EXELON CORPORATION (EXC, NYSE)
Annual report, fiscal year 2019


# UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K

## ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

## For the Fiscal Year Ended December 31, 2019

## or

## ☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

<table><tr><td>Commission File Number</td><td>Name of Registrant; State or Other Jurisdiction of Incorporation; Address of Principal Executive Offices; and Telephone Number</td><td>IRS Employer Identification Number</td></tr><tr><td>001-16169</td><td>EXELON CORPORATION</td><td>23-2990190</td></tr><tr><td></td><td>(a Pennsylvania corporation)</td><td></td></tr><tr><td></td><td>10 South Dearborn Street</td><td></td></tr><tr><td></td><td>P.O. Box 805379</td><td></td></tr><tr><td></td><td>Chicago, Illinois 60680-5379</td><td></td></tr><tr><td></td><td>(800) 483-3220</td><td></td></tr><tr><td>333-85496</td><td>EXELON GENERATION COMPANY, LLC</td><td>23-3064219</td></tr><tr><td></td><td>(a Pennsylvania limited liability company)</td><td></td></tr><tr><td></td><td>300 Exelon Way</td><td></td></tr><tr><td></td><td>Kennett Square, Pennsylvania 19348-2473</td><td></td></tr><tr><td></td><td>(610) 765-5959</td><td></td></tr><tr><td>001-01839</td><td>COMMONWEALTH EDISON COMPANY</td><td>36-0938600</td></tr><tr><td></td><td>(an Illinois corporation)</td><td></td></tr><tr><td></td><td>440 South LaSalle Street</td><td></td></tr><tr><td></td><td>Chicago, Illinois 60605-1028</td><td></td></tr><tr><td></td><td>(312) 394-4321</td><td></td></tr><tr><td>000-16844</td><td>PECO ENERGY COMPANY</td><td>23-0970240</td></tr><tr><td></td><td>(a Pennsylvania corporation)</td><td></td></tr><tr><td></td><td>P.O. Box 8699</td><td></td></tr><tr><td></td><td>2301 Market Street</td><td></td></tr><tr><td></td><td>Philadelphia, Pennsylvania 19101-8699</td><td></td></tr><tr><td></td><td>(215) 841-4000</td><td></td></tr><tr><td>001-01910</td><td>BALTIMORE GAS AND ELECTRIC COMPANY</td><td>52-0280210</td></tr><tr><td></td><td>(a Maryland corporation)</td><td></td></tr><tr><td></td><td>2 Center Plaza</td><td></td></tr><tr><td></td><td>110 West Fayette Street</td><td></td></tr><tr><td></td><td>Baltimore, Maryland 21201-3708</td><td></td></tr><tr><td></td><td>(410) 234-5000</td><td></td></tr><tr><td>001-31403</td><td>PEPCO HOLDINGS LLC</td><td>52-2297449</td></tr><tr><td></td><td>(a Delaware limited liability company)</td><td></td></tr><tr><td></td><td>701 Ninth Street, N.W.</td><td></td></tr><tr><td></td><td>Washington, District of Columbia 20068</td><td></td></tr><tr><td></td><td>(202) 872-2000</td><td></td></tr><tr><td>001-01072</td><td>POTOMAC ELECTRIC POWER COMPANY</td><td>53-0127880</td></tr><tr><td></td><td>(a District of Columbia and Virginia corporation)</td><td></td></tr><tr><td></td><td>701 Ninth Street, N.W.</td><td></td></tr><tr><td></td><td>Washington, District of Columbia 20068</td><td></td></tr><tr><td></td><td>(202) 872-2000</td><td></td></tr><tr><td>001-01405</td><td>DELMARVA POWER &amp; LIGHT COMPANY</td><td>51-0084283</td></tr><tr><td></td><td>(a Delaware and Virginia corporation)</td><td></td></tr><tr><td></td><td>500 North Wakefield Drive</td><td></td></tr><tr><td></td><td>Newark, Delaware 19702</td><td></td></tr><tr><td></td><td>(202) 872-2000</td><td></td></tr><tr><td>001-03559</td><td>ATLANTIC CITY ELECTRIC COMPANY</td><td>21-0398280</td></tr><tr><td></td><td>(a New Jersey corporation)</td><td></td></tr><tr><td></td><td>500 North Wakefield Drive</td><td></td></tr><tr><td></td><td>Newark, Delaware 19702</td><td></td></tr><tr><td></td><td>(202) 872-2000</td><td></td></tr></table>



## Securities registered pursuant to Section 12(b) of the Act:

<table><tr><td>Title of each class</td><td>Trading Symbol(s)</td><td>Name of each exchange on which registered</td></tr><tr><td>EXELON CORPORATION:</td><td></td><td></td></tr><tr><td>Common Stock, without par value</td><td>EXC</td><td>The Nasdaq Stock Market LLC</td></tr><tr><td>PECO ENERGY COMPANY:</td><td></td><td></td></tr><tr><td>Trust Receipts of PECO Energy Capital Trust III, each representing a 7.38% Cumulative Preferred Security, Series D, $25 stated value, issued by PECO Energy Capital, L.P. and unconditionally guaranteed by PECO Energy Company</td><td>EXC/28</td><td>New York Stock Exchange</td></tr></table>

## Securities registered pursuant to Section 12(g) of the Act:

## Title of Each Class

## COMMONWEALTH EDISON COMPANY:

Common Stock Purchase Warrants (1971 Warrants and Series B Warrants)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

<table><tr><td>Exelon Corporation</td><td>Yes</td><td>☒</td><td>No</td><td>☐</td></tr><tr><td>Exelon Generation Company, LLC</td><td>Yes</td><td>☐</td><td>No</td><td>☒</td></tr><tr><td>Commonwealth Edison Company</td><td>Yes</td><td>☐</td><td>No</td><td>☒</td></tr><tr><td>PECO Energy Company</td><td>Yes</td><td>☐</td><td>No</td><td>☒</td></tr><tr><td>Baltimore Gas and Electric Company</td><td>Yes</td><td>☐</td><td>No</td><td>☒</td></tr><tr><td>Pepco Holdings LLC</td><td>Yes</td><td>☐</td><td>No</td><td>☒</td></tr><tr><td>Potomac Electric Power Company</td><td>Yes</td><td>☐</td><td>No</td><td>☒</td></tr><tr><td>Delmarva Power &amp; Light Company</td><td>Yes</td><td>☐</td><td>No</td><td>☒</td></tr><tr><td>Atlantic City Electric Company</td><td>Yes</td><td>☐</td><td>No</td><td>☒</td></tr></table>

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

<table><tr><td>Exelon Corporation</td><td>Yes</td><td>☐</td><td>No</td><td>☒</td></tr><tr><td>Exelon Generation Company, LLC</td><td>Yes</td><td>☐</td><td>No</td><td>☒</td></tr><tr><td>Commonwealth Edison Company</td><td>Yes</td><td>☐</td><td>No</td><td>☒</td></tr><tr><td>PECO Energy Company</td><td>Yes</td><td>☐</td><td>No</td><td>☒</td></tr><tr><td>Baltimore Gas and Electric Company</td><td>Yes</td><td>☐</td><td>No</td><td>☒</td></tr><tr><td>Pepco Holdings LLC</td><td>Yes</td><td>☐</td><td>No</td><td>☒</td></tr><tr><td>Potomac Electric Power Company</td><td>Yes</td><td>☐</td><td>No</td><td>☒</td></tr><tr><td>Delmarva Power &amp; Light Company</td><td>Yes</td><td>☐</td><td>No</td><td>☒</td></tr><tr><td>Atlantic City Electric Company</td><td>Yes</td><td>☐</td><td>No</td><td>☒</td></tr></table>

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. Yes ☑ 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 and post such files). Yes ☑ 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.



