that the previously approved expiration dates will be restored.

4. Revenue from Contracts with Customers

We recognize revenue from contracts with customers to depict the transfer of goods or services to customers at an amount that we expect to be entitled to in exchange for those goods or services. Our primary sources of revenue include competitive sales of power, natural gas, and other energy-related products and sustainable solutions. The performance obligations, revenue recognition, and payment terms associated with these sources of revenue are further discussed in the table below. There are no significant financing components for these sources of revenue.

Unless otherwise noted, for each of the significant revenue categories and related performance obligations described below, we have the right to consideration from the customer in an amount that corresponds directly with the value transferred to the customer for the performance completed to date. Therefore, we generally recognize revenue in the amount for which we have the right to invoice the customer. As a result, there are generally no significant judgments used in determining or allocating the transaction price.

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 4 — Revenue from Contracts with Customers


Revenue Source	Description	Performance Obligation	Timing of Revenue Recognition	Payment Terms
Power Sales	Sales of power and other energy-related commodities to wholesale and retail customers through our customer-facing business	Various, including the delivery of power (generally delivered over time) and other energy-related commodities such as capacity (generally delivered over time), CMCs, ZECs, RECs or other ancillary services (generally delivered at a point in time)	Concurrently as power is generated for bundled power sale contracts (a)	Generally within the month following delivery to the customer
Natural Gas Sales	Sales of natural gas to wholesale and retail customers through our customer-facing business	Various, including the delivery of natural gas (generally delivered overtime) and sustainable natural gas attributes (generally delivered at a point in time)	Over time as the natural gas is delivered to the customer	Generally within the month following delivery to the customer
Other Products and Services	Sales of other energy-related products and sustainable solutions such as long-term construction and installation of energy efficiency assets and new power generating facilities, primarily to C&I customers	Construction and/or installation of the asset for the customer	Revenues and associated costs are recognized throughout the contract term using an input method to measure progress towards completion(b)	Generally within 30 or 45 days from the invoice date

(a)Certain contracts may contain limits on the total amount of revenue we are able to collect over the entire term of the contract. In such cases, we estimate the total consideration expected to be received over the term of the contract net of the constraint and allocate the expected consideration to the performance obligations in the contract such that revenue is recognized ratably over the term of the entire contract as the performance obligations are satisfied.

(b)The method recognizes revenue based on the various inputs used to satisfy the performance obligation, such as costs incurred and total labor hours expended. The total amount of revenue that will be recognized is based on the agreed upon contractually-stated amount. The average contract term for these projects is approximately 18 months.

We incur incremental costs in order to execute certain retail power and gas sales contracts. These costs, which primarily relate to retail broker fees and sales commissions, are capitalized when incurred as contract acquisition costs and generally amortized over the corresponding term of the contract. These capitalized costs and related amortization were not material as of and for the years ended December 31, 2023 and 2022.

Contract Balances

Contract Assets

We record contract assets for the revenue recognized on the construction and installation of energy efficiency assets and new power generating facilities before we have an unconditional right to bill for and receive the consideration from the customer. These contract assets are subsequently reclassified to receivables when the right to payment becomes unconditional. We record contract assets and contract receivables in Other current assets and Customer accounts receivable, net, respectively, in the Consolidated Balance Sheets.

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 4 — Revenue from Contracts with Customers

The following table provides a rollforward of the contract assets reflected in the Consolidated Balance Sheets:



	2023		2022
Beginning balance as of January 1	$	130	$	149
Amounts reclassified to receivables	(127)		(81)
Revenues recognized	79		62

Ending balance as of December 31	$	82	$	130

Contract Liabilities

We record contract liabilities when consideration is received or due prior to the satisfaction of the performance obligations. We record contract liabilities in Other current liabilities and Other deferred credits and other liabilities in the Consolidated Balance Sheets. These contract liabilities primarily relate to upfront consideration received or due for equipment service plans, the Mystic COS, and the Illinois ZEC program. The Mystic COS includes upfront consideration received or due that differs from the recognized earnings over the cost of the service period. The Illinois ZEC program introduces an annual cap on the total consideration to be received by us for each delivery period. The ZEC price is established on a per MWh of production basis with a maximum annual cap for total compensation to be received for each planning year, while requiring delivery of all ZECs produced by our participating facilities during each delivery period. ZECs delivered to Illinois utilities in excess of the annual cost cap may be paid in subsequent years if the payments do not exceed the prescribed annual cost cap for that year. There were no outstanding contract liabilities for the Illinois ZEC program as of December 31, 2023, and were not material as of December 31, 2022.

The following table provides a rollforward of the contract liabilities reflected in the Consolidated Balance Sheets:



	2023		2022		2021
Beginning balance as of January 1	$	47	$	75	$	84
Consideration received or due	331		339		251
Revenues recognized	(338)		(367)		(263)
Contract liabilities reclassified as held for sale	—		—		3
Ending balance as of December 31	$	40	$	47	$	75

The following table reflects revenues recognized in the years ended December 31, 2023, 2022 and 2021, which were included in contract liabilities at December 31, 2022, 2021, and 2020, respectively:


			2023						2022						2021
Revenues recognized			$	26					$	71					$	82

Transaction Price Allocated to Remaining Performance Obligations

The following table shows the amounts of future revenues expected to be recorded in each year for performance obligations that are unsatisfied or partially unsatisfied as of December 31, 2023. This disclosure only includes contracts for which the total consideration is fixed and determinable at contract inception. The average contract term varies by customer type and commodity but ranges from one month to several years. This disclosure excludes mark-to-market derivatives and certain power and gas sales contracts which contain variable volumes and/or variable pricing.


			2024						2025						2026						2027						2028 and thereafter						Total
Remaining performance obligations			$	152					$	44					$	20					$	18					$	130					$	364

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 4 — Revenue from Contracts with Customers

Transaction Price Allocated to Previously Satisfied Performance Obligations

Illinois ZEC Revenues

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. For the June 1, 2023 to May 31, 2024 planning year the ZEC price has been established at $0.30 per ZEC, subject to an annual cap of $224 million. ZECs generated and delivered during this planning year will not exceed the annual cap, providing capacity to compensate for ZECs delivered in prior planning years in excess of the compensation cap. 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.

PJM Performance Bonuses

For the year ended December 31, 2023, we recognized a benefit of $120 million (pre-tax) for performance bonuses (net of non-performance charges), primarily driven by the overperformance of our nuclear fleet during the 2022 winter storm Elliott. See Note 3 — Regulatory Matters for additional information on the PJM performance bonuses.

Revenue Disaggregation

We disaggregate the revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. See Note 5 — Segment Information for the presentation of revenue disaggregation.

5. Segment Information

Operating segments are determined based on information used by the CODM in deciding how to evaluate performance and allocate resources. We have five reportable segments consisting of the Mid-Atlantic, Midwest, New York, ERCOT, and all other power regions referred to collectively as “Other Power Regions.”

The basis for our reportable segments is the integrated management of our electricity business that is located in different geographic regions, and largely representative of the footprints of ISO/RTO and/or NERC regions, which utilize multiple supply sources to provide electricity through various distribution channels (wholesale and retail). Our hedging strategies and risk metrics are also aligned to these same geographic regions. Descriptions of each of our five reportable segments are as follows:

Mid-Atlantic** represents operations in the 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** represents operations in the western half of PJM and the United States footprint of MISO, excluding MISO’s Southern Region.
New York** represents operations within NYISO.
ERCOT** represents operations within Electric Reliability Council of Texas that covers a majority of the state of Texas.
Other Power Regions:**
New England represents operations within ISO-NE.

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 5 — Segment Information

South** represents operations in FRCC, MISO’s Southern Region, and the remaining portions of SERC not included within MISO or PJM.
West** represents operations in WECC, which includes CAISO.
Canada** represents operations across the entire country of Canada and includes AESO, OIESO, and the Canadian portion of MISO.

The CODM evaluates the performance of our electric business activities and allocates resources based on Operating revenues net of Purchased power and fuel expense (RNF). We believe this is a useful measurement of operational performance, although it is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report. Our operating revenues include all sales to third parties and affiliate sales to Exelon's utility subsidiaries, prior to the separation on February 1, 2022. Purchased power costs include all costs associated with the procurement and supply of electricity including capacity, energy, and ancillary services. Fuel expense includes the fuel costs for our owned generation and fuel costs associated with tolling agreements. The results of our other business activities are not regularly reviewed by the CODM and are therefore not classified as operating segments or included in the regional reportable segment amounts. These activities include wholesale and retail sales of natural gas, energy-related sales in the United Kingdom, as well as sales of other energy-related products and sustainable solutions that are not significant to our overall results of operations. Further, our unrealized mark-to-market gains and losses on economic hedging activities and our amortization of certain intangible assets and liabilities relating to commodity contracts recorded at fair value from mergers and acquisitions are also excluded from the regional reportable segment amounts. The CODM does not use a measure of total assets in making decisions regarding allocating resources to or assessing the performance of these reportable segments.

The following tables disaggregate the revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. The disaggregation of revenues reflects our two primary products of power sales and natural gas sales, with further disaggregation of power sales provided by geographic region.

The following tables also show the reconciliation of reportable segment revenues and RNF to our total revenues and RNF for the years ended December 31, 2023, 2022, and 2021.


	2023
	Revenues from external customers
	Contracts with customers		Other(a)		Total		Intersegment Revenues		Total Revenues
Mid-Atlantic	$	5,453	$	(265)	$	5,188	$	(50)	$	5,138
Midwest	4,846		(191)		4,655		3		4,658
New York	1,910		56		1,966		55		2,021
ERCOT	1,232		109		1,341		5		1,346
Other Power Regions	4,956		908		5,864		(13)		5,851
Total Reportable Segment Power Revenues	18,397		617		19,014		—		19,014
Total Natural Gas Revenues	1,859		1,866		3,725		—		3,725
Total Other Revenues(b)	585		1,594		2,179		—		2,179
Total Consolidated Operating Revenues	$	20,841	$	4,077	$	24,918	$	—	$	24,918

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 5 — Segment Information


	2022
	Revenues from external customers(c)
	Contracts with customers		Other(a)		Total		Intersegment Revenues		Total Revenues
Mid-Atlantic	$	5,264	$	(105)	$	5,159	$	5	$	5,164
Midwest	5,164		(507)		4,657		(7)		4,650
New York	2,004		(408)		1,596		(1)		1,595
ERCOT	954		602		1,556		(13)		1,543
Other Power Regions	5,035		1,681		6,716		16		6,732
Total Reportable Segment Power Revenues	18,421		1,263		19,684		—		19,684
Total Natural Gas Revenues	2,559		2,408		4,967		—		4,967
Total Other Revenues(b)	591		(802)		(211)		—		(211)
Total Consolidated Operating Revenues	$	21,571	$	2,869	$	24,440	$	—	$	24,440


	2021
	Revenues from external customers(c)
	Contracts with customers		Other(a)		Total		Intersegment Revenues		Total Revenues
Mid-Atlantic	$	4,381	$	183	$	4,564	$	20	$	4,584
Midwest	4,265		(205)		4,060		—		4,060
New York	1,633		(57)		1,576		(1)		1,575
ERCOT	896		276		1,172		9		1,181
Other Power Regions	3,937		981		4,918		(28)		4,890
Total Reportable Segment Power Revenues	15,112		1,178		16,290		—		16,290
Total Natural Gas Revenues	1,777		1,602		3,379		—		3,379
Total Other Revenues(b)	365		(385)		(20)		—		(20)
Total Consolidated Operating Revenues	$	17,254	$	2,395	$	19,649	$	—	$	19,649

(a)Includes revenues from derivatives and leases.

(b)Represents activities not allocated to a region. See text above for a description of included activities. Includes unrealized mark-to-market gains of $1,399 million and losses of $1,188 million, and $633 million for the years ended December 31, 2023, 2022, and 2021, respectively.

(c)Includes all wholesale and retail electric sales to third parties and affiliated sales to Exelon's utility subsidiaries prior to the separation on February 1, 2022. See Note 24 — Related Party Transactions for additional information.

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 5 — Segment Information


	2023						2022						2021
	RNF from external customers		Intersegment RNF		Total RNF		RNF from external customers(b)		Intersegment RNF		Total RNF		RNF from external customers(b)		Intersegment RNF		Total RNF
Mid-Atlantic	$	2,972	$	(48)	$	2,924	$	2,129	$	9	$	2,138	$	2,247	$	17	$	2,264
Midwest	3,252		3		3,255		2,765		(1)		2,764		2,717		—		2,717
New York	1,189		62		1,251		1,061		6		1,067		1,151		10		1,161
ERCOT	588		(6)		582		503		(96)		407		(668)		(157)		(825)
Other Power Regions	1,270		(30)		1,240		952		(31)		921		984		(93)		891
Total RNF for Reportable Segments	9,271		(19)		9,252		7,410		(113)		7,297		6,431		(223)		6,208
Other(a)	(354)		19		(335)		(432)		113		(319)		1,055		223		1,278
Total RNF	$	8,917	$	—	$	8,917	$	6,978	$	—	$	6,978	$	7,486	$	—	$	7,486

(a)Other represents activities not allocated to a region. See text above for a description of included activities. Primarily includes:

Unrealized mark-to-market losses of $972 million and $1,013 million and gains of $565 million for the years ended December 31, 2023, 2022, and 2021, respectively; and
Accelerated nuclear fuel amortization associated with the announced early plant retirements as discussed in Note 7 - Early Plant Retirements of $148 million for the year ended December 31, 2021.

(b)Includes purchases and sales from/to third parties and affiliated sales to Exelon's utility subsidiaries prior to the separation on February 1, 2022. See Note 24 — Related Party Transactions for additional information.

6. Accounts Receivable

Unbilled Customer Revenue

We recorded $372 million and $564 million of unbilled customer revenues in Customer accounts receivables, net in the Consolidated Balance Sheets as of December 31, 2023 and 2022, respectively.

Sales of Customer Accounts Receivable

On April 8, 2020, NER, a bankruptcy remote, special purpose entity, which is wholly owned by us, entered into a revolving accounts receivable financing arrangement with a number of financial institutions and a commercial paper conduit (Purchasers) to sell certain customer accounts receivable (Facility). On August 16, 2022, we entered into an amendment on the Facility, which increased the maximum funding limit of the Facility from $900 million to $1.1 billion and extended the term of the Facility through August 15, 2025, unless renewed by the mutual consent of the parties in accordance with its terms. Under the Facility, NER may sell eligible short-term customer accounts receivable to the Purchasers in exchange for cash and subordinated interest. The transfers are reported as sales of receivables in the consolidated financial statements. The subordinated interest in collections upon the receivables sold to the Purchasers is referred to as the DPP, which is reflected in Other current assets in the Consolidated Balance Sheets.

The Facility requires the balance of eligible receivables to be maintained at or above the balance of cash proceeds received from the Purchasers. To the extent the eligible receivables decrease below such balance, we are required to repay cash to the Purchasers. When eligible receivables exceed cash proceeds, we have the ability to increase the cash received up to the maximum funding limit. These cash inflows and outflows impact the DPP.

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 6 — Accounts Receivable

The following table summarizes the impact of the sale of certain receivables:


	As of December 31,
	2023		2022
Derecognized receivables transferred at fair value	$	1,516	$	1,615
Less: Cash proceeds received	300		1,100
DPP	$	1,216	$	515


	For the Years Ended December 31,
	2023		2022		2021
Loss on sale of receivables(a)	$	75	$	69	$	36

(a)Reflected in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. This represents the amount by which the accounts receivable sold into the Facility are discounted, limited to credit losses.


	For the Years Ended December 31,
	2023		2022		2021
Proceeds from new transfers(a)	$	3,649	$	6,108	$	6,095
Cash collections received on DPP and reinvested in the Facility(b)	8,140		4,764		3,502
Cash collections reinvested in the Facility	$	11,789	$	10,872	$	9,597

(a)Customer accounts receivable sold into the Facility were $11,746 million, $11,274 million, and $9,747 million for the years ended December 31, 2023, 2022, and 2021, respectively.

(b)Does not include the $800 million net cash payments to the Purchasers in 2023, the $200 million net cash proceeds received from the Purchasers in 2022, or $400 million cash proceeds received from the Purchases in 2021.

Our risk of loss following the transfer of accounts receivable is limited to the DPP outstanding. Payment of DPP is not subject to significant risks other than delinquencies and credit losses on accounts receivable transferred.

We recognize the cash proceeds received upon sale in Cash flows from operating activities in the Consolidated Statements of Cash Flows. The collection and reinvestment of DPP is recognized in Cash flows from investing activities in the Consolidated Statements of Cash Flows.

See Note 18 — Fair Value of Financial Assets and Liabilities and Note 22 — Variable Interest Entities for additional information.

Other Sales of Customer Accounts Receivables

We are required, under supplier tariffs, to sell customer receivables to utility companies. The following table presents the total receivables sold:


	For the Years Ended December 31,
	2023		2022		2021
Total receivables sold	$	356	$	423	$	147

7. Early Plant Retirements

We continuously evaluate factors that affect the current and expected economic value of our plants, including, but not limited to: market power prices, results of capacity auctions, potential legislative and regulatory solutions to ensure plants are fairly compensated for benefits they provide through their carbon-free emissions, reliability or fuel security, and the impact of potential rules from the EPA requiring reduction of carbon and other emissions and the efforts of states to implement those final rules. We remain committed to continued operations for our nuclear plants receiving state-supported payments under the Illinois CMC (Byron, Dresden, and Braidwood), Illinois ZES (Clinton and Quad Cities), New Jersey ZEC program (Salem), and the New York CES (FitzPatrick, Ginna, and Nine Mile Point), assuming the continued effectiveness of each program. While the current ZEC

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 7 — Early Plant Retirements

program in New York ends in 2029, the state has acknowledged our nuclear assets are vital to achieving its clean energy goals and we believe New York will continue to promote policies that support nuclear in the state beyond 2029. With the passage of the IRA, we expect that many of our nuclear assets will operate at least through the end of the nuclear PTC period, concluding at the end of 2032. To enable long term operations, we plan to file applications to extend the licenses of our nuclear fleet to 80 years for the units that receive continued support under federal or state policies or a combination of both. See Note 8 — Property, Plant, and Equipment for additional information on depreciable provisions of the stations, and Note 10 — Asset Retirement Obligations for additional information on ARO.

Nuclear Generation

On August 27, 2020, we announced our intention to permanently cease our operations at Byron in September 2021 and at Dresden in November 2021. On September 15, 2021, we announced that we had reversed our previous decision to retire Byron and Dresden given the opportunity for additional revenue under the Illinois Clean Energy Law. Our Byron, Dresden, and Braidwood nuclear plants were each awarded CMC contracts.

In 2021, we reversed $81 million of severance benefit costs and $13 million of other one-time charges initially recorded in Operating and maintenance expense in 2020 associated with the early retirements. In addition, we updated the expected economic useful life for both facilities to 2044 and 2046, for Byron Units 1 and 2, respectively, and to 2029 and 2031 for Dresden Units 2 and 3, respectively, the end of the respective NRC operating license for each unit. Depreciation was therefore adjusted beginning September 15, 2021, to reflect these extended useful life estimates. See Note 10 — Asset Retirement Obligations for additional detail on changes to the nuclear decommissioning ARO balances resulting from the initial decision and subsequent reversal of the decision to early retire Byron and Dresden.

The total impact for the year ended December 31, 2021 in the Consolidated Statements of Operations and Comprehensive Income resulting from the initial decision and subsequent reversal of the decision to early retire Byron and Dresden is summarized in the table below:


Income statement expense (pre-tax)	For the Year Ended December 31, 2021
Depreciation and amortization
Accelerated depreciation(a)	$	1,805
Accelerated nuclear fuel amortization	148
Operating and maintenance
One-time charges	(94)
Other charges	9
Contractual offset(b)	(451)
Total	$	1,417

(a)Includes the accelerated depreciation of plant assets including any ARC.

(b)Reflects contractual offset for ARO accretion, ARC depreciation, ARO remeasurement, and excludes any changes in earnings in the NDT funds. Decommissioning-related impacts were not offset for the Byron units starting in the second quarter of 2021 due to the inability to recognize a regulatory asset at ComEd. With our September 15, 2021 reversal of the previous decision to retire Byron, we resumed contractual offset for Byron as of that date. Based on the regulatory agreement with the ICC, decommissioning-related activities are offset in the Consolidated Statements of Operations and Comprehensive Income as long as the net cumulative decommissioning-related activity result in a regulatory liability at ComEd. The offset resulted in an equal adjustment to the noncurrent payables to ComEd. See Note 10 - Asset Retirement Obligations for additional information.

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 7 — Early Plant Retirements

Other Generation

In March 2018, we notified ISO-NE of our plans to early retire the Mystic Generating Station's units 8 and 9 ("Mystic 8 and 9") absent regulatory reforms to properly value reliability and regional fuel security. Thereafter, ISO-NE identified Mystic 8 and 9 as being needed to ensure fuel security for the region and entered into a cost of service agreement with these two units for the period between June 1, 2022 to May 31, 2024. The agreement was approved by FERC in December 2018. In August 2020, we announced we will permanently cease generation operations at Mystic 8 and 9 at the expiration of the cost of service commitment in May 2024. See Note 3 — Regulatory Matters for additional discussion of Mystic’s cost of service agreement. The annual financial impacts stemming from shortening the expected economic useful life of Mystic 8 and 9 were not material to the periods presented.

