Constellation Energy Corporation

11/04/2024 | Press release | Distributed by Public on 11/04/2024 10:43

Quarterly Report for Quarter Ending September 30, 2024 (Form 10-Q)

ceg-20240930
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended September 30, 2024
or
☐
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission
File Number 		Name of Registrant; State or Other Jurisdiction of Incorporation; Address of Principal Executive Offices; and Telephone Number IRS Employer Identification Number
001-41137 CONSTELLATION ENERGY CORPORATION 87-1210716
(a Pennsylvania corporation)
1310 Point Street
Baltimore, Maryland 21231-3380
(833) 883-0162
333-85496 CONSTELLATION ENERGY GENERATION, LLC 23-3064219
(a Pennsylvania limited liability company)
200 Energy Way
Kennett Square, Pennsylvania 19348-2473
(833) 883-0162
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Trading Symbol(s) Name of each exchange on which registered
CONSTELLATION ENERGY CORPORATION:
Common Stock, without par value CEG The Nasdaq Stock Market LLC
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Constellation Energy Corporation Yes x No ☐
Constellation Energy Generation, LLC Yes x No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ý No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Constellation Energy Corporation Large Accelerated Filer x Accelerated Filer
☐
Non-accelerated Filer
☐
Smaller Reporting Company
☐
Emerging Growth Company
☐
Constellation Energy Generation, LLC Large Accelerated Filer
☐
Accelerated Filer
☐
Non-accelerated Filer x Smaller Reporting Company
☐
Emerging Growth Company
☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No x
The number of shares outstanding of each registrant's common stock as of October 31, 2024 was as follows:
Constellation Energy Corporation Common Stock, without par value 312,766,599
Constellation Energy Generation, LLC Not applicable
TABLE OF CONTENTS
Page No.
GLOSSARY OF TERMS AND ABBREVIATIONS
1
FILING FORMAT
4
CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION
4
WHERE TO FIND MORE INFORMATION
4
PART I
FINANCIAL INFORMATION
4
ITEM 1.
FINANCIAL STATEMENTS
4
Constellation Energy Corporation
Consolidated Statements of Operations and Comprehensive Income
5
Consolidated Statements of Cash Flows
6
Consolidated Balance Sheets
7
Consolidated Statements of Changes in Equity
9
Constellation Energy Generation, LLC
Consolidated Statements of Operations and Comprehensive Income
11
Consolidated Statements of Cash Flows
12
Consolidated Balance Sheets
13
Consolidated Statements of Changes in Equity
15
Combined Notes to Consolidated Financial Statements
1. Basis of Presentation
17
2. Mergers, Acquisitions, and Dispositions
17
3. Revenue from Contracts with Customers
18
4. Segment Information
20
5. Government Assistance
23
6. Accounts Receivable
23
7. Nuclear Decommissioning
25
8. Income Taxes
26
9. Retirement Benefits
27
10. Derivative Financial Instruments
28
11. Debt and Credit Agreements
33
12. Fair Value of Financial Assets and Liabilities
34
13. Commitments and Contingencies
40
14. Shareholders' Equity
41
15. Variable Interest Entities
42
16. Supplemental Financial Information
45
ITEM 2.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
48
Executive Overview
48
Significant Transactions and Developments
48
Other Key Business Drivers
49
Critical Accounting Policies and Estimates
49
Financial Results of Operations
50
Liquidity and Capital Resources
62
ITEM 3.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
68
ITEM 4.
CONTROLS AND PROCEDURES
72
PART II
OTHER INFORMATION
72
ITEM 1.
LEGAL PROCEEDINGS
72
ITEM 1A.
RISK FACTORS
72
ITEM 2.
UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
72
ITEM 4.
MINE SAFETY DISCLOSURES
73
ITEM 5.
OTHER INFORMATION
73
ITEM 6.
EXHIBITS
74
SIGNATURES
75
Constellation Energy Corporation
75
Constellation Energy Generation, LLC
76
Table of Contents
GLOSSARY OF TERMS AND ABBREVIATIONS
Constellation Energy Corporation and Related Entities
CEG Parent Constellation Energy Corporation
Constellation
Constellation Energy Generation, LLC
Registrants CEG Parent and Constellation, collectively
Antelope Valley Antelope Valley Solar Ranch One
Calvert Cliffs
Calvert Cliffs nuclear generating station
Continental Wind Continental Wind LLC
CR
Constellation Renewables, LLC
Crane Crane Clean Energy Center (formerly known as Three Mile Island Unit 1)
CRP
Constellation Renewables Partners, LLC
FitzPatrick James A. FitzPatrick nuclear generating station
NER NewEnergy Receivables LLC
NMP Nine Mile Point nuclear generating station
RPG Renewable Power Generation, LLC
STP
South Texas Project nuclear generating station
West Medway II West Medway Generating Station II
Former Related Entities
Exelon Exelon Corporation
ComEd Commonwealth Edison Company
PECO PECO Energy Company
BGE Baltimore Gas and Electric Company
1
Table of Contents
GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
AEP Texas
American Electric Power Texas
AESO Alberta Electric Systems Operator
AOCI Accumulated Other Comprehensive Income (Loss)
ARC Asset Retirement Cost
ARO Asset Retirement Obligation
ASR Accelerated Share Repurchase
CAISO California ISO
CenterPoint
CenterPoint Energy Houston Electric, LLC
Clean Air Act Clean Air Act of 1963, as amended
CMC Carbon Mitigation Credit
CODM Chief Operating Decision Maker
DOE United States Department of Energy
DPP Deferred Purchase Price
EPA United States Environmental Protection Agency
ERCOT Electric Reliability Council of Texas
ERISA Employee Retirement Income Security Act of 1974, as amended
ERP
Enterprise Resource Planning
Exchange Act
Securities Exchange Act of 1934, as amended
FERC Federal Energy Regulatory Commission
Former PECO Units Limerick, Peach Bottom, and Salem nuclear generating units
Former ComEd Units Braidwood, Byron, Dresden, LaSalle and Quad Cities nuclear generating units
FRCC Florida Reliability Coordinating Council
GAAP Generally Accepted Accounting Principles in the United States
GDP
Gross Domestic Product
GHG Greenhouse Gas
GWh Gigawatt hour
ICE Intercontinental Exchange
IPA Illinois Power Agency
IRA
Inflation Reduction Act of 2022
IRS Internal Revenue Service
ISO Independent System Operator
ISO-NE ISO New England Inc.
ITC Investment Tax Credit
MISO Midcontinent Independent System Operator, Inc.
MW Megawatt
MWh Megawatt hour
Mystic COS
Mystic Cost of Service Agreement
NAV Net Asset Value
NASDAQ
Nasdaq Stock Market, LLC
NDT Nuclear Decommissioning Trust
NERC North American Electric Reliability Corporation
NGX Natural Gas Exchange, Inc.
Non-Regulatory Agreement Units Nuclear generating units or portions thereof whose decommissioning-related activities are not subject to contractual elimination under regulatory accounting
2
Table of Contents
NPNS Normal Purchase Normal Sale scope exception
NRC Nuclear Regulatory Commission
NYISO New York ISO
NYMEX New York Mercantile Exchange
OCI Other Comprehensive Income
OIESO Ontario Independent Electricity System Operator
OPEB Other Postretirement Employee Benefits
Pension Protection Act (the Act) Pension Protection Act of 2006
PG&E Pacific Gas and Electric Company
PJM PJM Interconnection, LLC
PPA Power Purchase Agreement
PP&E Property, Plant, and Equipment
PSDAR Post-shutdown Decommissioning Activities Report
PSEG Public Service Enterprise Group Incorporated
PTC Production Tax Credit
Regulatory Agreement Units
Nuclear generating units or portions thereof whose decommissioning-related activities are subject to contractual elimination under regulatory accounting (includes the Former ComEd units, the Former PECO units and STP)
RNF Operating Revenues Net of Purchased Power and Fuel Expense
ROU Right-of-use
RTO Regional Transmission Organization
S&P Standard & Poor's Ratings Services
SEC United States Securities and Exchange Commission
SERC
SERC Reliability Corporation (formerly Southeast Electric Reliability Council)
SNF Spent Nuclear Fuel
SOFR Secured Overnight Financing Rate
SPP Southwest Power Pool
STPNOC
STP Nuclear Operating Company
TMA Tax Matters Agreement
TSA Transition Services Agreement
U.S. Treasury
U.S. Department of the Treasury
VIE Variable Interest Entity
WECC Western Electric Coordinating Council
ZEC Zero Emission Credit
3
Table of Contents
FILING FORMAT
This combined Form 10-Q is being filed separately by Constellation Energy Corporation and Constellation Energy Generation, LLC, (the Registrants). Information contained herein relating to any individual Registrant is filed by the Registrant on its own behalf. Neither Registrant makes any representation as to information relating to the other Registrant.
CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION
This Report contains certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are subject to risks and uncertainties. Words such as "could," "may," "expects," "anticipates," "will," "targets," "goals," "projects," "intends," "plans," "believes," "seeks," "estimates," "predicts," and variations on such words, and similar expressions that reflect our current views with respect to future events and operational, economic, and financial performance, are intended to identify such forward-looking statements.
The factors that could cause actual results to differ materially from the forward-looking statements made by us include those factors discussed herein, as well as the items discussed in (1) the Registrants' combined 2023 Annual Report on Form 10-K in (a) Part I, ITEM 1A. Risk Factors, (b) Part II, ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations, and (c) Part II, ITEM 8. Financial Statements and Supplementary Data: Note 19, Commitments and Contingencies; (2) this Quarterly Report on Form 10-Q in (a) Part II, ITEM 1A. Risk Factors, (b) Part I, ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations, and (c) Part I, ITEM 1. Financial Statements: Note 13, Commitments and Contingencies; and (3) other factors discussed in filings with the SEC by the Registrants.
Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this Report. Neither Registrant undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this Report.
WHERE TO FIND MORE INFORMATION
The SEC maintains an Internet site at www.sec.gov that contains reports, proxy and information statements, and other information that we file electronically with the SEC. These documents are also available to the public from commercial document retrieval services and our website at www.ConstellationEnergy.com. Information contained on our website shall not be deemed incorporated into, or to be a part of, this Report.
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
4
Table of Contents
Constellation Energy Corporation and Subsidiary Companies
Consolidated Statements of Operations and Comprehensive Income
(Unaudited)
Three Months Ended September 30, Nine Months Ended September 30,
(In millions, except per share data) 2024 2023 2024 2023
Operating revenues $ 6,550 $ 6,111 $ 18,186 $ 19,122
Operating expenses
Purchased power and fuel 3,119 3,367 8,828 11,983
Operating and maintenance 1,535 1,353 4,666 4,263
Depreciation and amortization 266 266 868 808
Taxes other than income taxes 165 148 446 419
Total operating expenses 5,085 5,134 14,808 17,473
Gain (loss) on sales of assets and businesses 2 - 2 28
Operating income (loss) 1,467 977 3,380 1,677
Other income and (deductions)
Interest expense, net (147) (82) (416) (292)
Other, net 325 - 693 919
Total other income and (deductions) 178 (82) 277 627
Income (loss) before income taxes 1,645 895 3,657 2,304
Income tax (benefit) expense 449 205 768 677
Equity in income (losses) of unconsolidated affiliates - - (1) (11)
Net income (loss) 1,196 690 2,888 1,616
Net income (loss) attributable to noncontrolling interests (4) (41) (9) (44)
Net income (loss) attributable to common shareholders $ 1,200 $ 731 $ 2,897 $ 1,660
Comprehensive income (loss), net of income taxes
Net income (loss) $ 1,196 $ 690 $ 2,888 $ 1,616
Other comprehensive income (loss), net of income taxes
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost (1) - (3) (3)
Actuarial loss reclassified to periodic cost 15 5 53 18
Pension and non-pension postretirement benefit plan valuation adjustment - - (4) (53)
Unrealized gain (loss) on cash flow hedges 1 - 3 -
Unrealized gain (loss) on foreign currency translation 12 (2) 8 1
Other comprehensive income (loss), net of income taxes 27 3 57 (37)
Comprehensive income (loss) 1,223 693 2,945 1,579
Comprehensive income (loss) attributable to noncontrolling interests (4) (41) (9) (44)
Comprehensive income (loss) attributable to common shareholders $ 1,227 $ 734 $ 2,954 $ 1,623
Average shares of common stock outstanding:
Basic 313 322 315 324
Assumed exercise and/or distributions of stock-based awards 1 1 1 1
Diluted 314 323 316 325
Earnings per average common share
Basic $ 3.83 $ 2.27 $ 9.20 $ 5.12
Diluted $ 3.82 $ 2.26 $ 9.17 $ 5.11
See the Combined Notes to Consolidated Financial Statements
5
Table of Contents
Constellation Energy Corporation and Subsidiary Companies
Consolidated Statements of Cash Flows
(Unaudited)
Nine Months Ended
September 30,
(In millions) 2024 2023
Cash flows from operating activities
Net income (loss) $ 2,888 $ 1,616
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 2,049 1,840
Deferred income taxes and amortization of ITCs 358 189
Net fair value changes related to derivatives (1,161) 146
Net realized and unrealized (gains) losses on NDT funds (475) (154)
Net realized and unrealized (gains) losses on equity investments 115 (490)
Other non-cash operating activities (161) 147
Changes in assets and liabilities:
Accounts receivable 1,083 942
Inventories 31 90
Accounts payable and accrued expenses (38) (1,526)
Option premiums received (paid), net 159 (36)
Collateral received (posted), net 1,495 (222)
Income taxes 154 277
Pension and non-pension postretirement benefit contributions (178) (46)
Other assets and liabilities (7,767) (4,892)
Net cash flows provided by (used in) operating activities (1,448) (2,119)
Cash flows from investing activities
Capital expenditures (1,836) (1,735)
Proceeds from NDT fund sales 4,934 4,221
Investment in NDT funds (5,140) (4,374)
Collection of DPP, net 7,104 4,058
Acquisitions of assets and businesses (22) (21)
Other investing activities 16 30
Net cash flows provided by (used in) investing activities 5,056 2,179
Cash flows from financing activities
Change in short-term borrowings (1,105) (959)
Proceeds from short-term borrowings with maturities greater than 90 days 200 527
Repayments of short-term borrowings with maturities greater than 90 days (739) (200)
Issuance of long-term debt 900 3,192
Retirement of long-term debt (99) (150)
Dividends paid on common stock (333) (277)
Repurchases of common stock (999) (750)
Other financing activities (5) 6
Net cash flows provided by (used in) financing activities (2,180) 1,389
Increase (decrease) in cash, restricted cash, and cash equivalents 1,428 1,449
Cash, restricted cash, and cash equivalents at beginning of period 454 528
Cash, restricted cash, and cash equivalents at end of period $ 1,882 $ 1,977
Supplemental cash flow information
Increase (decrease) in capital expenditures not paid $ 20 $ (63)
Increase (decrease) in DPP 7,682 5,288
Increase (decrease) in PP&E related to ARO update (1,475) 762
See the Combined Notes to Consolidated Financial Statements
6
Table of Contents
Constellation Energy Corporation and Subsidiary Companies
Consolidated Balance Sheets
(Unaudited)
(In millions) September 30, 2024 December 31, 2023
ASSETS
Current assets
Cash and cash equivalents $ 1,793 $ 368
Restricted cash and cash equivalents 89 86
Accounts receivable
Customer accounts receivable (net of allowance for credit losses of $55 and $56 as of September 30, 2024 and December 31, 2023, respectively)
1,208 1,934
Other accounts receivable (net of allowance for credit losses of $6 and $5 as of September 30, 2024 and December 31, 2023)
557 917
Mark-to-market derivative assets 632 1,179
Inventories, net
Natural gas, oil, and emission allowances 209 284
Materials and supplies 1,263 1,216
Renewable energy credits 700 660
Other 2,819 1,655
Total current assets 9,270 8,299
Property, plant, and equipment (net of accumulated depreciation and amortization of $17,972 and $17,423 as of September 30, 2024 and December 31, 2023, respectively)
20,892 22,116
Deferred debits and other assets
Nuclear decommissioning trust funds 17,694 16,398
Investments 494 563
Goodwill 420 425
Mark-to-market derivative assets 732 995
Deferred income taxes 35 52
Other 2,297 1,910
Total deferred debits and other assets 21,672 20,343
Total assets(a)
$ 51,834 $ 50,758
See the Combined Notes to Consolidated Financial Statements
7
Table of Contents
Constellation Energy Corporation and Subsidiary Companies
Consolidated Balance Sheets
(Unaudited)
(In millions) September 30, 2024 December 31, 2023
LIABILITIES AND EQUITY
Current liabilities
Short-term borrowings $ - $ 1,644
Long-term debt due within one year 1,034 121
Accounts payable and accrued expenses
2,685 2,612
Mark-to-market derivative liabilities 502 632
Renewable energy credit obligation 909 972
Other 322 338
Total current liabilities 5,452 6,319
Long-term debt 7,378 7,496
Deferred credits and other liabilities
Deferred income taxes and unamortized ITCs 3,554 3,209
Asset retirement obligations 12,322 14,118
Pension obligations 867 1,070
Non-pension postretirement benefit obligations 774 732
Spent nuclear fuel obligation 1,349 1,296
Payables related to Regulatory Agreement Units 4,828 3,688
Mark-to-market derivative liabilities 341 419
Other 2,028 1,125
Total deferred credits and other liabilities 26,063 25,657
Total liabilities(a)
38,893 39,472
Commitments and contingencies (Note 13)
Shareholders' equity
Common stock (No par value, 1,000 shares authorized, 313 shares and 317 shares outstanding as of September 30, 2024 and December 31, 2023, respectively)
11,379 12,355
Retained earnings (deficit) 3,325 761
Accumulated other comprehensive income (loss), net
(2,134) (2,191)
Total shareholders' equity 12,570 10,925
Noncontrolling interests 371 361
Total equity 12,941 11,286
Total liabilities and shareholders' equity $ 51,834 $ 50,758
__________
(a)Our consolidated assets include $3,992 million and $3,355 million at September 30, 2024 and December 31, 2023, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Our consolidated liabilities include $982 million and $990 million at September 30, 2024 and December 31, 2023, respectively, of certain VIEs for which the VIE creditors do not have recourse to us. See Note 15 - Variable Interest Entities for additional information.