<table><tr><td>Exelon Corporation</td><td>Large Accelerated Filer ☑</td><td>Accelerated Filer ☐</td><td>Non-accelerated Filer ☐</td><td>Smaller Reporting Company ☐</td><td>Emerging Growth Company ☐</td></tr><tr><td>Exelon Generation Company, LLC</td><td>Large Accelerated Filer ☐</td><td>Accelerated Filer ☐</td><td>Non-accelerated Filer ☑</td><td>Smaller Reporting Company ☐</td><td>Emerging Growth Company ☐</td></tr><tr><td>Commonwealth Edison Company</td><td>Large Accelerated Filer ☐</td><td>Accelerated Filer ☐</td><td>Non-accelerated Filer ☑</td><td>Smaller Reporting Company ☐</td><td>Emerging Growth Company ☐</td></tr><tr><td>PECO Energy Company</td><td>Large Accelerated Filer ☐</td><td>Accelerated Filer ☐</td><td>Non-accelerated Filer ☑</td><td>Smaller Reporting Company ☐</td><td>Emerging Growth Company ☐</td></tr><tr><td>Baltimore Gas and Electric Company</td><td>Large Accelerated Filer ☐</td><td>Accelerated Filer ☐</td><td>Non-accelerated Filer ☑</td><td>Smaller Reporting Company ☐</td><td>Emerging Growth Company ☐</td></tr><tr><td>Pepco Holdings LLC</td><td>Large Accelerated Filer ☐</td><td>Accelerated Filer ☐</td><td>Non-accelerated Filer ☑</td><td>Smaller Reporting Company ☐</td><td>Emerging Growth Company ☐</td></tr><tr><td>Potomac Electric Power Company</td><td>Large Accelerated Filer ☐</td><td>Accelerated Filer ☐</td><td>Non-accelerated Filer ☑</td><td>Smaller Reporting Company ☐</td><td>Emerging Growth Company ☐</td></tr><tr><td>Delmarva Power &amp; Light Company</td><td>Large Accelerated Filer ☐</td><td>Accelerated Filer ☐</td><td>Non-accelerated Filer ☑</td><td>Smaller Reporting Company ☐</td><td>Emerging Growth Company ☐</td></tr><tr><td>Atlantic City Electric Company</td><td>Large Accelerated Filer ☐</td><td>Accelerated Filer ☐</td><td>Non-accelerated Filer ☑</td><td>Smaller Reporting Company ☐</td><td>Emerging Growth Company ☐</td></tr></table>

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. □

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☑

The estimated aggregate market value of the voting and non-voting common equity held by nonaffiliates of each registrant as of June 30, 2019 was as follows:

<table><tr><td>Exelon Corporation Common Stock, without par value</td><td>$46,542,193,363</td></tr><tr><td>Exelon Generation Company, LLC</td><td>Not applicable</td></tr><tr><td>Commonwealth Edison Company Common Stock, $12.50 par value</td><td>No established market</td></tr><tr><td>PECO Energy Company Common Stock, without par value</td><td>None</td></tr><tr><td>Baltimore Gas and Electric Company, without par value</td><td>None</td></tr><tr><td>Pepco Holdings LLC</td><td>Not applicable</td></tr><tr><td>Potomac Electric Power Company</td><td>None</td></tr><tr><td>Delmarva Power &amp; Light Company</td><td>None</td></tr><tr><td>Atlantic City Electric Company</td><td>None</td></tr></table>

The number of shares outstanding of each registrant's common stock as of January 31, 2020 was as follows:

<table><tr><td>Exelon Corporation Common Stock, without par value</td><td>974,319,565</td></tr><tr><td>Exelon Generation Company, LLC</td><td>Not applicable</td></tr><tr><td>Commonwealth Edison Company Common Stock, $12.50 par value</td><td>127,021,349</td></tr><tr><td>PECO Energy Company Common Stock, without par value</td><td>170,478,507</td></tr><tr><td>Baltimore Gas and Electric Company Common Stock, without par value</td><td>1,000</td></tr><tr><td>Pepco Holdings LLC</td><td>Not applicable</td></tr><tr><td>Potomac Electric Power Company Common Stock, $0.01 par value</td><td>100</td></tr><tr><td>Delmarva Power &amp; Light Company Common Stock, $2.25 par value</td><td>1,000</td></tr><tr><td>Atlantic City Electric Company Common Stock, $3.00 par value</td><td>8,546,017</td></tr></table>



## Documents Incorporated by Reference

Portions of the Exelon Proxy Statement for the 2019 Annual Meeting of Shareholders and the Commonwealth Edison Company 2019 Information Statement are incorporated by reference in Part III.

Exelon Generation Company, LLC, PECO Energy Company, Baltimore Gas and Electric Company, Pepco Holdings LLC, Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and are therefore filing this Form in the reduced disclosure format.



## TABLE OF CONTENTS

GLOSSARY OF TERMS AND ABBREVIATIONS
FILING FORMAT
CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION
WHERE TO FIND MORE INFORMATION
PART I
ITEM 1. BUSINESS
General
Exelon Generation Company, LLC
Utility Operations
Employees
Environmental Regulation
Executive Officers of the Registrants
RISK FACTORS
UNRESOLVED STAFF COMMENTS
PROPERTIES
Exelon Generation Company, LLC
The Utility Registrants
LEGAL PROCEEDINGS
MINE SAFETY DISCLOSURES
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
ITEM 6. SELECTED FINANCIAL DATA
Exelon Corporation
Exelon Generation Company, LLC
Commonwealth Edison Company
PECO Energy Company
Baltimore Gas and Electric Company
Pepco Holdings LLC
Potomac Electric Power Company
Delmarva Power & Light Company
Atlantic City Electric Company