8. Property, Plant, and Equipment

The following table presents a summary of property, plant, and equipment by asset category as of December 31, 2023 and 2022:


Asset Category	December 31, 2023		December 31, 2022
Electric	$	32,889	$	30,804
Nuclear fuel(a)	5,503		5,106
Construction work in progress	1,133		630
Other property, plant, and equipment	14		8
Total property, plant, and equipment	39,539		36,548
Less: accumulated depreciation(b)	17,423		16,726
Property, plant, and equipment, net	$	22,116	$	19,822

(a)Includes nuclear fuel that is in the fabrication and installation phase of $1,265 million and $937 million as of December 31, 2023 and 2022, respectively.

(b)Includes accumulated amortization of nuclear fuel in the reactor core of $2,484 million and $2,657 million as of December 31, 2023 and 2022, respectively.

The following table presents the average service life for each asset category in number of years:


Asset Category			Average Service Life (years)
Electric			1-60
Nuclear fuel			1-8
Other property, plant, and equipment			1-10

Depreciation provisions are based on the estimated useful lives of the stations, which generally correspond with the term of the NRC operating licenses, except for Clinton, Dresden Units 2 and 3, Ginna, NMP Unit 1, Peach Bottom Units 2 and 3 and Conowingo. Depreciation provisions for Clinton, Dresden Units 2 and 3, Ginna, NMP Unit 1, and Peach Bottom Units 2 and 3 all assume an additional 20 years beyond current license expiration. Conowingo depreciation provisions are based on an estimated useful life through 2071, in anticipation that a 50-year license will be issued. See Note 3 — Regulatory Matters for additional information regarding license renewals for Peach Bottom and Conowingo.

Beginning August 2020, Byron and Dresden depreciation provisions were based on their announced shutdown dates of September 2021, November 2021, and May 2024, respectively. On September 15, 2021, we updated the estimated useful lives for Byron and Dresden to reflect the end of the available NRC operating license for each unit. Beginning in the third quarter of 2022, we updated Dresden depreciation provisions consistent with the license renewal of 2029. See Note 3 — Regulatory Matters for additional information regarding license renewals for Peach Bottom and Conowingo. See Note 7 — Early Plant Retirements for additional information on the impacts related to Byron and Dresden.

Annual depreciation rates for electric generation were 3.26%, 3.46%, and 8.67% for the years ended December 31, 2023, 2022, and 2021, respectively. Nuclear fuel amortization is charged to fuel expense using the unit-of-production method and not included in the annual depreciation rates.

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 9 — Jointly Owned Electric Plant

9. Jointly Owned Electric Plant

Our material undivided ownership interests in jointly owned nuclear plants as of December 31, 2023 and 2022 were as follows:


	Nuclear Generation
	Quad Cities			Peach Bottom			Salem			Nine Mile Point Unit 2			South Texas Project
Operator	Constellation			Constellation			PSEG Nuclear			Constellation			STPNOC
Ownership interest	75.00		%	50.00		%	42.59		%	82.00		%	44.00		%
Our share as of December 31, 2023
Plant in service	$	1,263		$	1,552		$	781		$	1,073		$	1,089
Accumulated depreciation	805			689			357			292			5
Construction work in progress	8			14			49			35			13
Our share as of December 31, 2022
Plant in service	$	1,243		$	1,534		$	772		$	1,063		$	—
Accumulated depreciation	761			659			328			256			—
Construction work in progress	7			12			23			26			—

Our undivided ownership interests are financed with our funds and all operations are proportionately consolidated consistent with our ownership interest. Our share of direct expenses of the jointly owned plants are included in Purchased power and fuel and Operating and maintenance expenses in the Consolidated Statements of Operations and Comprehensive Income.

10. Asset Retirement Obligations

Nuclear Decommissioning Asset Retirement Obligations

We have a legal obligation to decommission our nuclear power plants following the permanent cessation of operations. To estimate our nuclear decommissioning obligations we use 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. We update our AROs annually, unless circumstances warrant more frequent updates, based on our review of updated cost studies and our annual evaluation of cost escalation factors and probabilities assigned to various scenarios. We began decommissioning the TMI nuclear plant upon permanently ceasing operations in 2019. See below for further discussion of the decommissioning of Zion Station.

The financial statement impact for changes in the ARO, on an individual unit basis, due to the changes in and timing of estimated cash flows generally result in a corresponding change in the unit’s ARC in Property, plant, and equipment in the Consolidated Balance Sheets. If the ARO decreases for a Non-Regulatory Agreement unit without any remaining ARC, the corresponding change is recorded as a decrease in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income, whereas the corresponding

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 10 — Asset Retirement Obligations

decrease for Regulatory Agreement Units without any remaining ARC results in an increase to the Payables related to Regulatory Agreement Units in the Consolidated Balance Sheets.

The following table provides a rollforward of the nuclear decommissioning AROs reflected in the Consolidated Balance Sheets from January 1, 2022 to December 31, 2023:


	2023		2022
Beginning balance as of January 1	$	12,500	$	12,676
Net increase (decrease) due to changes in, and timing of, estimated future cash flows	411		(648)
Accretion expense	582		532
Acquisition of joint ownership in STP(b)	429		—
Costs incurred related to decommissioning plants	(31)		(60)
Ending balance as of December 31(a)	$	13,891	$	12,500

(a)Includes $30 million and $40 million as the current portion of the ARO as of December 31, 2023 and 2022, respectively, which is included in Other current liabilities in the Consolidated Balance Sheets.

(b)Reflects our estimated share of the STP decommissioning obligation. See Note 2 — Mergers, Acquisitions, and Dispositions for additional information.

The net $411 million increase in the ARO during 2023 for changes in the amounts and timing of estimated decommissioning cash flows was driven by multiple adjustments, including the following:

An increase of approximately $610 million due to an increase in cost escalation rates, partially offset by an increase in discount rates.
Net increase of approximately $470 million due to updated cost assumptions for dry cask storage across the fleet and revised cost studies for Dresden, Limerick and Peach Bottom.
Net decrease of approximately $675 million due to changes in assumed retirement dates for Ginna, NMP Unit 1, and Salem.

The 2023 ARO updates resulted in a decrease of $68 million in Operating and maintenance expense for the year ended December 31, 2023 in the Consolidated Statement of Operations and Comprehensive Income.

The net $648 million decrease in the ARO during 2022 for changes in the amounts and timing of estimated decommissioning cash flows was driven by multiple adjustments throughout the year, including the following:

Net decrease of approximately $790 million due to an increase in discount rates partly offset by an increase in cost escalation rates, primarily labor and energy.
A decrease of approximately $235 million due to changes in assumed retirement dates as a result of the passage of the IRA and useful life extension for Clinton and Dresden plants. See Note 3 - Regulatory Matters for additional information.
An increase of approximately $320 million due to revisions to the projected decommissioning schedule for our New York nuclear plants in connection with our separation from Exelon as discussed further below.
Net increase of approximately $75 million due to higher estimated decommissioning costs resulting from the completion of updated cost studies for our New York nuclear plants, Quad Cities, Calvert Cliffs, and Three Mile Island.

The 2022 ARO updates resulted in a decrease of $226 million in Operating and maintenance expense for the year ended December 31, 2022 in the Consolidated Statement of Operations and Comprehensive Income.

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 10 — Asset Retirement Obligations

NDT Funds

NDT funds have been established for each of our nuclear units to satisfy our nuclear decommissioning obligations, as required by the NRC, and withdrawals from these funds for reasons other than to pay for decommissioning are restricted pursuant to NRC requirements until all decommissioning activities have been completed. Generally, NDT funds established for a particular unit may not be used to fund the decommissioning obligations of any other unit.

The NDT funds associated with our nuclear units have been funded with amounts collected from the previous owners and their respective utility customers. PECO is authorized to collect funds, in revenues, through regulated rates for decommissioning the former PECO nuclear plants, and these collections are scheduled through the operating lives of these former PECO plants. The amounts collected from PECO customers are remitted to us and deposited into the NDT funds for the unit for which funds are collected. Every five years, PECO files a rate adjustment with the PAPUC that reflects PECO’s calculations of the estimated amount needed to decommission each of the former PECO units based on updated fund balances and estimated decommissioning costs. The rate adjustment is used to determine the amount collectible from PECO customers. On March 31, 2022, PECO filed its Nuclear Decommissioning Cost Adjustment with the PAPUC proposing an annual recovery from customers of approximately $4 million. On August 19, 2022, the PAPUC approved the filing, and the new rates became effective January 1, 2023.

Additionally, for the newly acquired STP units, we maintain decommissioning trust funds for those units proportionate to our 44% ownership. We also retain the authority through the PUCT to obtain additional decommissioning funding through CenterPoint Energy Houston Electric, LLC and AEP Texas, Inc.

Any shortfall of funds necessary for decommissioning, determined for each generating station unit, are generally required to be funded by us, with the exception of STP and the former PECO nuclear plants. We have recourse to collect additional amounts from the respective utility customers through the utility commissions for the former PECO units and STP in the event of a shortfall of NDT funds. Collection of additional amounts for the former PECO units are subject to certain limitations and thresholds, as prescribed by an order from the PAPUC that limits collection of amounts associated with the first $50 million of any shortfall of trust funds compared to decommissioning costs, as well as 5% of any additional shortfalls, on an aggregate basis for all former PECO units. The initial $50 million and up to 5% of any additional shortfalls would be borne by us. Aside from the former PECO units and STP, no recourse exists to collect additional amounts from utility customers for any of our other nuclear units.

With respect to the Regulatory Agreement Units, any funds remaining in the NDTs after all decommissioning has been completed are required to be refunded to the respective utility customers, subject to certain limitations that allow sharing of excess funds with us related to the former PECO units. With respect to our other nuclear units, we retain any funds remaining after decommissioning. However, in connection with CENG's acquisition of the Nine Mile Point and Ginna plants and settlements with certain regulatory agencies, certain conditions pertaining to NDT funds apply that, if met, could possibly result in obligations to make payments to certain third parties (clawbacks). For Nine Mile Point and Ginna, the clawback provisions are triggered only in the event that the required decommissioning activities are discontinued or not started or completed in a timely manner. In the event that the clawback provisions are triggered for Nine Mile Point, then, depending upon the triggering event, an amount equal to 50% of the total amount withdrawn from the funds for non-decommissioning activities as defined in the agreement or 50% of any excess funds in the trust funds above the amounts required for decommissioning (including SNF management and site restoration) is to be paid to the Nine Mile Point sellers. In the event that the clawback provisions are triggered for Ginna, then an amount equal to any estimated cost savings realized by not completing any of the required decommissioning activities is to be paid to the Ginna sellers. We expect to comply with applicable regulations and timely commence and complete all required decommissioning activities.

We had NDT funds totaling $16,398 million and $14,127 million as of December 31, 2023 and 2022, respectively. As of December 31, 2023, there was no current portion of the NDT funds. $13 million of the NDT funds were current as of December 31, 2022, and included in Other current assets in the Consolidated Balance Sheets. See Note 23 — Supplemental Financial Information for additional information on activities of the NDT funds.

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 10 — Asset Retirement Obligations

Accounting Implications of the Regulatory Agreement Units

See Note 1 — Basis of Presentation for additional information on the accounting policy for Regulatory Agreement Units.

For the former PECO units and STP, given the symmetric settlement provisions that allow for continued recovery of decommissioning costs from the respective utility customers in the event of a shortfall and the obligation for us to ultimately return excess funds to the respective utility customers (on an aggregate basis for all seven former PECO units and on the underlying utility customer basis for STP) decommissioning-related activities are generally offset in the Consolidated Statements of Operations and Comprehensive Income regardless of whether the NDT funds are expected to exceed or fall short of the total estimated decommissioning obligation. The offset of decommissioning-related activities in the Consolidated Statements of Operations and Comprehensive Income results in an equal adjustment to noncurrent payables or noncurrent receivables. Any changes to the existing PECO or STP regulatory agreements could impact our ability to offset decommissioning-related activities in the Consolidated Statements of Operations and Comprehensive Income, and the potential impact to our consolidated financial statements could be material.

For the former ComEd units, given no further recovery from ComEd customers is permitted and we retain an obligation to ultimately return any unused NDTs to ComEd customers (on a unit-by-unit basis), to the extent the related NDT investment balances are expected to exceed the total estimated decommissioning obligation for each unit, decommissioning-related activities are offset in the Consolidated Statements of Operations and Comprehensive Income which results in us recognizing a noncurrent payable. However, given the asymmetric settlement provision that does not allow for continued recovery from ComEd customers in the event of a shortfall, recognition of a receivable related to former ComEd Units is not permissible and accounting for decommissioning-related activities for that unit would not be offset, and the impact to the Consolidated Statements of Operations and Comprehensive Income could be material during such periods. For the year ended December 31, 2021, a pre-tax charge of $193 million was recorded in the Consolidated 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. With our September 15, 2021 reversal of the previous decision to retire Byron and the corresponding adjustment to the ARO for Byron discussed previously, we resumed contractual offset for Byron as of that date.

The following table presents our noncurrent payables to ComEd and PECO, as well as CenterPoint Energy Houston Electric, LLC and AEP Texas, Inc. for STP, which are recorded as Payables related to Regulatory Agreement Units in the Consolidated Balance Sheets as of December 31, 2023 and 2022:


	As of December 31,
	2023		2022
ComEd	$	2,955	$	2,660
PECO	278		237
CenterPoint Energy Houston Electric, LLC	338		—
AEP Texas, Inc.	117		—
Payables related to Regulatory Agreement Units	$	3,688	$	2,897

As of December 31, 2023, decommissioning-related activities for all of the former ComEd units, except for Zion (see Zion Station Decommissioning below), are currently offset in the Consolidated Statements of Operations and Comprehensive Income.

The decommissioning-related activities for the Non-Regulatory Agreement Units are reflected in the Consolidated Statements of Operations and Comprehensive Income within Operating and maintenance expense, Depreciation and amortization expense, and in Other, net.

Zion Station Decommissioning

In 2010, we completed an ASA under which ZionSolutions assumed responsibility for decommissioning Zion Station and we transferred to ZionSolutions substantially all the Zion Station’s assets, including the related NDT funds. On November 16, 2023, ZionSolutions completed its contractual obligations and transferred the NRC

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 10 — Asset Retirement Obligations

license back to us. We will store the SNF at Zion Station until it is transferred to the DOE for ultimate disposal and complete all remaining decommissioning activities associated with the SNF dry storage facility.

Any shortage of funds necessary to maintain the SNF and decommission the SNF storage facility is ultimately required to be funded by us. As of December 31, 2023 and 2022, the ARO associated with Zion's SNF storage facility is $139 million and $138 million, respectively, and the NDT funds available to fund this obligation are $62 million and $58 million, respectively.

NRC Minimum Funding Requirements

NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts to decommission the facility at the end of its life. The estimated decommissioning obligations are calculated using an NRC methodology that is different from the ARO recorded in the Consolidated Balance Sheets primarily due to differences in the type of costs included in the estimates, the basis for estimating such costs, and assumptions regarding the decommissioning alternatives to be used, potential license renewals, decommissioning cost escalation, and the growth rate in the NDT funds. Under NRC regulations, if the minimum funding requirements for radiological decommissioning calculated under the NRC methodology are greater than the future value of the NDT funds, also calculated under the NRC methodology, then the NRC requires resolution of the shortfalls which could include further funding or other financial guarantees.

Key assumptions used in the minimum funding calculation for radiological decommissioning costs using the NRC methodology at December 31, 2023 include: (1) consideration of costs only for the removal of radiological contamination at each unit; (2) the option on a unit-by-unit basis to use generic, non-site specific cost estimates; (3) consideration of only one decommissioning scenario for each unit; (4) the plants cease operation at the end of their current license lives (with no assumed license renewals for those units that have not already received renewals); (5) the assumption of current nominal dollar cost estimates that are neither escalated through the anticipated period of decommissioning, nor discounted using the CARFR; and (6) assumed annual after-tax returns on the NDT funds of 2% (3% for the former PECO units, as specified by the PAPUC).

In contrast, the key criteria and assumptions used by us to determine the ARO and to forecast the target growth in the NDT funds as of December 31, 2023 include: (1) the use of site specific cost estimates that are updated at least once every five years; (2) the inclusion in the ARO estimate of all legally unavoidable costs required to decommission the unit (e.g., radiological decommissioning and full site restoration for certain units, on-site SNF maintenance and storage subsequent to ceasing operations and until DOE acceptance, and disposal of certain LLRW); (3) as applicable, the consideration of multiple scenarios where decommissioning and site restoration activities, as applicable, are completed under possible scenarios ranging from 10 to 70 years after the cessation of plant operations or the end of the current licensed operating life; (4) the consideration of multiple end of life scenarios; (5) the measurement of the obligation at the present value of the future estimated costs and an annual average accretion of the ARO of approximately 4% through a period of approximately 30 years after the end of the extended lives of the units; and (6) an estimated targeted annual pre-tax return on the NDT funds of 6.1% to 7.1% (as compared to a historical 5-year annual average pre-tax return of approximately 8.0%).

We are required to provide to the NRC a biennial report by unit (annually for units that have been retired or are within five years of license expiration), based on values as of December 31, addressing our ability to meet the NRC minimum funding levels. Depending on the value of the trust funds, we may be required to take steps, such as providing financial guarantees through surety bonds, letters of credit, or parent company guarantees or making additional contributions to the trusts, which could be significant, to ensure that the trusts are adequately funded and that NRC minimum funding requirements are met. As a result, our cash flows and financial position may be significantly adversely affected.

We filed our biennial decommissioning funding status report with the NRC on March 23, 2023 for all units, including our shutdown units, except for Zion Station which was included in a separate report to the NRC submitted by ZionSolutions, LLC. The status report demonstrated adequate decommissioning funding assurance as of December 31, 2022 for all units except for Peach Bottom Unit 1. As a former PECO plant, financial assurance for decommissioning Peach Bottom Unit 1 is provided by the NDT fund, collections from PECO customers, and the ability to adjust those collections in accordance with the approved PAPUC tariff. See NDT Funds section above for additional information. Additionally, the STP units demonstrated adequate

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 10 — Asset Retirement Obligations

decommissioning funding assurance as of December 31, 2022 in the decommissioning funding status report filed with the NRC by STPNOC on March 29, 2023.

We will file the next decommissioning funding status report with the NRC by March 31, 2024. This report will reflect the status of decommissioning funding as of December 31, 2023 for shutdown units, including Zion, and any units within five years of license expiration. We expect the funding status report to demonstrate adequate funding assurance for all units except for Peach Bottom Unit 1. Financial assurance for decommissioning Peach Bottom Unit 1 is provided by the collections from PECO customers as mentioned above. Additionally, the decommissioning funding status report for STP following our November 1, 2023 acquisition of a 44% interest will be filed by STPNOC in March 2024. The status report will demonstrate adequate funding assurance as of December 31, 2023.

As the future values of trust funds change due to market conditions, the NRC minimum funding status of our units will change. In addition, if changes occur to the regulatory agreements with the PAPUC or the PUCT that currently allow amounts to be collected from utility customers for decommissioning the former PECO and STP units, the NRC minimum funding status of those plants could change at subsequent NRC filing dates.

Impact of Separation from Exelon

Satisfying a condition precedent, on December 16, 2021, the NYPSC authorized our separation from Exelon and accepted the terms of a Joint Proposal that became binding upon closing of the separation on February 1, 2022. As part of the Joint Proposal, among other items, we have projected completion of radiological decommissioning and site restoration activities necessary to achieve a partial site release from the NRC (release of the site for unrestricted use, except for any on-site dry cask storage) within 20 years from the end of licensed life for each of our Ginna and FitzPatrick units and from the end of licensed life for the last of the NMP operating units. While there is flexibility under the Joint Proposal, there was an increase to the AROs, as noted above, associated with our New York nuclear plants during the first quarter of 2022.

The Joint Proposal also required a contribution of $15 million to the NDT for NMP Unit 2 in January 2022 and requires various financial assurance mechanisms through the duration of decommissioning and site restoration, including a minimum NDT balance for each unit, adjusted for specific stages of decommissioning, and a parent guaranty for site restoration costs updated annually as site restoration progresses, which must be replaced with a third-party surety bond or equivalent financial instrument in the event we were to fall below investment grade.

See Note 1 — Basis of Presentation for additional information on the separation.

Non-Nuclear Asset Retirement Obligations

We have AROs for plant closure costs associated with our natural gas, oil, and renewable generating facilities, including asbestos abatement, removal of certain storage tanks, restoring leased land to the condition it was in prior to construction of renewable generating stations, and other decommissioning-related activities. See Note 1 — Basis of Presentation for additional information on the accounting policy for AROs.

The following table provides a rollforward of the non-nuclear AROs reflected in the Consolidated Balance Sheets from January 1, 2022 to December 31, 2023:


	2023		2022
Beginning balance as of January 1	$	239	$	216
Net increase due to changes in, and timing of, estimated future cash flows	14		18
Accretion expense	14		11
Asset divestitures	(9)		(1)
Payments	(1)		(5)

Ending balance as of December 31	$	257	$	239

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 11 — Leases

11. Leases

Lessee

We have operating leases for which we are the lessee. The significant types of leases are contracted generation, real estate, and vehicles and equipment. The following table outlines other terms and conditions of the lease agreements as of December 31, 2023. We did not have material finance leases in 2023, 2022, or 2021.