See the Combined Notes to Consolidated Financial Statements
8
Table of Contents
Constellation Energy Corporation and Subsidiary Companies
Consolidated Statements of Changes in Equity
(Unaudited)
Nine Months Ended September 30, 2024
Shareholders' Equity
(In millions, shares in thousands) Issued Shares Common Stock Retained Earnings (Deficit)
Accumulated Other Comprehensive Income (Loss), net
Noncontrolling Interests
Total Equity
Balance, December 31, 2023 317,472 $ 12,355 $ 761 $ (2,191) $ 361 $ 11,286
Net Income (loss) - - 883 - - 883
Employee incentive plans 661 (4) - - - (4)
Common stock dividends ($0.3525/common share)
- - (112) - - (112)
Common stock repurchased (2,900) (504) - - - (504)
Other comprehensive income (loss), net of income taxes - - - 11 - 11
Balance, March 31, 2024 315,233 $ 11,847 $ 1,532 $ (2,180) $ 361 $ 11,560
Net Income (loss) - - 814 - (5) 809
Employee incentive plans 72 8 - - - 8
Common stock dividends ($0.3525/common share)
- - (110) - - (110)
Common stock repurchased (2,091) (505) - - - (505)
Other comprehensive income (loss), net of income taxes - - - 19 - 19
Balance, June 30, 2024 313,214 $ 11,350 $ 2,236 $ (2,161) $ 356 $ 11,781
Net Income (loss) - - 1,200 - (4) 1,196
Employee incentive plans 78 29 - - - 29
Changes in equity of noncontrolling interests - - - - 19 19
Common stock dividends ($0.3525/common share)
- - (111) - - (111)
Common stock repurchased (528) - - - - -
Other comprehensive income (loss), net of income taxes - - - 27 27
Balance, September 30, 2024 312,764 $ 11,379 $ 3,325 $ (2,134) $ 371 $ 12,941
See the Combined Notes to Consolidated Financial Statements
9
Table of Contents
Nine Months Ended September 30, 2023
Shareholders' Equity
(In millions, shares in thousands) Issued Shares Common Stock Retained Earnings (Deficit)
Accumulated Other Comprehensive Income (Loss), net
Noncontrolling Interests
Total Equity
Balance, December 31, 2022 327,130 $ 13,274 $ (496) $ (1,760) $ 354 $ 11,372
Net Income (loss) - - 96 - 6 102
Employee incentive plans 528 6 - - - 6
Changes in equity of noncontrolling interests - - - - (2) (2)
Common stock dividends ($0.2820/common share)
- - (93) - - (93)
Common stock repurchased (3,239) (251) - - - (251)
Other comprehensive income (loss), net of income taxes - - - (48) - (48)
Balance, March 31, 2023 324,419 $ 13,029 $ (493) $ (1,808) $ 358 $ 11,086
Net Income (loss) - - 833 - (9) 824
Employee incentive plans 115 31 - - - 31
Changes in equity of noncontrolling interests - - - - 7 7
Common stock dividends ($0.2820/common share)
- - (92) - - (92)
Common stock repurchased (2,958) (252) - - - (252)
Other comprehensive income, net of income taxes - - - 8 - 8
Balance, June 30, 2023 321,576 $ 12,808 $ 248 $ (1,800) $ 356 $ 11,612
Net Income (loss) - - 731 - (41) 690
Employee incentive plans 144 21 - - - 21
Changes in equity of noncontrolling interests
- - - - 19 19
Common stock dividends ($0.2820/common share)
- - (92) - - (92)
Common stock repurchased (2,338) (253) - - - (253)
Other comprehensive income, net of income taxes - - - 3 - 3
Balance, September 30, 2023 319,382 $ 12,576 $ 887 $ (1,797) $ 334 $ 12,000
See the Combined Notes to Consolidated Financial Statements
10
Table of Contents
Constellation Energy Generation, LLC and Subsidiary Companies
Consolidated Statements of Operations and Comprehensive Income
(Unaudited)
Three Months Ended September 30, Nine Months Ended September 30,
(In millions) 2024 2023 2024 2023
Operating revenues $ 6,550 $ 6,111 $ 18,186 $ 19,122
Operating expenses
Purchased power and fuel 3,119 3,367 8,828 11,983
Operating and maintenance 1,535 1,353 4,666 4,263
Depreciation and amortization 266 266 868 808
Taxes other than income taxes 165 148 446 419
Total operating expenses 5,085 5,134 14,808 17,473
Gain (loss) on sales of assets and businesses 2 - 2 28
Operating income (loss) 1,467 977 3,380 1,677
Other income and (deductions)
Interest expense, net (147) (82) (416) (292)
Other, net 325 - 693 919
Total other income and (deductions) 178 (82) 277 627
Income (loss) before income taxes 1,645 895 3,657 2,304
Income tax (benefit) expense 449 205 768 677
Equity in income (losses) of unconsolidated affiliates - - (1) (11)
Net income (loss) 1,196 690 2,888 1,616
Net income (loss) attributable to noncontrolling interests (4) (41) (9) (44)
Net income (loss) attributable to membership interest $ 1,200 $ 731 $ 2,897 $ 1,660
Comprehensive income (loss), net of income taxes
Net income (loss) $ 1,196 $ 690 $ 2,888 $ 1,616
Other comprehensive income (loss), net of income taxes
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost (1) - (3) (3)
Actuarial loss reclassified to periodic cost 15 5 53 18
Pension and non-pension postretirement benefit plan valuation adjustment - - (4) (53)
Unrealized gain (loss) on cash flow hedges 1 - 3 -
Unrealized gain (loss) on foreign currency translation 12 (2) 8 1
Other comprehensive income (loss), net of income taxes 27 3 57 (37)
Comprehensive income (loss) 1,223 693 2,945 1,579
Comprehensive income (loss) attributable to noncontrolling interests (4) (41) (9) (44)
Comprehensive income (loss) attributable to membership interest $ 1,227 $ 734 $ 2,954 $ 1,623
See the Combined Notes to Consolidated Financial Statements
11
Table of Contents
Constellation Energy Generation, LLC and Subsidiary Companies
Consolidated Statements of Cash Flows
(Unaudited)
Nine Months Ended
September 30,
(In millions) 2024 2023
Cash flows from operating activities
Net income (loss) $ 2,888 $ 1,616
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 2,049 1,840
Deferred income taxes and amortization of ITCs 358 189
Net fair value changes related to derivatives (1,161) 146
Net realized and unrealized (gains) losses on NDT funds (475) (154)
Net realized and unrealized (gains) losses on equity investments 115 (490)
Other non-cash operating activities (195) 99
Changes in assets and liabilities:
Accounts receivable 1,085 936
Receivables from and payables to affiliates, net 238 23
Inventories 31 90
Accounts payable and accrued expenses (38) (1,546)
Option premiums received (paid), net 159 (36)
Collateral received (posted), net 1,495 (222)
Income taxes 154 277
Pension and non-pension postretirement benefit contributions (178) (46)
Other assets and liabilities (7,977) (4,953)
Net cash flows provided by (used in) operating activities (1,452) (2,231)
Cash flows from investing activities
Capital expenditures (1,836) (1,735)
Proceeds from NDT fund sales 4,934 4,221
Investment in NDT funds (5,140) (4,374)
Collection of DPP, net 7,104 4,058
Acquisitions of assets and businesses (22) (21)
Other investing activities 16 30
Net cash flows provided by (used in) investing activities 5,056 2,179
Cash flows from financing activities
Change in short-term borrowings (1,105) (959)
Proceeds from short-term borrowings with maturities greater than 90 days 200 527
Repayments of short-term borrowings with maturities greater than 90 days (739) (200)
Issuance of long-term debt 900 3,192
Retirement of long-term debt (99) (150)
Distributions to member (1,331) (909)
Other financing activities - (3)
Net cash flows provided by (used in) financing activities (2,174) 1,498
Increase (decrease) in cash, restricted cash, and cash equivalents 1,430 1,446
Cash, restricted cash, and cash equivalents at beginning of period 440 501
Cash, restricted cash, and cash equivalents at end of period $ 1,870 $ 1,947
Supplemental cash flow information
Increase (decrease) in capital expenditures not paid $ 20 $ (63)
Increase (decrease) in DPP 7,682 5,288
Increase (decrease) in PP&E related to ARO update (1,475) 762
See the Combined Notes to Consolidated Financial Statements
12
Table of Contents
Constellation Energy Generation, LLC and Subsidiary Companies
Consolidated Balance Sheets
(Unaudited)
(In millions) September 30, 2024 December 31, 2023
ASSETS
Current assets
Cash and cash equivalents $ 1,793 $ 366
Restricted cash and cash equivalents 77 74
Accounts receivable
Customer accounts receivable (net of allowance for credit losses of $55 and $56 as of September 30, 2024 and December 31, 2023, respectively)
1,208 1,934
Other accounts receivable (net of allowance for credit losses of $6 and $5 as of September 30, 2024 and December 31, 2023)
549 911
Mark-to-market derivative assets 632 1,179
Inventories, net
Natural gas, oil, and emission allowances 209 284
Materials and supplies 1,263 1,216
Renewable energy credits 700 660
Other 2,819 1,655
Total current assets 9,250 8,279
Property, plant, and equipment (net of accumulated depreciation and amortization of $17,972 and $17,423 as of September 30, 2024 and December 31, 2023, respectively)
20,892 22,116
Deferred debits and other assets
Nuclear decommissioning trust funds 17,694 16,398
Investments 494 563
Goodwill 420 425
Mark-to-market derivative assets 732 995
Deferred income taxes 35 52
Other 2,294 1,910
Total deferred debits and other assets 21,669 20,343
Total assets(a)
$ 51,811 $ 50,738
See the Combined Notes to Consolidated Financial Statements
13
Table of Contents
Constellation Energy Generation, LLC and Subsidiary Companies
Consolidated Balance Sheets
(Unaudited)
(In millions) September 30, 2024 December 31, 2023
LIABILITIES AND EQUITY
Current liabilities
Short-term borrowings $ - $ 1,644
Long-term debt due within one year 1,034 121
Accounts payable and accrued expenses
2,410 2,486
Payables to affiliates 356 118
Mark-to-market derivative liabilities 502 632
Renewable energy credit obligation 909 972
Other 318 338
Total current liabilities 5,529 6,311
Long-term debt 7,378 7,496
Deferred credits and other liabilities
Deferred income taxes and unamortized ITCs 3,554 3,209
Asset retirement obligations 12,322 14,118
Pension obligations 867 1,070
Non-pension postretirement benefit obligations 774 732
Spent nuclear fuel obligation 1,349 1,296
Payables related to Regulatory Agreement Units 4,828 3,688
Mark-to-market derivative liabilities 341 419
Other 1,862 1,025
Total deferred credits and other liabilities 25,897 25,557
Total liabilities(a)
38,804 39,364
Commitments and contingencies (Note 13)
Equity
Member's equity
Membership interest 10,538 11,537
Undistributed earnings (deficit)
4,232 1,667
Accumulated other comprehensive income (loss), net
(2,134) (2,191)
Total member's equity 12,636 11,013
Noncontrolling interests 371 361
Total equity 13,007 11,374
Total liabilities and equity $ 51,811 $ 50,738
__________
(a)Our consolidated assets include $3,992 million and $3,355 million as of September 30, 2024 and December 31, 2023, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Our consolidated liabilities include $982 million and $990 million as of September 30, 2024 and December 31, 2023, respectively, of certain VIEs for which the VIE creditors do not have recourse to us. See Note 15 - Variable Interest Entities for additional information.
See the Combined Notes to Consolidated Financial Statements
14
Table of Contents
Constellation Energy Generation, LLC and Subsidiary Companies
Consolidated Statements of Changes in Equity
(Unaudited)
Nine Months Ended September 30, 2024
Member's Equity
(In millions)
Membership Interest
Undistributed Earnings (Deficit)
Accumulated Other Comprehensive Income (Loss), net
Noncontrolling Interests Total Equity
Balance, December 31, 2023 $ 11,537 $ 1,667 $ (2,191) $ 361 $ 11,374
Net Income (loss) - 883 - - 883
Distributions to member (499) (111) - - (610)
Other comprehensive income (loss), net of income taxes - - 11 - 11
Balance, March 31, 2024 $ 11,038 $ 2,439 $ (2,180) $ 361 $ 11,658
Net Income (loss) - 814 - (5) 809
Distribution to member (500) (110) - - (610)
Other comprehensive income (loss), net of income taxes - - 19 - 19
Balance, June 30, 2024 $ 10,538 $ 3,143 $ (2,161) $ 356 $ 11,876
Net Income (loss) - 1,200 - (4) 1,196
Changes in equity of noncontrolling interests - - - 19 19
Distribution to member - (111) - - (111)
Other comprehensive income (loss), net of income taxes - - 27 - 27
Balance, September 30, 2024 $ 10,538 $ 4,232 $ (2,134) $ 371 $ 13,007
See the Combined Notes to Consolidated Financial Statements
15
Table of Contents
Nine Months Ended September 30, 2023
Member's Equity
(In millions)
Membership Interest
Undistributed Earnings (Deficit)
Accumulated Other Comprehensive Income (Loss), net
Noncontrolling Interests Total Equity
Balance, December 31, 2022 $ 12,408 $ 412 $ (1,760) $ 354 $ 11,414
Net Income (loss) - 96 - 6 102
Changes in equity of noncontrolling interests - - - (2) (2)
Distributions to member (152) (97) - - (249)
Other comprehensive income (loss), net of income taxes - - (48) - (48)
Balance, March 31, 2023 $ 12,256 $ 411 $ (1,808) $ 358 $ 11,217
Net Income (loss) - 833 - (9) 824
Changes in equity of noncontrolling interests - - - 7 7
Distribution to member (244) (91) - - (335)
Other comprehensive income (loss), net of income taxes - - 8 - 8
Balance, June 30, 2023 $ 12,012 $ 1,153 $ (1,800) $ 356 $ 11,721
Net Income (loss) - 731 - (41) 690
Changes in equity of noncontrolling interests - - - 19 19
Contribution from member - - - - -
Distributions to member (234) (91) - - (325)
Other comprehensive income (loss), net of income taxes - - 3 - 3
Balance, September 30, 2023 $ 11,778 $ 1,793 $ (1,797) $ 334 $ 12,108
See the Combined Notes to Consolidated Financial Statements
16
Table of Contents
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
The accompanying Consolidated Financial Statements as of September 30, 2024 and for the three and nine months ended September 30, 2024 and 2023 are unaudited but, in our opinion include all adjustments that are considered necessary for a fair statement of the financial statements in accordance with GAAP. All adjustments are of a normal, recurring nature, unless otherwise disclosed. The Consolidated Financial Statements include the accounts of our subsidiaries and all intercompany transactions have been eliminated. Constellation's December 31, 2023 Consolidated Balance Sheet was derived from audited financial statements. The interim financial statements are to be read in conjunction with prior annual financial statements and notes. Financial results for interim periods are not necessarily indicative of results that may be expected for any other interim period or for the fiscal year ending December 31, 2024. These Combined Notes to Consolidated Financial Statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations. 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.
Summary of Significant Accounting Policies
See Note 1 - Basis of Presentation of our 2023 Form 10-K for additional information on significant accounting policies.
2. Mergers, Acquisitions, and Dispositions
Acquisition of Joint Ownership in South Texas Project
In November 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. Other owners include City Public Service Board of San Antonio (CPS, 40%) and the City of Austin, Texas (Austin, 16%). See Note 2 - Mergers, Acquisitions, and Dispositions of our 2023 Form 10-K for additional information.
In May 2024, we executed a settlement agreement with all parties (CPS/City of San Antonio, Austin, and NRG), resolving all litigation involving our purchase of the ownership interest in STP, which was initiated by CPS and Austin in Texas state court and before the NRC. The terms of the settlement include us selling a 2% ownership interest in STP to CPS at the same price and terms that we paid NRG for our 44% interest, subject to regulatory approvals from the NRC and the Public Utility Commission of Texas. Pursuant to the settlement, CPS and Austin filed Notices of Dismissal with Prejudice with the Court, which ends the litigation, and likewise withdrew their pending objections to the sale with the NRC. As a result of the settlement, we have reflected assets and liabilities associated with a 2% undivided ownership interest in STP as held for sale. The held for sale amounts are included in the Other current assets and Other current liabilities balances in the Consolidated Balance Sheets as of September 30, 2024. Closing is expected to occur within the first half of 2025. Upon closing of the sale, we and CPS will each own a 42% interest in STP, and Austin's interest will remain at 16%. The terms of settlement are not expected to have a material impact on our consolidated financial statements.
17
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)
Note 3 - Revenue from Contracts with Customers
3. 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.
See Note 4 - Revenue from Contracts with Customers of our 2023 Form 10-K for additional information regarding the performance obligations, revenue recognition, and payment terms associated with these sources of revenue.
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.
The following table provides a rollforward of the contract assets reflected in the Consolidated Balance Sheets for the three and nine months ended September 30, 2024 and 2023.
2024 2023
Beginning balance as of January 1
$ 82 $ 130
Amounts reclassified to receivables (15) (11)
Revenues recognized 14 31
Ending balance as of March 31
81 150
Amounts reclassified to receivables (4) (76)
Revenues recognized 16 15
Ending balance as of June 30
93 89
Amounts reclassified to receivables (44) (32)
Revenues recognized 37 12
Ending balance as of September 30
$ 86 $ 69
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, which ended in May 2024, included upfront consideration received 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 (June through May), 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. The balance as of September 30, 2024 primarily related to equipment service plans. The balance as of December 31, 2023 primarily related to equipment services plans and the Mystic COS.
18
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)
Note 3 - Revenue from Contracts with Customers
The following table provides a rollforward of the contract liabilities reflected in the Consolidated Balance Sheets for the three and nine months ended September 30, 2024 and 2023.
2024 2023
Beginning balance as of January 1
$ 40 $ 47
Consideration received or due 49 131
Revenues recognized (55) (115)
Ending balance as of March 31
34 63
Consideration received or due 47 81
Revenues recognized (46) (92)
Ending balance as of June 30
35 52
Consideration received or due 11 56
Revenues recognized (11) (68)
Ending balance as of September 30
$ 35 $ 40
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 September 30, 2024. 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 $ 47 $ 139 $ 98 $ 86 $ 295 $ 665
Transaction Price Allocated to Previously Satisfied Performance Obligations
Our Clinton and Quad Cities units contract with certain utilities in Illinois which requires delivery of all ZECs produced during each planning year (June through May), 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 June 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 2023 through May 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. During the second quarter of 2023, we recognized $218 million of revenue as a receivable for ZECs delivered in prior planning years, with payment received in the third quarter of 2024. For the June 2024 through May 2025 planning year, the ZEC price has been established at $9.38 per ZEC, subject to an annual cap of $222 million. Revenue recognized during the second quarter of 2024 for ZECs delivered in prior planning years was not material.
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 4 - Segment Information for the presentation of revenue disaggregation.
19
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)
Note 4 - Segment Information
4. 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.
•Midwestrepresents operations in the western half of PJM and the United States footprint of MISO, excluding MISO's Southern Region.
•New Yorkrepresents operations within NYISO.
•ERCOTrepresents operations within Electric Reliability Council of Texas that covers a majority of the state of Texas.
•Other Power Regions:
•New Englandrepresents operations within ISO-NE.
•Southrepresents operations in FRCC, MISO's Southern Region, and the remaining portions of SERC not included within MISO or PJM.
•Westrepresents operations in WECC, which includes CAISO.
•Canadarepresents 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 as well as government assistance. 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.
20
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)
Note 4 - Segment Information
The following tables also show the reconciliation of reportable segment revenues and RNF to our total revenues and RNF for the three and nine months ended September 30, 2024 and 2023.