<table><tr><td>ITEM 7.</td><td>MANAGEMENT&#x27;S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS</td><td>Page No.</td></tr><tr><td></td><td>Exelon Corporation</td><td>60</td></tr><tr><td></td><td>Executive Overview</td><td>60</td></tr><tr><td></td><td>Financial Results of Operations</td><td>61</td></tr><tr><td></td><td>Significant 2019 Transactions and Recent Developments</td><td>64</td></tr><tr><td></td><td>Exelon&#x27;s Strategy and Outlook for 2020 and Beyond</td><td>68</td></tr><tr><td></td><td>Other Key Business Drivers and Management Strategies</td><td>69</td></tr><tr><td></td><td>Critical Accounting Policies and Estimates</td><td>74</td></tr><tr><td></td><td>Results of Operations</td><td>84</td></tr><tr><td></td><td>Exelon Generation Company, LLC</td><td>85</td></tr><tr><td></td><td>Commonwealth Edison Company</td><td>91</td></tr><tr><td></td><td>PECO Energy Company</td><td>94</td></tr><tr><td></td><td>Baltimore Gas and Electric Company</td><td>98</td></tr><tr><td></td><td>Pepco Holdings LLC</td><td>101</td></tr><tr><td></td><td>Potomac Electric Power Company</td><td>102</td></tr><tr><td></td><td>Delmarva Power &amp; Light Company</td><td>105</td></tr><tr><td></td><td>Atlantic City Electric Company</td><td>110</td></tr><tr><td></td><td>Liquidity and Capital Resources</td><td>112</td></tr><tr><td></td><td>Contractual Obligations and Off-Balance Sheet Arrangements</td><td>129</td></tr><tr><td>ITEM 7A.</td><td>QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK</td><td>134</td></tr><tr><td></td><td>Exelon Corporation</td><td>134</td></tr><tr><td></td><td>Exelon Generation Company, LLC</td><td>141</td></tr><tr><td></td><td>Commonwealth Edison Company</td><td>143</td></tr><tr><td></td><td>PECO Energy Company</td><td>145</td></tr><tr><td></td><td>Baltimore Gas and Electric Company</td><td>147</td></tr><tr><td></td><td>Pepco Holdings LLC</td><td>149</td></tr><tr><td></td><td>Potomac Electric Power Company</td><td>151</td></tr><tr><td></td><td>Delmarva Power &amp; Light Company</td><td>153</td></tr><tr><td></td><td>Atlantic City Electric Company</td><td>155</td></tr></table>



ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 157
Exelon Corporation 178
Exelon Generation Company, LLC 183
Commonwealth Edison Company 188
PECO Energy Company 193
Baltimore Gas and Electric Company 198
Pepco Holdings LLC 203
Potomac Electric Power Company 208
Delmarva Power & Light Company 213
Atlantic City Electric Company 218
Combined Notes to Consolidated Financial Statements 223
1. Significant Accounting Policies 223
2. Mergers, Acquisitions and Dispositions 232
3. Regulatory Matters 235
4. Revenue from Contracts with Customers 252
5. Segment Information 255
6. Early Plant Retirements 265
7. Property, Plant and Equipment 269
8. Jointly Owned Electric Utility Plant 271
9. Asset Retirement Obligations 272
10. Leases 277
11. Asset Impairments 280
12. Intangible Assets 280
13. Income Taxes 283
14. Retirement Benefits 292
15. Derivative Financial Instruments 305
16. Debt and Credit Agreements 312
17. Fair Value of Financial Assets and Liabilities 322
18. Commitments and Contingencies 338
19. Shareholders' Equity 348
20. Stock-Based Compensation Plans 349
21. Changes in Accumulated Other Comprehensive Income 352
22. Variable Interest Entities 353
23. Supplemental Financial Information 356
24. Related Party Transactions 363
25. Quarterly Data 367
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 370
ITEM 9A. CONTROLS AND PROCEDURES 370
ITEM 9B. OTHER INFORMATION 370



## PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE 371
ITEM 11. EXECUTIVE COMPENSATION 372
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS 373
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE 374
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES 375
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES 376
ITEM 16. FORM 10-K SUMMARY 421
SIGNATURES
Exelon Corporation 422
Exelon Generation Company, LLC 423
Commonwealth Edison Company 424
PECO Energy Company 425
Baltimore Gas and Electric Company 426
Pepco Holdings LLC 427
Potomac Electric Power Company 428
Delmarva Power & Light Company 429
Atlantic City Electric Company 430



GLOSSARY OF TERMS AND ABBREVIATIONS

<table><tr><td colspan="2">Exelon Corporation and Related Entities</td></tr><tr><td>Exelon</td><td>Exelon Corporation</td></tr><tr><td>Generation</td><td>Exelon Generation Company, LLC</td></tr><tr><td>ComEd</td><td>Commonwealth Edison Company</td></tr><tr><td>PECO</td><td>PECO Energy Company</td></tr><tr><td>BGE</td><td>Baltimore Gas and Electric Company</td></tr><tr><td>Pepco Holdings or PHI</td><td>Pepco Holdings LLC (formerly Pepco Holdings, Inc.)</td></tr><tr><td>Pepco</td><td>Potomac Electric Power Company</td></tr><tr><td>DPL</td><td>Delmarva Power &amp; Light Company</td></tr><tr><td>ACE</td><td>Atlantic City Electric Company</td></tr><tr><td>Registrants</td><td>Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, collectively</td></tr><tr><td>Utility Registrants</td><td>ComEd, PECO, BGE, Pepco, DPL and ACE, collectively</td></tr><tr><td>Legacy PHI</td><td>PHI, Pepco, DPL, ACE, PES and PCI collectively</td></tr><tr><td>ACE Funding or ATF</td><td>Atlantic City Electric Transition Funding LLC</td></tr><tr><td>Antelope Valley</td><td>Antelope Valley Solar Ranch One</td></tr><tr><td>BondCo</td><td>RSB BondCo LLC</td></tr><tr><td>BSC</td><td>Exelon Business Services Company, LLC</td></tr><tr><td>CENG</td><td>Constellation Energy Nuclear Group, LLC</td></tr><tr><td>Constellation</td><td>Constellation Energy Group, Inc.</td></tr><tr><td>EEDC</td><td>Exelon Energy Delivery Company, LLC</td></tr><tr><td>EGR IV</td><td>ExGen Renewables IV, LLC</td></tr><tr><td>EGRP</td><td>ExGen Renewables Partners, LLC</td></tr><tr><td>EGTP</td><td>ExGen Texas Power, LLC</td></tr><tr><td>Entergy</td><td>Entergy Nuclear FitzPatrick, LLC</td></tr><tr><td>Exelon Corporate</td><td>Exelon in its corporate capacity as a holding company</td></tr><tr><td>Exelon Transmission Company</td><td>Exelon Transmission Company, LLC</td></tr><tr><td>Exelon Wind</td><td>Exelon Wind, LLC and Exelon Generation Acquisition Company, LLC</td></tr><tr><td>FitzPatrick</td><td>James A. FitzPatrick nuclear generating station</td></tr><tr><td>Ginna</td><td>R. E. Ginna nuclear generating station</td></tr><tr><td>PCI</td><td>Potomac Capital Investment Corporation and its subsidiaries</td></tr><tr><td>PEC L.P.</td><td>PECO Energy Capital, L.P.</td></tr><tr><td>PECO Trust III</td><td>PECO Capital Trust III</td></tr><tr><td>PECO Trust IV</td><td>PECO Energy Capital Trust IV</td></tr><tr><td>Pepco Energy Services or PES</td><td>Pepco Energy Services, Inc. and its subsidiaries</td></tr><tr><td>PHI Corporate</td><td>PHI in its corporate capacity as a holding company</td></tr><tr><td>PHISCO</td><td>PHI Service Company</td></tr><tr><td>RPG</td><td>Renewable Power Generation</td></tr><tr><td>SolGen</td><td>SolGen, LLC</td></tr><tr><td>TMI</td><td>Three Mile Island nuclear facility</td></tr><tr><td>UI</td><td>Unicom Investments, Inc.</td></tr></table>