			In Years
Remaining lease terms			1-32
Options to extend the term			2-30
Options to terminate within			1

The components of operating lease costs were as follows:


	For the Years Ended December 31,
	2023		2022		2021
Operating lease costs	$	96	$	109	$	161
Variable lease costs	146		169		168





Total lease costs(a)	$	242	$	278	$	329

(a)Excludes $50 million, $49 million, $44 million of sublease income recorded for each of the years ended December 31, 2023, 2022, and 2021, respectively.

The following table provides additional information regarding the presentation of operating lease ROU assets and lease liabilities in the Consolidated Balance Sheets:


	As of December 31,
	2023		2022
Operating lease ROU assets(a)
Other deferred debits and other assets	$	494	$	545

Operating lease liabilities(a)
Other current liabilities	67		67
Other deferred credits and other liabilities	583		643
Total operating lease liabilities	$	650	$	710

(a)The operating ROU assets and lease liabilities include $212 million and $334 million, respectively, related to contracted generation as of December 31, 2023, and $248 million and $377 million, respectively, as of December 31, 2022.

The weighted average remaining lease terms, in years, and the weighted average discount rates for operating leases were as follows:


	As of December 31,
	2023		2022		2021
Weighted average remaining lease term	8.4		9.3		10.1
Weighted average discount rate	5.0	%	5.0	%	5.0	%

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 11 — Leases

The following table reconciles the undiscounted cash flows for our operating leases to the operating lease liabilities recorded on our consolidated balance sheet as of December 31, 2023:


2024	$	101
2025	104
2026	104
2027	102
2028	103
Thereafter	325
Total lease payments	839
Less: Imputed interest	189
Operating lease liabilities	$	650

Supplemental cash flow information related to operating leases was as follows:


	For the Years Ended December 31,
	2023		2022		2021
Cash paid for amounts included in the measurement of operating lease liabilities	$	102	$	114	$	162
ROU assets obtained in exchange for operating lease obligations	13		14		2

Lessor

We have operating leases for which we are the lessor. The significant types of leases are contracted generation and real estate. The following table outlines other terms and conditions of the lease agreements as of December 31, 2023.


			In Years
Remaining lease terms			1-17
Options to extend the term			1-20

The components of lease income were as follows:


	For the Years Ended December 31,
	2023		2022		2021
Operating lease income	$	51	$	51	$	47
Variable lease income	248		258		261

The following table presents maturity analysis of the lease payments we expect to receive as of December 31, 2023:


2024	$	48
2025	48
2026	49
2027	49
2028	48
Thereafter	85
Total	$	327

12. Asset Impairments

We evaluate the carrying value of long-lived assets or asset groups for recoverability whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators of

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 12 — Asset Impairments

impairment may include a deteriorating business climate, including, but not limited to, declines in energy prices, condition of the asset, or plans to dispose of a long-lived asset significantly before the end of its useful life. We determine if long-lived assets or asset groups are potentially impaired by comparing the undiscounted expected future cash flows to the carrying value when indicators of impairment exist. When the undiscounted cash flow analysis indicates a long-lived asset or asset group may not be recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. The fair value analysis is primarily based on the income approach using significant unobservable inputs (Level 3) including revenue and generation forecasts, projected capital and maintenance expenditures and discount rates. A variation in the assumptions used could lead to a different conclusion regarding the recoverability of an asset or asset group and, thus, could potentially result in material future impairments of our long-lived assets. Generally, pre-tax impairment losses on long-lived assets or asset groups are recorded in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income.

New England Asset Group

In the second quarter of 2021, an overall decline in the asset group's portfolio value suggested that the carrying value of the New England asset group may be impaired. We completed a comprehensive review of the estimated undiscounted future cash flows of the New England asset group and concluded that the carrying value was not recoverable and that its fair value was less than its carrying value. As a result, a pre-tax impairment charge of $350 million was recorded in the second quarter of 2021 in Operating and maintenance expense in the Consolidated Statement of Operations and Comprehensive Income.

13. Intangible Assets

Goodwill

The following table presents the carrying amount of goodwill as of December 31, 2023 and 2022. There were no impairment losses during the years ended December 31, 2023, 2022, and 2021.


	Goodwill
Balance at December 31, 2022	$	47
Goodwill resulting from acquisition of STP(a)	378
Balance at December 31, 2023	$	425

(a)See Note 2 — Mergers, Acquisitions, and Dispositions for additional information.

See Note 1 — Basis of Presentation for our policy regarding goodwill. Our operating segments are also considered reporting units for goodwill impairment assessment purposes. The goodwill recognized in 2023 has been assigned entirely to the ERCOT operating segment.

Other Intangible Assets and Liabilities

Our other intangible assets and liabilities, included in Other current assets, Other deferred debits and other assets, Other current liabilities, Other deferred credits and other liabilities in the Consolidated Balance Sheets, consisted of the following as of December 31, 2023 and 2022. The intangible assets and liabilities shown below are generally amortized on a straight line basis, except for unamortized energy contracts which are amortized in relation to the expected realization of the underlying cash flows:


	December 31, 2023						December 31, 2022
	Gross		Accumulated Amortization		Net		Gross		Accumulated Amortization		Net
Unamortized Energy Contracts	$	1,892	$	(1,631)	$	261	$	1,960	$	(1,708)	$	252
Customer Relationships	242		(167)		75		356		(265)		91


Total	$	2,134	$	(1,798)	$	336	$	2,316	$	(1,973)	$	343

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 13 — Intangible Assets

The following table summarizes the amortization expense related to our other intangible assets and liabilities for each of the years ended December 31, 2023, 2022, and 2021:


For the Years Ended December 31,	Amortization Expense(a)
2023	$	58
2022	61
2021	80

(a)See Note 23 — Supplemental Financial Information for additional information related to the amortization of unamortized energy contracts.

The following table summarizes the estimated future amortization expense related to our other intangible assets and liabilities as of December 31, 2023:


For the Years Ending December 31,	Estimated Future Amortization Expense
2024	$	62
2025	58
2026	51
2027	37
2028	31
2029 and thereafter	97

14. Income Taxes

Components of Income Tax Expense or Benefit

Income taxes are comprised of the following components:


	For the Years Ended December 31,
	2023		2022		2021
Federal
Current	$	464	$	219	$	394
Deferred	301		(655)		(153)
ITC amortization	(15)		(15)		(15)
State
Current	142		34		36
Deferred	(33)		29		(37)
Total income tax (benefit) expense	$	859	$	(388)	$	225

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 14 — Income Taxes

Rate Reconciliation

The effective income tax rate varies from the U.S. federal statutory rate principally due to the following:


	For the Years Ended December 31,
	2023(a)		2022(b)		2021(a)
U.S. federal statutory rate	21.0	%	21.0	%	21.0	%
(Decrease) increase due to:
State income taxes, net of federal income tax benefit(c)	3.5		(9.2)		—
Qualified NDT fund income and losses	10.3		46.3		165.1
Amortization of investment tax credit, including deferred taxes on basis differences	(0.5)		2.2		(9.0)

Production tax credits and other credits	(0.6)		7.7		(28.7)
Noncontrolling interests	0.4		(0.3)		(3.0)


Other(d)	1.0		3.9		2.6
Effective income tax rate(e)	35.1	%	71.6	%	148.0	%

(a)Positive percentages represent income tax expense. Negative percentages represent income tax benefit.

(b)As there was a pre-tax loss during 2022, negative percentages represent income tax expense. Positive percentages represent income tax benefit.

(c)Includes ($4) million and $30 million related to state rate changes and certain state tax positions in 2023 and 2022, respectively.

(d)Primarily related to disallowed excess officer compensation in 2023 and $32 million prior period income tax adjustment recorded in 2022.

(e)The change in effective tax rate in 2023 is primarily due to the impacts of higher realized NDT Income and significant pretax income in 2023 compared to pretax loss in 2022.

Tax Differences and Carryforwards

The tax effects of temporary differences and carryforwards, which give rise to significant portions of the deferred tax assets (liabilities), as of December 31, 2023 and 2022 are presented below:


	December 31, 2023		December 31, 2022
Plant basis differences	$	(3,130)	$	(3,005)
Accrual-based contracts	(32)		(35)
Derivatives and other financial instruments	984		43
Deferred pension and postretirement obligation	(314)		287
Nuclear decommissioning activities	(640)		(371)
Tax loss carryforward, net of valuation allowances	47		67
Tax credit carryforward	—		179
Investment in partnerships	(193)		(205)
Other, net	460		407
Deferred income tax liabilities (net)	(2,818)		(2,633)
Unamortized ITCs	(339)		(354)
Total deferred income tax liabilities (net) and unamortized ITCs	$	(3,157)	$	(2,987)

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 14 — Income Taxes

The following table provides our carryforwards, of which the state-related items are presented on a post-apportioned basis, and any corresponding valuation allowances as of December 31, 2023:


Federal	December 31, 2023


Federal general business credits carryforwards and other carryforwards	$	—
Year in which net operating loss or credit carryforwards will begin to expire	2043
State
State net operating losses and other carryforwards	477
Deferred taxes on state tax attributes (net)	21
Valuation allowance on state tax attributes	(10)
Foreign
Foreign net operating losses and other carryforwards	145
Deferred taxes on foreign tax attributes (net)	36

Unrecognized Tax Benefits

Our unrecognized tax benefits were not material as of and for the 12 months ended December 31, 2023, 2022, and 2021, and if recognized, would not significantly impact our effective tax rate. Further, these amounts are not expected to significantly increase or decrease within the next 12 months.

Total amounts of interest and penalties recognized

We did not record material interest and penalty expense related to tax positions reflected in the Consolidated Balance Sheets. Interest expense and penalty expense are recorded in Interest expense, net and Other, net, respectively, in Other income and deductions in the Consolidated Statements of Operations and Comprehensive Income.

Description of tax years open to assessment by major jurisdiction


Major Jurisdiction			Open Years(a)
Federal consolidated income tax returns			2010-2022
Illinois unitary corporate income tax returns			2012-2022
New Jersey separate corporate income tax returns			2017-2018
New Jersey combined corporate income tax returns			2019-2022
New York combined corporate income tax returns			2015-2022
Pennsylvania separate corporate income tax returns			2020-2022

(a)Tax years open to assessment include years when we were consolidated by Exelon. See discussion below under the Tax Matters Agreement for responsibility of taxes of these open years.

Other Tax Matters

Allocation of Tax Benefits

Prior to separation, we were a party to an agreement with Exelon and other subsidiaries of Exelon that provided for the allocation of consolidated tax liabilities and benefits (Tax Sharing Agreement). The Tax Sharing Agreement provided that each party was allocated an amount of tax similar to that which would be owed had the party been separately subject to tax. In addition, any net federal and state benefits attributable to Exelon were reallocated to the parties. That allocation was treated as a contribution from Exelon to the party receiving the benefit.

The allocation of tax benefits from Exelon to us under the Tax Sharing Agreement at December 31, 2021 was $64 million.

Tax Matters Agreement

In connection with the separation, we entered into a Tax Matters Agreement (TMA) with Exelon. The TMA governs the respective rights, responsibilities, and obligations between us and Exelon after the separation with

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 14 — Income Taxes

respect to tax liabilities and benefits, tax attributes, tax returns, tax contests and other tax sharing regarding U.S. federal, state, local and foreign income taxes, other tax matters and related tax returns.

Responsibility and Indemnification for Taxes. As a former subsidiary of Exelon, we have joint and several liability with Exelon to the IRS and certain state jurisdictions relating to the taxable periods that we were included in federal and state filings. However, the TMA specifies the portion of this tax liability for which we will bear contractual responsibility, and we and Exelon agreed to indemnify each other against any amounts for which such indemnified party is not responsible. Specifically, we will be liable for taxes due and payable in connection with tax returns that we are required to file. We will also be liable for our share of certain taxes required to be paid by Exelon with respect to taxable years or periods (or portions thereof) ending on or prior to the separation to the extent that we would have been responsible for such taxes under the Exelon tax sharing agreement then existing. As such, our Consolidated Balance Sheets at separation reflected a payable of $103 million for tax liabilities where we maintain contractual responsibility to Exelon, with $53 million recognized in Accounts payable and accrued expenses and $50 million in Noncurrent other liabilities. As of December 31, 2023 and 2022, respectively, we had $11 million and $18 million in Other accounts receivable, no payables in Accounts payable and accrued expenses and $37 million and $50 million in Noncurrent other liabilities.

Tax Refunds and Attributes. The TMA provides for the allocation of certain pre-closing tax attributes between us and Exelon. Tax attributes will be allocated in accordance with the principles set forth in the existing Exelon tax sharing agreement, unless otherwise required by law. Under the TMA, we will be entitled to refunds for taxes for which we are responsible. In addition, it is expected that Exelon will have tax attributes that may be used to offset Exelon’s future tax liabilities. A significant portion of such attributes were generated by our business. Upon separation, we reclassified $508 million from Deferred income taxes to reflect receivables of $11 million and $497 million in Other accounts receivable and Other deferred debits and other assets, respectively, in the Consolidated Balance Sheets for the tax attributes expected to be utilized by Exelon after separation in accordance with the terms of the TMA. As of December 31, 2023 and 2022, respectively, we had $336 million and $168 million in Other accounts receivable and $178 million and $362 million in Other deferred debits and other assets for the reclassified tax attributes.

Subsequent to the balance sheet date but prior to issuance we executed an amendment to the TMA that modified the timing of Exelon's payment of amounts due to us. The impact results in a reclassification of $152 million from Other accounts receivable to Other deferred debits in our Consolidated Balance Sheet and will be reflected in the first quarter of 2024.

15. Retirement Benefits

Defined Benefit Pension and OPEB

The majority of current employees participate in the defined benefit pension and OPEB plans that we sponsor. As the plan sponsor, our Consolidated Balance Sheets reflect underfunded pension and OPEB liabilities equal to an excess of either the PBO or APBO over the fair value of the plan assets, consistent with a single employer benefit plan. Newly hired employees are generally not eligible for either pension or OPEB benefits; instead, these employees are eligible to receive an enhanced non-discretionary fixed employer contribution under our sponsored defined contribution savings plan.

Effective February 1, 2022, in connection with the separation, pension and OPEB obligations and the related plan assets for participants (inclusive of employees and certain former employees and their beneficiaries assigned to us from Exelon upon separation) were transferred to pension and OPEB plans established by us as the plan sponsor. We no longer account for our interest in Exelon sponsored pension and OPEB plans under the multi-employer benefit plan guidance as we are no longer participants. That previous approach historically resulted in the recognition of a net prepaid pension asset in our Consolidated Balance Sheets representing an excess of contributions over cumulative costs.

Benefit Obligations, Plan Assets, and Funded Status

As of February 1, 2022, we assumed from Exelon the PBO, APBO, and plan assets for our plan participants in connection with the separation. The defined benefit pension and OPEB plans were remeasured to determine the obligations and related plan assets to be transferred to us as of that date. The pension assets allocated to us were based on the rules prescribed by ERISA for transfers of assets in connection with a pension plan separation. A portion of the Exelon OPEB plan assets, which are held in VEBA trusts, were also allocated to us

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 15 — Retirement Benefits

separately for each funding vehicle based on the ratio of the APBO assumed by us to the total APBO attributed to each funding vehicle.

The remeasurement completed at separation is reflected in the table below as a separation-related adjustment and resulted in the recognition of pension obligations of $953 million, net of pension plan assets of $8,267 million, and OPEB obligations of $876 million, net of OPEB plan assets of $904 million. Additionally, we recognized $2,006 million (after-tax) in Accumulated other comprehensive loss for actuarial losses and prior service costs that had accrued over the lives of the plans prior to separation, primarily based on our proportionate share of the total projected pension and OPEB obligations at Exelon prior to separation.

In connection with the acquisition of STP in the fourth quarter of 2023, Constellation recorded pension and OPEB obligations, net of plan assets, reflected in the tables below as an acquisition-related adjustment of $17 million and $14 million, respectively. Refer to Note 2 - Mergers, Acquisitions and Dispositions for additional discussion of the acquisition of STP.

We use a December 31 measurement date for our pension and OPEB obligations and the related plan assets. The actuarial losses experienced upon remeasurement as of December 31, 2023 were offset against AOCI and attributable to decreases in the discount rates used to measure the benefit obligations net of actual investment performance that was less than expected. See the table below for the actuarial loss associated with the pension valuation.

The following tables provide a rollforward of the changes in the benefit obligations and plan assets for the years ended December 31, 2023 and 2022 for all plans combined:


	Pension Benefits				OPEB
	2023		2022		2023		2022
Change in benefit obligation:
Benefit obligation as of the beginning of the year	$	7,275	$	—	$	1,360	$	847
Separation-related adjustment	—		9,220		—		933

Benefit obligation as of February 1, 2022	—		9,220		—		1,780
Service cost	89		115		16		23
Interest cost	394		269		74		52
Plan participants' contributions	—		—		23		20
Actuarial loss/(gain), net	368		(1,756)		99		(401)
Acquisition-related adjustment(a)	187		—		14		—
Settlements	—		(15)		—		—
Gross benefits paid	(543)		(558)		(143)		(114)
Benefit obligation as of the end of year	$	7,770	$	7,275	$	1,443	$	1,360

(a)Pension and OPEB adjustment related to the acquisition of STP in 2023. See Note 2 — Mergers, Acquisitions, and Dispositions for additional information.

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 15 — Retirement Benefits


	Pension Benefits				OPEB
	2023		2022		2023		2022
Change in plan assets:
Plan assets as of the beginning of year(a)	$	6,660	$	1,683	$	734	$	—
Separation-related adjustment	—		6,584		—		904

Fair value of plan assets as of February 1, 2022	—		8,267		—		904
Actual return (loss) on plan assets	374		(1,245)		50		(99)
Employer contributions	26		211		—		—
Plan participants' contributions	—		—		18		15
Gross benefits paid	(543)		(558)		(110)		(86)
Acquisition-related adjustment(b)	170		—		—		—
Settlements	—		(15)		—		—
Fair value of plan assets as of the end of year	$	6,687	$	6,660	$	692	$	734

Over (under) funded status (Plan assets less benefit obligations)	$	(1,083)	$	(615)	$	(751)	$	(626)

(a)The balance on January 1, 2022 was reflected as a prepaid pension asset.

(b)Pension and OPEB adjustment related to the acquisition of STP in 2023. See Note 2 — Mergers, Acquisitions, and Dispositions for additional information.

We present our benefit obligations net of plan assets on our Consolidated Balance Sheets within the following line items:


	Pension Benefits				OPEB
	2023		2022		2023		2022

Other current liabilities	$	(13)	$	(10)	$	(19)	$	(17)
Pension obligations	(1,070)		(605)		—		—
Non-pension postretirement benefit obligations	—		—		(732)		(609)

The following table provides the ABO and fair value of plan assets for all pension plans with an ABO in excess of plan assets.


ABO in Excess of Plan Assets	December 31, 2023		December 31, 2022
ABO	$	(7,567)	$	(7,121)
Fair value of net plan assets	6,687		6,660

Components of Net Periodic Benefit (Credits) Costs

See Note 1 — Basis of Presentation for additional information on where we report the service cost and other non-service cost (credit) components for all plans.

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 15 — Retirement Benefits

The following table presents the components of our net periodic benefit (credits) costs, prior to capitalization and co-owner allocations, for the years ended December 31 2023, 2022 and 2021:


	Pension Benefits						OPEB						Total Pension Benefits and OPEB
	2023		2022		2021(a)		2023		2022		2021(a)		2023		2022		2021(a)
Components of net periodic benefit (credit) cost:
Service cost	$	89	$	126	$	145	$	16	$	25	$	29	$	105	$	151	$	174
Non-service components of pension benefits & OPEB (credit) cost:
Interest cost	404		290		235		76		55		45		480		345		280
Expected return on assets	(520)		(565)		(493)		(45)		(55)		(58)		(565)		(620)		(551)
Amortization of:
Prior service (credit) cost	1		1		1		(10)		(7)		(9)		(9)		(6)		(8)
Actuarial (gain) loss	48		148		199		(12)		(1)		10		36		147		209
Settlement charges	—		6		20		—		—		—		—		6		20

Non-service components of pension benefits & OPEB credit (cost)(b)	(67)		(120)		(38)		9		(8)		(12)		(58)		(128)		(50)
Net periodic benefit (credit) cost(c)(d)(e)	$	22	$	6	$	107	$	25	$	17	$	17	$	47	$	23	$	124

(a)Costs recognized for the year ended December 31, 2021 were allocated to us by Exelon under the Exelon sponsored pension and OPEB plans prior to separation.

(b)Effective February 1, 2022, these non-service (credits) costs are reflected in Other, net in the Consolidated Statements of Operations and Comprehensive Income.

(c)The pension benefit and OPEB service costs reflected in the Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2023 totaled $94 million. The pension benefit and OPEB non-service credits reflected in the Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2023 totaled ($54) million.