Three Months Ended September 30, 2024
Revenues from external customers
Contracts with customers
Other(a)
Total Intersegment Revenues Total Revenues
Mid-Atlantic $ 1,504 $ 97 $ 1,601 $ 2 $ 1,603
Midwest 958 316 1,274 1 1,275
New York 472 39 511 (4) 507
ERCOT 307 215 522 1 523
Other Power Regions 1,213 230 1,443 - 1,443
Total Reportable Segment Power Revenues
4,454 897 5,351 - 5,351
Total Natural Gas Revenues
184 349 533 - 533
Total Other Revenues(b)
135 531 666 - 666
Total Consolidated Operating Revenues $ 4,773 $ 1,777 $ 6,550 $ - $ 6,550
Three Months Ended September 30, 2023
Revenues from external customers
Contracts with customers
Other(a)
Total Intersegment Revenues Total Revenues
Mid-Atlantic $ 1,493 $ (78) $ 1,415 $ (4) $ 1,411
Midwest 1,160 (43) 1,117 - 1,117
New York 522 (14) 508 4 512
ERCOT 489 69 558 1 559
Other Power Regions 1,284 309 1,593 (1) 1,592
Total Reportable Segment Power Revenues
4,948 243 5,191 - 5,191
Total Natural Gas Revenues
220 385 605 - 605
Total Other Revenues(b)
145 170 315 - 315
Total Consolidated Operating Revenues $ 5,313 $ 798 $ 6,111 $ - $ 6,111
Nine Months Ended September 30, 2024
Revenues from external customers
Contracts with customers
Other(a)
Total Intersegment Revenues Total Revenues
Mid-Atlantic $ 4,154 $ (10) $ 4,144 $ 4 $ 4,148
Midwest 2,951 584 3,535 2 3,537
New York 1,428 102 1,530 4 1,534
ERCOT 819 378 1,197 4 1,201
Other Power Regions 3,673 593 4,266 (14) 4,252
Total Reportable Segment Power Revenues 13,025 1,647 14,672 - 14,672
Total Natural Gas Revenues 1,024 1,252 2,276 - 2,276
Total Other Revenues(b)
389 849 1,238 - 1,238
Total Consolidated Operating Revenues $ 14,438 $ 3,748 $ 18,186 $ - $ 18,186
21
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)
Note 4 - Segment Information
Nine Months Ended September 30, 2023
Revenues from external customers
Contracts with customers
Other(a)
Total Intersegment Revenues Total Revenues
Mid-Atlantic $ 4,140 $ (241) $ 3,899 $ (45) $ 3,854
Midwest 3,707 (231) 3,476 3 3,479
New York 1,424 53 1,477 41 1,518
ERCOT 979 73 1,052 4 1,056
Other Power Regions 3,766 732 4,498 (3) 4,495
Total Reportable Segment Power Revenues 14,016 386 14,402 - 14,402
Total Natural Gas Revenues 1,394 1,352 2,746 - 2,746
Total Other Revenues(b)
435 1,539 1,974 - 1,974
Total Consolidated Operating Revenues $ 15,845 $ 3,277 $ 19,122 $ - $ 19,122
__________
(a)Includes revenues from nuclear PTCs beginning in 2024 as well as derivatives and leases in all periods presented.
(b)Represents activities not allocated to a region. See text above for a description of included activities. Includes unrealized mark-to-market gains of $516 million and $177 million for the three months ended September 30, 2024 and 2023, respectively, and unrealized mark-to-market gains of $769 million and $1,317 million for the nine months ended September 30, 2024 and 2023, respectively. See Note 10 - Derivative Financial Instruments for additional information on mark-to-market derivatives.
Three Months Ended September 30, 2024 Three Months Ended September 30, 2023
RNF from external customers
Intersegment RNF
Total RNF
RNF from external customers
Intersegment RNF
Total RNF
Mid-Atlantic $ 806 $ 3 $ 809 $ 747 $ (3) $ 744
Midwest 881 3 884 776 2 778
New York 361 (4) 357 311 6 317
ERCOT 404 (1) 403 211 (4) 207
Other Power Regions 441 (8) 433 434 (3) 431
Total RNF for Reportable Segments 2,893 (7) 2,886 2,479 (2) 2,477
Other(a)
538 7 545 265 2 267
Total RNF $ 3,431 $ - $ 3,431 $ 2,744 $ - $ 2,744
Nine Months Ended September 30, 2024 Nine Months Ended September 30, 2023
RNF from external customers
Intersegment RNF
Total RNF
RNF from external customers
Intersegment RNF
Total RNF
Mid-Atlantic $ 2,235 $ 7 $ 2,242 $ 2,202 $ (44) $ 2,158
Midwest 2,345 7 2,352 2,439 2 2,441
New York 1,070 4 1,074 851 46 897
ERCOT 836 (10) 826 429 (6) 423
Other Power Regions 1,126 (31) 1,095 909 (8) 901
Total RNF for Reportable Segments 7,612 (23) 7,589 6,830 (10) 6,820
Other(a)
1,746 23 1,769 309 10 319
Total RNF $ 9,358 $ - $ 9,358 $ 7,139 $ - $ 7,139
__________
(a)Other represents activities not allocated to a region. See text above for a description of included activities. See Note 10 - Derivative Financial Instruments for additional information on mark-to-market derivatives.
22
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)
Note 5 - Government Assistance
5. Government Assistance
As a result of the enactment of the IRA, we qualify for certain federal government incentives through eligible activities. These incentives include both refundable and transferable tax credits. The current GAAP framework does not address the receipt of government assistance by for-profit entities. We account for this government assistance by analogy to International Accounting Standard (IAS) 20, Accounting for Government Grants and Disclosure of Government Assistance, and recognize the benefits when there is reasonable assurance that we will comply with the required conditions and that the benefits will be received. We believe the reasonable assurance term as used in IAS 20 is analogous to the term probable as defined in Accounting Standards Codification 450-20 of GAAP.
Beginning in 2024, our nuclear units are eligible for a PTC extending through 2032. The nuclear PTC provides a transferable credit up to $15 per MWh (a base credit of $3 per MWh with a five times multiplier provided certain prevailing wage requirements are met) and is subject to phase-out when annual gross receipts are between $25.00 per MWh and $43.75 per MWh. We have determined that we will meet the annual prevailing wage requirements at all our nuclear units and are eligible for the five times multiplier. Both the amount of the PTC and the gross receipts thresholds adjust for inflation after 2024 through the duration of the program based on the GDP price deflator for the preceding calendar year. The benefits of the PTC may be realized through a credit against our federal income taxes or transferred via sale to an unrelated party.
For the three and nine months ended September 30, 2024, our Consolidated Statements of Operations and Comprehensive Income include an estimated nuclear PTC benefit of approximately $670 million and $1,380 million, respectively. Our estimate required the exercise of judgment in determining the amount of nuclear PTC expected for each of our nuclear units. Since the amount of nuclear PTC is a function of annual gross receipts, the actual amount of PTC earned cannot be determined until 2025 and may be different from this initial estimate. Further, the nuclear PTC continues to be the subject of additional guidance expected to be issued from the U.S. Treasury and IRS that may materially impact the total amount of benefits we receive.
Nuclear PTCs are initially recorded within Other deferred debits and other assets within the Consolidated Balance Sheets and reclassified as a reduction to Accounts payable and accrued expenses when used to reduce our federal income tax payable, or an increase in Cash and cash equivalents or Other current assets when sold, depending on the specific payment terms of each contract.
During the third quarter of 2024, we executed agreements for the sale of $1 billion of nuclear PTCs to unaffiliated third parties at a nominal discount, with approximately $670 million of cash proceeds received upon sale (included within Cash flows from operating activities in our Consolidated Statements of Cash Flows) and approximately $290 million to be received over the course of the fourth quarter of 2024 and first quarter of 2025. As of September 30, 2024, our Consolidated Balance Sheets reflect approximately, $240 million of estimated nuclear PTCs within Other deferred debits and other assets, $290 million within Other current assets, and a reduction to Accounts payable and accrued expenses of $140 million for estimated nuclear PTCs that we have utilized as a credit against our current federal income taxes payable.
Many of the state-sponsored programs providing compensation for the emissions-free attributes of generation from certain of our nuclear units include contractual or other provisions that require us to refund that compensation up to the amount of the nuclear PTC received or pass through the entirety of the nuclear PTC received. As of September 30, 2024, we have recognized approximately $720 million of estimated payables within Other deferred credits and other liabilities on our Consolidated Balance Sheets and a reduction to net operating revenue of approximately $115 million (pre-tax) for the three months ended September 30, 2024 and recognized approximately $10 million of net operating revenue (pre-tax) for the nine months ended September 30, 2024 associated with programs requiring refunds or pass through of the nuclear PTC in our Consolidated Statements of Operations and Comprehensive Income. As with the actual amount of the PTC earned, which cannot be determined until after the end of the calendar year, the actual amounts due under state-sponsored programs may be different from our initial estimate.
6. Accounts Receivable
Unbilled Customer Revenue
We recorded $175 million and $372 million of unbilled customer revenues in Customer accounts receivables, net in the Consolidated Balance Sheets as of September 30, 2024 and December 31, 2023, respectively.
23
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)
Note 6 - Accounts Receivable
Sales of Customer Accounts Receivable
In 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). The maximum funding limit of the Facility is $1.1 billion through August 2025. 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.
The following tables summarize the impact of the sale of certain receivables:
As of September 30, 2024 As of December 31, 2023
Derecognized receivables transferred at fair value $ 1,766 $ 1,516
Less: Cash proceeds received
- 300
DPP $ 1,766 $ 1,216
Three Months Ended September 30, Nine Months Ended September 30,
2024 2023 2024 2023
Loss on sale of receivables(a)
$ 11 $ 12 $ 43 $ 58
__________
(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.
Nine Months Ended September 30,
2024 2023
Proceeds from new transfers(a)
$ 1,688 $ 3,632
Cash collections received on DPP(b)
7,404 5,158
Cash collections reinvested in the Facility $ 9,092 $ 8,790
__________
(a)Customer accounts receivable sold into the Facility were $9,370 million and $8,920 million for the nine months ended September 30, 2024 and 2023, respectively.
(b)Does not include the $300 million and $1,100 million net cash payments to the Purchasers for the nine months ended September 30, 2024 and 2023, respectively.
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 within the Changes in Other assets and liabilities line in the Consolidated Statements of Cash Flows, which were ($7,682) million and ($5,288) million for the nine months ended September 30, 2024 and 2023, respectively. The collection and reinvestment of DPP is recognized in Cash flows from investing activities in the Collection of DPP, net line in the Consolidated Statements of Cash Flows, which were $7,104 million and $4,058 million for the nine months ended September 30, 2024 and 2023, respectively.
See Note 12 - Fair Value of Financial Assets and Liabilities and Note 15 - Variable Interest Entities for additional information.
24
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)
Note 6 - Accounts Receivable
Other Sales of Customer Accounts Receivables
We are required, under supplier tariffs, to sell customer receivables to utility companies. The total receivables sold was $228 million and $274 million for the nine months ended September 30, 2024 and 2023, respectively.
7. Nuclear Decommissioning
Nuclear Decommissioning Asset Retirement Obligations
We have a legal obligation to decommission our nuclear power plants following the permanent cessation of operations. See Note 10 - Asset Retirement Obligations of our 2023 Form 10-K for additional information regarding AROs and the financial statement impact of changes in estimate.
The following table provides a rollforward of the nuclear decommissioning AROs reflected in the Consolidated Balance Sheets from December 31, 2023 to September 30, 2024:
Balance as of December 31, 2023(a)
$ 13,891
Netdecrease due to changes in, and timing of, estimated future cash flows
(2,275)
Accretion expense 488
ARO transferred to Liabilities held for sale
(22)
Costs incurred related to decommissioning plants (21)
Balance as of September 30, 2024(a)
$ 12,061
__________
(a)Includes $14 millionand $30 million as the current portion of the ARO as of September 30, 2024 and December 31, 2023, respectively, which is included in Other current liabilities in the Consolidated Balance Sheets.
During the nine months ended September 30, 2024, the net $2,275 million decrease in the ARO for the changes in the amounts and timing of estimated decommissioning cash flows was driven by multiple adjustments, including the following:
•Net decrease of approximately $2,940 million due to changes in assumed retirement dates for various plants, including Braidwood, Byron, Calvert Cliffs, FitzPatrick, LaSalle, Limerick, NMP Unit 2, Quad Cities, and Crane.
•A decrease of approximately $138 million related to a change in assumed timing of DOE acceptance of SNF.
•An increase of approximately $803 million due to an increase in cost escalation rates and lower discount rates.
The 2024 ARO update resulted in a decrease of $78 million in Operating and maintenance expense for the three and nine months ended September 30, 2024 in the Consolidated Statements of Operations and Comprehensive Income.The 2023 ARO update resulted in a decrease of $68 million in Operating and maintenance expense for the three and nine months ended September 30, 2023 in the Consolidated Statements of Operations and Comprehensive Income.
NDT Funds
We had NDT funds totaling $17,798 millionand $16,398 million as of September 30, 2024 and December 31, 2023, respectively. As of September 30, 2024, $104 millionof the NDT funds were current and included in Other current assets in the Consolidated Balance Sheets. As of December 31, 2023, none of the NDT funds were reflected in Other current assets. See Note 16 - Supplemental Financial Information for additional information on activities of the NDT funds.
Accounting Implications of the Regulatory Agreement Units
See Note 1 - Basis of Presentation and Note 10 - Asset Retirement Obligations of our 2023 Form 10-K for additional information on the Regulatory Agreement Units.
25
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)
Note 7 - Nuclear Decommissioning
The following table presents our noncurrent payables to ComEd, PECO, CenterPoint, and AEP Texas reflected as Payables related to Regulatory Agreement Units in the Consolidated Balance Sheets as of September 30, 2024 and December 31, 2023:
September 30, 2024 December 31, 2023
ComEd $ 3,983 $ 2,955
PECO 338 278
CenterPoint
375 338
AEP Texas
132 117
Payables related to Regulatory Agreement Units $ 4,828 $ 3,688
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 for radiological decommissioning of the facility at the end of its life.
In March 2024, we filed our annual decommissioning funding status report with the NRC for our shutdown units, including Zion Station, which was transferred back to us in November 2023. The status report demonstrated adequate decommissioning funding assurance as of December 31, 2023 for all our shutdown units except for Peach Bottom Unit 1. Financial assurance for decommissioning Peach Bottom Unit 1 is provided by collections from PECO customers. Additionally in March 2024, STPNOC filed the decommissioning funding status report for STP. The status report demonstrated adequate funding assurance as of December 31, 2023. See Note 10 - Asset Retirement Obligations of our 2023 Form 10-K for additional information.
8. Income Taxes
Rate Reconciliation
The effective income tax rate varies from the U.S. federal statutory rate principally due to the following:
Three Months Ended September 30, Nine Months Ended September 30,
2024
2023
2024
2023
U.S. federal statutory rate 21.0 % 21.0 % 21.0 % 21.0 %
(Decrease) increase due to:
State income taxes, net of federal income tax benefit 4.8 4.3 1.1 4.1
Qualified NDT fund income and losses 8.2 (2.6) 6.6 4.7
Amortization of ITC, including deferred taxes on basis differences (0.3) (0.5) (0.2) (0.5)
PTCs and other credits (8.1) (0.6) (8.1) (0.6)
Noncontrolling interests 0.1 0.7 0.1 0.3
Other 1.6 0.6 0.5 0.4
Effective income tax rate 27.3 % 22.9 % 21.0 % 29.4 %
Other Tax Matters
Tax Matters Agreement
In connection with the separation, we entered into a TMA with Exelon. The TMA governs the respective rights, responsibilities, and obligations between us and Exelon after the separation with 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. See Note 14 - Income Taxes of our 2023 Form 10-K for additional information on the separation.
26
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)
Note 8 - Income Taxes
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 of September 30, 2024 and December 31, 2023, our Consolidated Balance Sheets reflect $39 million and $37 million in Other deferred credits and other liabilities, respectively, for tax liabilities where we maintain contractual responsibility to Exelon.
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. In February 2024, we executed an amendment to the TMA that modified the timing of Exelon's payment of amounts due to us. As of September 30, 2024, our Consolidated Balance Sheets reflects receivables of $130 million and $201 million in Other accounts receivable and Other deferred debits and other assets, respectively. As of December 31, 2023, our Consolidated Balance Sheets reflected receivables of $336 million and $178 million in Other accounts receivable and Other deferred debits and other assets, respectively.
9. Retirement Benefits
Components of Net Periodic Benefit (Credits) Costs
See Note 1 - Basis of Presentation of our 2023 Form 10-K for additional information on where we report the service cost and other non-service cost (credit) components for all plans.
The following tables present the components of our net periodic benefit (credit) cost, prior to capitalization and co-owner allocations, for the three and nine months ended September 30, 2024 and 2023:
Pension Benefits OPEB Total Pension Benefits and OPEB
Three Months Ended September 30, Three Months Ended September 30, Three Months Ended September 30,
2024 2023 2024 2023 2024 2023
Components of net periodic benefit (credit) cost
Service cost $ 22 $ 22 $ 4 $ 4 $ 26 $ 26
Non-service components of pension benefits & OPEB (credit) cost
Interest cost 95 99 18 19 113 118
Expected return on assets (123) (127) (11) (11) (134) (138)
Amortization of:
Prior service (credit) cost
1 - (2) (2) (1) (2)
Actuarial (gain) loss
25 12 (3) (3) 22 9
Settlement charges 3 - - - 3 -
Non-service components of pension benefits & OPEB (credit) cost 1 (16) 2 3 3 (13)
Net periodic benefit (credit) cost(a)
$ 23 $ 6 $ 6 $ 7 $ 29 $ 13
27
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)
Note 9 - Retirement Benefits
Pension Benefits OPEB Total Pension Benefits and OPEB
Nine Months Ended September 30, Nine Months Ended September 30, Nine Months Ended September 30,
2024 2023 2024 2023 2024 2023
Components of net periodic benefit (credit) cost:
Service cost $ 67 $ 67 $ 13 $ 12 $ 80 $ 79
Non-service components of pension benefits & OPEB (credit) cost:
Interest cost 286 296 54 56 340 352
Expected return on assets (371) (381) (32) (34) (403) (415)
Amortization of:
Prior service (credit) cost
1 - (5) (5) (4) (5)
Actuarial (gain) loss
76 35 (7) (10) 69 25
Settlement charges 7 - - - 7 -
Non-service components of pension benefits & OPEB (credit) cost (1) (50) 10 7 9 (43)
Net periodic benefit (credit) cost(a)
$ 66 $ 17 $ 23 $ 19 $ 89 $ 36
__________
(a)The pension benefit and OPEB service costs reflected in the Consolidated Statements of Operations and Comprehensive Income is $24 millionand $74 million for the three and nine months ended September 30, 2024, respectively, and $24 million and $71 million for the three and nine months ended September 30, 2023, respectively.
10. 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 Baa1 by S&P and Moody's, respectively, it would take a three notch downgrade by S&P or Moody's for us to go below investment grade.