GLOSSARY OF TERMS AND ABBREVIATIONS

<table><tr><td colspan="2">Other Terms and Abbreviations</td></tr><tr><td>AEC</td><td>Alternative Energy Credit that is issued for each megawatt hour of generation from a qualified alternative energy source</td></tr><tr><td>AESO</td><td>Alberta Electric Systems Operator</td></tr><tr><td>AFUDC</td><td>Allowance for Funds Used During Construction</td></tr><tr><td>AGE</td><td>Albany Green Energy Project</td></tr><tr><td>AMI</td><td>Advanced Metering Infrastructure</td></tr><tr><td>AMP</td><td>Advanced Metering Program</td></tr><tr><td>AOCI</td><td>Accumulated Other Comprehensive Income (Loss)</td></tr><tr><td>ARC</td><td>Asset Retirement Cost</td></tr><tr><td>ARO</td><td>Asset Retirement Obligation</td></tr><tr><td>ARP</td><td>Alternative Revenue Program</td></tr><tr><td>ASA</td><td>Asset Sale Agreement</td></tr><tr><td>BGS</td><td>Basic Generation Service</td></tr><tr><td>CAISO</td><td>California ISO</td></tr><tr><td>CAP</td><td>Customer Assistance Program</td></tr><tr><td>CCGTs</td><td>Combined-Cycle gas turbines</td></tr><tr><td>CERCLA</td><td>Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended</td></tr><tr><td>CES</td><td>Clean Energy Standard</td></tr><tr><td>Clean Air Act</td><td>Clean Air Act of 1963, as amended</td></tr><tr><td>Clean Water Act</td><td>Federal Water Pollution Control Amendments of 1972, as amended</td></tr><tr><td>CODM</td><td>Chief Operating Decision Maker</td></tr><tr><td>Conectiv</td><td>Conectiv, LLC, a wholly owned subsidiary of PHI and the parent of DPL and ACE during the Predecessor periods</td></tr><tr><td>Conectiv Energy</td><td>Conectiv Energy Holdings, Inc. and substantially all of its subsidiaries, which were sold to Calpine in July 2010</td></tr><tr><td>ConEdison Solutions</td><td>The competitive retail electricity and natural gas business of Consolidated Edison Solutions, Inc., a subsidiary of Consolidated Edison, Inc</td></tr><tr><td>CSAPR</td><td>Cross-State Air Pollution Rule</td></tr><tr><td>CTA</td><td>Consolidated tax adjustment</td></tr><tr><td>D.C. Circuit Court</td><td>United States Court of Appeals for the District of Columbia Circuit</td></tr><tr><td>DC PLUG</td><td>District of Columbia Power Line Underground Initiative</td></tr><tr><td>DCPSC</td><td>District of Columbia Public Service Commission</td></tr><tr><td>DDOT</td><td>District Department of Transportation</td></tr><tr><td>DOE</td><td>United States Department of Energy</td></tr><tr><td>DOEE</td><td>Department of Energy &amp; Environment</td></tr><tr><td>DOJ</td><td>United States Department of Justice</td></tr><tr><td>DPSC</td><td>Delaware Public Service Commission</td></tr><tr><td>DSP</td><td>Default Service Provider</td></tr><tr><td>DSP Program</td><td>Default Service Provider Program</td></tr><tr><td>EDF</td><td>Electricite de France SA and its subsidiaries</td></tr><tr><td>EIMA</td><td>Energy Infrastructure Modernization Act (Illinois Senate Bill 1652 and Illinois House Bill 3036)</td></tr><tr><td>EmPower</td><td>A Maryland demand-side management program for Pepco and DPL</td></tr></table>



GLOSSARY OF TERMS AND ABBREVIATIONS

<table><tr><td colspan="2">Other Terms and Abbreviations</td></tr><tr><td>EPA</td><td>United States Environmental Protection Agency</td></tr><tr><td>EPSA</td><td>Electric Power Supply Association</td></tr><tr><td>ERCOT</td><td>Electric Reliability Council of Texas</td></tr><tr><td>ERISA</td><td>Employee Retirement Income Security Act of 1974, as amended</td></tr><tr><td>EROA</td><td>Expected Rate of Return on Assets</td></tr><tr><td>FASB</td><td>Financial Accounting Standards Board</td></tr><tr><td>FEJA</td><td>Illinois Public Act 99-0906 or Future Energy Jobs Act</td></tr><tr><td>FERC</td><td>Federal Energy Regulatory Commission</td></tr><tr><td>FRCC</td><td>Florida Reliability Coordinating Council</td></tr><tr><td>FRR</td><td>Fixed Resource Requirement</td></tr><tr><td>GAAP</td><td>Generally Accepted Accounting Principles in the United States</td></tr><tr><td>GCR</td><td>Gas Cost Rate</td></tr><tr><td>GHG</td><td>Greenhouse Gas</td></tr><tr><td>GSA</td><td>Generation Supply Adjustment</td></tr><tr><td>GWh</td><td>Gigawatt hour</td></tr><tr><td>IBEW</td><td>International Brotherhood of Electrical Workers</td></tr><tr><td>ICC</td><td>Illinois Commerce Commission</td></tr><tr><td>ICE</td><td>Intercontinental Exchange</td></tr><tr><td>IIP</td><td>Infrastructure Investment Program</td></tr><tr><td>Illinois EPA</td><td>Illinois Environmental Protection Agency</td></tr><tr><td>Illinois Settlement Legislation</td><td>Legislation enacted in 2007 affecting electric utilities in Illinois</td></tr><tr><td>Integrys</td><td>Integrys Energy Services, Inc.</td></tr><tr><td>IPA</td><td>Illinois Power Agency</td></tr><tr><td>IRC</td><td>Internal Revenue Code</td></tr><tr><td>IRS</td><td>Internal Revenue Service</td></tr><tr><td>ISO</td><td>Independent System Operator</td></tr><tr><td>ISO-NE</td><td>ISO New England Inc.</td></tr><tr><td>NYISO</td><td>New York ISO</td></tr><tr><td>kV</td><td>Kilovolt</td></tr><tr><td>kW</td><td>Kilowatt</td></tr><tr><td>kWh</td><td>Kilowatt-hour</td></tr><tr><td>LIBOR</td><td>London Interbank Offered Rate</td></tr><tr><td>LLRW</td><td>Low-Level Radioactive Waste</td></tr><tr><td>LNG</td><td>Liquefied Natural Gas</td></tr><tr><td>LTIP</td><td>Long-Term Incentive Plan</td></tr><tr><td>MAPP</td><td>Mid-Atlantic Power Pathway</td></tr><tr><td>MATS</td><td>U.S. EPA Mercury and Air Toxics Rule</td></tr><tr><td>MBR</td><td>Market Based Rates Incentive</td></tr><tr><td>MDE</td><td>Maryland Department of the Environment</td></tr><tr><td>MDPSC</td><td>Maryland Public Service Commission</td></tr><tr><td>MGP</td><td>Manufactured Gas Plant</td></tr><tr><td>MISO</td><td>Midcontinent Independent System Operator, Inc.</td></tr></table>