(d)The pension benefit and OPEB service costs reflected in the Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2022 totaled $131 million. The pension benefit and OPEB non-service credits reflected in the Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2022 totaled ($116) million. Our portion of the total net periodic benefit (credits) costs allocated to us from Exelon in January 2022 prior to separation was not material and remains in total Operating and maintenance expense.

(e)The pension benefit and OPEB service costs reflected in the Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2021 totaled $144 million. The pension benefit and OPEB non-service credits reflected in the Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2021 totaled ($50) million.

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 15 — Retirement Benefits

Components of AOCI

We recognize the overfunded or underfunded status of defined benefit pension and OPEB plans as an asset or liability on our balance sheet, with offsetting entries to AOCI. The following tables provide the pre-tax components of AOCI for the years ended December 31, 2023 and 2022, for all plans combined:


	Pension Benefits				OPEB
	2023		2022		2023		2022
Changes in plan assets and benefit obligations recognized in AOCI:
Separation-related adjustment	$	—	$	2,664	$	—	$	22
Current year actuarial (gain) loss	509		11		94		(253)
Amortization of actuarial (loss) gain	(46)		(134)		14		1

Amortization of prior service (cost) credit	(1)		(1)		6		7

Settlements	—		(6)		—		—
Total recognized in AOCI	$	462	$	2,534	$	114	$	(223)

The following table provides the components of gross accumulated other comprehensive loss that have not been recognized as components of periodic benefit cost as of December 31, 2023 and 2022, for all plans combined:


	Pension Benefits				OPEB
	2023		2022		2023		2022
Prior service (credit) cost	$	9	$	10	$	(24)	$	(30)
Actuarial (gain) loss	2,985		2,524		(85)		(193)
Total	$	2,994	$	2,534	$	(109)	$	(223)

Average Remaining Service Period

For pension benefits, we amortize the unrecognized prior service (credits) costs and certain actuarial gains and losses reflected in AOCI, as applicable, based on participants’ average remaining service periods.

For OPEB, we amortize the unrecognized prior service (credits) costs reflected in AOCI over participants’ average remaining service period to benefit eligibility age, and amortize certain actuarial gains and losses reflected in AOCI over participants’ average remaining service period to expected retirement.

The resulting average remaining service periods for pension and OPEB were as follows as of December 31, 2023 and 2022:


	December 31, 2023	December 31, 2022
Pension plans	12.4	12.2
OPEB plans:
Benefit Eligibility Age	7.5	7.4
Expected Retirement	8.3	8.3

Assumptions

The measurement of the plan obligations and costs of providing benefits under our defined benefit pension and OPEB plans involves various factors, including the development of valuation assumptions and inputs and accounting policy elections. The measurement of benefit obligations and costs is impacted by several assumptions and inputs, as shown below, among other factors. When developing the required assumptions, we consider historical information as well as future expectations.

Discount Rate. The discount rates are determined by developing a spot rate curve based on the yield to maturity of a universe of high-quality non-callable (or callable with make whole provisions) bonds with similar maturities to the related pension and OPEB obligations. The spot rates are used to discount the estimated future benefit distribution amounts under the pension and OPEB plans. The discount rate is the single level rate that

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 15 — Retirement Benefits

produces the same result as the spot rate curve. We utilize an analytical tool developed by our actuaries to determine the discount rates.

Expected Rate of Return. In determining the EROA, we consider historical economic indicators (including inflation and GDP growth) that impact asset returns, as well as expectation regarding future long-term capital market performance, weighted by our target asset class allocations.

Mortality. The mortality assumption is composed of a base table that represents the current expectation of life expectancy of the population adjusted by an improvement scale that attempts to anticipate future improvements in life expectancy. Upon remeasurement as of December 31, 2023 and December 31, 2022, we utilized the mortality tables and projection scales released by the SOA.

The following assumptions were used to determine the benefit obligations for the plans as of December 31, 2023 and December 31, 2022. Assumptions used to determine year-end benefit obligations are the assumptions used to estimate the subsequent year’s net periodic benefit costs.


	Pension Benefits				OPEB
	December 31, 2023		December 31, 2022		December 31, 2023		December 31, 2022
Discount rate(a)	5.17	%	5.52	%	5.15	%	5.50	%
Investment crediting rate(b)	5.07	%	5.15	%	N/A		N/A
Rate of compensation increase(c)	4.25	%	3.75	%	4.25	%	3.75	%
Mortality table	Pri-2012 table with MP-2021 improvement scale (adjusted)		Pri-2012 table with MP-2021 improvement scale (adjusted)		Pri-2012 table with MP-2021 improvement scale (adjusted)		Pri-2012 table with MP-2021 improvement scale (adjusted)
Healthcare cost trend on covered charges	N/A		N/A		Initial and ultimate rate of 5.00%		Initial and ultimate rate of 5.00%

(a)The discount rates above represent the blended rates used to calculate the majority of Constellation's pension and OPEB costs.

(b)The investment crediting rate above represents a weighted average rate.

(c)Includes 4.25% average for the 5 year period (2024-2028) and 3.75% average thereafter.

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 15 — Retirement Benefits

The following assumptions were used to determine the net periodic benefit cost for the plans for the years ended December 31, 2023 and 2022.


	Pension Benefits				OPEB
	2023		2022		2023		2022
Discount rate(a)	5.52	%	3.23	%	5.50	%	3.21	%
Investment crediting rate(b)	5.15	%	3.86	%	N/A		N/A
Expected return on plan assets(c)	6.50	%	6.50	%	6.51	%	6.39	%
Rate of compensation increase	3.75	%	3.75	%	3.75	%	3.75	%
Mortality table	Pri-2012 table with MP-2021 improvement scale (adjusted)		Pri-2012 table with MP-2021 improvement scale (adjusted)		Pri-2012 table with MP-2021 improvement scale (adjusted)		Pri-2012 table with MP-2021 improvement scale (adjusted)
Healthcare cost trend on covered charges	N/A		N/A		Initial and ultimate rate of 5.00%		Initial and ultimate rate of 5.00%

(a)The discount rates above represent the blended rates used to calculate the majority of Constellation's pension and OPEB costs.

(b)The investment crediting rate above represents a weighted average rate.

(c)Applicable to our pension and OPEB plans with plan assets, with the OPEB rate representing a weighted average.

Contributions

We consider various factors when making qualified pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act, and management of the pension obligation. The Pension Protection Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification). The projected contributions below reflect a funding strategy to make levelized annual contributions with the objective of achieving 100% funded status over time. This level funding strategy helps minimize the volatility of future period required pension contributions. Based on this funding strategy and current market conditions, which are both subject to change, we made our annual qualified pension contribution in July 2023.

Our non-qualified pension plans are not funded given that they are not subject to statutory minimum contribution requirements. OPEB plans are also not subject to statutory minimum contribution requirements, though we have funded certain plans. For our funded OPEB plans, we consider several factors in determining the level of contributions to these plans, including liabilities management and levels of benefit claims paid.

The following table provides our contributions paid to our qualified pension plans, non-qualified pension plans, and OPEB plans for the years ended December 31, 2023, 2022, and 2021:


	2023		2022		2021(b)
Pension contributions(a)	$	26	$	212	$	231
OPEB contributions	28		26		28
Total contributions	$	54	$	238	$	259

(a)In 2023 and 2022, our annual qualified pension contributions were $21 million and $192 million, respectively. The benefit payments to the non-qualified pension plans in 2023 and 2022 were not material.

(b)Prior to separation, Exelon allocated contributions related to its legacy Exelon sponsored pension and OPEB plans to its subsidiaries based on accounting cost or employee participation (both active and retired).

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 15 — Retirement Benefits

The following table provides our planned contributions to our qualified pension plans, non-qualified pension plans, and OPEB plans in 2024 (including our benefit payments related to unfunded plans):


			Qualified Pension Plans						Non-Qualified Pension Plans						OPEB						Total
Planned contributions			$	161					$	13					$	20					$	194

Estimated Future Benefit Payments

Estimated future benefit payments to participants over the next ten years in all pension and OPEB plans as of December 31, 2023 are as follows:


	Pension Benefits		OPEB
2024	$	576	$	117
2025	575		116
2026	581		115
2027	581		114
2028	587		114
2029 through 2033	2,880		546
Total estimated future benefits payments through 2033	$	5,780	$	1,122

Plan Assets

On a regular basis, we evaluate our investment strategy to ensure that plan assets will be sufficient to pay plan benefits when due. We have developed and implemented a liability hedging investment strategy for our qualified pension plans that has reduced the volatility of these pension assets relative to the associated pension obligations. We are likely to continue to gradually increase the liability hedging portfolio as the funded status of the plans improve. The overall objective is to achieve attractive risk-adjusted returns that will balance with the liquidity requirements of the plans’ liabilities while striving to minimize the risk of significant losses. Trust assets for our OPEB plans are managed in a diversified investment strategy that prioritizes maximizing liquidity and returns while minimizing asset volatility.

Actual asset returns have an impact on the costs reported for the pension and OPEB plans. The actual asset returns across our pension and OPEB plans for the year ended December 31, 2023 were 6.50% and 9.50%, respectively, compared to an expected long-term return assumption of 6.50% and 6.50%, respectively. We used an EROA of 6.50% to estimate both our 2024 pension and OPEB costs.

Our pension and OPEB plan target asset allocations as of December 31, 2023 and 2022 were as follows:


	December 31, 2023				December 31, 2022
Asset Category	Pension Benefits		OPEB		Pension Benefits		OPEB
Equity securities	21	%	17	%	21	%	43	%
Fixed income securities	54	%	70	%	54	%	45	%
Alternative investments(a)	25	%	13	%	25	%	12	%
Total	100	%	100	%	100	%	100	%

(a)Alternative investments include private equity, hedge funds, real estate, and private credit.

We evaluated our pension and OPEB plans’ asset portfolios for the existence of significant concentrations of credit risk as of December 31, 2023. Types of concentrations that were evaluated include, but are not limited to, investment concentrations in a single entity, type of industry, foreign country, and individual fund. As of December 31, 2023, our pension and OPEB plans held no credit risk concentrations surpassing 10% of plan assets.

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 15 — Retirement Benefits

Fair Value Measurements

The following table presents pension and OPEB plan assets measured and recorded at fair value as a net component of Pension obligations and Non-pension postretirement benefit obligations in our Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2023 and 2022:


	December 31, 2023								December 31, 2022
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Pension plan assets(a)
Cash equivalents	$	192	$	—	$	—	$	192	$	216	$	—	$	—	$	216
Equities(b)	598		—		—		598		776		—		—		776
Fixed income	740		2,137		—		2,877		693		1,951		8		2,652
Private equity	—		—		—		—		—		—		180		180



Total assets measured at fair value	1,530		2,137		—		3,667		1,685		1,951		188		3,824
Assets measured at NAV	—		—		—		3,283		—		—		—		2,879
Pension plan assets subtotal	1,530		2,137		—		6,950		1,685		1,951		188		6,703

OPEB plan assets(a)
Cash equivalents	—		—		—		$	—	40		—		—		$	40
Equities	232		—		—		232		152		—		—		152





Fixed income	62		94		—		156		67		61		—		128




Total assets measured at fair value	294		94		—		388		259		61		—		320
Assets measured at NAV	—		—		—		304		—		—		—		414
OPEB plan assets subtotal	294		94		—		692		259		61		—		734
Total pension and OPEB plan assets(c)	$	1,824	$	2,231	$	—	$	7,642	$	1,944	$	2,012	$	188	$	7,437

(a)See Note 18 — Fair Value of Financial Assets and Liabilities for a description of levels within the fair value hierarchy.

(b)Includes derivative instruments of $31 million and $6 million for the years ended December 31, 2023 and 2022, respectively, which have total notional amounts of $1,986 million and $1,879 million as of December 31, 2023 and 2022, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do not represent the amount of the company’s exposure to credit or market loss.

(c)Excludes net liabilities of $263 million and $43 million as of December 31, 2023 and 2022, respectively, which include certain derivative assets that have notional amounts of $15 million and $41 million as of December 31, 2023 and 2022, respectively. These items are required to reconcile to the fair value of net plan assets and consist primarily of receivables or payables related to pending securities sales and purchases, and interest and dividends receivable.

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 15 — Retirement Benefits

The following table presents the reconciliation of Level 3 assets and liabilities measured at fair value for pension and OPEB plans for the years ended December 31, 2023 and 2022:


Pension Assets	Fixed Income		Private Equity		Total
Balance as of January 1, 2023	$	8	$	180	$	188
Actual return on plan assets:
Relating to assets still held as of the reporting date	—		12		12
Relating to assets sold during the period	—		(13)		(13)
Purchases and settlements:
Purchases	—		8		8

Settlements(a)	—		(187)		(187)
Transfers out of Level 3	(8)		—		(8)
Balance as of December 31, 2023	$	—	$	—	$	—

Pension Assets	Fixed Income		Private Equity		Total
Balance as of January 1, 2022	$	—	$	—	$	—
Separation-related adjustment	9		—		9
Actual return on plan assets:
Relating to assets still held as of the reporting date	(1)		(54)		(55)

Purchases and settlements:
Purchases	—		18		18

Settlements(a)	—		(4)		(4)
Transfers out of Level 3(b)	—		220		220
Balance as of December 31, 2022	$	8	$	180	$	188

(a)Represents cash settlements only.

(b)Includes certain private equity investments previously measured at fair value using NAV or its equivalent as a practical expedient at separation transferred to Level 3 primarily due to changes in market liquidity or data.

Valuation Techniques Used to Determine Fair Value

The techniques used to fair value the pension and OPEB assets invested in cash equivalents, equities, fixed income, derivatives, private equity, real estate, and private credit investments are the same as the valuation techniques for these types of investments in NDT funds. See Cash Equivalents and NDT Fund Investments in Note 18 — Fair Value of Financial Assets and Liabilities for further information.

Pension and OPEB assets also include investments in hedge funds. Hedge fund investments include those that employ a broad range of strategies to enhance returns and provide additional diversification. The fair value of hedge funds is determined using NAV or its equivalent as a practical expedient, and therefore, hedge funds are not classified within the fair value hierarchy. We have the ability to redeem these investments at NAV or its equivalent subject to certain restrictions which may include a lock-up period or a gate.

Defined Contribution Savings Plan

We sponsor the Constellation Employee Savings Plan, a 401(k) defined contribution savings plan. The plan allows employees to contribute a portion of their pre-tax and/or after-tax income in accordance with specified guidelines. We match a percentage of the employee contributions up to certain limits. In addition, certain employees are eligible for a fixed non-discretionary employer contribution in lieu of a pension benefit. The employer contributions to the savings plan were $106 million, $90 million and $53 million for the years ended December 31, 2023, 2022, and 2021, respectively.

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 16 — Derivative Financial Instruments

16. Derivative Financial Instruments

We use derivative instruments to manage commodity price risk, interest rate risk, and foreign exchange risk related to ongoing business operations.

Authoritative guidance requires that derivative instruments be recognized as either assets or liabilities at fair value, with changes in fair value of the derivative recognized in earnings immediately. Other accounting treatments are available through special election and designation, provided they meet specific, restrictive criteria both at the time of designation and on an ongoing basis. These alternative permissible accounting treatments include NPNS, cash flow hedges, and fair value hedges. All derivative instruments, excluding NPNS and cash flow hedges, are recorded at fair value through earnings. For all NPNS derivative instruments, accounts receivable or accounts payable are recorded when derivatives settle, and revenue or expense is recognized in earnings as the underlying physical commodity is sold or delivered.

Authoritative guidance about offsetting assets and liabilities requires the fair value of derivative instruments to be shown in the Combined Notes to Consolidated Financial Statements on a gross basis, even when the derivative instruments are subject to legally enforceable master netting agreements and qualify for net presentation in the Consolidated Balance Sheets. A master netting agreement is an agreement between two counterparties that may have derivative and non-derivative contracts with each other providing for the net settlement of all referenced contracts via one payment stream, which takes place as the contracts deliver, when collateral is requested or in the event of default. In the tables below, which present fair value balances, our energy-related economic hedges and proprietary trading derivatives are shown gross. The impact of the netting of fair value balances with the same counterparty that are subject to legally enforceable master netting agreements, as well as netting of cash collateral, including margin on exchange positions, is aggregated in the collateral and netting columns.

Our use of cash collateral is generally unrestricted unless we were downgraded below investment grade. As our senior unsecured debt rating is currently rated at BBB+ and Baa2 by S&P and Moody's, respectively, it would take a three notch downgrade by S&P or a two notch downgrade by Moody's for us to go below investment grade.

Commodity Price Risk

We employ established policies and procedures to manage our risks associated with market fluctuations in commodity prices by entering physical and financial derivative contracts, including swaps, futures, forwards, options, and short-term and long-term commitments to purchase and sell energy and energy-related products. We believe these instruments, which are either determined to be non-derivative or classified as economic hedges, mitigate exposure to fluctuations in commodity prices.

To the extent the amount of energy we produce or procure differs from the amount of energy we have contracted to sell and in connection with portfolio optimization, we are exposed to market fluctuations in the prices of electricity, natural gas, and other commodities. We use a variety of derivative and non-derivative instruments to manage the commodity price risk of our electric generation facilities, including power and gas sales, fuel and power purchases, natural gas transportation and pipeline capacity agreements, and other energy-related products marketed and purchased. To manage these risks, we may enter fixed-price derivative or non-derivative contracts to hedge the variability in future cash flows from expected sales of power and gas and purchases of power and fuel. The objectives for executing such hedges include fixing the price for a portion of anticipated future electricity sales at a level that provides an acceptable return. We are also exposed to differences between the locational settlement prices of certain economic hedges and the hedged generating units. This price difference is actively managed through other instruments which include derivative congestion products, whose changes in fair value are recognized in earnings each period, and auction revenue rights, which are accounted for on an accrual basis.

Additionally, we are exposed to certain market risks through our proprietary trading activities. The proprietary trading activities are a complement to our energy marketing portfolio but represent a small portion of our overall energy marketing activities and are subject to limits established by the Executive Committee. Proprietary trading includes all contracts executed with the intent of benefiting from shifts or changes in market prices as opposed to those executed with the intent of hedging or managing risk. Gains and losses associated with proprietary trading are reported as Operating revenues in the Consolidated Statements of Operations and Comprehensive Income and are included in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 16 — Derivative Financial Instruments

Flows. For the years ended December 31, 2023, 2022, and 2021, net pre-tax commodity mark-to-market gains and losses were not material.

The following tables provide a summary of the derivative fair value balances recorded as of December 31, 2023 and 2022:


December 31, 2023	Economic Hedges		Proprietary Trading		Collateral (a)(b)		Netting(a)		Total
Mark-to-market derivative assets (current)	$	7,927	$	2	$	703	$	(7,472)	$	1,160
Mark-to-market derivative assets (noncurrent)	3,345		—		330		(2,682)		993
Total mark-to-market derivative assets	11,272		2		1,033		(10,154)		2,153
Mark-to-market derivative liabilities (current)	(9,019)		(2)		922		7,472		(627)
Mark-to-market derivative liabilities (noncurrent)	(3,545)		—		445		2,682		(418)
Total mark-to-market derivative liabilities	(12,564)		(2)		1,367		10,154		(1,045)
Total mark-to-market derivative net assets (liabilities)	$	(1,292)	$	—	$	2,400	$	—	$	1,108

December 31, 2022
Mark-to-market derivative assets (current)	$	15,296	$	10	$	161	$	(13,123)	$	2,344
Mark-to-market derivative assets (noncurrent)	5,100		—		217		(4,074)		1,243
Total mark-to-market derivative assets	20,396		10		378		(17,197)		3,587
Mark-to-market derivative liabilities (current)	(15,049)		(6)		374		13,123		(1,558)
Mark-to-market derivative liabilities (noncurrent)	(5,203)		—		146		4,074		(983)
Total mark-to-market derivative liabilities	(20,252)		(6)		520		17,197		(2,541)
Total mark-to-market derivative net assets (liabilities)	$	144	$	4	$	898	$	—	$	1,046

(a)We net all available amounts allowed in our Consolidated Balance Sheets in accordance with authoritative guidance for derivatives. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral.

(b)Includes $1,712 million of variation margin posted and $836 million of variation margin held from the exchanges as of December 31, 2023 and 2022, respectively.

Economic Hedges (Commodity Price Risk)

For the years ended December 31, 2023, 2022, and 2021, we recognized the following net pre-tax commodity mark-to-market gains (losses), which are also included in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows.



	For the Years Ended December 31,
Income Statement Location	2023		2022		2021

Operating revenues	$	1,402	$	(1,193)	$	(635)
Purchased power and fuel	(2,368)		167		1,206
Total	$	(966)	$	(1,026)	$	571

In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on owned and contracted generation positions that have not been hedged. 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

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 16 — Derivative Financial Instruments

nuclear PTC and state programs may not fully mitigate. We also enter transactions that further optimize the economic benefits of our overall portfolio.

Interest Rate and Foreign Exchange Risk

We utilize interest rate swaps to manage our interest rate exposure and foreign currency derivatives to manage foreign exchange rate exposure associated with international commodity purchases in currencies other than U.S. dollars, both of which are treated as economic hedges. The notional amounts were $562 million and $524 million as of December 31, 2023 and 2022, respectively.