28
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)
Note 10 - Derivative Financial Instruments
Commodity Price Risk
We employ established policies and procedures to manage our risks associated with market fluctuations in commodity prices by entering into 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 into 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.
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 for inflation after 2024 through the duration of the program based on the GDP price deflator for the preceding calendar year. See Note 5 - Government Assistance for additional information on the nuclear PTC.
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 the price risk associated with our load serving contracts, non-nuclear generation, and any residual price risk for our nuclear generation that the nuclear PTC and state programs may not fully mitigate. We also enter transactions that further optimize the economic benefits of our overall portfolio.
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 Flows. For the three and nine months ended September 30, 2024 and 2023, net pre-tax commodity mark-to-market gains and losses associated with proprietary trading activities were not material.
29
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)
Note 10 - Derivative Financial Instruments
The following tables provide a summary of the derivative fair value balances recorded as of September 30, 2024 and December 31, 2023:
September 30, 2024
Economic Hedges
Proprietary Trading
Collateral (a)(b)
Netting(a)
Total
Mark-to-market derivative assets (current)
$ 5,514 $ 1 $ 228 $ (5,120) $ 623
Mark-to-market derivative assets (noncurrent)
3,911 - 193 (3,373) 731
Total mark-to-market derivative assets 9,425 1 421 (8,493) 1,354
Mark-to-market derivative liabilities (current)
(5,866) (1) 258 5,120 (489)
Mark-to-market derivative liabilities (noncurrent)
(3,923) - 212 3,373 (338)
Total mark-to-market derivative liabilities (9,789) (1) 470 8,493 (827)
Total mark-to-market derivative net assets (liabilities)
$ (364) $ - $ 891 $ - $ 527
December 31, 2023
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
_________
(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 $606 million and $1,712 million of variation margin posted on the exchanges as of September 30, 2024 and December 31, 2023, respectively.
Economic Hedges (Commodity Price Risk)
For the three and nine months ended September 30, 2024 and 2023, we recognized the following net pre-tax commodity mark-to-market gains (losses), which are also located in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows.
Three Months Ended September 30, Nine Months Ended September 30,
Income Statement Location 2024 2023 2024 2023
Operating revenues $ 519 $ 173 $ 774 $ 1,317
Purchased power and fuel (119) (36) 404 (1,448)
Total $ 400 $ 137 $ 1,178 $ (131)
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 $883 million and $562 million as of September 30, 2024 and December 31, 2023, respectively.
The mark-to-market derivative assets and liabilities as of September 30, 2024 and December 31, 2023 and the mark-to-market gains and losses associated with management of interest rate and foreign currency risk for the three and nine months ended September 30, 2024 and 2023 were not material. The mark-to-market gains and losses associated with management of interest rate and foreign currency exchange rate risk are also included in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows.
30
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)
Note 10 - Derivative Financial Instruments
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.
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 September 30, 2024. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual 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 September 30, 2024
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 $ 722 $ 17 $ 705 - $ -
Non-investment grade 13 3 10 - -
No external ratings
Internally rated - investment grade 120 - 120 - -
Internally rated - non-investment grade 207 43 164 - -
Total $ 1,062 $ 63 $ 999 - $ -
__________
(a)As of September 30, 2024, credit collateral held from counterparties where we had credit exposure included $8 million of cash and $55 million of letters of credit.
Net Credit Exposure by Type of Counterparty As of September 30, 2024
Investor-owned utilities, marketers, power producers $ 733
Energy cooperatives and municipalities 130
Financial Institutions 48
Other 88
Total $ 999
31
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)
Note 10 - Derivative Financial Instruments
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 a reasonable estimate for the contingent collateral obligation, which has been factored into the disclosure below.
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:
Credit-Risk-Related Contingent Features September 30, 2024 December 31, 2023
Gross fair value of derivative contracts containing this feature
$ (1,285) $ (1,894)
Offsetting fair value of in-the-money contracts under master netting arrangements
578 925
Net fair value of derivative contracts containing this feature $ (707) $ (969)
As of September 30, 2024 and December 31, 2023, 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.
September 30, 2024 December 31, 2023
Cash collateral posted(a)
$ 917 $ 2,449
Letters of credit posted(a)
868 777
Cash collateral held(a)
26 64
Letters of credit held(a)
87 61
Additional collateral required in the event of a credit downgrade below investment grade (at BB+/Ba1)(b)(c)(d)
1,873 1,914
__________
(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 three notch downgrade from their current levels of BBB+ and Baa1 at S&P and Moody's, respectively.
We routinely 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.
32
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)
Note 11 - Debt and Credit Agreements
11. 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
In June 2024, we amended our existing $3.5 billion revolving credit facility (RCF), to increase the available aggregate commitment to $4.5 billion and extend the maturity date from January 2027 to June 2029. The RCF may be drawn down in the form of loans and/or to support commercial paper and letters of credit issuances.
The RCF fixed facility fee rate is 0.175% and borrowings under the RCF 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 7.5 basis points and 107.5 basis points, respectively. The letters of credit bear interest at a rate of 1.075%.
If we were to lose our investment grade credit 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 fees vary depending upon our credit rating.
As of September 30, 2024 and December 31, 2023, we had the following aggregate bank commitments, credit facility borrowings and available capacity under our respective credit facilities:
September 30, 2024
Facility Type Aggregate Bank
Commitment 		Facility Draws Outstanding
Letters of Credit 		Outstanding Commercial Paper(a)
Total Available Capacity
Revolving Credit Facility
$ 4,500 $ - $ 51 $ - $ 4,449
Bilaterals(b)
1,850 - 1,317 - 533
Liquidity Facility 971 - 827 - 106
(c)
Project Finance 137 - 121 - 16
Total $ 7,458 $ - $ 2,316 $ - $ 5,104
December 31, 2023
Revolving Credit Facility
$ 3,500 $ - $ 60 $ 1,107 $ 2,333
Bilaterals
1,500 - 878 - 622
Liquidity Facility 971 - 720 - 191
(c)
Project Finance 137 - 117 - 20
Total $ 6,108 $ - $ 1,775 $ 1,107 $ 3,166
__________
(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 September 30, 2024 and December 31, 2023, the maximum program size of our commercial paper program was $4.5 billion and $3.5 billion, respectively. 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 5.48% and 5.66% as of September 30, 2024 and December 31, 2023, respectively.
(b)In March 2024, we initiated a new bilateral credit agreement for $200 million, with no maturity date. In May 2024, we initiated a new bilateral credit agreement for $150 million, with no maturity date. In June 2024, a bilateral credit agreement initiated in November 2019 was extended for an additional two years to June 2026.
(c)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 September 30, 2024 and December 31, 2023, without posting additional collateral, the actual availability of facility, prior to outstanding letters of credit was $933 million and $911 million, respectively.
33
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)
Note 11 - Debt and Credit Agreements
Short-Term Loan Agreements
As of September 30, 2024 and December 31, 2023, we had the following short-term loan agreements:
Month Initiated
Interest Rate
Maturity
Outstanding Amount as of September 30, 2024
Outstanding Amount as of December 31, 2023
January 2023
1-month SOFR + 0.80%
January 2024 $ - $ 100
February 2023
1-month SOFR + 1.05%
February 2024 - 400
Long-Term Debt
Debt Issuances and Redemptions
During the nine months ended September 30, 2024, the following long-term debt was issued (redeemed):
Type Interest Rate Maturity Amount
Green Senior Notes(a)
5.75 % March 2054 $ 900
Energy Efficiency Project Financing(b)
2.20% - 4.96%
March 2025 1
CR Nonrecourse Debt
3-month SOFR + 2.25% (c)
December 2027 (22)
Continental Wind Nonrecourse Debt 6.00 % February 2033 (28)
West Medway II Nonrecourse Debt
1-month SOFR + 3.225%
March 2026 (25)
Antelope Valley DOE Nonrecourse Debt
2.29% - 3.56%
January 2037 (15)
RPG Nonrecourse Debt 4.11 % March 2035 (9)
Total long-term debt issued (redeemed)
$ 802
__________
(a)The Green Senior Notes were issued to finance or refinance, in whole or in part, one or more new or existing Eligible Projects. Eligible Projects are defined as investments and expenditures made by us in the 24 months prior to or after the issuance of the notes within the following eligible green categories: clean generation fleet, clean hydrogen, energy storage, and clean commercial offerings.
(b)Energy Efficiency Project Financing represents funding to install energy conservation measures. The maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt.
(c)The interest rate for long-term debt redemptions prior to July 19, 2024 were based on SOFR + 2.76%. Beginning on July 19, 2024 these redemptions are based on SOFR + 2.25%.
Debt Covenants
As of September 30, 2024, we are in compliance with all debt covenants.
12. 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.
34
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)
Note 12 - Fair Value of Financial Assets and Liabilities
Fair Value of Financial Liabilities Recorded at Amortized Cost
The following table presents the carrying amounts and fair values of our long-term debt and SNF obligation as of September 30, 2024 and December 31, 2023. 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.
September 30, 2024 December 31, 2023
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
$ 8,412 $ 8,205 $ 737 $ 8,942 $ 7,617 $ 7,140 $ 774 $ 7,914
SNF Obligation 1,349 1,310 - 1,310 1,296 1,222 - 1,222
Valuation Techniques Used to Determine Fair Value and Net Asset Value
Our valuation techniques used to measure the fair value and net asset value of the assets and liabilities are in accordance with the policies discussed in Note 18 - Fair Value of Financial Assets and Liabilities of our 2023 Form 10-K.
35
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)
Note 12 - Fair Value of Financial Assets and Liabilities
Recurring Fair Value Measurements
The following table 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 September 30, 2024 and December 31, 2023:
As of September 30, 2024 As of December 31, 2023
Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets
Cash equivalents(a)
$ 130 $ - $ - $ 130 $ 42 $ - $ - $ 42
NDT fund investments
Cash equivalents(b)
267 152 - 419 356 87 - 443
Equities 5,567 2,021 1 7,589 4,574 1,990 1 6,565
Fixed income 2,209 1,467 365 4,041 2,043 1,523 277 3,843
Private credit - - 133 133 - - 151 151
Assets measured at NAV - - - 5,616 - - - 5,396
NDT fund investments subtotal(c)
8,043 3,640 499 17,798 6,973 3,600 429 16,398
Rabbi trust investments 55 38 1 94 48 33 1 82
Investments in equities 258 - - 258 372 - - 372
Mark-to-market derivative assets
Economic hedges 1,412 4,466 3,558 9,436 2,330 5,821 3,143 11,294
Proprietary trading - - 1 1 - - 2 2
Effect of netting and allocation of
collateral(d)
(1,300) (4,003) (2,770) (8,073) (1,996) (5,195) (1,931) (9,122)
Mark-to-market derivative assets subtotal 112 463 789 1,364 334 626 1,214 2,174
DPP consideration - 1,766 - 1,766 - 1,216 - 1,216
Total assets measured at fair value 8,598 5,907 1,289 21,410 7,769 5,475 1,644 20,284
Liabilities
Mark-to-market derivative liabilities
Economic hedges (1,509) (4,657) (3,640) (9,806) (2,681) (7,154) (2,736) (12,571)
Proprietary trading - - (1) (1) - - (2) (2)
Effect of netting and allocation of
collateral(d)
1,443 4,463 3,058 8,964 2,587 6,542 2,393 11,522
Mark-to-market derivative liabilities subtotal (66) (194) (583) (843) (94) (612) (345) (1,051)
Deferred compensation obligation - (98) - (98) - (69) - (69)
Total liabilities measured at fair value
(66) (292) (583) (941) (94) (681) (345) (1,120)
Total net assets $ 8,532 $ 5,615 $ 706 $ 20,469 $ 7,675 $ 4,794 $ 1,299 $ 19,164
__________
(a)CEG Parent has $142 million and $54 million of Level 1 cash equivalents as of September 30, 2024 and December 31, 2023, respectively. We exclude cash of $1,676 million and $349 million as of September 30, 2024 and December 31, 2023, respectively, and restricted cash of $64 million and $49 million as of September 30, 2024 and December 31, 2023, respectively. CEG Parent has excluded an additional $1 million and $2 million of cash as of September 30, 2024 and December 31, 2023, respectively.
(b)Includes net liabilities of $131 million and $115 million as of September 30, 2024 and December 31, 2023, respectively, which 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.
(c)Includes total NDT derivative assets and liabilities that are not material, which have notional amounts of $1,068 million and $948 million as of September 30, 2024 and December 31, 2023, 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 $606 million and $1,712 million of variation margin posted on the exchanges as of September 30, 2024 and December 31, 2023, respectively.
36
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)
Note 12 - Fair Value of Financial Assets and Liabilities
As of September 30, 2024, our NDTs have outstanding commitments to invest in private credit, private equity, and real assets of $378 million, $337 million, and $734 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 $135 million and $103 million as of September 30, 2024 and December 31, 2023, respectively. Changes in fair value, cumulative adjustments, and impairments were not material for the three and nine months ended September 30, 2024 and the year ended December 31, 2023.
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 three and nine months ended September 30, 2024 and 2023:
For the Three Months Ended September 30, 2024
NDT Fund Investments
Mark-to-Market Derivatives
Life Insurance Contracts Total
Balance as of July 1, 2024 $ 492 $ 312 $ 1 $ 805
Total realized / unrealized gains (losses)
Included in net income (loss)
4 58
(a)
- 62
Included in Payable related to Regulatory Agreement Units 9 - - 9
Change in collateral - (166) (166)
Purchases, sales, issuances and settlements
Purchases - 14 - 14
Sales - - - -
Settlements (7) - - (7)
Transfers into Level 3 1 (12)
(b)
- (11)
Transfers out of Level 3 - -
(b)
- -
Balance as of September 30, 2024 $ 499 $ 206 $ 1 $ 706
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2024
$ 4 $ 191 $ - $ 195
For the Three Months Ended September 30, 2023
NDT Fund Investments
Mark-to-Market Derivatives
Life Insurance Contracts Total
Balance as of July 1, 2023 $ 421 $ 651 $ 1 $ 1,073
Total realized / unrealized gains (losses)
Included in net income (loss)
- (236)
(a)
- (236)
Included in Payable related to Regulatory Agreement Units - - - -
Change in collateral - (7) - (7)
Purchases, sales, issuances and settlements
Purchases - 35 - 35
Sales - (3) - (3)
Settlements - 32 - 32
Transfers into Level 3 - -
(b)
- -
Transfers out of Level 3 - (91)
(b)
- (91)
Balance as of September 30, 2023 $ 421 $ 381 $ 1 $ 803
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2023
$ - $ 54 $ - $ 54
37
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)
Note 12 - Fair Value of Financial Assets and Liabilities
For the Nine Months Ended September 30, 2024
NDT Fund Investments
Mark-to-Market Derivatives
Life Insurance Contracts Total
Balance as of January 1, 2024 $ 429 $ 869 $ 1 $ 1,299
Total realized / unrealized gains (losses)
Included in net income (loss)
4 (433)
(a)
- (429)
Included in Payable related to Regulatory Agreement Units 13 - - 13
Change in collateral - (173) - (173)
Purchases, sales, issuances and settlements
Purchases 66 32 - 98
Sales - (83) - (83)
Settlements (14) (2) - (16)
Transfers into Level 3 1 27
(b)
- 28
Transfers out of Level 3 - (31)
(b)
- (31)
Balance as of September 30, 2024 $ 499 $ 206 $ 1 $ 706
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2024
$ 4 $ 216 $ - $ 220
For the Nine Months Ended September 30, 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)
1 24
(a)
- 25
Included in Payable related to Regulatory Agreement Units 4 - - 4
Change in collateral - 99 - 99
Purchases, sales, issuances and settlements
Purchases - 120 - 120
Sales - (9) - (9)
Settlements (7) 32 - 25
Transfers into Level 3 - 59
(b)
- 59
Transfers out of Level 3 - (163)
(b)
- (163)
Balance as of September 30, 2023 $ 421 $ 381 $ 1 $ 803
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2023
$ 1 $ 759 $ - $ 760
__________
(a)Includes a reduction of $133 million and $651 million for realized gains due to the settlement of derivative contracts for the three and nine months ended September 30, 2024, respectively. Includes a reduction of $258 million and $703 million for realized gains due to the settlement of derivative contracts for the three and nine months ended September 30, 2023, 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.
38
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)
Note 12 - Fair Value of Financial Assets and Liabilities
The following tables present 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 three and nine months ended September 30, 2024 and 2023:
For the Three Months Ended September 30,
Operating Revenues
Purchased Power and Fuel
Other, net
2024 2023 2024 2023 2024 2023
Total gains (losses) included in net income
$ 177 $ (129) $ (119) $ (75) $ 4 $ -
Total unrealized gains (losses)
300 97 (109) (43) - -
For the Nine Months Ended September 30,
Operating Revenues
Purchased Power and Fuel
Other, net
2024 2023 2024 2023 2024 2023
Total gains (losses) included in net income
$ (97) $ 388 $ (338) $ (332) $ 4 $ 1
Total unrealized gains (losses)
561 1,144 (345) (385) - 1
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 September 30, 2024 Fair Value as of December 31, 2023
Valuation Technique
Unobservable Input
2024 Range & Arithmetic Average
2023 Range & Arithmetic Average
Mark-to market derivatives-Economic hedges(a)(b)
$ (82) $ 407 Discounted Cash Flow Forward power price
$4.28 - $138
$47
$9.64 - $216
$48
Forward gas price
$1.07 - $13
$3.41
$1.20 - $14
$3.09
Option Model Volatility percentage
11% - 75%
45%
23% - 200%
87%
__________
(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 on Level 3 positions of $288 million and $462 million as of September 30, 2024 and December 31, 2023, 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.
39
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)
Note 13 - Commitments and Contingencies
13. Commitments and Contingencies
Commitments
Commercial Commitments. Commercial commitments as of September 30, 2024, representing commitments potentially triggered by future events, were as follows:
Expiration within
2024
2025
2026
2027
2028
2029 and beyond
Total
Letters of credit $ 1,202 $ 990 $ 1 $ 1 $ 121 $ 1 $ 2,316
Surety bonds(a)
319 364 - - - - 683
Total commercial commitments $ 1,521 $ 1,354 $ 1 $ 1 $ 121 $ 1 $ 2,999
__________
(a)Surety bonds-Guarantees issued related to contract and commercial agreements, excluding bid bonds.
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 September 30, 2024 and December 31, 2023, we had accrued undiscounted amounts for environmental liabilities of $56 million and $61 million, respectively, in Accounts payable and accrued expenses and $167 million and $88 million, respectively, in Other deferred credits and other liabilities in the Consolidated Balance Sheets. See Note 19 - Commitments and Contingencies of our 2023 Form 10-K for additional information on environmental remediation matters. As of September 30, 2024, and through the date of filing, there have been no material changes in amounts recognized for the matters discussed in our 2023 Form 10-K.
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.
See Note 19 - Commitments and Contingencies of our 2023 Form 10-K for additional information on litigation matters. As of September 30, 2024, and through the date of filing, there have been no significant developments to the matters discussed in our 2023 Form 10-K.
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.