GLOSSARY OF TERMS AND ABBREVIATIONS

<table><tr><td colspan="2">Other Terms and Abbreviations</td></tr><tr><td>mmcf</td><td>Million Cubic Feet</td></tr><tr><td>Moody&#x27;s</td><td>Moody&#x27;s Investor Service</td></tr><tr><td>MOPR</td><td>Minimum Offer Price Rule</td></tr><tr><td>MRV</td><td>Market-Related Value</td></tr><tr><td>MW</td><td>Megawatt</td></tr><tr><td>MWh</td><td>Megawatt hour</td></tr><tr><td>n.m.</td><td>not meaningful</td></tr><tr><td>NAAQS</td><td>National Ambient Air Quality Standards</td></tr><tr><td>NAV</td><td>Net Asset Value</td></tr><tr><td>NDT</td><td>Nuclear Decommissioning Trust</td></tr><tr><td>NEIL</td><td>Nuclear Electric Insurance Limited</td></tr><tr><td>NERC</td><td>North American Electric Reliability Corporation</td></tr><tr><td>NGS</td><td>Natural Gas Supplier</td></tr><tr><td>NJBPL</td><td>New Jersey Board of Public Utilities</td></tr><tr><td>NJDEP</td><td>New Jersey Department of Environmental Protection</td></tr><tr><td>NLRB</td><td>National Labor Relations Board</td></tr><tr><td>Non-Regulatory Agreements Units</td><td>Nuclear generating units or portions thereof whose decommissioning-related activities are not subject to contractual elimination under regulatory accounting</td></tr><tr><td>NOSA</td><td>Nuclear Operating Services Agreement</td></tr><tr><td>NPDES</td><td>National Pollutant Discharge Elimination System</td></tr><tr><td>NPNS</td><td>Normal Purchase Normal Sale scope exception</td></tr><tr><td>NRC</td><td>Nuclear Regulatory Commission</td></tr><tr><td>NSPS</td><td>New Source Performance Standards</td></tr><tr><td>NWPA</td><td>Nuclear Waste Policy Act of 1982</td></tr><tr><td>NYMEX</td><td>New York Mercantile Exchange</td></tr><tr><td>NYPSC</td><td>New York Public Service Commission</td></tr><tr><td>OCI</td><td>Other Comprehensive Income</td></tr><tr><td>OIESO</td><td>Ontario Independent Electricity System Operator</td></tr><tr><td>OPC</td><td>Office of People&#x27;s Counsel</td></tr><tr><td>OPEB</td><td>Other Postretirement Employee Benefits</td></tr><tr><td>PA DEP</td><td>Pennsylvania Department of Environmental Protection</td></tr><tr><td>PAPUC</td><td>Pennsylvania Public Utility Commission</td></tr><tr><td>PCB</td><td>Polychlorinated Biphenyl</td></tr><tr><td>PGC</td><td>Purchased Gas Cost Clause</td></tr><tr><td>PG&amp;E</td><td>Pacific Gas and Electric Company</td></tr><tr><td>PJM</td><td>PJM Interconnection, LLC</td></tr><tr><td>POLR</td><td>Provider of Last Resort</td></tr><tr><td>POR</td><td>Purchase of Receivables</td></tr><tr><td>PPA</td><td>Power Purchase Agreement</td></tr><tr><td>Price-Anderson Act</td><td>Price-Anderson Nuclear Industries Indemnity Act of 1957</td></tr><tr><td>Preferred Stock</td><td>Originally issued shares of non-voting, non-convertible and non-transferable Series A preferred stock, par value $0.01 per share</td></tr></table>



GLOSSARY OF TERMS AND ABBREVIATIONS

<table><tr><td colspan="2">Other Terms and Abbreviations</td></tr><tr><td>PRP</td><td>Potentially Responsible Parties</td></tr><tr><td>PSEG</td><td>Public Service Enterprise Group Incorporated</td></tr><tr><td>PV</td><td>Photovoltaic</td></tr><tr><td>RCRA</td><td>Resource Conservation and Recovery Act of 1976, as amended</td></tr><tr><td>REC</td><td>Renewable Energy Credit which is issued for each megawatt hour of generation from a qualified renewable energy source</td></tr><tr><td>Regulatory Agreement Units</td><td>Nuclear generating units or portions thereof whose decommissioning-related activities are subject to contractual elimination under regulatory accounting</td></tr><tr><td>RES</td><td>Retail Electric Suppliers</td></tr><tr><td>RFP</td><td>Request for Proposal</td></tr><tr><td>Rider</td><td>Reconcilable Surcharge Recovery Mechanism</td></tr><tr><td>RGGI</td><td>Regional Greenhouse Gas Initiative</td></tr><tr><td>RMC</td><td>Risk Management Committee</td></tr><tr><td>RNF</td><td>Revenue Net of Purchased Power and Fuel Expense</td></tr><tr><td>ROE</td><td>Return on equity</td></tr><tr><td>ROU</td><td>Right-of-use</td></tr><tr><td>RPM</td><td>PJM Reliability Pricing Model</td></tr><tr><td>RPS</td><td>Renewable Energy Portfolio Standards</td></tr><tr><td>RSSA</td><td>Reliability Support Services Agreement</td></tr><tr><td>RTEP</td><td>Regional Transmission Expansion Plan</td></tr><tr><td>RTO</td><td>Regional Transmission Organization</td></tr><tr><td>S&amp;P</td><td>Standard &amp; Poor&#x27;s Ratings Services</td></tr><tr><td>SEC</td><td>United States Securities and Exchange Commission</td></tr><tr><td>SERC</td><td>SERC Reliability Corporation (formerly Southeast Electric Reliability Council)</td></tr><tr><td>SGIG</td><td>Smart Grid Investment Grant from DOE</td></tr><tr><td>SILO</td><td>Sale-In, Lease-Out</td></tr><tr><td>SNF</td><td>Spent Nuclear Fuel</td></tr><tr><td>SOS</td><td>Standard Offer Service</td></tr><tr><td>SPFPA</td><td>Security, Police and Fire Professionals of America</td></tr><tr><td>SPP</td><td>Southwest Power Pool</td></tr><tr><td>TCJA</td><td>Tax Cuts and Jobs Act</td></tr><tr><td>Transition Bond Charge</td><td>Revenue ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds and related taxes, expenses and fees</td></tr><tr><td>Transition Bonds</td><td>Transition Bonds issued by ACE Funding</td></tr><tr><td>Upstream</td><td>Natural gas and oil exploration and production activities</td></tr><tr><td>VIE</td><td>Variable Interest Entity</td></tr><tr><td>WECC</td><td>Western Electric Coordinating Council</td></tr><tr><td>ZEC</td><td>Zero Emission Credit</td></tr><tr><td>ZES</td><td>Zero Emission Standard</td></tr></table>