The following table provides the mark-to-market derivative assets and liabilities as of December 31, 2023 and 2022:


	December 31, 2023						December 31, 2022
	Economic Hedges		Netting(a)		Total		Economic Hedges		Netting(a)		Total
Mark-to-market derivative assets (current)	$	20	$	(1)	$	19	$	29	$	(5)	$	24
Mark-to-market derivative assets (noncurrent)	2		—		2		18		—		18
Total mark-to-market derivative assets	22		(1)		21		47		(5)		42
Mark-to-market derivative liabilities (current)	(6)		1		(5)		(5)		5		—
Mark-to-market derivative liabilities (noncurrent)	(1)		—		(1)		—		—		—
Total mark-to-market derivative liabilities	(7)		1		(6)		(5)		5		—
Total mark-to-market derivative net assets (liabilities)	$	15	$	—	$	15	$	42	$	—	$	42

(a)We net all available amounts in our Consolidated Balance Sheets in accordance with authoritative guidance for derivatives. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements.

The mark-to-market gains and losses associated with management of interest rate and foreign currency exchange rate risk for the years ended December 31, 2023, 2022, and 2021 were not material, which are also included in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows.

Credit Risk

We would be exposed to credit-related losses in the event of non-performance by counterparties on executed derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts as of the reporting date.

For commodity derivatives, we enter into enabling agreements that allow for payment netting with our counterparties, which reduces our exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. Typically, each enabling agreement is for a specific commodity and, with respect to each individual counterparty, netting is limited to transactions involving that specific commodity product, except where master netting agreements exist with a counterparty that allows for cross product netting. In addition to payment netting language in the enabling agreement, our credit department establishes credit limits, margining thresholds and collateral requirements for each counterparty, which are defined in the derivative contracts. Counterparty credit limits are based on an internal credit review process that considers a variety of factors, including the results of a scoring model, leverage, liquidity, profitability, credit ratings by credit rating agencies, and other risk management criteria. To the extent that a counterparty’s margining thresholds are exceeded, the counterparty is required to post collateral with us, as specified in each enabling agreement. Our credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis.

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 16 — Derivative Financial Instruments

The following tables provide information on the 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, 2023. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk by types of counterparties. The amounts in the tables below exclude credit risk exposure from individual retail counterparties and exposure through RTOs, ISOs, NYMEX, ICE, NASDAQ, NGX, and Nodal commodity exchanges.


Rating as of December 31, 2023	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	$	1,257	$	51	$	1,206	1	$	222
Non-investment grade	22		7		15		—	—
No external ratings
Internally rated — investment grade	116		—		116		—	—
Internally rated — non-investment grade	259		45		214		—	—
Total	$	1,654	$	103	$	1,551	1	$	222

(a)As of December 31, 2023, credit collateral held from counterparties where we had credit exposure included $44 million of cash and $59 million of letters of credit. The credit collateral does not include non-liquid collateral.


Net Credit Exposure by Type of Counterparty	As of December 31, 2023
Investor-owned utilities, marketers, power producers	$	1,271
Energy cooperatives and municipalities	132
Financial Institutions	49
Other	99
Total	$	1,551

Credit-Risk-Related Contingent Features

As part of the normal course of business, we routinely enter into physically or financially settled contracts for the purchase and sale of capacity, electricity, fuels, emissions allowances, and other energy-related products. Certain of our derivative instruments contain provisions that require us to post collateral. We also enter into commodity transactions on exchanges where the exchanges act as the counterparty to each trade. Transactions on the exchanges must adhere to comprehensive collateral and margining requirements. This collateral may be posted in the form of cash or credit support with thresholds contingent upon our credit ratings from S&P and Moody's. The collateral and credit support requirements vary by contract and by counterparty. These credit-risk-related contingent features stipulate that if we were to be downgraded or lose our investment grade credit ratings (based on our senior unsecured debt rating), we would be required to provide additional collateral. This incremental collateral requirement allows for the offsetting of derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master netting agreements. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. In this case, we believe an amount of several months of future payments (e.g., capacity payments) rather than a calculation of fair value is the best estimate for the contingent collateral obligation, which has been factored into the disclosure below.

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 16 — Derivative Financial Instruments

The aggregate fair value of all derivative instruments with credit-risk-related contingent features in a liability position that are not fully collateralized (excluding transactions on the exchanges that are fully collateralized) is detailed in the table below:


	As of December 31,
Credit-Risk-Related Contingent Features	2023		2022
Gross fair value of derivative contracts containing this feature	$	(1,894)	$	(4,736)
Offsetting fair value of in-the-money contracts under master netting arrangements	925		2,048
Net fair value of derivative contracts containing this feature	$	(969)	$	(2,688)

As of December 31, 2023 and 2022, we posted or held the following amounts of cash collateral and letters of credit on derivative contracts with external counterparties, after giving consideration to offsetting derivative and non-derivative positions under master netting agreements.


	As of December 31,
	2023		2022
Cash collateral posted(a)	$	2,449	$	1,636
Letters of credit posted(a)	777		947
Cash collateral held(a)	64		765
Letters of credit held(a)	61		115
Additional collateral required in the event of a credit downgrade below investment grade (at BB+/Ba1)(b)(c)(d)	1,914		3,337

(a)The cash collateral and letters of credit amounts are inclusive of NPNS contracts.

(b)Certain of our contracts contain provisions that allow a counterparty to request additional collateral when there has been a subjective determination that our credit quality has deteriorated, generally termed “adequate assurance.” Due to the subjective nature of these provisions, we estimate the amount of collateral that we may ultimately be required to post in relation to the maximum exposure with the counterparty.

(c)The downgrade collateral is inclusive of all contracts in a liability position regardless of accounting treatment and excludes any contracts with individual retail counterparties.

(d)A loss of investment grade credit rating would require a significant reduction in credit ratings from their current levels of BBB+ and Baa2 at S&P and Moody's, respectively.

We enter into supply forward contracts with certain utilities with one-sided collateral postings only from us. If market prices fall below the benchmark price levels in these contracts, the utilities are not required to post collateral. However, when market prices rise above the benchmark price levels, we are required to post collateral once certain unsecured credit limits are exceeded.

17. Debt and Credit Agreements

Short-Term Borrowings

We meet our short-term liquidity requirements primarily through the issuance of commercial paper. We may use our credit facility for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit.

Credit Agreements

On February 1, 2022, we entered into a credit agreement establishing a $3.5 billion five-year revolving credit facility at a variable interest rate of SOFR plus 1.275% and on February 9, 2022 we entered into a $1 billion five-year liquidity facility with the primary purpose of supporting our letter of credit issuances. Many of our bilateral credit agreements remain in effect.

Borrowings under our revolving credit agreement bear interest at a rate based upon either the Daily Simple SOFR rate or a Term SOFR rate, plus an adder based upon our credit ratings. The adders for the Daily Simple SOFR based borrowings and Term SOFR borrowings are 27.5 basis points and 127.5 basis points, respectively.

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 17 — Debt and Credit Agreements

If we lose our investment grade rating, the maximum adders for Daily Simple SOFR rate borrowings and Term SOFR rate borrowings would be 100 basis points and 200 basis points, respectively. The credit agreements also require us to pay facility fees based upon the aggregate commitments. The fee varies depending upon our credit rating. See below for additional details.

As of December 31, 2023 and 2022 we had the following aggregate bank commitments, credit facility borrowings and available capacity under our respective credit facilities:


Facility Type	Aggregate Bank Commitment		Facility Draws		Outstanding Letters of Credit		Outstanding Commercial Paper(a)		Available Capacity as of December 31, 2023
Syndicated Revolver	$	3,500	$	—	$	60	$	1,107	$	2,333
Bilaterals	1,500		—		878		—		622
Liquidity Facility	971		—		720		—		191		(b)
Project Finance	137		—		117		—		20
Total	$	6,108	$	—	$	1,775	$	1,107	$	3,166


Facility Type	Aggregate Bank Commitment		Facility Draws		Outstanding Letters of Credit		Outstanding Commercial Paper(a)		Available Capacity as of December 31, 2022
Syndicated Revolver	$	3,500	$	—	$	765	$	959	$	1,776
Bilaterals	1,200		—		867		—		333
Liquidity Facility	971		—		732		—		139		(b)
Project Finance	131		—		111		—		20
Total	$	5,802	$	—	$	2,475	$	959	$	2,268

(a)Our commercial paper program is supported by the revolving credit agreement. In order to maintain our commercial paper program in the amounts indicated above, we must have a credit facility in place, at least equal to the amount of our commercial paper program. As of both December 31, 2023 and 2022, the maximum program size of our commercial paper program was $3.5 billion. We do not issue commercial paper in an aggregate amount exceeding the then available capacity under our credit facility. The weighted average interest rate on commercial paper borrowings was 5.66% and 4.90% as of December 31, 2023 and 2022, respectively.

(b)The maximum amount of the bank commitment is not to exceed $971 million. The aggregate available capacity of the facility is subject to market fluctuations based on the value of U.S Treasury Securities which determines the amount of collateral held in the trust. We may post additional collateral to borrow up to the maximum bank commitment. As of December 31, 2023 and 2022, without posting additional collateral, the actual availability of facility, prior to outstanding letters of credit was $911 million and $871 million, respectively.

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 17 — Debt and Credit Agreements

Bilateral Credit Agreements

The following table reflects the bilateral credit agreements at December 31, 2023:


Date Initiated		Latest Amendment Date	Maturity Date(a)	Amount

January 5, 2016	(b)	April 4, 2023	April 3, 2026	$	150

October 25, 2019	(b)	N/A	N/A	200

November 20, 2019	(b)	N/A	N/A	300
November 21, 2019	(b)	N/A	N/A	100
November 21, 2019	(b)	November 15, 2022	November 21, 2024	100
May 15, 2020	(b)	March 31, 2023	N/A	300
August 12, 2022	(b)	N/A	N/A	50
March 29, 2023	(b)	N/A	March 29, 2025	100
December 8, 2023	(b)	N/A	N/A	200

(a)Credit facilities that do not contain a maturity date are specific to the agreements set within each contract. In some instances, credit facilities are automatically renewed based on the contingency standards set within the specific agreement.

(b)Bilateral credit agreements solely support the issuance of letters of credit and do not back our commercial paper program.

Short-Term Loan Agreements

On March 31, 2020, we entered into a term loan agreement for $300 million. We repaid $100 million of the term loan on March 29, 2022. The remaining $200 million from the loan agreement was renewed on March 29, 2022 and repaid on March 29, 2023. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to SOFR plus 0.80% and all indebtedness thereunder is unsecured. The loan was reflected in Short-term borrowings in the Consolidated Balance Sheets as of December 31, 2022.

On January 26, 2023, we entered into a term loan agreement for $100 million. The loan agreement has an expiration of January 25, 2024. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to SOFR plus 0.80% and all indebtedness thereunder is unsecured. The loan was reflected in Short-term borrowings in the Consolidated Balance Sheet as of December 31, 2023. We repaid this loan on January 25, 2024.

On February 9, 2023, we entered into a term loan agreement for $400 million. The loan agreement has an expiration of February 8, 2024. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to SOFR plus 1.05% and all indebtedness thereunder is unsecured. The loan was reflected in Short-term borrowings in the Consolidated Balance Sheet as of December 31, 2023. We repaid this loan on February 8, 2024.

On February 12, 2024, we entered into a term loan agreement for $200 million. The loan agreement has an expiration of February 8, 2025. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to SOFR plus 0.90% and all indebtedness thereunder is unsecured.

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 17 — Debt and Credit Agreements

Long-Term Debt

The following table presents the outstanding long-term debt as of December 31, 2023 and 2022:


						Maturity Date	December 31,
	Rates					2023	2022
Long-term debt
Senior unsecured notes	3.25	%	-	6.50	%	2025 - 2053	$	5,688	$	2,938
Tax-exempt notes	4.10	%	-	4.45	%	2025 - 2053(a)	435		—


Notes payable and other	2.10	%	-	5.85	%	2024 - 2029	34		68
Nonrecourse debt:
Fixed rates	2.29	%	-	6.00	%	2031 - 2037	780		839
Variable rates	7.24	%	-	8.57	%	2026 - 2027	740		805
Total long-term debt							7,677		4,650
Unamortized debt discount and premium, net							(4)		(5)
Unamortized debt issuance costs							(56)		(36)

Long-term debt due within one year							(121)		(143)
Long-term debt							$	7,496	$	4,466

(a)The Tax-exempt notes have a maturity date of March 1, 2025 - April 1, 2053, and a mandatory purchase date that ranges from March 1, 2025 - June 1, 2029.

Long-term debt maturities in the periods 2024 through 2028 and thereafter are as follows:


2024	$	121
2025	1,010
2026	121
2027	705
2028	1,160
Thereafter	4,560
Total	$	7,677

Debt Covenants

As of December 31, 2023, we are in compliance with all debt covenants.

Nonrecourse Debt

We have also issued nonrecourse debt, for which approximately $2 billion of generating assets have been pledged as collateral as of both December 31, 2023 and 2022, respectively. Borrowings under these agreements are secured by the assets and equity of each respective project. The lenders do not have recourse against us in the event of a default. If a specific project financing entity does not maintain compliance with its specific nonrecourse debt covenants, there could be a requirement to accelerate repayment of the associated debt or other borrowings earlier than the stated maturity dates. In these instances, if such repayment was not satisfied, the lenders or security holders would generally have rights to foreclose against the project-specific assets and related collateral. The potential requirement to satisfy the associated debt or other borrowings earlier than otherwise anticipated could lead to impairments due to a higher likelihood of disposing of the respective project-specific assets significantly before the end of their useful lives.

Antelope Valley Solar Ranch One. In December 2011, the DOE Loan Programs Office issued a guarantee for up to $646 million for a nonrecourse loan from the Federal Financing Bank to support the financing of the construction of the Antelope Valley facility. The project became fully operational in 2014. The loan will mature on January 5, 2037. Interest rates on the loan were fixed upon each advance at a spread of 37.5 basis points above

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 17 — Debt and Credit Agreements

U.S. Treasuries of comparable maturity. The advances were completed as of December 31, 2015 and the outstanding loan balance bears interest at an average blended interest rate of 2.82%. As of December 31, 2023 and 2022, approximately $390 million and $415 million were outstanding, respectively. In addition, we have issued letters of credit to support the equity investment in the project, with $36 million and $37 million outstanding as of December 31, 2023 and 2022, respectively. In December 2017, our interests in Antelope Valley were contributed to and are pledged as collateral for the CR financing structures referenced below.

Continental Wind, LLC. In September 2013, Continental Wind, our indirect subsidiary, completed the issuance and sale of $613 million senior secured notes. Continental Wind owns and operates a portfolio of wind farms in Idaho, Kansas, Michigan, Oregon, New Mexico and Texas with a total net capacity of 667 MWs. The net proceeds were distributed to us for general business purposes. The notes are scheduled to mature on February 28, 2033. The notes bear interest at a fixed rate of 6.00% with interest payable semi-annually. As of December 31, 2023 and December 31, 2022, approximately $315 million and $345 million were outstanding, respectively.

In addition, Continental Wind has a $128 million letter of credit facility and $4 million working capital revolver facility. Continental Wind has issued letters of credit to satisfy certain of its credit support and security obligations. As of December 31, 2023 and 2022, the Continental Wind letter of credit facility had $116 million and $111 million in letters of credit outstanding related to the project, respectively.

In 2017, our interests in Continental Wind were contributed to CRP. See Note 22 - Variable Interest Entities for additional information on CRP.

Renewable Power Generation. In March 2016, RPG, our indirect subsidiary, issued $150 million aggregate principal amount of nonrecourse senior secured notes. The net proceeds were distributed to us for paydown of long term debt obligations at Sacramento PV Energy and Constellation Solar Horizons and for general business purposes. The loan is scheduled to mature on March 31, 2035. The term loan bears interest at a fixed rate of 4.11% payable semi-annually. As of December 31, 2023 and December 31, 2022, approximately $70 million and $80 million were outstanding, respectively. In 2017, our interests in RPG were contributed to CRP. See Note 22 - Variable Interest Entities for additional information on CRP.

Constellation Renewables. In November 2017, CR, our indirect subsidiary, entered into an $850 million nonrecourse senior secured term loan credit facility agreement with a maturity date of November 28, 2024. In addition to the financing, CR entered into interest rate swaps to manage a portion of the interest rate exposure in connection with the financing. The swap had an initial notional amount of $636 million and fixed the 3-month LIBOR at 2.32%.

In December 2020, CR entered into a financing agreement for a $750 million nonrecourse senior secured term loan credit facility, scheduled to mature on December 15, 2027. Beginning in June 2023, the term loan bears interest at a variable rate equal to 3-month SOFR plus 2.76%, subject to a 1% SOFR floor with interest payable quarterly. Redemptions prior to June 2023 were based on LIBOR + 2.50%. In addition to the financing, CR entered into interest rate swaps to manage a portion of the interest rate exposure in connection with the financing. The swap had an initial notional amount of $516 million and fixed the 3-month LIBOR at 1.05%. Beginning in June 2023, the swap fixed the 3-month SOFR at 0.8295%.

The proceeds were used to repay the November 2017 nonrecourse senior secured term loan credit facility of $850 million, of which $709 million was outstanding as of the retirement date in December 2020, and to settle the November 2017 interest rate swap. Our interests in CRP and Antelope Valley remain contributed to and pledged as collateral for this financing. As of December 31, 2023 and 2022, $650 million and $690 million was outstanding, respectively. See Note 22 — Variable Interest Entities for additional information on CRP and Note 16 — Derivative Financial Instruments for additional information on interest rate swaps.

West Medway II, LLC. On May 13, 2021, West Medway II, LLC (West Medway II), our indirect subsidiary, entered into a financing agreement for a $150 million nonrecourse senior secured term loan credit facility with a maturity date of March 31, 2026. Beginning in May 2023, the term loan bears interest at a variable rate equal to 1-month SOFR plus the variable interest rate of 2.975% - 3.225%, paid quarterly. Redemptions prior to May 2023 were based on LIBOR + 2.875%. In addition to the financing, West Medway II entered into interest rate swaps to manage a portion of the interest rate exposure in connection with the financing. The swaps had an initial notional amount of $113 million and fixed the 1-month LIBOR at 0.61%. Beginning in May, the swap fixed the 1-month

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 17 — Debt and Credit Agreements

SOFR at 0.5365%. We used the net proceeds for general corporate purposes. Our interests in West Medway II, were pledged as collateral for this financing. As of December 31, 2023 and 2022, approximately $85 million and $115 million was outstanding, respectively. See Note 16 — Derivative Financial Instruments for additional information on interest rate swaps.

18. Fair Value of Financial Assets and Liabilities

We measure and classify fair value measurements in accordance with the hierarchy as defined by GAAP. The hierarchy prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:

Level 1 — quoted prices (unadjusted) in active markets for identical assets or liabilities that we have the ability to liquidate as of the reporting date.
Level 2 — inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data.
Level 3 — unobservable inputs, such as internally developed pricing models or third-party valuations for the asset or liability due to little or no market activity for the asset or liability.

Fair Value of Financial Liabilities Recorded at Amortized Cost

The following tables present the carrying amounts and fair values of our long-term debt and the SNF obligation as of December 31, 2023 and 2022. We have no financial liabilities classified as Level 1.

The carrying amounts of the short-term liabilities as presented in the Consolidated Balance Sheets are representative of their fair value (Level 2) because of the short-term nature of these instruments.


	December 31, 2023											December 31, 2022
	Carrying Amount			Fair Value								Carrying Amount		Fair Value
			Level 2			Level 3			Total			Level 2		Level 3		Total
Long-Term Debt, including amounts due within one year	$	7,617		$	7,140		$	774		$	7,914	$	4,609	$	3,688	$	859	$	4,547
SNF Obligation	1,296			1,222			—			1,222		1,230		1,021		—		1,021

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 18 — Fair Value of Financial Assets and Liabilities

We use the following methods and assumptions to estimate fair value of our financial liabilities recorded at carrying cost:


Type	Level	Valuation
Long-term Debt, including amounts due within one year
Taxable Debt Securities	2	The fair value is determined by a valuation model that is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. We obtain credit spreads based on trades of our existing debt securities as well as other issuers in the utility sector with similar credit ratings. The yields are then converted into discount rates of various tenors that are used for discounting the respective cash flows of the same tenor for each bond or note.
Variable Rate Financing Debt	2	Debt rates are reset on a regular basis and the carrying value approximates fair value.
Government Backed Fixed Rate Project Financing Debt	3	The fair value is similar to the process for taxable debt securities. Due to the lack of market trading data on similar debt, the discount rates are derived based on the original loan interest rate spread to the applicable U.S. Treasury rate as well as a current market curve derived from government-backed securities.
Non-Government Backed Fixed Rate Nonrecourse Debt	3	Fair value is based on market and quoted prices for its own and other nonrecourse debt with similar risk profiles. Given the low trading volume in the nonrecourse debt market, the price quotes used to determine fair value will reflect certain qualitative factors, such as market conditions, investor demand, new developments that might significantly impact the project cash flows or off-taker credit, and other circumstances related to the project.
SNF Obligation
SNF Obligation	2	The carrying amount is derived from a contract with the DOE to provide for disposal of SNF from certain of our nuclear generating stations. See Note 19 — Commitments and Contingencies for further details. When determining the fair value of the obligation, the future carrying amount of the SNF obligation is calculated by compounding the current book value of the SNF obligation at the 13-week U.S. Treasury rate. The compounded obligation amount is discounted back to present value using our discount rate, which is calculated using the same methodology as described above for the taxable debt securities, and an estimated maturity date of 2035.