40
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)
Note 13 - Commitments and Contingencies
At September 30, 2024 and December 31, 2023, we recorded estimated liabilities of approximately $126 million and $131 million, respectively, in total for asbestos-related bodily injury claims. As of September 30, 2024, approximately $14 million of this amount related to 201 open claims presented to us, while the remaining $112 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.
14. Shareholders' Equity
Share Repurchase Program (CEG Parent)
During 2023, our Board of Directors authorized the repurchase of up to $2 billion of the Company's outstanding common stock. In April 2024, our Board of Directors approved a $1 billion increase to the program, authorizing up to $3 billion in total repurchases. As of September 30, 2024, there was approximately $991 million of remaining authority to repurchase shares of the Company's outstanding common stock. No other repurchase plans or programs have been authorized. See Note 20 - Shareholders' Equity of our 2023 Form 10-K for additional information on our share repurchase program.
During the nine months ended September 30, 2024, we repurchased from the open market 1.2 million shares of our common stock for a total cost, inclusive of taxes and transaction costs, of $150 million. There were no open market repurchases for the three months ended September 30, 2024.During the three and nine months ended September 30, 2023, we repurchased from the open market 2.3 million and 8.5 million shares, respectively, of our common stock for a total cost, inclusive of taxes and transaction costs, of $253 million and $756 million, respectively.
In 2024, we entered into ASR agreements with financial institutions to initiate share repurchases of our common stock. Under the ASR agreements, we paid a specified amount to the financial institution and received an initial delivery of shares of common stock, which resulted in an immediate reduction in the number of our shares outstanding. Based on the terms of the ASR agreements below, we received an initial share delivery based on 80% of the ASR agreements' cost. Upon settlement of the ASR agreements, the financial institution delivers additional incremental shares. The total number of shares ultimately delivered, and therefore the average price paid per share, is determined at the end of the applicable purchase period of each ASR agreement based on the average of the daily-volume weighted average share price, less a discount.
The following table summarizes each ASR agreement for the nine months ended September 30, 2024:
(in millions, except average price paid per share)
ASR Agreement Initiation Total Cost Initial Shares Received ASR Agreement Settlement
Additional Shares Received(a)
Total Number of Shares Purchased Average Price Paid per Share
March 2024 $ 354 1.7 May 2024 0.2 1.9 $ 182.65
May 2024 $ 505 1.8 July 2024 0.6 2.4 $ 211.40
__________
(a)The 0.6 million additional shares received and settled in July 2024 were rounded for footing.
41
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)
Note 14 - Shareholders' Equity
Changes in Accumulated Other Comprehensive Loss (All Registrants)
The following tables present changes in AOCI, net of tax, by component:
Three Months Ended September 30, 2024
Gains (losses) on Cash Flow Hedges
Pension and OPEB Items(a)
Foreign Currency Items Total
Beginning balance $ (8) $ (2,125) $ (28) $ (2,161)
OCI before reclassifications - - 12 12
Amounts reclassified from AOCI 1 14 - 15
Net current-period OCI 1 14 12 27
Ending balance $ (7) $ (2,111) $ (16) $ (2,134)
Three Months Ended September 30, 2023
Beginning balance $ (9) $ (1,768) $ (23) $ (1,800)
OCI before reclassifications - - (2) (2)
Amounts reclassified from AOCI - 5 - 5
Net current-period OCI - 5 (2) 3
Ending balance $ (9) $ (1,763) $ (25) $ (1,797)
Nine Months Ended September 30, 2024
Beginning balance $ (10) $ (2,157) $ (24) $ (2,191)
OCI before reclassifications - (4) 8 4
Amounts reclassified from AOCI 3 50 - 53
Net current-period OCI 3 46 8 57
Ending balance $ (7) $ (2,111) $ (16) $ (2,134)
Nine Months Ended September 30, 2023
Beginning balance $ (9) $ (1,725) $ (26) $ (1,760)
OCI before reclassifications (1) (53) 1 (53)
Amounts reclassified from AOCI 1 15 - 16
Net current-period OCI - (38) 1 (37)
Ending balance $ (9) $ (1,763) $ (25) $ (1,797)
__________
(a)AOCI amounts are included in the computation of net periodic pension and OPEB cost. See Note 9 - Retirement Benefits for additional information. See our 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):
Three Months Ended September 30, Nine Months Ended September 30,
2024 2023 2024 2023
Pension and OPEB plans:
Actuarial loss reclassified to periodic benefit cost $ (5) $ (3) $ (18) $ (8)
Pension and OPEB plans valuation adjustment
- - 2 18
15. Variable Interest Entities
At September 30, 2024 and December 31, 2023, 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 VIEsbelow). Consolidated and unconsolidated VIEs are aggregated to the extent that the entities have similar risk profiles.
42
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)
Note 15 - 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 September 30, 2024 and December 31, 2023. 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.
September 30, 2024 December 31, 2023
Cash and cash equivalents $ 61 $ 48
Restricted cash and cash equivalents 51 47
Accounts receivable
Customer accounts receivable, net
41 19
Other accounts receivable, net
10 10
Inventories, net
Materials and supplies
13 14
Other current assets 1,811 1,249
Total current assets 1,987 1,387
Property, plant, and equipment, net 2,017 1,979
Other noncurrent assets 149 166
Total noncurrent assets 2,166 2,145
Total assets(a)
$ 4,153 $ 3,532
Long-term debt due within one year $ 64 $ 63
Accounts payable and accrued expenses
59 31
Total current liabilities 123 94
Long-term debt 653 704
Asset retirement obligations 204 190
Other noncurrent liabilities 2 2
Total noncurrent liabilities 859 896
Total liabilities
$ 982 $ 990
__________
(a)Our balances include unrestricted assets for current unamortized energy contract assets of $22 million and $22 million, disclosed within other current assets in the table above and noncurrent unamortized energy contract assets of $139 million and $155 million, disclosed within other noncurrent assets in the table above as of September 30, 2024 and December 31, 2023, respectively.
43
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)
Note 15 - Variable Interest Entities
As of September 30, 2024 and December 31, 2023, 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.
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 September 30, 2024 and December 31, 2023, 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.
The following table presents summary information about our significant unconsolidated VIE entities:
September 30, 2024 December 31, 2023
Commercial Agreement VIEs
Equity Investment VIEs
Total
Commercial Agreement VIEs
Equity Investment VIEs
Total
Total assets(a)
$ 671 $ - $ 671 $ 704 $ - $ 704
Total liabilities(a)
55 - 55 77 - 77
Other ownership interests in VIE(a)
616 - 616 627 - 627
__________
(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 September 30, 2024 and December 31, 2023.
44
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)
Note 15 - Variable Interest Entities
As of September 30, 2024 and December 31, 2023 the unconsolidated VIEs consist of:
Unconsolidated VIE groups: Reason entity is a VIE: Reason we are not the primary beneficiary:
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.
16. Supplemental Financial Information
Supplemental Statement of Operations and Comprehensive Income Information
The following tables provide additional information about items recorded in the Consolidated Statements of Operations and Comprehensive Income.
Operating revenues
Three Months Ended September 30, Nine Months Ended September 30,
2024 2023 2024 2023
Operating lease income $ 29 $ 29 $ 47 $ 46
Variable lease income 69 73 189 197
Taxes other than income taxes
Three Months Ended September 30, Nine Months Ended September 30,
2024 2023 2024 2023
Gross receipts(a)
$ 37 $ 37 $ 102 $ 105
Property 76 67 215 188
Payroll 48 39 122 108
__________
(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.
Other, net
Three Months Ended September 30, Nine Months Ended September 30,
2024 2023 2024 2023
Decommissioning-related activities:
Net realized income on NDT funds(a)
Regulatory Agreement Units $ 203 $ 126 $ 460 $ 575
Non-Regulatory Agreement Units 118 37 233 322
Net unrealized gain (loss) on NDT funds
Regulatory Agreement Units 337 (242) 548 (156)
Non-Regulatory Agreement Units 190 (123) 329 (78)
Regulatory offset to NDT fund-related activities(b)
(433) 93 (808) (335)
Total decommissioning-related activities 415 (109) 762 328
Non-service net periodic benefit credit(c)
2 14 (4) 41
Net realized and unrealized gains (losses) from equity investments (104) 76 (115) 490
Other
12 19 50 60
Total Other, net $ 325 $ - $ 693 $ 919
__________
(a)Realized income includes interest, dividends and realized gains and losses on sales of NDT fund investments.
45
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)
Note 16 - Supplemental Financial Information
(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.
(c)The non-service credit (cost) components are included in Other, net, in accordance with single employer plan accounting. See Note 15 - Retirement Benefits of our 2023 Form 10-K for additional information.
Supplemental Cash Flow Information
The following tables provide additional information about items recorded within our Consolidated Statements of Cash Flows.
Depreciation, amortization, and accretion
Nine Months Ended September 30,
2024 2023
Property, plant, and equipment(a)
$ 850 $ 791
Amortization of intangible assets, net(a)
18 17
Amortization of energy contract assets and liabilities(b)
27 26
Nuclear fuel(c)
656 573
ARO accretion(d)
498 433
Total depreciation, amortization, and accretion $ 2,049 $ 1,840
__________
(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.
Other non-cash operating activities
CEG Parent Constellation
Nine Months Ended September 30, Nine Months Ended September 30,
2024 2023 2024 2023
Other decommissioning-related activity(a)
$ (488) $ (330) $ (488) $ (330)
Energy-related options(b)
40 159 40 159
Asset impairments
6 71 6 71
(Gain) loss on sale of receivables
43 58 43 58
Amortization of operating ROU asset 57 57 57 57
Long-term incentive plan 31 44 - -
Pension and OPEB costs
81 36 81 36
__________
(a)Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income, and income taxes related to all NDT fund activity for these units.
(b)Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations.
46
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)
Note 16 - Supplemental Financial Information
The following table provides a reconciliation of cash, restricted cash, and cash equivalents reported within our Consolidated Balance Sheets that sum to the total of the same amounts in the Consolidated Statements of Cash Flows.
September 30, 2024 CEG Parent Constellation
Cash and cash equivalents $ 1,793 $ 1,793
Restricted cash and cash equivalents 89 77
Total cash, restricted cash, and cash equivalents $ 1,882 $ 1,870
December 31, 2023
Cash and cash equivalents $ 368 $ 366
Restricted cash and cash equivalents 86 74
Total cash, restricted cash, and cash equivalents $ 454 $ 440
September 30, 2023
Cash and cash equivalents $ 1,889 $ 1,888
Restricted cash and cash equivalents 88 59
Total cash, restricted cash, and cash equivalents $ 1,977 $ 1,947
For additional information on restricted cash, see Note 1 - Basis of Presentation of our 2023 Form 10-K.
Supplemental Balance Sheet Information
The following table provides additional information about items recorded within our Consolidated Balance Sheets.
Accounts payable and accrued expenses
September 30, 2024 CEG Parent Constellation
Accounts payable
$ 1,302 $ 1,286
Compensation-related accruals(a)
797 555
Taxes accrued(b)
219 201
December 31, 2023
Accounts payable
$ 1,302 $ 1,289
Compensation-related accruals(a)
680 576
Taxes accrued 399 390
__________
(a)Primarily includes accrued payroll, bonuses and other incentives, vacation, and benefits.
(b)Includes $140 million related to nuclear PTC that was used to offset the current tax liability. See Note 5 - Government Assistance for additional information on the nuclear PTC.
47
Table of Contents
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
(Dollars in millions except per share data, unless otherwise noted)
Executive Overview
We are a supplier of carbon-free energy. Our generating capacity primarily consists of 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 competitive markets across multiple geographic regions. We have five reportable segments: Mid-Atlantic, Midwest, New York, ERCOT and Other Power Regions.
Significant Transactions and Developments
Crane Clean Energy Center
During the third quarter of 2024, we executed a 20-year PPA with Microsoft that will support the restart of Three Mile Island Unit 1, renamed as the Crane Clean Energy Center, which was retired in 2019 for economic reasons. Under the agreement, Microsoft will purchase the output generated from the renewed plant as part of its goal to help power its data centers in PJM with clean energy. We expect Crane will also be eligible for the technology-neutral clean electricity PTC (45Y) provided for by the IRA for its first 10 years of operations. We estimate the project will require approximately $1.6 billion of cash from operations for capital expenditures necessary to restart the plant, with an estimated in-service date of 2028. The restart of the plant and delivery of electricity under the PPA is subject to certain regulatory approvals, including the NRC comprehensive safety and environmental review, as well as permits from relevant state and local agencies. Additionally, through a separate request, we will pursue obtaining a renewed license that will extend operations at the plant to at least 2054.
Nuclear PTC
As a result of the enactment of the IRA, we qualify for certain federal government incentives through eligible activities. These incentives include both refundable and transferable tax credits. Beginning in 2024, our existing nuclear units are eligible for a PTC extending through 2032. The nuclear PTC (45U) provides a transferable credit up to $15 per MWh (a base credit of $3 per MWh with a five times multiplier provided certain prevailing wage requirements are met) and is subject to phase-out when annual gross receipts are between $25.00 per MWh and $43.75 per MWh. We have determined that we will meet the annual prevailing wage requirements at all our nuclear units and are eligible for the five times multiplier. Both the amount of the PTC and the gross receipts thresholds adjust annually for inflation over the duration of the program, and the benefits of the PTC may be realized through a credit against our federal income taxes or transferred via sale to an unrelated party. For the three and nine months ended September 30, 2024, our Consolidated Statements of Operations and Comprehensive Income include an estimate of $670 million and $1,380 million, respectively, that is reflected in Operating revenues. See Note 5 - Government Assistance of the Combined Notes to Consolidated Financial Statements for additional information.
Share Repurchase Program
In April 2024, our Board of Directors approved a $1 billion increase to the previously announced share repurchase program, authorizing total repurchases of up to $3 billion. As of September 30, 2024, we have purchased a total of approximately 16.1 million shares for a total cost of $2 billion, with remaining authority to purchase up to $991 million of the Company's outstanding common stock. See Note 14 - Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information.
48
Table of Contents
Other Key Business Drivers
Russia and Ukraine Conflict
We are closely monitoring developments of the ongoing Russia and Ukraine conflict, including United States, United Kingdom, European Union, and Canadian sanctions, and legislation that may impact exports and imports of Russian nuclear fuel supply and enrichment activities, as well as the potential for Russia to limit fuel deliveries. We are cognizant of the recent enactment of the "Prohibiting Russian Uranium Imports Act" that bans the import of low-enriched uranium into the U.S. that is produced in Russia or by Russian entities, absent a waiver from the DOE. The passage of this bill will allow the Department of Energy to begin the process of distributing billions of dollars that were previously appropriated to support expansion of the domestic nuclear fuel cycle within the United States to improve carbon-free energy security. Our fuel procurement activities comply with all U.S. and international trade laws and to-date, our nuclear fuel deliveries have not been affected by the Russia and Ukraine conflict. Our nuclear fuel is obtained predominantly through long-term uranium supply and service contracts. We work with a diverse set of domestic and international suppliers years in advance to procure our nuclear fuel and generally have enough nuclear fuel to support all our refueling needs for multiple years regardless of sanctions. Recognizing the potential for the continuing conflict to impact our longer-term security and cost of supply, we have entered into contracts to increase the size of our nuclear fuel inventory. We will continue to take advantage of all available avenues to ensure continuity in our nuclear fuel supply, including working with our diverse set of suppliers to ensure we can secure the nuclear fuel needed to continue to operate our nuclear fleet long-term and provide the necessary fuel to bridge potential Russian supply disruption into 2029, which is the date multiple suppliers have indicated they will have incremental additional capacity online.
Environmental Regulation
Regulation of GHGs from Power Plants under the Clean Air Act. In April 2024, EPA issued a final rule that regulates greenhouse gases from existing coal, new natural gas-fired power plants, and existing oil/gas steam generators under Clean Air Act section 111. The applicable standards are subcategorized by retirement date for existing coal and capacity factor for existing gas. We are evaluating market impacts of this rule, which will be affected by upcoming state implementation and ongoing litigation. EPA has solicited comment on approaches for regulating GHGs from existing gas plants in a docket that closed in May 2024. In October 2024, the U.S. Supreme Court rejected a request to temporarily block implementation of EPA's GHG standards for existing coal, new gas and existing oil/gas steam generators. The DC Circuit currently is considering the merits of EPA's GHG power plant rule. We cannot reasonably predict the outcome of this matter.
Good Neighbor Rule. On June 5, 2023, the EPA published a final rule called "Federal 'Good Neighbor Plan' for the 2015 Ozone National Ambient Air Quality Standards" also known as the "Transport Rule". The rule, among other things, establishes nitrogen oxides emissions budgets requiring fossil fuel-fired power plants in 23 states to participate in an allowance-based ozone season trading program beginning in 2023. On February 13, 2023, EPA disapproved state implementation plans submitted by 21 states for failure to address their obligations under the "good neighbor" provisions of the Clean Air Act. However, several Regional Courts of Appeals issued orders staying, pending judicial review, EPA's disapproval of several state plans (including Texas). In June 2024, the Supreme Court stayed EPA's rule for the duration of the litigation. The rule is currently under review on the merits before the D.C. Circuit and we cannot reasonably predict the outcome of this litigation.
Critical Accounting Policies and Estimates
Management makes a number of significant estimates, assumptions, and judgements in the preparation of our financial statements. At September 30, 2024, our critical accounting policies and estimates had not changed significantly from December 31, 2023, with the exception of accounting for government grants and disclosure of government assistance. See Note 5 - Government Assistance of the Combined Notes to Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Critical Accounting Policies and Estimates of our 2023 Form 10-K for further information.
49
Table of Contents
Financial Results of Operations
GAAP Results of Operations. The following table sets forth our consolidated GAAP Net Income (Loss) Attributable to Common Shareholders for the three and nine months ended September 30, 2024 compared to the same period in 2023. For additional information regarding the financial results for the three and nine months ended September 30, 2024 and 2023, see the discussions of Results of Operations below.
Three Months Ended September 30,
Favorable Variance
Nine Months Ended September 30,
Favorable Variance
2024 2023 2024 2023
GAAP Net Income (Loss) Attributable to Common Shareholders
$ 1,200 $ 731 $ 469 $ 2,897 $ 1,660 $ 1,237
Adjusted (non-GAAP) Operating Earnings. We utilize Adjusted (non-GAAP) Operating Earnings (and/or its per share equivalent) in our internal analysis, and in communications with investors and analysts, as a consistent measure for comparing our financial performance and discussing the factors and trends affecting our business. The presentation of Adjusted (non-GAAP) Operating Earnings is intended to complement and should not be considered an alternative to, nor more useful than, the presentation of GAAP Net Income.
50
Table of Contents
The table below provides a reconciliation of GAAP Net Income to Adjusted (non-GAAP) Operating Earnings. Adjusted (non-GAAP) Operating Earnings is not a standardized financial measure and may not be comparable to other companies' presentations of similarly titled measures.