## FILING FORMAT

This combined Annual Report on Form 10-K is being filed separately by Exelon Corporation, Exelon Generation Company, LLC, Commonwealth Edison Company, PECO Energy Company, Baltimore Gas and Electric Company, Pepco Holdings LLC, Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company (Registrants). Information contained herein relating to any individual Registrant is filed by such Registrant on its own behalf. No Registrant makes any representation as to information relating to any 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. The factors that could cause actual results to differ materially from the forward-looking statements made by the Registrants include those factors discussed herein, including those factors discussed with respect to the Registrants discussed 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 18, Commitments and Contingencies; and (d) 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. None of the Registrants 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 the Registrants file electronically with the SEC. These documents are also available to the public from commercial document retrieval services and the Registrants' website at www.exeloncorp.com. Information contained on the Registrants' website shall not be deemed incorporated into, or to be a part of, this Report.



## PART I

## ITEM 1.

## General

## Corporate Structure and Business and Other Information

Exelon is a utility services holding company engaged in the generation, delivery and marketing of energy through Generation and the energy distribution and transmission businesses through ComEd, PECO, BGE, Pepco, DPL and ACE.

<table><tr><td>Name of Registrant</td><td>State/Jurisdiction and Year of Incorporation</td><td>Business</td><td>Service Territories</td></tr><tr><td>Exelon Generation Company, LLC</td><td>Pennsylvania (2000)</td><td>Generation, physical delivery and marketing of power across multiple geographical regions through its customer-facing business, Constellation, which sells electricity to both wholesale and retail customers. Generation also sells natural gas, renewable energy and other energy-related products and services.</td><td>Five reportable segments: Mid-Atlantic, Midwest, New York, ERCOT and Other Power Regions</td></tr><tr><td>Commonwealth Edison Company</td><td>Illinois (1913)</td><td>Purchase and regulated retail sale of electricity</td><td>Northern Illinois, including the City of Chicago</td></tr><tr><td></td><td></td><td>Transmission and distribution of electricity to retail customers</td><td></td></tr><tr><td>PECO Energy Company</td><td>Pennsylvania (1929)</td><td>Purchase and regulated retail sale of electricity and natural gas</td><td>Southeastem Pennsylvania, including the City of Philadelphia (electricity)</td></tr><tr><td></td><td></td><td>Transmission and distribution of electricity and distribution of natural gas to retail customers</td><td>Pennsylvania counties surrounding the City of Philadelphia (natural gas)</td></tr><tr><td>Baltimore Gas and Electric Company</td><td>Maryland (1906)</td><td>Purchase and regulated retail sale of electricity and natural gas</td><td>Central Maryland, including the City of Baltimore (electricity and natural gas)</td></tr><tr><td></td><td></td><td>Transmission and distribution of electricity and distribution of natural gas to retail customers</td><td></td></tr><tr><td>Pepco Holdings LLC</td><td>Delaware (2016)</td><td>Utility services holding company engaged, through its reportable segments Pepco, DPL and ACE</td><td>Service Territories of Pepco, DPL and ACE</td></tr><tr><td>Potomac Electric Power Company</td><td>District of Columbia (1896) Virginia (1949)</td><td>Purchase and regulated retail sale of electricity</td><td>District of Columbia and Major portions of Montgomery and Prince George&#x27;s Counties, Maryland</td></tr><tr><td></td><td></td><td>Transmission and distribution of electricity to retail customers</td><td></td></tr><tr><td>Delmarva Power &amp; Light Company</td><td>Delaware (1909) Virginia (1979)</td><td>Purchase and regulated retail sale of electricity and natural gas</td><td>Portions of Delaware and Maryland (electricity)</td></tr><tr><td></td><td></td><td>Transmission and distribution of electricity and distribution of natural gas to retail customers</td><td>Portions of New Castle County, Delaware (natural gas)</td></tr><tr><td>Atlantic City Electric Company</td><td>New Jersey (1924)</td><td>Purchase and regulated retail sale of electricity</td><td>Portions of Southern New Jersey</td></tr><tr><td></td><td></td><td>Transmission and distribution of electricity to retail customers</td><td></td></tr></table>

## Business Services

Through its business services subsidiary, BSC, Exelon provides its subsidiaries with a variety of support services at cost, including legal, human resources, financial, information technology and supply management services. PHI also has a business services subsidiary, PHISCO, which provides a variety of support services at cost, including legal, accounting, engineering, customer operations, distribution and transmission planning, asset management, system operations, and power procurement, to PHI operating companies. The costs of BSC and PHISCO are directly charged or allocated to the applicable subsidiaries. The results of Exelon's corporate operations are presented as



“Other” within the consolidated financial statements and include intercompany eliminations unless otherwise disclosed.

## Merger with Pepco Holdings, Inc. (Exelon)

On March 23, 2016, Exelon completed the merger contemplated by the Merger Agreement among Exelon, Purple Acquisition Corp., a wholly owned subsidiary of Exelon (Merger Sub) and PHI. As a result of that merger, Merger Sub was merged into PHI (the PHI Merger) with PHI surviving as a wholly owned subsidiary of Exelon and EEDC, a wholly owned subsidiary of Exelon which also owns Exelon's interests in ComEd, PECO and BGE (through a special purpose subsidiary in the case of BGE). Following the completion of the PHI Merger, Exelon and PHI completed a series of internal corporate organization restructuring transactions resulting in the transfer of PHI's unregulated business interests to Exelon and Generation and the transfer of PHI, Pepco, DPL and ACE to a special purpose subsidiary of EEDC.

## Generation

Generation, one of the largest competitive electric generation companies in the United States as measured by owned and contracted MW, physically delivers and markets power across multiple geographic regions through its customer-facing business, Constellation. Constellation sells electricity and natural gas, including renewable energy, in competitive energy markets to both wholesale and retail customers. Generation leverages its energy generation portfolio to ensure delivery of energy to both wholesale and retail customers under long-term and short-term contracts, and in wholesale power markets. Generation operates in well-developed energy markets and employs an integrated hedging strategy to manage commodity price volatility. Generation's fleet also provides geographic and supply source diversity. Generation's customers include distribution utilities, municipalities, cooperatives, financial institutions, and commercial, industrial, governmental, and residential customers in competitive markets. Generation's customer-facing activities foster development and delivery of other innovative energy-related products and services for its customers.