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 18 — Fair Value of Financial Assets and Liabilities

Recurring Fair Value Measurements

The following tables present assets and liabilities measured and recorded at fair value in the Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2023 and 2022:


	As of December 31, 2023						As of December 31, 2022
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Cash equivalents(a)	$	42	$	—	$	—	$	42	$	41	$	—	$	—	$	41
NDT fund investments
Cash equivalents(b)	356		87		—		443		181		88		—		269
Equities	4,574		1,990		1		6,565		3,462		1,498		—		4,960






Fixed income	2,043		1,523		277		3,843		2,017		1,044		264		3,325
Private credit	—		—		151		151		—		—		159		159
Assets measured at NAV	—		—		—		5,396		—		—		—		5,414



NDT fund investments subtotal(c)	6,973		3,600		429		16,398		5,660		2,630		423		14,127
Rabbi trust investments	48		33		1		82		40		27		1		68




Investments in equities(d)	372		—		—		372		6		—		—		6
Commodity derivative assets
Economic hedges	2,330		5,821		3,143		11,294		3,505		11,353		5,585		20,443
Proprietary trading	—		—		2		2		—		4		6		10
Effect of netting and allocation of collateral(e)(f)	(1,996)		(5,195)		(1,931)		(9,122)		(2,951)		(10,348)		(3,525)		(16,824)
Commodity derivative assets subtotal	334		626		1,214		2,174		554		1,009		2,066		3,629
DPP consideration	—		1,216		—		1,216		—		515		—		515
Total assets measured at fair value	7,769		5,475		1,644		20,284		6,301		4,181		2,490		18,386
Total assets	7,769		5,475		1,644		20,284		6,301		4,181		2,490		18,386
Liabilities
Commodity derivative liabilities
Economic hedges	(2,681)		(7,154)		(2,736)		(12,571)		(3,171)		(11,498)		(5,588)		(20,257)
Proprietary trading	—		—		(2)		(2)		—		(4)		(2)		(6)
Effect of netting and allocation of collateral(e)(f)	2,587		6,542		2,393		11,522		3,279		10,700		3,743		17,722
Commodity derivative liabilities subtotal	(94)		(612)		(345)		(1,051)		108		(802)		(1,847)		(2,541)
Deferred compensation obligation	—		(69)		—		(69)		—		(57)		—		(57)
Total liabilities	(94)		(681)		(345)		(1,120)		108		(859)		(1,847)		(2,598)
Total net assets	$	7,675	$	4,794	$	1,299	$	19,164	$	6,409	$	3,322	$	643	$	15,788

(a)CEG Parent has $54 million of Level 1 cash equivalents as of December 31, 2023. We exclude cash of $349 million and $390 million as of December 31, 2023 and December 31, 2022, respectively, and restricted cash of $49 million and $70 million as of December 31, 2023 and December 31, 2022, respectively. CEG Parent has excluded an additional $2 million and $19 million of cash as of December 31, 2023 and 2022, respectively.

(b)Includes net liabilities of $115 million and $168 million as of December 31, 2023 and 2022, respectively, which include certain derivative assets that have notional amounts of $64 million and $59 million as of December 31, 2023 and 2022, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, repurchase agreement obligations, and payables related to pending securities purchases. The repurchase agreements are generally short-term in nature with durations generally of 30 days or less. In the prior year net liabilities were excluded, prior year amounts have been updated for consistency with current year presentation.

(c)Includes derivative assets and liabilities that are not material, which have total notional amounts of $884 million and $494 million as of December 31, 2023 and 2022, respectively. The notional principal amounts provide one measure of the transaction volume outstanding as of the periods ended and do not represent the amount of our exposure to credit or market loss.

(d)Includes an equity investment that became publicly traded in the second quarter of 2023 and now has a readily determinable fair value (and no longer is accounted for as an equity method investment due to lack of significant influence). We record the fair value of this investment in Investments on the Consolidated Balance Sheets based on the quoted market price of the stock at June 30, 2023, which resulted in an unrealized gain of $313 million within Other, net in the Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2023.

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 18 — Fair Value of Financial Assets and Liabilities

(e)Net collateral posted to/(received from) counterparties totaled $591 million, $1,347 million, and $462 million allocated to Level 1, Level 2, and Level 3 mark-to-market derivatives, respectively, as of December 31, 2023. Net collateral posted to/(received from) counterparties totaled $328 million, $352 million, and $218 million allocated to Level 1, Level 2, and Level 3 mark-to-market derivatives, respectively, as of December 31, 2022.

(f)Includes $1,712 million of variation margin posted and $836 million of variation margin held from the exchanges as of December 31, 2023 and 2022, respectively.

As of December 31, 2023, our NDTs have outstanding commitments to invest in private credit, private equity, and real estate investments of $344 million, $88 million, and $373 million, respectively. These commitments will be funded by our existing NDT funds.

Equity Security Investments without Readily Determinable Fair Values. We hold investments without readily determinable fair values with carrying amounts of $103 million and $46 million as of December 31, 2023 and 2022, respectively. Changes in fair value, cumulative adjustments, and impairments were not material for the years ended December 31, 2023 and 2022.

Reconciliation of Level 3 Assets and Liabilities

The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 2023 and 2022:


	For the Year Ended December 31, 2023
	NDT Fund Investments		Mark-to-Market Derivatives			Life Insurance Contracts		Total
Balance as of January 1, 2023	$	423	$	219		$	1	$	643

Total realized / unrealized gains (losses)
Included in net income (loss)	2		171		(a)	—		173
Included in Payables related to Regulatory Agreement Units	10		—			—		10
Change in collateral	—		243			—		243

Purchases, sales, issuances and settlements
Purchases	—		160			—		160
Sales	1		(29)			—		(28)

Settlements	(7)		32			—		25
Transfers into Level 3	—		46		(b)	—		46
Transfers out of Level 3	—		27		(b)	—		27
Balance as of December 31, 2023	$	429	$	869		$	1	$	1,299
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of December 31, 2023	$	2	$	1,194		$	—	$	1,196

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 18 — Fair Value of Financial Assets and Liabilities


	For the Year Ended December 31, 2022
	NDT Fund Investments		Mark-to-Market Derivatives			Life Insurance Contracts		Total
Balance as of January 1, 2022	$	464	$	(94)		$	—	$	370

Total realized / unrealized gains (losses)
Included in net income (loss)	(2)		(753)		(a)	(2)		(757)
Included in Payables related to Regulatory Agreement Units	(10)		—			—		(10)
Change in collateral	—		253			—		253
Impacts of separation	—		—			3		3
Purchases, sales, issuances and settlements
Purchases	5		594			—		599
Sales	—		(50)			—		(50)

Settlements	(35)		(102)			—		(137)
Transfers into Level 3	2		381		(b)	—		383
Transfers out of Level 3	(1)		(10)		(b)	—		(11)

Balance as of December 31, 2022	$	423	$	219		$	1	$	643
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of December 31, 2022	$	(2)	$	(1,265)		$	(2)	$	(1,269)

(a)Includes a reduction of ($991) million for realized gains and an addition of $410 million for realized losses due to the settlement of derivative contracts for the years ended December 31, 2023 and 2022, respectively.

(b)Transfers into and out of Level 3 generally occur when the contract tenor becomes less and more observable, respectively, primarily due to changes in market liquidity or assumptions for certain commodity contracts.

The following table presents the income statement classification of the total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 2023, 2022, and 2021:


	Operating Revenues						Purchased Power and Fuel						Other, net
	2023		2022		2021		2023		2022		2021		2023		2022		2021
Total gains (losses) included in net income	$	706	$	(860)	$	(1,343)	$	(503)	$	5	$	531	$	2	$	(4)	$	5

Total unrealized gains (losses)	1,673		(1,330)		(1,577)		(479)		65		355		2		(2)		5

Valuation Techniques Used to Determine Fair Value

Cash Equivalents. Investments with original maturities of three months or less when purchased, including mutual and money market funds, are considered cash equivalents. The fair values are based on observable market prices and, therefore, are included in the recurring fair value measurements hierarchy as Level 1.

NDT Fund Investments. The trust fund investments have been established to satisfy our nuclear decommissioning obligations as required by the NRC. The NDT funds hold debt and equity securities directly and indirectly through commingled funds and mutual funds, which are included in equities and fixed income. Our NDT fund investments policies outline investment guidelines for the trusts and limit the trust funds’ exposures to investments in highly illiquid markets and other alternative investments, including private credit, private equity, and real estate. Investments with maturities of three months or less when purchased, including certain short-term fixed income securities are considered cash equivalents and included in the recurring fair value measurements hierarchy as Level 1 or Level 2.

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 18 — Fair Value of Financial Assets and Liabilities

Equities. These investments consist of individually held equity securities, equity mutual funds, and equity commingled funds in domestic and foreign markets. With respect to individually held equity securities, the trustees obtain prices from pricing services, whose prices are generally obtained from direct feeds from market exchanges, which we are able to independently corroborate. Equity securities held individually, including real estate investment trusts, rights, and warrants, are primarily traded on exchanges that contain only actively traded securities due to the volume trading requirements imposed by these exchanges. The equity securities that are held directly by the trust funds are valued based on quoted prices in active markets and categorized as Level 1. Certain equity securities have been categorized as Level 2 because they are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities. Certain private placement equity securities are categorized as Level 3 because they are not publicly traded and are priced using significant unobservable inputs.

Equity commingled funds and mutual funds are maintained by investment companies, and fund investments are held in accordance with a stated set of fund objectives. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized as Level 1. For equity commingled funds and mutual funds which are not publicly quoted, the fund administrators value the funds using the NAV per fund share, derived from the quoted prices in active markets on the underlying securities and are not classified within the fair value hierarchy. These investments can typically be redeemed monthly or more frequently, with 30 or less days of notice and without further restrictions.

Fixed income. For fixed income securities, which consist primarily of corporate debt securities, U.S. government securities, foreign government securities, municipal bonds, asset and mortgage-backed securities, commingled funds, mutual funds, and derivative instruments, the trustees obtain multiple prices from pricing vendors whenever possible, which enables cross-provider validations in addition to checks for unusual daily movements. A primary price source is identified based on asset type, class, or issue for each security. With respect to individually held fixed income securities, the trustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the portfolio managers challenge an assigned price and the trustees determine that another price source is preferable. We have obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, we selectively corroborate the fair values of securities by comparison to other market-based price sources. Investments in U.S. Treasury securities have been categorized as Level 1 because they trade in highly-liquid and transparent markets. Certain private placement fixed income securities have been categorized as Level 3 because they are priced using certain significant unobservable inputs and are typically illiquid. The remaining fixed income securities, including certain other fixed income investments, are based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences and are categorized as Level 2. This includes equity investments sold short during the period, which represent liabilities.

Other fixed income investments primarily consist of fixed income commingled funds and mutual funds, which are maintained by investment companies and hold fund investments in accordance with a stated set of fund objectives. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized as Level 1. For fixed income commingled funds and mutual funds which are not publicly quoted, the fund administrators value the funds using the NAV per fund share, derived from the quoted prices in active markets of the underlying securities and are not classified within the fair value hierarchy. These investments typically can be redeemed monthly or more frequently, with 30 or less days of notice and without further restrictions.

Derivative instruments. These instruments, consisting primarily of futures and swaps to manage risk, are recorded at fair value. Over-the-counter derivatives are valued daily, based on quoted prices in active markets and trade in open markets, and have been categorized as Level 1. Derivative instruments other than over-the-counter derivatives are valued based on external price data of comparable securities and have been categorized as Level 2.

Private credit. Private credit investments primarily consist of investments in private debt strategies. These investments are generally less liquid assets with an underlying term of 3 to 5 years and are intended to be held to maturity. The fair value of these investments is determined by the fund manager or administrator using a combination of valuation models including cost models, market models, and income models and typically cannot be redeemed until maturity of the term loan. Private credit investments held directly by us are categorized as Level 3 because they are based largely on inputs that are unobservable and utilize complex valuation models.

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 18 — Fair Value of Financial Assets and Liabilities

For certain private credit funds, the fair value is determined using a combination of valuation models including cost models, market models, and income models and typically cannot be redeemed until maturity of the term loan. These investments are not classified within the fair value hierarchy because their fair value is determined using NAV or its equivalent as a practical expedient.

Private equity. These investments include those in limited partnerships that invest in operating companies that are not publicly traded on a stock exchange such as leveraged buyouts, growth capital, venture capital, distressed investments, and investments in natural resources. These investments typically cannot be redeemed and are generally liquidated over a period of 8 to 10 years from the initial investment date, which is based on our understanding of the investment funds. Private equity valuations are reported by the fund manager and are based on the valuation of the underlying investments, which include unobservable inputs such as cost, operating results, discounted future cash flows, and market-based comparable data. These valuation inputs are unobservable. The fair value of private equity investments is determined using NAV or its equivalent as a practical expedient, and therefore, these investments are not classified within the fair value hierarchy.

Real estate. These investments are funds with a direct investment in pools of real estate properties. These funds are reported by the fund manager and are generally based on independent appraisals of the underlying investments from sources with professional qualifications, typically using a combination of market-based comparable data and discounted cash flows. These valuation inputs are unobservable. Certain real estate investments cannot be redeemed and are generally liquidated over a period of 8 to 10 years from the initial investment date, which is based on our understanding of the investments funds. The remaining liquid real estate investments are generally redeemable from the investment vehicle quarterly, with 30 to 90 days of notice. The fair value of real estate investments is determined using NAV or its equivalent as a practical expedient, and therefore, these investments are not classified within the fair value hierarchy.

We evaluated our NDT portfolios for the existence of significant concentrations of credit risk as of December 31, 2023. Types of concentrations that were evaluated include, but are not limited to, investment concentrations in a single entity, type of industry, foreign country, and individual fund. As of December 31, 2023, there were no significant concentrations (generally defined as greater than 10 percent) of risk in the NDT assets.

See Note 10 — Asset Retirement Obligations for additional information on the NDT fund investments.

Rabbi Trust Investments. The Rabbi trusts were established to hold assets related to deferred compensation plans existing for certain active and retired members of executive management and directors. The Rabbi trusts' assets are included in investments in the Consolidated Balance Sheets and consist primarily of money market funds, mutual funds, and life insurance policies. Money market funds and mutual funds are publicly quoted and have been categorized as Level 1 given the clear observability of the prices. The life insurance policies are valued using the cash surrender value of the policies, net of loans against those policies, which is provided by a third-party. Certain life insurance policies, which consist primarily of mutual funds that are priced based on observable market data, have been categorized as Level 2 because the life insurance policies can be liquidated at the reporting date for the value of the underlying assets.

Deferred Compensation Obligations. Our deferred compensation plans allow participants to defer certain cash compensation into a notional investment account. We include such plans in other current and noncurrent liabilities in the Consolidated Balance Sheets. The value of our deferred compensation obligations is based on the market value of the participants’ notional investment accounts. The underlying notional investments are comprised primarily of equities, mutual funds, commingled funds, and fixed income securities which are based on directly and indirectly observable market prices. Since the deferred compensation obligations themselves are not exchanged in an active market, they are categorized as Level 2 in the fair value hierarchy.

The value of certain employment agreement obligations (which are included with the Deferred compensation obligation in the table above) are based on a known and certain stream of payments to be made over time and are categorized as Level 2 within the fair value hierarchy.

Investments in Equities. We hold certain investments in equity securities with readily determinable fair values in addition to those held within the NDT funds. These equity securities are valued based on quoted prices in active markets and are categorized as Level 1.

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 18 — Fair Value of Financial Assets and Liabilities

Deferred Purchase Price Consideration. We have DPP consideration for the sale of certain receivables of retail electricity. This amount is valued based on the sales price of the receivables net of allowance for credit losses based on accounts receivable aging historical experience coupled with specific identification through a credit monitoring process, which considers current conditions and forward-looking information such as industry trends, macroeconomic factors, changes in the regulatory environment, external credit ratings, publicly available news, payment status, payment history, and the exercise of collateral calls. Since the DPP consideration is based on the sales price of the receivables, it is categorized as Level 2 in the fair value hierarchy. See Note 6 — Accounts Receivable for additional information on the sale of certain receivables.

Mark-to-Market Derivatives. Derivative contracts are traded in both exchange-based and non-exchange-based markets. Exchange-based derivatives that are valued using unadjusted quoted prices in active markets are categorized in Level 1 in the fair value hierarchy. Certain derivatives’ pricing is verified using indicative price quotations available through brokers or over-the-counter, on-line exchanges and are categorized in Level 2. These price quotations reflect the average of the bid-ask, mid-point prices and are obtained from sources that we believe provide the most liquid market for the commodity. The price quotations are reviewed and corroborated to ensure the prices are observable and representative of an orderly transaction between market participants. This includes consideration of actual transaction volumes, market delivery points, bid-ask spreads, and contract duration. The remainder of derivative contracts are valued using the Black model, an industry standard option valuation model. The Black model considers inputs such as contract terms, including maturity, and market parameters, including assumptions of the future prices of energy, interest rates, volatility, credit worthiness, and credit spread. For derivatives that trade in liquid markets, such as generic forwards, swaps, and options, model inputs are generally observable. Such instruments are categorized in Level 2. Our derivatives are predominantly at liquid trading points. For derivatives that trade in less liquid markets with limited pricing information, model inputs generally would include both observable and unobservable inputs. These valuations may include an estimated basis adjustment from an illiquid trading point to a liquid trading point for which active price quotations are available. Such instruments are categorized in Level 3.

For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations whose contract tenure extends into unobservable periods. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility, and contract duration. Such instruments are categorized in Level 3 as the model inputs generally are not observable. Forward price curves for the power market utilized by the front office to manage the portfolio, are reviewed and verified by the middle office, and used for financial reporting by the back office. We consider credit and non-performance risk in the valuation of derivative contracts categorized in Level 2 and 3, including both historical and current market data, in our assessment of credit and non-performance risk by counterparty. Due to master netting agreements and collateral posting requirements, the impacts of credit and non-performance risk were not material to the consolidated financial statements.

Disclosed below is detail surrounding our significant Level 3 valuations. The calculated fair value includes marketability discounts for margining provisions and other attributes. The Level 3 balance generally consists of forward sales and purchases of power and natural gas and certain transmission congestion contracts. We utilize various inputs and factors including market data and assumptions that market participants would use in pricing assets or liabilities as well as assumptions about the risks inherent in the inputs to the valuation technique. The inputs and factors include forward commodity prices, commodity price volatility, contractual volumes, delivery location, interest rates, credit quality of counterparties, and credit enhancements.

For commodity derivatives, the primary input to the valuation models is the forward commodity price curve for each instrument. Forward commodity price curves are derived by risk management for liquid locations and by the traders and portfolio managers for illiquid locations. All locations are reviewed and verified by risk management considering published exchange transaction prices, executed bilateral transactions, broker quotes, and other observable or public data sources. The relevant forward commodity curve used to value each of the derivatives depends on a number of factors, including commodity type, delivery location, and delivery period. Price volatility varies by commodity and location. When appropriate, we discount future cash flows using risk-free interest rates with adjustments to reflect the credit quality of each counterparty for assets and our own credit quality for liabilities. The level of observability of a forward commodity price varies generally due to the delivery location and delivery period. Certain delivery locations including PJM West Hub (for power) and Henry Hub (for natural gas) are more liquid and prices are observable for up to three years in the future. The observability period of volatility

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 18 — Fair Value of Financial Assets and Liabilities

is generally shorter than the underlying power curve used in option valuations. The forward curve for a less liquid location is estimated by using the forward curve from the liquid location and applying a spread to represent the cost to transport the commodity to the delivery location. This spread does not typically represent a majority of the instrument’s market price. As a result, the change in fair value is closely tied to liquid market movements and not a change in the applied spread. The change in fair value associated with a change in the spread is generally immaterial. An average spread calculated across all Level 3 power and gas delivery locations is approximately $47.76 and $3.09 for power and natural gas, respectively as of December 31, 2023. Many of the commodity derivatives are short term in nature and thus a majority of the fair value may be based on observable inputs even though the contract as a whole must be classified as Level 3.

See Note 16 — Derivative Financial Instruments for additional information on mark-to-market derivatives.

The following table presents the significant inputs to the forward curve used to value these positions:


Type of trade	Fair Value as of December 31, 2023		Fair Value as of December 31, 2022		Valuation Technique	Unobservable Input	2023 Range & Arithmetic Average				2022 Range & Arithmetic Average
Mark-to-market derivatives—Economic hedges(a)(b)	$	407	$	(3)	Discounted Cash Flow	Forward power price	$9.64	-	$216	$48	$0.63	-	$283	$72
						Forward gas price	$1.20	-	$14	$3.09	$1.67	-	$26	$4.57
					Option Model	Volatility percentage	23%	-	200%	87%	97%	-	119%	111%

(a)The valuation techniques, unobservable inputs, ranges, and arithmetic averages are the same for the asset and liability positions.