Unless otherwise noted, the income tax impact of each reconciling adjustment between GAAP Net Income (Loss) Attributable to Common Shareholders and Adjusted (non-GAAP) Operating Earnings is based on the marginal statutory federal and state income tax rates, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part. For all adjustments except the NDT fund investment returns, which are included in decommissioning-related activities, the marginal statutory income tax rate was 25.5% and 25.1% for the three and nine months ended September 30, 2024 and 2023, respectively. Under IRS regulations, NDT fund investment returns are taxed at different rates for investments if they are in qualified or non-qualified funds. The effective tax rates for the unrealized and realized gains and losses related to NDT funds were 54.6% and 52.6% for the three months ended September 30, 2024 and 2023, respectively and 55.3% and 55.4% for the nine months ended September 30, 2024 and 2023, respectively. The following table provides a reconciliation between GAAP Net Income (Loss) Attributable to Common Shareholders and Adjusted (non-GAAP) Operating Earnings for the three and nine months ended September 30, 2024 compared to the same period in 2023.
Three Months Ended September 30,
2024 2023
Earnings Per Share(a)
Earnings Per Share(a)
Net Income (Loss) Attributable to Common Shareholders $ 1,200 $ 3.82 $ 731 $ 2.26
Unrealized (Gain) Loss on Fair Value Adjustments (net of taxes of $72 and $53, respectively)(b)
(210) (0.67) (158) (0.49)
Plant Retirements and Divestitures (net of taxes of $10 and $-, respectively)
30 0.10 1 -
Decommissioning-Related Activities (net of taxes of $207 and $48, respectively)(c)
(195) (0.62) 76 0.24
Pension & OPEB Non-Service (Credits) Costs (net of taxes of $1 and $3, respectively)
(2) (0.01) (10) (0.03)
Separation Costs (net of taxes of $- and $6, respectively)(d)
- - 17 0.05
ERP System Implementation Costs (net of taxes of $- and $1, respectively)
1 - 4 0.01
Change in Environmental Liabilities (net of taxes of $2 and $3, respectively)
5 0.02 9 0.03
Income Tax-Related Adjustments(e)
33 0.11 (9) (0.03)
Acquisition-Related Costs (net of taxes of $- and $1, respectively)
- - 1 -
Asset Impairments (net of taxes of $- and $9, respectively)
- - 62 0.19
Noncontrolling Interests (net of taxes of $- and $-, respectively)(f)
(2) (0.01) (36) (0.11)
Adjusted (non-GAAP) Operating Earnings
$ 860 $ 2.74 $ 688 $ 2.13
51
Table of Contents
Nine Months Ended September 30,
2024 2023
Earnings Per Share(a)
Earnings Per Share(a)
Net Income (Loss) Attributable to Common Shareholders $ 2,897 $ 9.17 $ 1,660 $ 5.11
Unrealized (Gain) Loss on Fair Value Adjustments (net of taxes of $264 and $85, respectively)(b)
(786) (2.49) (251) (0.77)
Plant Retirements and Divestitures (net of taxes of $23 and $5, respectively)
68 0.22 (16) (0.05)
Decommissioning-Related Activities (net of taxes of $343 and $133, respectively)(c)
(227) (0.72) (2) (0.01)
Pension & OPEB Non-Service (Credits) Costs (net of taxes of $1 and $10, respectively)
2 0.01 (31) (0.10)
Separation Costs (net of taxes of $3 and $22, respectively)(d)
9 0.03 67 0.21
ERP System Implementation Costs (net of taxes of $2 and $5, respectively)
7 0.02 15 0.05
Change in Environmental Liabilities (net of taxes of $20 and $7, respectively)
60 0.19 22 0.07
Income Tax-Related Adjustments(e)
(55) (0.17) (9) (0.03)
Acquisition-Related Costs (net of taxes of $- and $1, respectively)
- - 1 -
Asset Impairments (net of taxes of $- and $9, respectively)
- - 62 0.19
Noncontrolling Interests (net of taxes of $- and $-, respectively)(f)
(5) (0.02) (39) (0.12)
Adjusted (non-GAAP) Operating Earnings
$ 1,970 $ 6.23 $ 1,479 $ 4.55
__________
(a)Amounts may not sum due to rounding. Earnings per share amount is based on average diluted common shares outstanding of 314 million and 323 million for the three months ended September 30, 2024 and 2023, respectively and 316 million and 325 million for the nine months ended September 30, 2024 and 2023, respectively.
(b)Includes mark-to-market on economic hedges, interest rate swaps, and fair value adjustments related to gas imbalances and equity investments.
(c)Reflects all gains and losses associated with NDTs, ARO accretion, ARC depreciation, ARO remeasurement, and impacts of contractual offset for Regulatory Agreement Units.
(d)Represents certain incremental costs related to the separation (system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the separation), including a portion of the amounts billed to us pursuant to the TSA. See Note 1 - Basis of Presentation of our 2023 Form 10-K for additional information.
(e)In 2024, primarily reflects the adjustment to deferred income taxes due to changes in forecasted apportionment.
(f)Represents elimination of the noncontrolling interests related to certain adjustments.
52
Table of Contents
Results of Operations
Three Months Ended September 30,
Favorable (Unfavorable) Variance
Nine Months Ended September 30,
Favorable (Unfavorable) Variance
2024 2023 2024 2023
Operating revenues $ 6,550 $ 6,111 $ 439 $ 18,186 $ 19,122 $ (936)
Operating expenses
Purchased power and fuel 3,119 3,367 248 8,828 11,983 3,155
Operating and maintenance 1,535 1,353 (182) 4,666 4,263 (403)
Depreciation and amortization 266 266 - 868 808 (60)
Taxes other than income taxes 165 148 (17) 446 419 (27)
Total operating expenses 5,085 5,134 49 14,808 17,473 2,665
Gain (loss) on sales of assets and businesses
2 - 2 2 28 (26)
Operating income (loss)
1,467 977 490 3,380 1,677 1,703
Other income and (deductions)
Interest expense, net (147) (82) (65) (416) (292) (124)
Other, net 325 - 325 693 919 (226)
Total other income and (deductions) 178 (82) 260 277 627 (350)
Income (loss) before income taxes
1,645 895 750 3,657 2,304 1,353
Income tax (benefit) expense
449 205 (244) 768 677 (91)
Equity in income (losses) of unconsolidated affiliates
- - - (1) (11) 10
Net income (loss)
1,196 690 506 2,888 1,616 1,272
Net income (loss) attributable to noncontrolling interests
(4) (41) 37 (9) (44) 35
Net income (loss) attributable to common shareholders
$ 1,200 $ 731 $ 469 $ 2,897 $ 1,660 1,237
Three Months Ended September 30, 2024 Compared to Three Months Ended September 30, 2023. The variance in Net income (loss) attributable to common shareholders was favorable by $469 million primarily due to:
•Favorable nuclear PTCs related to the IRA beginning in 2024;
•Favorable net realized and unrealized NDT activity;
•Favorable market and portfolio conditions primarily driven by higher realized margins on load contracts and generation-to-load optimization; and
•Favorable mark-to-market activity and other fair value adjustments.
The favorable items were partially offset by:
•Higher labor (inclusive of incentives), contracting, and materials;
•Lower unrealized gains resulting from an investment that became a publicly traded company in the second quarter of 2023; and
•Unfavorable impacts of nuclear outages.
53
Table of Contents
Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023. The variance in Net income (loss) attributable to common shareholders was favorable by $1,237 million primarily due to:
•Favorable mark-to-market activity and other fair value adjustments;
•Favorable market and portfolio conditions primarily driven by higher realized margins on load contracts and generation-to-load optimization;
•Favorable nuclear PTCs related to the IRA beginning in 2024;
•Favorable net realized and unrealized NDT activity; and
•Favorable impacts of nuclear outages.
The favorable items were partially offset by:
•Lower unrealized gains resulting from an investment that became a publicly traded company in the second quarter of 2023;
•Higher labor (inclusive of incentives), contracting, and materials;
•Lower revenue recognized for ZECs delivered under the Illinois ZEC program in prior planning years; and
•Higher Interest expense.
Operating revenues. Our five reportable segments are Mid-Atlantic, Midwest, New York, ERCOT, and Other Power Regions. See Note 4- Segment Information of the Combined Notes to Consolidated Financial Statements for additional information on these reportable segments.
Wholesale and retail sales of natural gas, as well as sales of other energy-related products and sustainable solutions and other miscellaneous business activities that are not significant to overall results of operations are reported under Other and not allocated to a region.
For the three and nine months ended September 30, 2024 compared to 2023, Operating revenues were as follows:
Three Months Ended September 30, Nine Months Ended September 30,
2024 2023 Variance
% Change(a)
2024 2023 Variance
% Change(a)
Mid-Atlantic $ 1,603 $ 1,411 $ 192 13.6 % $ 4,148 $ 3,854 $ 294 7.6 %
Midwest 1,275 1,117 158 14.1 % 3,537 3,479 58 1.7 %
New York 507 512 (5) (1.0) % 1,534 1,518 16 1.1 %
ERCOT 523 559 (36) (6.4) % 1,201 1,056 145 13.7 %
Other Power Regions 1,443 1,592 (149) (9.4) % 4,252 4,495 (243) (5.4) %
Total reportable segment electric revenues
5,351 5,191 160 3.1 % 14,672 14,402 270 1.9 %
Other 683 743 (60) (8.1) % 2,745 3,403 (658) (19.3) %
Mark-to-market gains (losses) 516 177 339 769 1,317 (548)
Total Operating revenues $ 6,550 $ 6,111 $ 439 7.2 % $ 18,186 $ 19,122 $ (936) (4.9) %
__________
(a)% Change in mark-to-market is not a meaningful measure.
54
Table of Contents
Sales and Supply Sources. Our sales and supply sources by region are summarized below:
Three Months Ended September 30, Nine Months Ended September 30,
(GWhs)
2024 2023 Variance % Change 2024 2023 Variance % Change
Nuclear Generation(a)
Mid-Atlantic 13,420 13,654 (234) (1.7) % 39,839 39,672 167 0.4 %
Midwest 23,835 24,023 (188) (0.8) % 71,381 69,975 1,406 2.0 %
New York 5,893 6,448 (555) (8.6) % 18,657 18,837 (180) (1.0) %
ERCOT
2,362 - 2,362 100.0 % 6,340 - 6,340 100.0 %
Total Nuclear Generation 45,510 44,125 1,385 3.1 % 136,217 128,484 7,733 6.0 %
Natural Gas, Oil, and Renewables
Mid-Atlantic 329 361 (32) (8.9) % 1,809 1,466 343 23.4 %
Midwest 151 155 (4) (2.6) % 774 715 59 8.3 %
ERCOT(b)
4,783 5,528 (745) (13.5) % 11,890 13,242 (1,352) (10.2) %
Other Power Regions 1,850 1,929 (79) (4.1) % 7,017 6,544 473 7.2 %
Total Natural Gas, Oil, and Renewables 7,113 7,973 (860) (10.8) % 21,490 21,967 (477) (2.2) %
Purchased Power
Mid-Atlantic
6,022 6,166 (144) (2.3) % 12,707 13,615 (908) (6.7) %
Midwest 107 104 3 2.9 % 639 726 (87) (12.0) %
ERCOT 771 1,612 (841) (52.2) % 2,496 4,561 (2,065) (45.3) %
Other Power Regions 10,813 13,221 (2,408) (18.2) % 30,855 32,875 (2,020) (6.1) %
Total Purchased Power 17,713 21,103 (3,390) (16.1) % 46,697 51,777 (5,080) (9.8) %
Total Supply/Sales by Region
Mid-Atlantic 19,771 20,181 (410) (2.0) % 54,355 54,753 (398) (0.7) %
Midwest 24,093 24,282 (189) (0.8) % 72,794 71,416 1,378 1.9 %
New York 5,893 6,448 (555) (8.6) % 18,657 18,837 (180) (1.0) %
ERCOT(b)
7,916 7,140 776 10.9 % 20,726 17,803 2,923 16.4 %
Other Power Regions 12,663 15,150 (2,487) (16.4) % 37,872 39,419 (1,547) (3.9) %
Total Supply/Sales by Region 70,336 73,201 (2,865) (3.9) % 204,404 202,228 2,176 1.1 %
__________
(a)Includes the proportionate share of output where we have an undivided ownership interest in jointly-owned generating plants.
(b)2023 values have been revised from those previously reported to reflect gross generation inclusive of behind the meter consumption.
55
Table of Contents
Nuclear Fleet Capacity Factor. The following table presents nuclear fleet operating data for our plants that, reflects ownership percentage of stations operated by us and excludes Salem and STP, which are operated by PSEG and STPNOC, respectively. The nuclear fleet capacity factor presented in the table is defined as the ratio of the actual output of a plant over a period of time to its output if the plant had operated at its net monthly mean capacity for that time period. We consider capacity factor to be a useful measure to analyze the nuclear fleet performance between periods. We have included the analysis below as a complement to the financial information provided in accordance with GAAP. However, these measures are not a presentation defined under GAAP and may not be comparable to other companies' presentations or be more useful than the GAAP information provided elsewhere in this report.
Three Months Ended
September 30, 		Nine Months Ended
September 30,
2024 2023 2024 2023
Nuclear fleet capacity factor 95.0 % 97.2 % 94.6 % 94.1 %
Refueling outage days 37 20 164 200
Non-refueling outage days 20 10 33 44
Nuclear PTC. Beginning in 2024, our nuclear units are eligible for a PTC extending through 2032. The nuclear PTC provides a transferable credit up to $15 per MWh (a base credit of $3 per MWh with a five times multiplier provided certain prevailing wage requirements are met) and is subject to phase-out when annual gross receipts are between $25.00 per MWh and $43.75 per MWh. We have determined that we will meet the annual prevailing wage requirements at all our nuclear units and are eligible for the five times multiplier. Both the amount of the PTC and the gross receipts thresholds adjust for inflation after 2024 through the duration of the program based on the GDP price deflator for the preceding calendar year. The benefits of the PTC may be realized through a credit against our federal income taxes or transferred via sale to an unrelated party.
Many of the state-sponsored programs (i.e., ZECs and CMCs) providing compensation for the emissions-free attributes of generation from certain of our nuclear units include contractual or other provisions that require us to refund that compensation up to the amount of the nuclear PTC received or pass through the entirety of the nuclear PTC received. See Note 5 - Government Assistance of the Combined Notes to Consolidated Financial Statements for additional information on the nuclear PTC.
ZEC Prices. We are compensated through state programs for the carbon-free attributes of our nuclear generation. Gross revenues from ZEC programs are a significant contributor to our total operating revenues. The following table includes the average ZEC reference prices ($/MWh) for each of our major regions in which state programs have been enacted. Gross prices reflect the weighted average price for the various delivery periods within the three and nine months ended September 30, 2024 and 2023 and may not necessarily reflect prices we ultimately realize as a result of interaction with the nuclear PTC discussed above.
Three Months Ended September 30, Nine Months Ended September 30,
State (Region)(a)
2024 2023 Variance % Change 2024 2023 Variance % Change
New Jersey (Mid-Atlantic)(b)
$ 10.00 $ 9.95 $ 0.05 0.5 % $ 9.97 $ 9.91 $ 0.06 0.6 %
Illinois (Midwest)
9.38 0.30 9.08 3026.7 % 4.34 6.81 (2.47) (36.3) %
New York (New York) 18.27 18.27 - - % 18.27 19.31 (1.04) (5.4) %
__________
(a)See ITEM 1. BUSINESS, Environmental Matters of our 2023 Form 10-K for additional information on the plants receiving payments through state programs.
(b)The ZEC price is expected to be $10.00/MWh for each delivery period and is subject to an annual update once full year generation is known. Following the latest annual update in August 2024, the ZEC price for the delivery period beginning June 2023 through May 2024 was calculated to be $9.95.
56
Table of Contents
Illinois CMC Price. The price received (paid) for each CMC is determined by the IPA monthly and is based on the accepted CMC bid, less the sum of (a) monthly weighted average PJM Busbar price, (b) ComEd zone capacity price and (c) any federal tax credit or subsidy received and is subject to a customer protection cap ($30.30 per MWh for initial delivery period June 2022 through May 2023, $32.50 per MWh for the period June 2023 through May 2024, and $33.43 per MWh for the period June 2024 through May 2025). If the monthly CMC price per MWh calculation results in a net positive value, ComEd will multiply that value by the delivered quantity and pay the total to us. If the CMC price per MWh calculation results in a net negative value, we will multiply this value by the delivered quantity and pay the net value to ComEd. The average CMC prices per MWh were $5.54 and $2.12 for the three months ended September 30, 2024 and 2023, respectively, and $7.73 and $3.54 for the nine months ended September 30, 2024 and 2023, respectively. The average CMC prices may not necessarily reflect prices we ultimately realize as a result of interaction with the nuclear PTC discussed above.
Capacity Prices. We participate in capacity auctions in each of our major regions, except ERCOT which does not have a capacity market. We also incur capacity costs associated with load served, which are factored into customer sales prices. Capacity prices have a significant impact on our operating revenues and purchased power and fuel expense. We report capacity on a net monthly basis within each region in either Operating revenues or Purchased power and fuel expense, depending on our net monthly position. The following table presents the average capacity prices ($/MW Day) for each of our major regions. Prices reflect the weighted average prices for the various auction periods within the three and nine months ended September 30, 2024 and 2023.
Three Months Ended September 30, Nine Months Ended September 30,
Location (Region) 2024 2023 Variance % Change 2024 2023 Variance % Change
Eastern Mid-Atlantic Area Council (Mid-Atlantic) $ 53.60 $ 49.49 $ 4.11 8.3 % $ 51.32 $ 76.36 $ (25.04) (32.8) %
ComEd (Midwest) 28.92 34.13 (5.21) (15.3) % 31.81 53.48 (21.67) (40.5) %
Rest of State (New York) 132.22 199.89 (67.67) (33.9) % 112.78 147.48 (34.70) (23.5) %
Southeast New England (Other) 949.57 66.67 882.90 1324.3 % 459.07 100.00 359.07 359.1 %
Electricity Prices. As a producer and supplier of electricity, the price of electricity has a significant impact on our operating revenues and purchased power cost. We report the sale and purchase of electricity in the spot market on a net hourly basis in either Operating revenues or Purchased power and fuel expense within each region, depending on our net hourly position. The price of electricity is impacted by several variables, including but not limited to, the price of fuels, generation resources in the region, weather, ongoing competition, emerging technologies, as well as macroeconomic and regulatory factors. The following table presents an average day-ahead around-the-clock reference price ($/MWh) for the periods presented for each of our major regions and does not necessarily reflect prices we ultimately realized.
Three Months Ended September 30, Nine Months Ended September 30,
Location (Region) 2024 2023 Variance % Change 2024 2023 Variance % Change
PJM West (Mid-Atlantic) $ 36.98 $ 33.31 $ 3.67 11.0 % $ 33.41 $ 31.95 $ 1.46 4.6 %
ComEd (Midwest) 28.92 30.85 (1.93) (6.3) % 25.80 26.75 (0.95) (3.6) %
Central (New York) 33.30 29.58 3.72 12.6 % 31.80 26.85 4.95 18.4 %
North (ERCOT) 26.61 129.60 (102.99) (79.5) % 27.75 64.41 (36.66) (56.9) %
Southeast Massachusetts (Other)(a)
38.37 33.45 4.92 14.7 % 37.34 38.15 (0.81) (2.1) %
__________
(a)Reflects New England, which comprises the majority of the activity in the Other region.