Generation is a public utility under the Federal Power Act and is subject to FERC’s exclusive ratemaking jurisdiction over wholesale sales of electricity and the transmission of electricity in interstate commerce. Under the Federal Power Act, FERC has the authority to grant or deny market-based rates for sales of energy, capacity and ancillary services to ensure that such sales are just and reasonable. FERC’s jurisdiction over ratemaking includes the authority to suspend the market-based rates of utilities and set cost-based rates should FERC find that its previous grant of market-based rates authority is no longer just and reasonable. Other matters subject to FERC jurisdiction include, but are not limited to, third-party financings; review of mergers; dispositions of jurisdictional facilities and acquisitions of securities of another public utility or an existing operational generating facility; affiliate transactions; intercompany financings and cash management arrangements; certain internal corporate reorganizations; and certain holding company acquisitions of public utility and holding company securities.

RTOs and ISOs exist in a number of regions to provide transmission service across multiple transmission systems. FERC has approved PJM, MISO, ISO-NE and SPP as RTOs and CAISO and NYISO as ISOs. These entities are responsible for regional planning, managing transmission congestion, developing wholesale markets for energy and capacity, maintaining reliability, market monitoring, the scheduling of physical power sales brokered through ICE and NYMEX and the elimination or reduction of redundant transmission charges imposed by multiple transmission providers when wholesale customers take transmission service across several transmission systems. ERCOT is not subject to regulation by FERC but performs a similar function in Texas to that performed by RTOs in markets regulated by FERC.

Specific operations of Generation are also subject to the jurisdiction of various other Federal, state, regional and local agencies, including the NRC and Federal and state environmental protection agencies. Additionally, Generation is subject to NERC mandatory reliability standards, which protect the nation's bulk power system against potential disruptions from cyber and physical security breaches.

## Acquisitions and Dispositions

Disposition of Oyster Creek. On July 1, 2019, Generation completed the sale with Holtec International (Holtec) and its indirect wholly owned subsidiary, Oyster Creek Environmental Protection, LLC (OCEP), of Oyster Creek located in Forked River, New Jersey, which permanently ceased generation operations on September 17, 2018.



Disposition of EGTP and Acquisition of Handley Generating Station. On November 7, 2017, EGTP and all of its wholly owned subsidiaries filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Code in the United States Bankruptcy Court for the District of Delaware. As a result of the bankruptcy filing, EGTP's assets and liabilities were deconsolidated from Exelon and Generation's consolidated financial statements. The Chapter 11 bankruptcy proceedings were finalized on April 17, 2018, resulting in the ownership of EGTP assets (other than the Handley Generating Station) being transferred to EGTP's lenders.

On April 4, 2018, Generation acquired the Handley Generating Station in conjunction with the EGTP Chapter 11 proceedings for a total purchase price of $62 million.

Acquisition of FitzPatrick. On March 31, 2017, Generation acquired the single-unit FitzPatrick plant located in Scriba, New York from Entergy for a total purchase price consideration of $289 million, resulting in an after-tax bargain purchase gain of $233 million in 2017.

Acquisition of ConEdison Solutions. On September 1, 2016, Generation acquired ConEdison Solutions for a purchase price of $257 million, including net working capital of $204 million. The renewable energy, sustainable services and energy efficiency businesses of ConEdison were excluded from the transaction.

See Note 2 — Mergers, Acquisitions and Dispositions and Note 11 — Asset Impairments of the Combined Notes to Consolidated Financial Statements for additional information on acquisitions and dispositions.

## Generating Resources

At December 31, 2019, the generating resources of Generation consisted of the following:

<table><tr><td>Type of Capacity</td><td>MW</td></tr><tr><td>Owned generation assets \( ^{(a)(b)} \)</td><td></td></tr><tr><td>Nuclear</td><td>18,872</td></tr><tr><td>Fossil (primarily natural gas and oil)</td><td>9,665</td></tr><tr><td>Renewable \( ^{(c)} \)</td><td>3,057</td></tr><tr><td>Owned generation assets</td><td>31,594</td></tr><tr><td>Contracted generation \( ^{(d)} \)</td><td>4,765</td></tr><tr><td>Total generating resources</td><td>36,359</td></tr></table>

(a) See “Fuel” for sources of fuels used in electric generation.

(b) Net generation capacity is stated at proportionate ownership share. See ITEM 2. PROPERTIES—Generation for additional information.

(c) Includes wind, hydroelectric, solar and biomass generation.

(d) Electric supply procured under site specific agreements.

Generation has five reportable segments, as described in the table below, representing the different geographical areas in which Generation’s generating resources are located and Generation’s customer-facing activities are conducted.

<table><tr><td>Segment</td><td>% of Capacity</td><td>Geographical Area</td></tr><tr><td></td><td></td><td>Eastern half of PJM, which includes Pennsylvania, New Jersey, Maryland, Virginia, West Virginia,</td></tr><tr><td>Mid-Atlantic</td><td>32%</td><td>Delaware, the District of Columbia and parts of North Carolina</td></tr><tr><td>Midwest</td><td>38%</td><td>Western half of PJM and the United States footprint of MISO, excluding MISO&#x27;s Southern Region</td></tr><tr><td>New York</td><td>6%</td><td>NYISO</td></tr><tr><td>ERCOT</td><td>11%</td><td>Electric Reliability Council of Texas</td></tr><tr><td>Other Power Regions</td><td>13%</td><td>New England, South, West and Canada</td></tr></table>



## Nuclear Facilities

Generation has ownership interests in thirteen nuclear generating stations currently in service, consisting of 23 units with an aggregate of 18,872 MW of capacity. Generation wholly owns all of its nuclear generating stations, except for undivided ownership interests in three jointly-owned nuclear stations: Quad Cities (75% ownership), Peach Bottom (50% ownership), and Salem (42.59% ownership), which are consolidated in Exelon's and Generation's financial statements relative to its proportionate ownership interest in each unit, and a 50.01% membership interest in CENG, a joint venture with EDF, which wholly owns the Calvert Cliffs and Ginna nuclear stations and Nine Mile Point Unit 1, in addition to an 82% undivided ownership interest in Nine Mile Point Unit 2. CENG is 100% consolidated in Exelon's and Generation's financial statements.

Generation and EDF entered into a Put Option Agreement on April 1, 2014, pursuant to which EDF has an option to sell its 49.99% equity interest in CENG to Generation. The put option became exercisable on January 1, 2016 and may be exercised any time until June 30, 2022. On November 20, 2019, Generation received notice of EDF's intention to exercise the put option and sell its ownership share in CENG to Generation. Under the terms of the Put Option Agreement, the purchase price is to be determined by agreement of the parties, or absent such agreement, by a third-party arbitration process. The transaction will require approval of the NYPSC, the FERC and the NRC. The process and regulatory approvals could take one to two years or more to complete.