(b)The fair values do not include cash collateral posted (received) on Level 3 positions of $462 million and $218 million as of December 31, 2023 and December 31, 2022, respectively.

The inputs listed above, which are as of the balance sheet date, would have a direct impact on the fair values of the above instruments if they were adjusted. The significant unobservable inputs used in the fair value measurement of our commodity derivatives are forward commodity prices and for options is price volatility. Increases (decreases) in the forward commodity price in isolation would result in significantly higher (lower) fair values for long positions (contracts that give us the obligation or option to purchase a commodity), with offsetting impacts to short positions (contracts that give us the obligation or right to sell a commodity). Increases (decreases) in volatility would increase (decrease) the value for the holder of the option (writer of the option). Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of volatility of prices. An increase to the heat rate or renewable factors would increase the fair value accordingly. Generally, interrelationships exist between market prices of natural gas and power. As such, an increase in natural gas pricing would potentially have a similar impact on forward power markets.

19. Commitments and Contingencies

Commercial Commitments. Commercial commitments as of December 31, 2023, representing commitments potentially triggered by future events, were as follows:


			Expiration within
	Total		2024		2025		2026		2027		2028		2029 and beyond
Letters of credit	$	1,775	$	1,631	$	27	$	1	$	—	$	116	$	—
Surety bonds(a)	824		824		—		—		—		—		—
Total commercial commitments	$	2,599	$	2,455	$	27	$	1	$	—	$	116	$	—

(a)Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 19 — Commitments and Contingencies

Nuclear Insurance

We are subject to liability, property damage and other risks associated with major incidents at any of our nuclear stations. Our financial exposure to these risks is mitigated through insurance and other industry risk-sharing provisions.

The Price-Anderson Act was enacted to ensure the availability of funds for public liability claims arising from an incident at any of the U.S. licensed nuclear facilities and to limit the liability of nuclear reactor owners for such claims from any single incident. As of December 31, 2023, the current liability limit per incident is $16.2 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors at least once every five years with the last adjustment effective November 1, 2018. In accordance with the Price-Anderson Act, we maintain financial protection at levels equal to the amount of liability insurance available from private sources through the purchase of private nuclear energy liability insurance for public liability claims that could arise in the event of an incident. Effective January 1, 2024, the required amount of nuclear energy liability insurance purchased is $500 million for each operating site. Claims exceeding that amount are covered through mandatory participation in a financial protection pool, as required by the Price Anderson-Act, which could provide up to approximately an additional $15.8 billion per incident at any U.S. nuclear power reactor in funds available for public liability claims. Participation in this secondary financial protection pool requires the operator of each reactor to fund its proportionate share of costs for any single incident at any U.S. nuclear power reactor that exceeds the primary layer of financial protection. Our share of this secondary layer would be approximately $3.5 billion, based on our ownership interest in the insured nuclear reactors, however, any amounts payable under this secondary layer would be capped at $520 million per incident within one calendar year.

In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay public liability claims exceeding the $16.2 billion limit for a single incident.

We are required by the NRC to maintain minimal levels of property insurance that demonstrates to the satisfaction of the NRC that we possess an equivalent amount of protection covering the licensee's obligation, in the event of an accident at the licensee's reactor, to stabilize and decontaminate the reactor and the reactor station site at which the reactor experiencing the accident is located. The insurance maintained for each facility is currently provided through insurance policies purchased from NEIL, an industry mutual insurance company of which we are a member. Currently, NRC requires that we maintain a minimum coverage limit for each reactor site of $1.06 billion, which is what our NEIL policies provide.

NEIL may declare distributions to its members as a result of favorable operating experience. In recent years, NEIL has made distributions to its members. Our portion of the annual distribution declared by NEIL is estimated to be $59 million for 2023, and was $30 million and $114 million for 2022 and 2021, respectively. The distributions were recorded as a reduction to Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income.

Premiums paid to NEIL by its members are also subject to a potential assessment for adverse loss experience in the form of a retrospective premium obligation. NEIL has never assessed this retrospective premium since its formation in 1973, and we cannot predict the level of future assessments, if any. The current maximum aggregate annual retrospective premium obligation for us is approximately $254 million. NEIL requires its members to maintain an investment grade credit rating or to ensure collectability of their annual retrospective premium obligation by providing a financial guarantee, letter of credit, deposit premium, or some other means of assurance.

NEIL provides “all risk” property damage, decontamination and premature decommissioning insurance for each station for losses resulting from damage to its nuclear plants, either due to accidents or acts of terrorism. If the decision is made to decommission the facility, a portion of the insurance proceeds will be allocated to a fund, which we are required by the NRC to maintain, to provide for decommissioning the facility. In the event of an insured loss, we are unable to predict the timing of the availability of insurance proceeds to us and the amount of such proceeds that would be available. In the event that one or more acts of terrorism cause accidental property damage within a twelve-month period from the first accidental property damage under one or more policies for all insured plants, the maximum recovery by us will be an aggregate of $3.2 billion plus such additional amounts as the insurer may recover for all such losses from reinsurance, indemnity and any other source, applicable to such losses.

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 19 — Commitments and Contingencies

For our insured losses, we are self-insured to the extent that losses are within the policy deductible or exceed the amount of insurance maintained. Uninsured losses and other expenses, to the extent not recoverable from insurers or the nuclear industry, could also be borne by us. Any such losses could have a material adverse effect on our consolidated financial statements.

Spent Nuclear Fuel Obligation

Under the NWPA, the DOE is responsible for the development of a geologic repository for and the disposal of SNF and high-level radioactive waste. As required by the NWPA, we are a party to contracts with the DOE (Standard Contracts) to provide for disposal of SNF from our nuclear generating stations. In accordance with the NWPA and the Standard Contracts, we had previously paid the DOE one mill ($0.001) per kWh of net nuclear generation for the cost of SNF disposal. The DOE reduced the SNF disposal fee to zero in May 2014. Until a new fee structure is in effect, we will not accrue any further costs related to SNF disposal fees. This fee may be adjusted prospectively to ensure full cost recovery.

We currently assume the DOE will begin accepting SNF in 2035 and use that date for purposes of estimating the nuclear decommissioning AROs. The SNF acceptance date assumption is based on management’s estimate of the amount of time required for DOE to select a site location and develop the necessary infrastructure for long-term SNF storage.

The NWPA and the Standard Contracts required the DOE to begin taking possession of SNF generated by nuclear generating units no later than January 31, 1998. The DOE, however, failed to meet that deadline and its performance has been, and is expected to remain, delayed. In August 2004, we and the DOJ, in close consultation with the DOE, reached a settlement under which the government agreed to reimburse us, subject to certain damage limitations based on the extent of the government’s breach, for costs associated with storage of SNF at our nuclear stations pending the DOE’s fulfillment of its obligations. That settlement agreement does not expire until all SNF has been collected from the sites that it covers. Calvert Cliffs, Ginna, Nine Mile Point, Fitzpatrick, and STP each have separate settlement agreements in place with the DOE which were extended during 2023 to provide for the reimbursement of SNF storage costs through December 31, 2025. We and the DOE have the option to extend those settlements every three years upon mutual consent.

Under the settlement agreements, we received total cumulative cash reimbursements of $1,855 million through December 31, 2023 for costs incurred. After considering the amounts due to co-owners of certain nuclear stations, we received net cumulative cash reimbursements of $1,615 million. As of December 31, 2023 and 2022, the amount of SNF storage costs for which reimbursement has been or will be requested from the DOE under the DOE settlement agreements is as follows:


	December 31, 2023		December 31, 2022
DOE receivable - current(a)	$	229	$	125
DOE receivable - noncurrent(b)	40		130
Amounts owed to co-owners(c)	(23)		(12)

(a)Recorded in Other accounts receivable.

(b)Recorded in Deferred debits and other assets, other.

(c)Recorded primarily in Accounts payable and accrued expenses and Other accounts receivable. Represents amounts owed to the co-owners of Peach Bottom, Quad Cities, and Nine Mile Point Unit 2 generating facilities.

The Standard Contracts with the DOE also required the payment to the DOE of a one-time fee applicable to nuclear plants that generated SNF prior to April 7, 1983. The below table outlines the SNF liability recorded as of December 31, 2023 and 2022:


	December 31, 2023		December 31, 2022
Former ComEd units(a)	$	1,158	$	1,100
Fitzpatrick(b)	138		130
Total SNF Obligation	$	1,296	$	1,230

(a)ComEd previously elected to defer payment of the one-time fee of $277 million for its units that began operations before April 7, 1983, with interest to the date of payment, until just prior to the first delivery of SNF to the DOE. The unfunded

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 19 — Commitments and Contingencies

liabilities for SNF disposal costs, including the one-time fee, were transferred to us as part of Exelon’s 2001 corporate restructuring. See Note 10 — Asset Retirement Obligations for additional detail on Zion Station’s SNF obligation which is included in the table above.

(b)A prior owner of FitzPatrick elected to defer payment of the one-time fee of $34 million, with interest to the date of payment, for the FitzPatrick unit. As part of the FitzPatrick acquisition on March 31, 2017, we assumed a SNF liability for the DOE one-time fee obligation with interest related to FitzPatrick along with an offsetting asset, included in Other deferred debits and other assets, for the contractual right to reimbursement from NYPA, a prior owner of FitzPatrick, for amounts paid for the FitzPatrick DOE one-time fee obligation.

Interest for our SNF liabilities accrues at the 13-week Treasury Rate. The 13-week Treasury Rate in effect for calculation of the interest accrual at December 31, 2023 was 5.488% for the deferred amount transferred from ComEd and 5.509% for the deferred FitzPatrick amount.

The following table summarizes sites for which we do not have an outstanding SNF Obligation:


Description			Sites
Fees have been paid or began operations after April 7, 1983			Former PECO units, Braidwood, Byron, Calvert Cliffs, Clinton, LaSalle Unit 2, Nine Mile Point Unit 2, and STP
Outstanding SNF Obligation remains with former owners			Nine Mile Point Unit 1, Ginna and TMI

Environmental Remediation Matters

General. Our operations have in the past, and may in the future, require substantial expenditures to comply with environmental laws. Additionally, under Federal and state environmental laws, we are generally liable for the costs of remediating environmental contamination of property now or formerly owned by us and of property contaminated by hazardous substances generated by us. We own or lease several real estate parcels, including parcels on which our operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. In addition, we are currently involved in proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future. Unless otherwise disclosed, we cannot reasonably estimate whether we will incur significant liabilities for additional investigation and remediation costs at these or additional sites identified by us, environmental agencies or others. Additional costs could have a material, unfavorable impact on our consolidated financial statements.

As of December 31, 2023 and 2022, we had accrued undiscounted amounts for environmental liabilities of $149 million and $119 million, respectively, in Accounts payable and accrued expenses and Other deferred credits and other liabilities in the Consolidated Balance Sheets.

Cotter Corporation. The EPA has advised Cotter Corporation (N.S.L.) (Cotter), a former ComEd subsidiary, that it is potentially liable in connection with radiological contamination at two sites in Missouri. In 2000, ComEd sold Cotter to an unaffiliated third-party. As part of the sale, ComEd agreed to indemnify Cotter for any liability arising from these two Missouri superfund sites, West Lake Landfill and Latty Avenue. In connection with Exelon’s 2001 corporate restructuring, this responsibility to indemnify Cotter was transferred to us, and ultimately retained by us per the terms of our separation from Exelon. Refer to Note 1 — Basis of Presentation for additional information on the separation.

West Lake Landfill. Including Cotter, there are three PRPs currently participating in the West Lake Landfill remediation proceeding.

In September 2018, the EPA issued its Record of Decision Amendment (RODA) for the selection of a final remedy that requires partial excavation of the radiological materials and capping the landfill. The EPA and the PRPs have entered into a Consent Agreement to perform the Remedial Design, which is expected to be completed in 2024. In March 2019, the PRPs received Special Notice Letters from the EPA to perform the Remedial Action work. The total estimated cost of the remedy, considering the current EPA technical requirements, is approximately $305 million, including cost escalation on an undiscounted basis. Our investigation has identified several other parties who also may be PRPs and could be liable to contribute to the final remedy.

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 19 — Commitments and Contingencies

In September 2018, the three identified PRPs, including Cotter, signed an Administrative Settlement Agreement and Order on Consent for the performance by the PRPs of the groundwater Remedial Investigation Feasibility Study (RI/FS). The purpose of this RI/FS is to define the nature and extent of any groundwater contamination from the West Lake Landfill site and evaluate remedial alternatives. We estimate the undiscounted cost for the groundwater RI/FS to be approximately $50 million. At this time we cannot predict the likelihood, or the extent to which remediation activities, if any, may be required and therefore cannot estimate a reasonably possible range of loss for response costs beyond those associated with the RI/FS component.

We determined a loss associated with the EPA's partial excavation and landfill cover remedy and the groundwater RI/FS is probable and have recorded a liability for each, both of which are included in the total amount as discussed above, that reflects management’s best estimate of Cotter’s allocable share of the cost among the PRPs. Given the joint and several nature of these two liabilities, the amount of our ultimate liability will depend on the actual costs incurred to implement each required remedy as well as on the nature and terms of any cost-sharing arrangements with the final group of PRPs. It is reasonably possible that the ultimate cost and Cotter's associated allocable share could differ significantly once these uncertainties are resolved, which could have a material impact on our consolidated financial statements.

Latty Avenue and Vicinity Properties. In August 2011, Cotter was notified by the DOJ that Cotter is considered a PRP with respect to the government’s clean-up costs for contamination attributable to low level radioactive residues at a former storage and reprocessing facility named Latty Avenue near St. Louis, Missouri.

Latty Avenue was investigated and remediated by the United States Army Corps of Engineers pursuant to funding under the Formerly Utilized Sites Remedial Action Program. On August 3, 2020, the DOJ advised Cotter that it is seeking approximately $90 million from all the PRPs. In April 2023, Cotter was informed by the DOJ about potential additional liability for all PRPs of approximately $90 million associated with the Latty Avenue site as well as certain allegedly contaminated properties in the vicinity of Latty Avenue, for which the government alleges that Cotter is a PRP. Pursuant to a series of agreements since 2011, the DOJ and Cotter have extended the Statute of Limitations through August 31, 2024.

We have determined that a loss associated with these claims is probable and have recorded an estimated liability, included in the total amount as discussed above, that reflects management's best estimate of Cotter's allocable share of the cost. It is reasonably possible that Cotter's allocable share could differ significantly, which could have a material impact on our consolidated financial statements.

Litigation

General. We are involved in various other litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. We maintain accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of reasonably possible loss, particularly where (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.

Impacts of the February 2021 Extreme Cold Weather Event and Texas-based Generating Assets Outages. Beginning on February 15, 2021, our Texas-based generating assets within the ERCOT market, specifically Colorado Bend II, Wolf Hollow II, and Handley, experienced outages as a result of extreme cold weather conditions. In addition, those weather conditions drove increased demand for service, dramatically increased wholesale power prices, and also increased gas prices in certain regions.

As a result of the event and outages, we incurred a loss of approximately $800 million for the year ended December 31, 2021. The estimated impact reduced our overall Net loss by approximately $50 million for the year ended December 31, 2022, attributable to a payment to ERCOT from a defaulting market participant, the bankruptcy settlement of a defaulting ERCOT market participant, and the settlement of a dispute related to gas penalties. There was no change to the financial impact in 2023.

Various lawsuits have been filed against us since the February 2021 event and outages. On March 5, 2021, we, along with more than 150 power generators and transmission and distribution companies, were sued by approximately 160 individually named plaintiffs, purportedly on behalf of all Texans who allegedly suffered loss of

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 19 — Commitments and Contingencies

life or sustained personal injury, property damage or other losses as a result of the weather events. The plaintiffs alleged that the defendants failed to properly prepare for the cold weather and failed to properly conduct their operations, seeking compensatory as well as punitive damages. Thereafter, numerous other plaintiffs filed multiple lawsuits against more than 300 defendants, including us, involving similar allegations of liability and claims of personal injury and property damage all arising out of the February weather events. These additional lawsuits allege wrongful death, property damage, or other losses. Co-defendants in these lawsuits include ERCOT, transmission and distribution utilities and other generators.

On December 28, 2021, approximately 130 insurance companies which insured Texas homeowners and businesses filed a subrogation lawsuit against multiple defendants alleging that defendants were at fault for the energy failure that resulted from the winter storm, causing significant property damage to the insureds. Subsequently, several hundred other insurance companies filed similar claims. All of these cases were combined in a Multi-District-Litigation (MDL) pending in Texas state court, which established a bellwether process to consider initial motions to dismiss by the different industry groups of defendants. Defendants filed motions to dismiss the amended complaints in five bellwether cases in July 2022. On February 3, 2023, the court granted the motions to dismiss pertaining to us in part and denied them in part, leaving the plaintiffs' negligence and nuisance claims to proceed. Since the motions to dismiss were partially denied, thousands of new claimants, many in multiple mass tort actions, filed lawsuits in various Texas state courts naming us, among hundreds of other defendants. The majority of these cases were transferred to the MDL. The MDL involves over 200 cases brought by approximately 30,000 plaintiffs, including more than 1,300 insurance companies, and we are defendants in the majority of them. We are also named in an alleged class action that seeks to assert claims on behalf of over 4.1 million Texans within ERCOT who lost power during Winter Storm Uri.

On December 14, 2023, the Court of Appeals for the First District of Texas granted the power generator defendants' Petition for a Writ of Mandamus in the five bellwether cases and ordered the MDL court to dismiss the remaining claims against the power generator defendants, including our entities. The motions to dismiss in the five bellwether cases are expected to be applied to all of the claims against the power generator defendants in the MDL. Plaintiffs have sought rehearing of the decision with all judges of the court.

We dispute liability and deny that we are responsible for any of plaintiffs’ alleged claims and are vigorously contesting them. No loss contingencies have been reflected in the consolidated financial statements with respect to these matters, nor can we currently estimate a range of loss. It is reasonably possible, however, that resolution of these matters could have a material, unfavorable impact on our consolidated financial statements.

Asbestos Personal Injury Claims. We maintain a reserve for claims associated with asbestos-related personal injury actions at certain facilities that are currently owned by us or were previously owned by ComEd, PECO, or BGE. The estimated liabilities are recorded on an undiscounted basis and exclude the estimated legal costs associated with handling these matters, which could be material.

At December 31, 2023 and 2022, we recorded estimated liabilities of approximately $131 million and $95 million, respectively, in total for asbestos-related bodily injury claims. As of December 31, 2023, approximately $20 million of this amount related to 235 open claims presented to us, while the remaining $111 million is for estimated future asbestos-related bodily injury claims anticipated to arise through 2055, based on actuarial assumptions and analyses, which are updated on an annual basis. On a quarterly basis, we monitor actual experience against the number of forecasted claims to be received and expected claim payments and evaluate whether adjustments to the estimated liabilities are necessary.

20. Shareholders' Equity

Share Repurchase Program (CEG Parent)

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. Share repurchases may be made through a variety of methods, which may include open market transactions, privately negotiated transactions, or purchases pursuant to a Rule 10b5-1 trading plan, provided that the amounts spent do not exceed what is authorized. Any repurchased shares are constructively retired and cancelled. The program does not obligate us to acquire a minimum number of shares during any period and our repurchase of CEG's common stock may be limited, suspended, or discontinued at any time at our discretion and without prior notice. Repurchases under this program commenced in March 2023.

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 20 — Shareholders' Equity

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.

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. As of December 31, 2023, there was $1 billion of remaining authority to repurchase shares. No other repurchase plans or programs have been authorized by our Board of Directors. Beginning in January 2024 through the date of this filing, we repurchased from the open market approximately 1.2 million shares of our common stock for a total cost, inclusive of taxes and transaction costs, of $150 million.

Changes in Accumulated Other Comprehensive Loss (All Registrants)

The following tables present changes in AOCI, net of tax, by component:


	Gains (losses) on Cash Flow Hedges		Pension and Non-Pension Postretirement Benefit Plan Items(a)		Foreign Currency Items		Total
Balance at December 31, 2020	$	(7)	$	—	$	(23)	$	(30)

OCI before reclassifications	(1)		—		—		(1)

Net current-period OCI	(1)		—		—		(1)
Balance at December 31, 2021	$	(8)	$	—	$	(23)	$	(31)
Separation-related adjustments	—		(2006)		—		(2,006)
OCI before reclassifications	(1)		186		(3)		182
Amounts reclassified from AOCI	—		95		—		95
Net current-period OCI	(1)		(1,725)		(3)		(1,729)
Balance at December 31, 2022	$	(9)	$	(1,725)	$	(26)	$	(1,760)

OCI before reclassifications	(2)		(453)		2		(453)
Amounts reclassified from AOCI	1		21		—		22
Net current-period OCI	(1)		(432)		2		(431)
Balance at December 31, 2023	$	(10)	$	(2,157)	$	(24)	$	(2,191)

(a)AOCI amounts are included in the computation of net periodic pension and OPEB cost. See Note 15 — Retirement Benefits for additional information. See our Consolidated Statements of Operations and Comprehensive Income for individual components of AOCI.