57
Table of Contents
For the three and nine months ended September 30, 2024 compared to 2023, changes in Operating revenuesby region were approximately as follows:
Three Months Ended
September 30 		Nine Months Ended
September 30
Variance
% Change(a)
Significant Drivers
Variance
% Change(a)
Significant Drivers
Mid-Atlantic 192 13.6 %
• favorable estimated nuclear PTC revenue of $160
$ 294 7.6 %
• favorable estimated nuclear PTC revenue of $340
• favorable retail load revenue of $110 primarily due to higher contracted energy prices and load volumes; partially offset by
• unfavorable wholesale load revenue of ($70) due to lower load volumes
• unfavorable net ZEC program revenue of ($60) due to estimated refund associated with nuclear PTC
Midwest 158 14.1 %
• favorable estimated nuclear PTC revenue of $390; partially offset by
• unfavorable net ZEC and CMC program revenue of ($150) due to estimated pass through associated with nuclear PTC on CMCs partially offset by increase in realized ZEC revenue
58 1.7 %
• favorable estimated nuclear PTC revenue of $855; partially offset by
• unfavorable net ZEC and CMC program revenue of ($575) due to decrease in ZEC revenue realized and estimated pass through associated with nuclear PTC on CMCs
• unfavorable net generation and wholesale load revenue of ($65) primarily due to lower load volumes
• unfavorable settled economic hedges of ($95) due to settled prices relative to hedged prices
New York (5) (1.0) %
• unfavorable net ZEC program revenue of ($65) primarily due to estimated refund associated with nuclear PTC; partially offset by
• favorable estimated nuclear PTC revenue of $60
16 1.1 %
• favorable retail load revenue of $125 primarily due to higher load volumes and contracted energy prices
• favorable estimated nuclear PTC revenue of $120; partially offset by
• unfavorable net ZEC program revenue of ($145) due to decrease in ZEC price in current planning year and estimated refund associated with nuclear PTC
• unfavorable settled economic hedges of ($80) due to settled prices relative to hedged prices
58
Table of Contents
Three Months Ended
September 30 		Nine Months Ended
September 30
Variance
% Change(a)
Significant Drivers
Variance
% Change(a)
Significant Drivers
ERCOT (36) (6.4) %
• unfavorable net generation and wholesale load revenue of ($80) due to lower contracted prices
• unfavorable retail load revenue of ($60) primarily due to lower contracted energy prices and load volumes; partially offset by
• favorable estimated nuclear PTC revenue of $70
145 13.7 %
• favorable settled economic hedges of $150 due to settled prices relative to hedged prices
• favorable estimated nuclear PTC revenue of $70; partially offset by
• unfavorable retail load revenue of ($75) primarily due to lower contracted energy prices
Other Power Regions (149) (9.4) %
• unfavorable wholesale load revenue of ($240) primarily due to lower contracted prices and load volumes; partially offset by
• favorable retail load revenue of $100 primarily due to higher contracted energy prices
(243) (5.4) %
• unfavorable wholesale load revenue of ($370) primarily due to lower contracted prices and load volumes; partially offset by
• favorable retail load revenue of $185 primarily due to higher contracted energy prices
Other (60) (8.1) %
• unfavorable gas revenue, including settled economic hedges, of ($70) primarily due to lower gas prices
(658) (19.3) %
• unfavorable gas revenue, including settled economic hedges, of ($470) primarily due to lower gas prices
• unfavorable revenues in the United Kingdom, including settled economic hedges, of ($130) primarily due to lower energy prices
Mark-to-market(b)
339
• gains on economic hedging activities of $516 in 2024 compared to gains of $177 in 2023
(548)
• gains on economic hedging activities of $769 in 2024 compared to gains of $1,317 in 2023
Total $ 439 7.2 % $ (936) (4.9) %
__________
(a)% Change in mark-to-market is not a meaningful measure.
(b)See Note 10 - Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on mark-to-market gains and losses.
59
Table of Contents
Purchased power and fuel. See Operating revenues above for discussion of our reportable segments and hedging strategies and for supplemental statistical data, including sales and supply sources by region, nuclear fleet capacity factor, capacity prices, and electricity prices.
Wholesale and retail natural gas activity, as well as other miscellaneous business activities that are not significant to overall results of operations are reported under Other and are not allocated to a region.
For the three and nine months ended September 30, 2024 compared to 2023, Purchased power and fuel expense were as follows:
Three Months Ended September 30, Nine Months Ended September 30,
2024 2023 Variance
% Change(a)
2024 2023 Variance
% Change(a)
Mid-Atlantic $ 794 $ 667 $ (127) (19.0) % $ 1,906 $ 1,696 $ (210) (12.4) %
Midwest 391 339 (52) (15.3) % 1,185 1,038 (147) (14.2) %
New York 150 195 45 23.1 % 460 621 161 25.9 %
ERCOT 120 352 232 65.9 % 375 633 258 40.8 %
Other Power Regions 1,010 1,161 151 13.0 % 3,157 3,594 437 12.2 %
Total electric purchased power and fuel 2,465 2,714 249 9.2 % 7,083 7,582 499 6.6 %
Other 537 613 76 12.4 % 2,149 2,947 798 27.1 %
Mark-to-market losses (gains) 117 40 (77) (404) 1,454 1,858
Total Purchased power and fuel $ 3,119 $ 3,367 $ 248 7.4 % $ 8,828 $ 11,983 $ 3,155 26.3 %
__________
(a)% Change in mark-to-market is not a meaningful measure.
For the three and nine months ended September 30, 2024 compared to 2023, changes in Purchased power and fuelexpense by region were approximately as follows:
60
Table of Contents
Three Months Ended
September 30 		Nine Months Ended
September 30
Variance
% Change(a)
Significant Drivers
Variance
% Change(a)
Significant Drivers
Mid-Atlantic $ (127) (19.0) %
• unfavorable cost of ($90) associated with purchased power to supply load relative to generation volumes primarily due to higher energy prices
$ (210) (12.4) %
• unfavorable cost of ($120) associated with purchased power to supply load relative to generation volumes primarily due to higher energy prices
Midwest (52) (15.3) %
• no individually significant drivers
(147) (14.2) %
• unfavorable cost of ($125) associated with purchased power to supply load relative to generation volumes
New York 45 23.1 %
• no individually significant drivers
161 25.9 %
• favorable settlement of economic hedges of $210
due to settled prices relative to hedged prices
ERCOT 232 65.9 %
• favorable cost of $205 associated with purchased power to supply load relative to generation volumes primarily due to higher generation partially offset by higher load served
258 40.8 %
• favorable cost of $260 associated with purchased power to supply load relative to generation volumes primarily due to higher generation partially offset by higher load served
• favorable settlement of economic hedges of $50
due to settled prices relative to hedged prices
Other Power Regions 151 13.0 %
• favorable purchased power and fuel of $150
primarily due to lower load served and energy prices
437 12.2 %
• favorable purchased power and fuel of $500
primarily due to lower energy prices and load served; partially offset by
• unfavorable settlement of economic hedges of ($50)
due to settled prices relative to hedged prices
Other 76 12.4 %
• favorable net gas purchases, inclusive of settled economic hedges, of $75 primarily due to lower gas prices
798 27.1 %
• favorable net gas purchases, inclusive of settled economic hedges of $630 primarily due to lower gas prices
• favorable purchases in the United Kingdom, inclusive of settled economic hedges, of $140 primarily due to lower energy prices
Mark-to-market(b)
(77)
• losses on economic hedging activities of ($117) in 2024 compared to losses of ($40) in 2023
1,858
• gains on economic hedging activities of $404 in 2024 compared to losses of ($1,454) in 2023
Total $ 248 7.4 % $ 3,155 26.3 %
.__________
(a)% Change in mark-to-market is not a meaningful measure.
(b)See Note 10 - Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on mark-to-market gains and losses.
61
Table of Contents
The changes in Operating and maintenance expenseconsisted of the following:
2024 vs. 2023
Increase (Decrease)
Three Months Ended September 30 Nine Months Ended September 30
Labor, contracting, and materials(a)
$ 149 $ 468
Change in environmental liabilities (7) 51
Plant retirements and divestitures
28 46
Nuclear refueling outage costs, including the co-owned Salem and STP generating units
55 (38)
Asset impairments
(71) (71)
Separation costs
(18) (73)
Other 46 20
Total increase $ 182 $ 403
__________
(a)Primarily reflects increased employee-related costs, including labor and other incentives.
Other, netwas favorable for the three months ended September 30, 2024 compared to the same period in 2023 and unfavorable for the nine months ended September 30, 2024 compared to the same period in 2023, due to activity described in the table below:
Other, net
Income (Deductions)
Three Months Ended September 30, Nine Months Ended September 30,
2024 2023 2024 2023
Decommissioning-related activities(a)
$ 415 $ (109) $ 762 $ 328
Non-service net periodic benefit credit(b)
2 14 (4) 41
Net realized and unrealized gains (losses) from equity investments (104) 76 (115) 490
Other
12 19 50 60
Other, net $ 325 $ - $ 693 $ 919
_________
(a)Includes net realized and net unrealized gains (losses) on NDT fund investments, the elimination of decommissioning-related activities, and the elimination of income taxes related to all NDT fund activity for the Regulatory Agreement Units. See Note 7 - Nuclear Decommissioning and Note 16 - Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements for additional information.
(b)The non-service credit (cost) components are included in Other, net, in accordance with single employer plan accounting. See Note 9 - Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information.
Effective income tax rates were 27.3% and 22.9% for the three months ended September 30, 2024 and 2023, respectively, and 21.0% and 29.4% for the nine months ended September 30, 2024 and 2023, respectively. The change in effective tax rate for the three months ended September 30, 2024 and 2023 is primarily due to tax effect of realized gains from qualified fund decommissioning activity, partially offset by nuclear PTC being inclusive in book income, which is not taxable. For the nine months ended September 30, 2024 and 2023, the change is primarily due to PTC being inclusive in book income, which is not taxable. See Note 8 - Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.
Liquidity and Capital Resources
All results included throughout the liquidity and capital resources section are presented on a GAAP basis.
Our operating and capital expenditures requirements are provided by internally generated cash flows from operations, the sale of certain receivables, as well as funds from external sources in the capital markets and
62
Table of Contents
through bank borrowings. Our business is capital intensive and requires considerable capital resources. We annually evaluate our financing plan and credit line sizing, focusing on maintaining our investment grade ratings while meeting our cash needs to fund capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and OPEB obligations, and invest in new and existing ventures. A broad spectrum of financing alternatives beyond the core financing options can be used to meet our needs and fund growth, including monetizing assets in the portfolio via project financing, asset sales, and the use of other financing structures (e.g., joint ventures, minority partners, etc.). Our access to external financing on reasonable terms depends on our credit ratings and current overall capital market business conditions. See the "Credit Matters and Cash Requirements" section below for additional information. We expect cash flows to be sufficient to meet operating expenses, financing costs, and capital expenditure requirements. See Note 11 - Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on our debt and credit agreements.
NRC Minimum Funding Requirements
NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that sufficient funds will be available in certain minimum amounts for radiological decommissioning of the facility. These NRC minimum funding levels are typically based upon the assumption that decommissioning activities will commence after the end of the current licensed life of each unit. If a unit fails the NRC minimum funding test, then the plant's owners or parent companies would be required to take steps, such as providing financial guarantees through surety bonds, letters of credit, or parent company guarantees or making additional cash contributions to the NDT fund to ensure sufficient funds are available. See Note 7 - Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements for additional information regarding the latest funding status report filed with the NRC.
As of September 30, 2024, the Crane NDT is fully funded under the SAFSTOR scenario that was the planned decommissioning option, as described in the Crane PSDAR filed with the NRC in April 2019. We will continue to file Crane's decommissioning funding status with the NRC annually until restart. Additionally, as of September 30, 2024, we have adequate NDT funds for the remaining radiological decommissioning costs at Zion Station related to the Independent Spent Fuel Storage Installation. Decommissioning costs other than radiological may require funding from us. See Liquidity and Capital Resources - NRC Minimum Funding Requirements of our 2023 Form 10-K for information regarding the risk of additional financial assurance for shutdown units.
Cash Flows from Operating Activities
Our cash flows from operating activities include the sale of electric energy and energy-related products and sustainable solutions, and government assistance. Our future cash flows from operating activities may be affected by future demand for, and market prices of, energy and our ability to continue to produce and supply power at competitive costs, as well as to obtain collections from customers and the sale of certain receivables.
The following table provides a summary of the change in cash flows from operating activities for the nine months ended September 30, 2024 and 2023:
63
Table of Contents
Nine Months Ended September 30,
Cash flows from operating activities 2024 2023 Change
Net income (loss) $ 2,888 $ 1,616 $ 1,272
Adjustments to reconcile net income (loss) to cash:
Collateral received (posted), net 1,495 (222) 1,717
Option premiums received (paid), net 159 (36) 195
Pension and non-pension postretirement benefit contributions (178) (46) (132)
Changes in working capital and other noncurrent assets and liabilities(a)
(6,537) (5,109) (1,428)
Total non-cash operating activities(b)
725 1,678 (953)
Net cash flows provided by (used in) operating activities $ (1,448) $ (2,119) $ 671
_________
(a)Includes changes in Accounts receivable, Inventories, Accounts payable and accrued expenses, Income taxes, and Other assets and liabilities.
(b)See the Consolidated Statements of Cash Flows for details of non-cash operating activities, includes Depreciation, amortization, and accretion, Deferred income taxes and amortization of ITCs, Net fair value changes related to derivatives, and Net realized and unrealized activity associated with NDTs and equity investments. See Note 16 - Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements for additional information on the Other non-cash operating activities line.
Changes in our cash flows from operations were generally consistent with changes in results of operations, as adjusted by changes in working capital in the normal course of business, except as discussed below. Significant operating cash flow impacts for the nine months ended September 30, 2024 and 2023 were as follows:
•In the third quarter of 2024, $670 million of cash was received related to the sale of nuclear PTCs. See Note 5 - Government Assistance of the Combined Notes to Consolidated Financial Statements for additional information.
•Depending upon whether we are in a net mark-to-market liability or asset position, collateralmay be required to be posted with or collected from our counterparties. In addition, the collateral posting and collection requirements differ depending on whether the transactions are on an exchange or in the over-the-counter markets. See Note 10 - Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral.
•Option premiums received (paid), net relates to options contracts that we purchase and sell as part of our established policies and procedures to manage risks associated with market fluctuations in commodity prices. See Note 10 - Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on derivative contracts.
•Increase in cash outflows for pension and non-pension postretirement benefit contributionsis primarily due to our annual qualified pension contribution of $161 million and $21 million made in February 2024 and July 2023, respectively. See Note 9 - Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information on pension and non-pension postretirement benefit plans.
•A net increase in cash outflows for changes in working capital and other noncurrent assets and liabilitiesprimarily driven by an increase in cash collections applied to DPP partially offset by an increase in ComEd CMC program activity and cash received in 2024 related to revenue for ZECs delivered in prior planning years. See Note 6 - Accounts Receivable and Note 3 - Revenue from Contracts with Customers of the Combined Notes to Consolidated Financial Statements for additional information.
64
Table of Contents
Cash Flows from Investing Activities
The following table provides a summary of the change in cash flows from investing activities for the nine months ended September 30, 2024 and 2023:
Nine Months Ended September 30,
Cash flows from investing activities 2024 2023 Change
Collection of DPP, net $ 7,104 $ 4,058 $ 3,046
Acquisitions of assets and businesses (22) (21) (1)
Investment in NDT funds, net (206) (153) (53)
Capital expenditures (1,836) (1,735) (101)
Other investing activities 16 30 (14)
Net cash flows provided by (used in) investing activities $ 5,056 $ 2,179 $ 2,877
Significant investing cash flow impact for the nine months ended September 30, 2024 and 2023 was as follows:
•Collection of DPP, netincreased primarily due to the increased cash collections applied to DPP as a result of a decrease in the drawn Facility balance in 2024 compared to 2023. In addition, more cash collections were reinvested in the Facility in 2024. See Note 6 - Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information.
Cash Flows from Financing Activities
The following table provides a summary of the change in cash flows from financing activities for the nine months ended September 30, 2024 and 2023:
Nine Months Ended September 30,
Cash flows from financing activities 2024 2023 Change
Long-term debt, net $ 801 $ 3,042 $ (2,241)
Changes in short-term borrowings, net (1,644) (632) (1,012)
Repurchases of common stock (999) (750) (249)
Dividends paid on common stock (333) (277) (56)
Other financing activities (5) 6 (11)
Net cash flows provided by (used in) financing activities $ (2,180) $ 1,389 $ (3,569)
Significant financing cash flow impacts for the nine months ended September 30, 2024 and 2023 were as follows:
•Long-term debt, net,varies due to debt issuances and redemptions each year. Refer to Note 11 - Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.
•Changes in short-term borrowings, net, is driven by repayments on and issuances of notes due within one year of issuance. Refer to Note 11 - Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.
•Repurchases of common stockis related to our share repurchase program that commenced in March 2023. See Note 14 - Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information.
65
Table of Contents
Quarterly dividends declared by our Board of Directors in 2024 were as follows:
Period Declaration Date Shareholder of Record Date Dividend Payable Date Cash per Share
First Quarter of 2024
February 26, 2024 March 8, 2024 March 19, 2024 $ 0.3525
Second Quarter of 2024
May 1, 2024 May 29, 2024 June 10, 2024 $ 0.3525
Third Quarter of 2024
July 30, 2024 August 12, 2024 September 6, 2024 $ 0.3525
Fourth Quarter of 2024 November 1, 2024 November 15, 2024 December 6, 2024 $ 0.3525
Credit Matters and Cash Requirements
We fund liquidity needs for capital expenditures, working capital, energy hedging and other financial commitments through cash flows from operations, public debt offerings, commercial paper markets and large, diversified credit facilities. As of September 30, 2024, we have access to facilities with aggregate bank commitments of $7.5 billion. We had access to the commercial paper markets and had availability under our revolving credit facilities during the third quarter of 2024 to fund our short-term liquidity needs, when necessary. We routinely review the sufficiency of our liquidity position, including appropriate sizing of credit facility commitments, by performing various stress test scenarios, such as commodity price movements, increases in margin-related transactions, changes in hedging levels, and the impacts of hypothetical credit downgrades. We closely monitor events in the financial markets and the financial institutions associated with the credit facilities, including monitoring credit ratings and outlooks, credit default swap levels, capital raising, and merger activity. See PART I, ITEM 1A. RISK FACTORS of our 2023 Form 10-K for additional information regarding the effects of uncertainty in the capital and credit markets.
We believe our cash flow from operating activities, access to credit markets and our credit facilities provide sufficient liquidity to support the estimated future cash requirements discussed below.
If we had lost our investment grade credit rating as of September 30, 2024, we would have been required to provide incremental collateral estimated to be approximately $1.9 billion to meet collateral obligations for derivatives, non-derivatives, NPNS, and applicable payables and receivables, net of the contractual right of offset under master netting agreements. A loss of investment grade credit rating would have required a three notch downgrade by S&P or Moody's from their current levels of BBB+ and Baa1, to BB+ and Ba1 or below, respectively. As of September 30, 2024, we had $5.1 billion of available capacity under our credit facilities and $1.8 billion of cash on hand. In the event of a credit downgrade below investment grade and a resulting requirement to provide incremental collateral exceeding available capacity under our credit facilities and cash on hand, we could be required to access additional liquidity through the capital markets. See Note 10 - Derivative Financial Instruments and Note 11 - Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.
Pension and Other Postretirement Benefits
We consider various factors when making 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 contributions below reflect a funding strategy to improve funded status with the objective of achieving 100% funded status over time. Based on this funding strategy and current market conditions, which are both subject to change, our annual qualified pension contribution was made in February 2024 for $161 million.
66
Table of Contents
Unlike the qualified pension plans, 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 parts of our plans. For our funded OPEB plans, we consider several factors in determining the level of our contributions, including liabilities management and levels of benefit claims paid. The estimated benefit payments to the non-qualified pension plans in 2024 are approximately $23 million and the planned contributions to the OPEB plans, including estimated benefit payments to unfunded plans, is $16 million. Refer to ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Liquidity and Capital Resources of our 2023 Form 10-K for additional information on pension and other postretirement benefits.
Cash Requirements for Other Financial Commitments
Refer to ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Liquidity and Capital Resources of our 2023 Form 10-K for additional information on our cash requirements for financial commitments.
Sales of Customer Accounts Receivable
We have an accounts receivable financing facility with a number of financial institutions and a commercial paper conduit to sell certain receivables, which expires in August 2025 unless renewed by the mutual consent of the parties in accordance with its terms. See Note 6 - Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information.
Project Financing
Project financing is based upon a nonrecourse financial structure, in which project debt is paid back from the cash generated by a specific asset or portfolio of assets. Borrowings under these agreements are secured by the assets and equity of each respective project. Lenders do not have recourse against us in the event of a default. If a project financing entity does not maintain compliance with its specific debt covenants, there could be a requirement to accelerate repayment of the associated debt or other project-related borrowings earlier than the stated maturity dates. In these instances, if such repayment were not satisfied, or restructured, the lenders or security holders would generally have rights to foreclose against the project-specific assets and related collateral. The potential requirement to repay the 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. See Note 17 - Debt and Credit Agreements of our 2023 Form 10-K for additional information on project finance credit facilities and nonrecourse debt.
Credit Facilities
We meet our short-term liquidity requirements primarily through the issuance of commercial paper. We may use our credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit. See Note 11 - Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on our credit facilities.
Security Ratings
Our access to the capital markets, including the commercial paper market, and our financing costs in those markets, may depend on our securities ratings.
Our borrowings are not subject to default or prepayment as a result of a downgrade of our securities, although such a downgrade could increase fees and interest charges under our credit agreements.
As part of the normal course of business, we enter into contracts that contain express provisions or otherwise permit us and our counterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable contracts law, if we are downgraded by a credit rating agency, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance, which could include the posting of additional collateral. See Note 10 - Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral provisions.
67
Table of Contents
Our credit ratings from S&P and Moody's are BBB+ and Baa1, respectively, as of September 30, 2024. In March 2024, Moody's raised our issuer credit rating to 'Baa1' from 'Baa2' citing confidence in our ability to maintain credit metrics and strong financial performance.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
(Dollars in millions, unless otherwise noted)
We are exposed to market risks associated with adverse changes in commodity prices, counterparty credit, interest rates, and equity prices. We manage these risks through risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of risk exposures. We report risk management issues to the Executive Committee and the Audit and Risk Committee of the Board of Directors. The following discussion serves as an update to ITEM 7A - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK of our 2023 Annual Report on Form 10-K incorporated herein by reference.
Commodity Price Risk
Commodity price risk is associated with price movements resulting from changes in supply and demand, fuel costs, market liquidity, weather conditions, governmental, regulatory and environmental policies, and other factors. To the extent the total amount of energy we produce or procure differs from the amount of energy we have contracted to sell, we are exposed to market fluctuations in commodity prices. We seek to mitigate our commodity price risk through the sale and purchase of electricity, natural gas and oil, and other commodities.
Electricity available from our owned or contracted generation supply in excess of our obligations to customers is sold into the wholesale markets. To reduce commodity price risk caused by market fluctuations, we enter into non-derivative contracts as well as derivative contracts, including swaps, futures, forwards, and options, with approved counterparties to hedge anticipated exposures. We use derivative instruments as economic hedges to mitigate exposure to fluctuations in commodity prices. We expect the settlement of the majority of our economic hedges will occur during 2024 through 2026.
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 for inflation after 2024 through the duration of the program based on the GDP price deflator for the preceding calendar year. See Note 5 - Government Assistance of the Combined Notes to Consolidated Financial Statements for additional information on the nuclear PTC.
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 the price risk associated with our load serving contracts, non-nuclear generation, and any residual price risk for our nuclear generation that the nuclear PTC and state programs may not fully mitigate. We also enter transactions that further optimize the economic benefits of our overall portfolio.
The forecasted market price risk exposure is the risk of a change in the value of unhedged positions. The forecasted market price risk exposure for our entire economic hedge portfolio associated with a $5/MWh reduction in the annual average around-the-clock energy price based on September 30, 2024 market conditions and hedged position results in an immaterial impact to net income (loss) for 2024 and 2025, respectively, largely due to the nuclear PTC. See Note 10 - Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
68
Table of Contents
Fuel Procurement
We procure natural gas through long-term and short-term contracts, and spot-market purchases. Nuclear fuel is obtained predominantly through long-term uranium concentrate supply contracts, contracted conversion services, contracted enrichment services, or a combination thereof, including contracts sourced from Russia, and contracted fuel fabrication services. The supply markets for uranium concentrates and certain nuclear fuel services are subject to price fluctuations and availability restrictions. Supply market conditions may make our procurement contracts subject to credit risk related to the potential non-performance of counterparties to deliver the contracted commodity or service at the contracted prices. We engage a diverse set of suppliers to ensure we can secure the nuclear fuel needed to continue to operate our nuclear fleet long-term. Approximately 45% of our uranium concentrate requirements for the remainder of 2024 through 2029 are supplied by three suppliers. To-date, we have not experienced any counterparty credit risk associated with these suppliers stemming from the Russia and Ukraine conflict. In the event of non-performance by these or other suppliers, we believe that replacement uranium concentrate can be obtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements. Geopolitical developments, including the Russia and Ukraine conflict and United States, United Kingdom, European Union, and Canadian sanctions against Russia, have the potential to impact delivery from multiple suppliers in the international uranium processing industry. Non-performance by these counterparties could have a material adverse impact on our consolidated financial statements. To-date, we have not experienced any delivery or non-performance issues from our suppliers, nor any degradation in the quality of fuel we have received, and we are closely monitoring developments from the conflict. See ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Other Key Business Drivers for more information on the Russia and Ukraine conflict.
Trading and Non-Trading Marketing Activities
The following table provides detail on changes in our commodity mark-to-market net assets (liabilities) balance sheet position from December 31, 2023 to September 30, 2024. It indicates the drivers behind changes in the balance sheet amounts. This table incorporates the mark-to-market activities that are immediately recorded in earnings. This table excludes all NPNS contracts and does not segregate proprietary trading activity. See Note 10 - Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on the balance sheet classification of the mark-to-market energy contract net assets (liabilities) recorded as of September 30, 2024 and December 31, 2023.
Balance as of December 31, 2023(a)
$ 1,108
Total change in fair value of contracts recorded in results of operations
(507)
Reclassification to realized at settlement of contracts recorded in results of operations 1,689
Changes in allocated collateral (1,509)
Net option premium paid (received)
(159)
Option premium amortization (40)
Upfront payments and amortizations(b)
(56)
Foreign currency translation 1
Balance as of September 30, 2024(a)
$ 527
__________
(a)Amounts are shown net of collateral paid to and received from counterparties.
(b)Includes derivative contracts acquired or sold through upfront payments or receipts of cash, excluding option premiums, and the associated amortizations.
69
Table of Contents
Fair Values
The following table presents maturity and source of fair value for mark-to-market commodity contract net assets (liabilities). See Note 12 - Fair Value of Financial Assets and Liabilities of the Combined Notes to Consolidated Financial Statements for additional information regarding fair value measurements and the fair value hierarchy.
Maturities Within
Total Fair Value
2024 2025 2026 2027 2028 2029 and Beyond
Normal Operations, Commodity derivative contracts(a)(b):
Actively quoted prices (Level 1) $ (54) $ 61 $ 59 $ 6 $ (18) $ (8) $ 46
Prices provided by external sources (Level 2) (84) 137 125 96 (4) 5 275
Prices based on model or other valuation methods (Level 3) 137 16 (5) (30) (2) 90 206
Total $ (1) $ 214 $ 179 $ 72 $ (24) $ 87 $ 527
__________
(a)Represents mark-to-market gains and losses on other economic hedge and trading derivative contracts that are recorded in the results of operations.
(b)Amounts are shown net of collateral paid to and received from counterparties (and offset against mark-to-market assets and liabilities) of $891 million at September 30, 2024.
Credit Risk
We would be exposed to credit-related losses in the event of non-performance by counterparties that execute derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date. See Note 10 - Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for a detailed discussion of credit risk.
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 electric capacity, electricity, fuels, emissions allowances, and other energy-related products. In accordance with the contracts and applicable law, if we are downgraded by a credit rating agency, especially if such downgrade is to a level below investment grade, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance. Depending on our net position with a counterparty, the demand could be for the posting of collateral. 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. See Note 10 - Derivative Financial Instruments and Note 13 - Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding the letters of credit supporting the cash collateral.
We transact output through bilateral contracts. The bilateral contracts are subject to credit risk, which relates to the ability of counterparties to meet their contractual payment obligations. Any failure to collect these payments from counterparties could have a material impact on our consolidated financial statements. As market prices rise above or fall below contracted price levels, we are required to post collateral with purchasers; as market prices fall below contracted price levels, counterparties are required to post collateral with us. To post collateral, we depend on access to bank credit facilities, which serve as liquidity sources to fund collateral requirements. See ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Liquidity and Capital Resources - Credit Matters and Cash Requirements - Credit Facilities for additional information.
70
Table of Contents
RTOs and ISOs
We participate in all of the established wholesale energy markets that are administered by PJM, ISO-NE, NYISO, CAISO, MISO, SPP, AESO, and ERCOT. ERCOT is not subject to regulation by FERC but performs a similar function in Texas to that performed by RTOs and ISOs in markets regulated by FERC. In these areas, power and related products are traded through bilateral agreements between buyers and sellers and in the energy markets that are administered by the RTOs or ISOs, as applicable. In areas where there is no RTO or ISO to administer energy markets, electricity and related products are purchased and sold solely through bilateral agreements. For activity administered by an RTO or ISO, the RTO or ISO maintains financial assurance policies that are established and enforced by those administrators. The credit policies of the RTOs and ISOs may, under certain circumstances, require that losses arising from the default of one member be shared by the remaining participants. Non-performance or non-payment by a major member of an RTO or ISO could result in a material adverse impact on our consolidated financial statements.
Exchange Traded Transactions
We enter into commodity transactions on NYMEX, ICE, NASDAQ, NGX, and the Nodal exchange (each an Exchange and, collectively, Exchanges). The Exchange clearinghouses act as the counterparty to each trade. Transactions on the Exchanges must adhere to comprehensive collateral and margining requirements. As a result, transactions on Exchanges are significantly collateralized and have limited counterparty credit risk.
Interest Rate and Foreign Exchange Risk
We use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. We may also utilize interest rate swaps to manage our interest rate exposure. A hypothetical 50 basis point increase in the interest rates associated with unhedged variable-rate debt (excluding Commercial Paper) and fixed-to-floating swaps would not have resulted in a material decrease in ourpre-taxincome for the nine months ended September 30, 2024. To manage foreign exchange rate exposure associated with international energy purchases in currencies other than U.S. dollars, we utilize foreign currency derivatives, which are typically designated as economic hedges. See Note 10 - Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
Equity Price Risk
We maintain trust funds, as required by the NRC, to fund the costs of decommissioning our nuclear plants. Our NDT funds are reflected at fair value in the Consolidated Balance Sheets. The mix of securities in the trust funds is designed to provide returns to be used to fund decommissioning and to compensate us for inflationary increases in decommissioning costs; however, the equity securities in the trust funds are exposed to price fluctuations in equity markets, and the value of fixed-rate, fixed-income securities are exposed to changes in interest rates. We actively monitor the investment performance of the trust funds and periodically review asset allocations in accordance with our NDT fund investment policy.
A hypothetical 25 basis points increase in interest rates and 10% decrease in equity prices would have resulted in a $977 million reduction in the fair value of our NDT trust assets as of September 30, 2024. This calculation holds all other variables constant and assumes only the discussed changes in interest rates and equity prices. See Note 7 - Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements and Liquidity and Capital Resources section of ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for additional information.
Our employee benefit plan trusts also hold investments in equity and debt securities. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Critical Accounting Policies and Estimates of our 2023 Form 10-K for further information.
71
Table of Contents
ITEM 4. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
During the third quarter of 2024, our principal executive officer and principal financial officer, evaluated the effectiveness of our disclosure controls and procedures related to the recording, processing, summarizing, and reporting of information in periodic reports that we file or submit with the SEC. These disclosure controls and procedures have been designed to ensure that (a) information relating to our consolidated subsidiaries, is accumulated and made known to our management, including our principal executive officer and principal financial officer, by other employees as appropriate to allow timely decisions regarding required disclosure, and (b) this information is recorded, processed, summarized, and reported, as applicable, within the time periods specified in the SEC's rules and forms. Due to the inherent limitations of control systems, not all misstatements may be detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls could be circumvented by the individual acts of some persons or by collusion of two or more people.
Accordingly, as of September 30, 2024, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective to accomplish their objectives.
Changes in Internal Control Over Financial Reporting
We continually strive to improve our disclosure controls and procedures to enhance the quality of our financial reporting and to maintain dynamic systems that change as conditions warrant. There have been no changes in internal control over financial reporting that occurred during the third quarter of 2024 that have materially affected, or are reasonably likely to materially affect, any of our internal control over financial reporting.
PART II. OTHER INFORMATION
(Dollars in millions except per share data, unless otherwise noted)
ITEM 1. LEGAL PROCEEDINGS
We are parties to various lawsuits and regulatory proceedings in the ordinary course of business. For information regarding material lawsuits and proceedings, see Note 13 - Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in PART I, ITEM 1. FINANCIAL STATEMENTS of this report. Such descriptions are incorporated herein by these references.
ITEM 1A. RISK FACTORS
At September 30, 2024, our risk factors were consistent with the risk factors described in our 2023 Form 10-K in ITEM 1A. RISK FACTORS.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
Issuer Purchases of Equity Securities (CEG Parent)
During 2023, our Board of Directors authorized the repurchase of up to $2 billion of the Company's outstanding common stock. In April 2024, our Board of Directors approved a $1 billion increase to the program, authorizing up to $3 billion in total repurchases. No other repurchase plans or programs have been authorized. See Note 14 - Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information regarding our share repurchase program.
72
Table of Contents
The following table provides information regarding our share repurchases under the program during the three months ended September 30, 2024:
Period
Total Number of Shares Purchased(a)(b)
Average Price Paid per Share(b)
Approximate Dollar Value of Shares that May Yet Be Purchased Under the Programs(c)
July 1 to July 31, 2024 528,078 $ 211.40 $ 991
August 1 to August 31, 2024 - - 991
September 1 to September 30, 2024 - - 991
Total
528,078 $ 991
__________
(a)We have not made any purchases of shares other than in connection with the publicly announced share repurchase program described above.
(b)Represents the additional shares delivered under the May 2024 ASR agreement, which was fully settled in July.
(c)Approximate dollar value of shares that may yet be purchased under the program includes taxes and commissions.
ITEM 4. MINE SAFETY DISCLOSURES
Not Applicable.
ITEM 5. OTHER INFORMATION
Rule 10b5-1 Trading Plans
During the three months ended September 30, 2024, none of our directors or executive officers (as defined in Rule 16a-1 under the Exchange Act) adopted or terminated any contract, instruction or written plan for the purchase or sale of our securities that was intended to satisfy the affirmative defense conditions of Rule 10b5-1(c) or any "non-Rule 10b5-1 trading arrangement" (as defined in Item 408 under Regulation S-K of the Exchange Act).
73
Table of Contents
ITEM 6. EXHIBITS
Certain of the following exhibits are incorporated herein by reference under Rule 12b-32 of the Exchange Act. Certain other instruments which would otherwise be required to be listed below have not been so listed because such instruments do not authorize securities in an amount which exceeds 10% of the total assets of the applicable Registrant and its subsidiaries on a consolidated basis and the relevant Registrant agrees to furnish a copy of any such instrument to the SEC upon request.
Exhibit No. Description
101.INS Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH Inline XBRL Taxonomy Extension Schema Document.
101.CAL Inline XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF Inline XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB Inline XBRL Taxonomy Extension Label Linkbase Document.
101.PRE Inline XBRL Taxonomy Extension Presentation Linkbase Document.
104 Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
Certifications Pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act as to the Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2024 filed by the following officers for the following companies:
Exhibit No. Description
31.1
Filed by Joseph Dominguez for Constellation Energy Corporation
31.2
Filed by Daniel L. Eggers for Constellation Energy Corporation
31.3
Filed by Joseph Dominguez for Constellation Energy Generation, LLC
31.4
Filed by Daniel L. Eggers for Constellation Energy Generation, LLC
Certifications Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code (Sarbanes - Oxley Act of 2002) as to the Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2024 filed by the following officers for the following companies:
Exhibit No. Description
32.1
Filed by Joseph Dominguez for Constellation Energy Corporation
32.2
Filed by Daniel L. Eggers for Constellation Energy Corporation
32.3
Filed by Joseph Dominguez for Constellation Energy Generation, LLC
32.4
Filed by Daniel L. Eggers for Constellation Energy Generation, LLC
74
Table of Contents
SIGNATURES
Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
CONSTELLATION ENERGY CORPORATION
/s/ JOSEPH DOMINGUEZ /s/ DANIEL L. EGGERS
Joseph Dominguez Daniel L. Eggers
President and Chief Executive Officer
(Principal Executive Officer)
Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
/s/ MATTHEW N. BAUER
Matthew N. Bauer
Senior Vice President and Controller
(Principal Accounting Officer)
November 4, 2024
75
Table of Contents
Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
CONSTELLATION ENERGY GENERATION, LLC
/s/ JOSEPH DOMINGUEZ /s/ DANIEL L. EGGERS
Joseph Dominguez Daniel L. Eggers
President and Chief Executive Officer
(Principal Executive Officer) 		Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
/s/ MATTHEW N. BAUER
Matthew N. Bauer
Senior Vice President and Controller
(Principal Accounting Officer)
November 4, 2024
76