The following table presents income tax (expense) benefit allocated to each component of our other comprehensive income (loss):


	Year Ended December 31,
	2023		2022		2021
Pension and non-pension postretirement benefit plans:

Actuarial loss reclassified to periodic benefit cost	$	(10)	$	(33)	$	—
Pension and non-pension postretirement benefit plans valuation adjustment(a)	151		619		—

(a)Includes $680 million of income tax benefit related to the separation adjustment for the year ended December 31, 2022.

21. Stock-Based Compensation Plans

Effective February 1, 2022, we established our own LTIP and began granting cash and stock-based awards that primarily include performance share awards and restricted stock units. Our LTIP authorized 20,000,000 shares of common stock for these awards. The existing, unvested cash and stock-based awards issued through the Exelon LTIP were modified in connection with the separation to align with our performance metrics and maintain an

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 21 — Stock-Based Compensation Plans

equivalent value immediately before and after separation. The impact of this modification was not material to our stock-based compensation expense for the year ended December 31, 2022.

Our employees were granted stock-based awards through the Exelon LTIP prior to separation, which primarily included performance share awards and restricted stock units. We also granted cash awards.

The following table presents the stock-based compensation expense included in the Consolidated Statements of Operations and Comprehensive Income. The information does not include expenses related to the cash awards as they are not considered stock-based compensation plans under the applicable authoritative guidance:


	Year Ended December 31,
	2023(a)		2022(a)		2021(b)
Total stock-based compensation expense included in operating and maintenance expense	$	178	$	116	$	47
Income tax benefit	(45)		(29)		(12)
Total after-tax stock-based compensation expense	$	133	$	87	$	35

(a)Costs recognized for the years ended December 31, 2023 and 2022 are related to the Constellation LTIP.

(b)Costs recognized for the year ended December 31, 2021 were allocated to us by Exelon under the Exelon LTIP prior to separation.

We receive a tax deduction based on the intrinsic value of the award on the distribution date for performance share awards and restricted stock units. The tax deduction related to performance share awards and restricted stock units was not material for the years ended December 31, 2023 and 2022. For each award, throughout the requisite service period, we recognize the tax benefit related to compensation costs. For performance share awards and restricted stock units, our realized tax benefit when distributed was not material for the years ended December 31, 2023 and 2022.

Performance Share Awards

Performance share awards are granted under the LTIP. The performance share awards are typically settled 50% in common stock and 50% in cash at the end of the three-year performance period, subject to certain ownership thresholds that, if met, may result in cash settlement of the entire award.

The common stock portion of the performance share awards is considered an equity award and is valued based on our stock price on the grant date. The cash portion of the performance share awards is considered a liability award which is remeasured each reporting period based on the current stock price. As the value of the common stock and cash portions of the awards are based on the stock price during the performance period, coupled with changes in the total expected payout of the award, the compensation costs are subject to volatility until payout is established.

For nonretirement-eligible employees, performance share awards are recognized over the vesting period of three years using the straight-line method. For performance share awards granted to retirement-eligible employees, the value of the performance shares is recognized ratably over the vesting period, which is the year of grant. We process forfeitures as they occur for employees who do not complete the requisite service period.

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 21 — Stock-Based Compensation Plans

The following table summarizes our unvested performance share awards activity:


	Shares	Weighted Average Grant Date Fair Value (per share)
Unvested at December 31, 2022	849,342	$	47.40
Granted	370,874	83.26
Change in performance	471,561	75.31

Forfeited	(20,615)	57.80
Undistributed vested awards(a)	(834,837)	90.81
Unvested at December 31, 2023	836,325	$	61.47

(a) Represents performance share awards that vested but were not distributed to retirement-eligible employees during 2023 and 2022.

The following table summarizes the weighted average grant date fair value and the total fair value of performance share awards vested:


	December 31, 2023(a)		December 31, 2022(a)
Weighted average grant date fair value (per share)	$	83.26	$	48.33
Total fair value of performance shares vested	76		69

(a)As of December 31, 2023 and 2022, $39 million and $28 million of total unrecognized compensation costs related to unvested performance shares are expected to be recognized over the remaining weighted-average period of 1.6 years and 1.7 years, respectively.

Restricted Stock Units

Restricted stock units are granted under the LTIP with the majority being settled in a specific number of shares of common stock after the service condition has been met. The corresponding cost is measured based on the grant date fair value of the restricted stock unit issued.

The value of the restricted stock units is expensed over the requisite service period using the straight-line method. The requisite service period for restricted stock units is generally three to five years. However, certain restricted stock unit awards become fully vested upon the employee reaching retirement eligibility. The value of the restricted stock units granted to retirement-eligible employees is either recognized ratably over the first six months in the year of grant if the employee reaches retirement eligibility prior to July 1st of the grant year or through the date of which the employee reaches retirement eligibility. We process forfeitures as they occur for employees who do not complete the requisite service period.

The following table summarizes our unvested restricted stock unit activity:


	Shares	Weighted Average Grant Date Fair Value (per share)
Unvested at December 31, 2022	790,668	$	53.72
Granted	620,002	86.10
Vested	(295,370)	53.46
Forfeited	(27,922)	69.14
Undistributed vested awards(a)	(222,573)	80.52
Unvested at December 31, 2023	864,805	$	69.42

(a)Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2023 and 2022.

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 21 — Stock-Based Compensation Plans

The following table summarizes the weighted average grant date fair value and the total fair value of restricted stock units vested:


	December 31, 2023(a)		December 31, 2022(a)
Weighted average grant date fair value (per share)	$	86.10	$	54.17
Total fair value of restricted stock units vested	34		35

(a)As of December 31, 2023 and 2022, $35 million and $27 million of total unrecognized compensation costs related to unvested restricted stock units are expected to be recognized over the remaining weighted-average period of 1.9 years and 2.0 years.

22. Variable Interest Entities

As of December 31, 2023 and 2022, we consolidated several VIEs or VIE groups for which we are the primary beneficiary (see Consolidated VIEs below) and had significant interests in several other VIEs for which we do not have the power to direct the entities’ activities and, accordingly, we were not the primary beneficiary (see Unconsolidated VIEs below). Consolidated and unconsolidated VIEs are aggregated to the extent that the entities have similar risk profiles.

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 22 — Variable Interest Entities

Consolidated VIEs

The table below shows the carrying amounts and classification of the consolidated VIEs’ assets and liabilities included in the consolidated financial statements as of December 31, 2023 and 2022. The assets, except as noted in the footnotes to the table below, can only be used to settle obligations of the VIEs. The liabilities, except as noted in the footnotes to the table below, are such that creditors, or beneficiaries, do not have recourse to our general credit.


	December 31, 2023		December 31, 2022
Cash and cash equivalents	$	48	$	51
Restricted cash and cash equivalents	47		46
Accounts receivable
Customer	19		20
Other	10		9

Inventories, net

Materials and supplies	14		12
Other current assets	1,249		549
Total current assets	1,387		687

Property, plant and equipment, net	1,979		1,965


Other noncurrent assets	166		190
Total noncurrent assets	2,145		2,155
Total assets(a)	$	3,532	$	2,842

Long-term debt due within one year	$	63	$	60
Accounts payable	11		17
Accrued expenses	20		23


Other current liabilities	—		2
Total current liabilities	94		102

Long-term debt	704		764

Asset retirement obligations	190		173




Other noncurrent liabilities	2		3
Total noncurrent liabilities	896		940
Total liabilities(b)	$	990	$	1,042

(a)Our balances include unrestricted assets for current unamortized energy contract assets of $22 million and $23 million, disclosed within other current assets in the table above and noncurrent unamortized energy contract assets of $155 million and $178 million, disclosed within other noncurrent assets in the table above as of December 31, 2023 and 2022, respectively.

(b)As of December 31, 2023, our balance does not include any liabilities with recourse. Our balance includes liabilities with recourse of $1 million as of December 31, 2022.

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 22 — Variable Interest Entities

As of December 31, 2023 and 2022, our consolidated VIEs included the following:


Consolidated VIE or VIE groups:	Reason entity is a VIE:	Reason we are the primary beneficiary:
CRP - A collection of wind and solar project entities. We have a 51% equity ownership in CRP. See additional discussion below.	Similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner.	We conduct the operational activities.
Bluestem Wind Energy Holdings, LLC - A Tax Equity structure which is consolidated by CRP.	Similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner.	We conduct the operational activities.
Antelope Valley - A solar generating facility, which is 100% owned by us. Antelope Valley sells all of its output to PG&E through a PPA.	The PPA contract absorbs variability through a performance guarantee.	We conduct all activities.
NER - A bankruptcy remote, special purpose entity which is 100% owned by us, which purchases certain of our customer accounts receivable arising from the sale of retail electricity. NER’s assets will be available first and foremost to satisfy the claims of the creditors of NER. Refer to Note 6 —Accounts Receivable for additional information on the sale of receivables.	Equity capitalization is insufficient to support its operations.	We conduct all activities.

CRP - CRP is a collection of wind and solar project entities and some of these project entities are VIEs that are consolidated by CRP. While we or CRP own 100% of the solar entities and 100% of the majority of the wind entities, it has been determined that the wholly owned solar and wind entities are VIEs because the entities' customers absorb price variability from the entities through fixed price power and/or REC purchase agreements. Additionally, for the wind entities that have minority interests, it has been determined that these entities are VIEs because the governance rights of some investors are not proportional to their financial rights. We are the primary beneficiary of these solar and wind entities that qualify as VIEs because we control operations and direct all activities of the facilities. There is limited recourse to us related to certain solar and wind entities.

In 2017, our interests in CRP were contributed to and are pledged for the CR non-recourse debt project financing structure. Refer to Note 17 — Debt and Credit Agreements for additional information.

Unconsolidated VIEs

Our variable interests in unconsolidated VIEs generally include equity investments and energy purchase and sale contracts. For the equity investments, the carrying amount of the investments is reflected in the Consolidated Balance Sheets in Investments. For the energy purchase and sale contracts (commercial agreements), the carrying amount of assets and liabilities in the Consolidated Balance Sheets that relate to our involvement with the VIEs are predominantly related to working capital accounts and generally represent the amounts owed by, or owed to, us for the deliveries associated with the current billing cycles under the commercial agreements.

As of December 31, 2023 and 2022, we had significant unconsolidated variable interests in several VIEs for which we were not the primary beneficiary. These interests include certain equity method investments and certain commercial agreements.

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 22 — Variable Interest Entities

The following table presents summary information about our significant unconsolidated VIE entities:


	December 31, 2023						December 31, 2022
	Commercial Agreement VIEs		Equity Investment VIEs		Total		Commercial Agreement VIEs		Equity Investment VIEs		Total
Total assets(a)	$	704	$	—	$	704	$	715	$	—	$	715
Total liabilities(a)	77		—		77		54		—		54

Other ownership interests in VIE(a)	627		—		627		661		—		661

(a)These items represent amounts on the unconsolidated VIE balance sheets, not in the Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs. We do not have any exposure to loss as we do not have a carrying amount in the equity investment VIEs as of December 31, 2023 and 2022.

As of December 31, 2023 and 2022, the unconsolidated VIEs consist of:


Unconsolidated VIE groups:	Reason entity is a VIE:	Reason we are not the primary beneficiary:
Equity investments in distributed energy companies. We have a 90% equity ownership in a distributed energy company. We sold this investment in the fourth quarter of 2022 resulting in it no longer being classified as an unconsolidated VIE .	Similar structures to a limited partnership and the limited partners do not have kick out rights with respect to the general partner.	We do not conduct the operational activities.
Energy Purchase and Sale agreements - We have several energy purchase and sale agreements with generating facilities.	PPA contracts that absorb variability through fixed pricing.	We do not conduct the operational activities.

23. Supplemental Financial Information

Supplemental Statement of Operations Information

The following tables provide additional information about material items recorded in the Consolidated Statements of Operations and Comprehensive Income.


	Taxes other than income taxes
	For the Years Ended December 31,
	2023		2022		2021
Gross receipts(a)	$	139	$	130	$	99
Property	253		274		268
Payroll	142		130		109

(a)Represent gross receipts taxes related to our retail operations. The offsetting collection of gross receipts taxes from customers is recorded in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income.

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 23 — Supplemental Financial Information


	Other, net
	For the Years Ended December 31,
	2023		2022		2021
Decommissioning-related activities:
Net realized income on NDT funds(a)
Regulatory Agreement Units	$	657	$	333	$	817
Non-Regulatory Agreement Units	335		97		449
Net unrealized (losses) gains on NDT funds
Regulatory Agreement Units	397		(1,354)		351
Non-Regulatory Agreement Units	259		(798)		209
Regulatory offset to NDT fund-related activities(b)	(845)		820		(917)
Total Decommissioning-related activities	803		(902)		909
Non-service net periodic benefit credit(c)	54		110		—
Net realized and unrealized (losses) gains from equity investments(d)	307		(13)		(160)
Return to provision adjustment(e)	19		(49)		—
Other(f)	85		68		46
Total Other, net	$	1,268	$	(786)	$	795

(a)Realized income includes interest, dividends and realized gains and losses on sales of NDT fund investments.

(b)Includes the elimination of decommissioning-related activities and the elimination of income taxes related to all NDT fund activity for the Regulatory Agreement Units except for decommissioning-related impacts that were not offset for the Byron units starting in the second quarter of 2021. With our September 15, 2021 reversal of the previous decision to retire Byron, we resumed contractual offset for Byron as of that date. See Note 10 — Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning and the contractual offset suspension for the Byron units.

(c)Prior to separation, we were allocated our portion of pension and OPEB non-service credits (costs) from Exelon, which was included in Operating and maintenance expense. Effective February 1, 2022, the non-service credit (cost) components are included in Other, net, in accordance with single employer plan accounting. See Note 15 — Retirement Benefits for additional information.

(d)For 2023, includes unrealized gain resulting from equity investment that became publicly traded in the second quarter of 2023 and now has a readily determinable fair value (and no longer is accounted for as an equity method investment due to lack of significant influence). We recorded the fair value of this investment in Investments on the Consolidated Balance Sheets based on quoted market price of the stock. See Note 18 — Fair Value of Financial Assets and Liabilities for additional information. For 2022, represents Net realized and unrealized (losses) gains from equity investments. For 2021, represents Net unrealized (losses) gains from equity investments.

(e)This reflects amounts contractually owed to Exelon under the TMA, which is offset in Income taxes. See Note 14 — Income Taxes for additional information.

(f)Includes amounts we billed Exelon for services pursuant to the TSA. See Note 1 — Basis of Presentation for additional information.

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 23 — Supplemental Financial Information

Supplemental Cash Flow Information

The following tables provide additional information about material items recorded in the Consolidated Statements of Cash Flows.


	Depreciation, amortization and accretion
	For the Years Ended December 31,
	2023		2022		2021
Property, plant, and equipment(a)	$	1,073	$	1,065	$	2,954
Amortization of intangible assets, net(a)	23		26		49
Amortization of energy contract assets and liabilities(b)	35		35		31
Nuclear fuel(c)	787		758		992
ARO accretion(d)	596		543		514
Total depreciation, amortization, and accretion	$	2,514	$	2,427	$	4,540

(a)Included in Depreciation and amortization expense in the Consolidated Statements of Operations and Comprehensive Income.

(b)Included in Operating revenues or Purchased power and fuel expense in the Consolidated Statements of Operations and Comprehensive Income.

(c)Included in Purchased power and fuel expense in the Consolidated Statements of Operations and Comprehensive Income.

(d)Included in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income.


	Cash paid during the year
	For the Years Ended December 31,
	2023		2022		2021
Interest (net of amount capitalized)	$	264	$	230	$	275
Income taxes (net of refunds)	466		287		426


	Other non-cash operating activities
	CEG Parent						Constellation
	For the Years Ended December 31,						For the Years Ended December 31,
	2023		2022		2021		2023		2022		2021
Pension and non-pension postretirement benefit costs	$	47	$	17	$	123	$	47	$	17	$	123

Other decommissioning-related activity(a)	(534)		(263)		(946)		(534)		(263)		(946)
Energy-related options(b)	183		293		125		183		293		125
Asset impairments	71		—		545		71		—		545
(Gain) loss on sale of assets and businesses	(27)		(1)		(201)		(27)		(1)		(201)
Severance costs	2		(1)		(73)		2		(1)		(73)
Long-term incentive plan	57		44		—		—		—		—

Amortization of operating ROU asset	64		75		119		64		75		119
(Gain) loss on sale of receivables	75		69		36		75		69		36

(a)Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units except for decommissioning-related impacts that were not offset for the Byron units starting in the second quarter of 2021, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income, and income taxes related to all NDT fund activity for these units. With our September 15, 2021 reversal of the previous decision to retire Byron, we resumed contractual offset for Byron as of that date. See Note 10 — Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning and the contractual offset suspension for the Byron units.

(b)Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations.

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 23 — Supplemental Financial Information

The following table provides a reconciliation of cash, restricted cash, and cash equivalents reported in the Consolidated Balance Sheets that sum to the total of the same amounts in the Consolidated Statements of Cash Flows.


December 31, 2023	CEG Parent		Constellation
Cash and cash equivalents	$	368	$	366
Restricted cash and cash equivalents	86		74

Total cash, restricted cash, and cash equivalents	$	454	$	440


December 31, 2022	CEG Parent		Constellation
Cash and cash equivalents	$	422	$	403
Restricted cash and cash equivalents	106		98
Total cash, restricted cash, and cash equivalents	$	528	$	501


December 31, 2021	CEG Parent		Constellation
Cash and cash equivalents	$	504	$	504
Restricted cash and cash equivalents	72		72

Total cash, restricted cash, and cash equivalents	$	576	$	576

For additional information on restricted cash, see Note 1 — Basis of Presentation.

Supplemental Balance Sheet Information

The following tables provide additional information about material items recorded in the Consolidated Balance Sheets.


	Investments
	December 31, 2023		December 31, 2022

Equity method investments(a)	$	7	$	82

Other investments:
Employee benefit trusts and investments(b)	82		68
Equity investments with readily determinable fair values(a)(c)	369		—
Equity investments without readily determinable fair values	103		46
Other available for sale debt security investments	2		6
Total investments	$	563	$	202

(a)An investment previously classified as an equity method investment became publicly traded in the second quarter of 2023 and now has a readily determinable fair value. We recorded the fair value of this investment in Investments on the Consolidated Balance Sheets based on quoted market price of the stock. See Note 18 — Fair Value of Financial Assets and Liabilities for additional information.

(b)Debt and equity security investments are recorded at fair market value.

(c)Does not include the equity investments with readily determinable fair values that are recorded in Other current assets in the Consolidated Balance Sheets. See Note 18 — Fair Value of Financial Assets and Liabilities for additional information on Investments in equities.


	Accounts payable and accrued expenses
December 31, 2023	CEG Parent		Constellation
Accounts payable	$	1,302	$	1,289
Compensation-related accruals(a)	680		576
Taxes accrued	399		390

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 23 — Supplemental Financial Information


	Accounts payable and accrued expenses
December 31, 2022	CEG Parent		Constellation
Accounts payable	$	2,828	$	2,810
Compensation-related accruals(a)	540		502
Taxes accrued	257		257

(a)Primarily includes accrued payroll, bonuses and other incentives, vacation, and benefits.

24. Related Party Transactions

Prior to completion of the separation on February 1, 2022, we engaged in transactions with affiliates of Exelon in the normal course of business, these affiliate transactions are summarized in the tables below. After February 1, 2022, all transactions with Exelon or its affiliates are no longer related party transactions.

Operating revenues from affiliates

The following table presents our Operating revenues from affiliates:


	For the Years Ended December 31,
	2022(a)		2021
ComEd(b)	$	58	$	376
PECO(c)	33		196
BGE(d)	18		236
PHI	51		366
Pepco(e)	39		270
DPL(f)	10		79
ACE(g)	2		17
Other	—		14
Total operating revenues from affiliates	$	160	$	1,188

(a)Represents only January 2022 costs prior to separation on February 1, 2022.

(b)We have an ICC-approved RFP contract with ComEd to provide a portion of ComEd’s electricity supply requirements. We also sell RECs and ZECs to ComEd.

(c)We provide electric supply to PECO under contracts executed through PECO’s competitive procurement process. In addition, we have a ten-year agreement with PECO to sell solar AECs.

(d)We provide a portion of BGE’s energy requirements under its MDPSC-approved market-based SOS and gas commodity programs.

(e)We provide electric supply to Pepco under contracts executed through Pepco's competitive procurement process approved by the MDPSC and DCPSC.

(f)We provide a portion of DPL's energy requirements under its MDPSC and DEPSC approved market-based SOS commodity programs.

(g)We provide electric supply to ACE under contracts executed through ACE's competitive procurement process.

Service Company Costs for Corporate Support

We received a variety of corporate support services from Exelon. Through its business services subsidiary, BSC, Exelon provided support services at cost, including legal, human resources, financial, information technology, and supply management services. The costs of BSC were directly charged or allocated to us. Certain of these services continue after the separation and are covered by the TSA. See Note 1 — Basis of Presentation for additional information. The operating and maintenance service company costs from affiliates allocated to us prior to separation were $44 million and $588 million for the years ended December 31, 2022 and 2021, respectively. The capitalized service company costs allocated to us prior to separation were $15 million and $129 million for the years ended December 31, 2022 and 2021, respectively.

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