See ITEM 2. PROPERTIES for additional information on Generation's nuclear facilities and Note 22 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for additional information regarding the CENG consolidation.

Generation’s nuclear generating stations are all operated by Generation, with the exception of the two units at Salem, which are operated by PSEG Nuclear, LLC (PSEG Nuclear), an indirect, wholly owned subsidiary of PSEG. In 2019, 2018 and 2017 electric supply (in GWh) generated from the nuclear generating facilities was 64%, 68% and 69%, respectively, of Generation’s total electric supply, which also includes fossil, hydroelectric and renewable generation and electric supply purchased for resale. Generation’s wholesale and retail power marketing activities are, in part, supplied by the output from the nuclear generating stations. See ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for additional information of Generation’s electric supply sources.

## Nuclear Operations

Capacity factors, which are significantly affected by the number and duration of refueling and non-refueling outages, can have a significant impact on Generation’s results of operations. Generation’s operations from its nuclear plants have historically had minimal environmental impact and the plants have a safe operating history.

During 2019, 2018 and 2017, the nuclear generating facilities operated by Generation achieved capacity factors of 95.7%, 94.6% and 94.1%, respectively. The capacity factors reflect ownership percentage of stations operated by Generation. Generation manages its scheduled refueling outages to minimize their duration and to maintain high nuclear generating capacity factors, resulting in a stable generation base for Generation's wholesale and retail power marketing activities. During scheduled refueling outages, Generation performs maintenance and equipment upgrades in order to minimize the occurrence of unplanned outages and to maintain safe, reliable operations.

In addition to the maintenance and equipment upgrades performed by Generation during scheduled refueling outages, Generation has extensive operating and security procedures in place to ensure the safe operation of the nuclear units. Generation also has extensive safety systems in place to protect the plant, personnel and surrounding area in the unlikely event of an accident or other incident.

## Regulation of Nuclear Power Generation

Generation is subject to the jurisdiction of the NRC with respect to the operation of its nuclear generating stations, including the licensing for operation of each unit. The NRC subjects nuclear generating stations to continuing review and regulation covering, among other things, operations, maintenance, emergency planning, security and environmental and radiological aspects of those stations. As part of its reactor oversight process, the NRC continuously assesses unit performance indicators and inspection results and communicates its assessment on a semi-annual basis. All nuclear generating stations operated by Generation are categorized by the NRC in the Licensee Response Column, which is the highest of five performance bands. The NRC may modify, suspend or revoke operating licenses and impose civil penalties for failure to comply with the Atomic Energy Act, the regulations.



under such Act or the terms of the operating licenses. Changes in regulations by the NRC may require a substantial increase in capital expenditures and/or operating costs for nuclear generating facilities.

## Licenses

Generation has original 40-year operating licenses from the NRC for each of its nuclear units and has received 20-year operating license renewals from the NRC for all its nuclear units except Clinton. Additionally, PSEG has received 20-year operating license renewals for Salem Units 1 and 2.

The following table summarizes the current license expiration dates for Generation’s operating nuclear facilities in service:

<table><tr><td>Station</td><td>Unit</td><td>In-Service Date(a)</td><td>Current License Expiration</td></tr><tr><td rowspan="2">Braidwood</td><td>1</td><td>1988</td><td>2046</td></tr><tr><td>2</td><td>1988</td><td>2047</td></tr><tr><td rowspan="2">Byron</td><td>1</td><td>1985</td><td>2044</td></tr><tr><td>2</td><td>1987</td><td>2046</td></tr><tr><td rowspan="2">Calvert Cliffs</td><td>1</td><td>1975</td><td>2034</td></tr><tr><td>2</td><td>1977</td><td>2036</td></tr><tr><td>Clinton(b)</td><td>1</td><td>1987</td><td>2027</td></tr><tr><td rowspan="2">Dresden</td><td>2</td><td>1970</td><td>2029</td></tr><tr><td>3</td><td>1971</td><td>2031</td></tr><tr><td>FitzPatrick</td><td>1</td><td>1974</td><td>2034</td></tr><tr><td rowspan="2">LaSalle</td><td>1</td><td>1984</td><td>2042</td></tr><tr><td>2</td><td>1984</td><td>2043</td></tr><tr><td rowspan="2">Limerick</td><td>1</td><td>1986</td><td>2044</td></tr><tr><td>2</td><td>1990</td><td>2049</td></tr><tr><td rowspan="2">Nine Mile Point</td><td>1</td><td>1969</td><td>2029</td></tr><tr><td>2</td><td>1988</td><td>2046</td></tr><tr><td rowspan="2">Peach Bottom(c)</td><td>2</td><td>1974</td><td>2033</td></tr><tr><td>3</td><td>1974</td><td>2034</td></tr><tr><td rowspan="2">Quad Cities</td><td>1</td><td>1973</td><td>2032</td></tr><tr><td>2</td><td>1973</td><td>2032</td></tr><tr><td>Ginna</td><td>1</td><td>1970</td><td>2029</td></tr><tr><td rowspan="2">Salem</td><td>1</td><td>1977</td><td>2036</td></tr><tr><td>2</td><td>1981</td><td>2040</td></tr></table>

(a) Denotes year in which nuclear unit began commercial operations.

(b) Although timing has been delayed, Generation currently plans to seek license renewal for Clinton and has notified the NRC that any license renewal application would not be filed until the first quarter of 2024. In 2019, the NRC approved a change of the operating license expiration for Clinton from 2026 to 2027.

(c) On July 10, 2018, Generation submitted a second 20-year license renewal application to NRC for Peach Bottom Units 2 and 3. See Note 3 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

The operating license renewal process takes approximately four to five years from the commencement of the renewal process, which includes approximately two years for Generation to develop the application and approximately two years for the NRC to review the application. To date, each granted license renewal has been for 20 years beyond the original operating license expiration. Depreciation provisions are based on the estimated useful lives of the stations, which reflect the first renewal of the operating licenses for all of Generation's operating nuclear generating stations except for Clinton and Peach Bottom. Clinton depreciation provisions are based on an estimated useful life of 2027 which is the last year of the Illinois ZES. Peach Bottom depreciation provisions are based on estimated



useful life of 2053 and 2054 for Unit 2 and Unit 3, respectively, which reflects the anticipated second renewal of its operating licenses. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on FEJA and Note 6 — Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information on early retirements.

## Nuclear Waste Storage and Disposal

There are no facilities for the reprocessing or permanent disposal of SNF currently in operation in the United States, nor has the NRC licensed any such facilities. Generation currently stores all SNF generated by its nuclear generating facilities on-site in storage pools or in dry cask storage facilities. Since Generation's SNF storage pools generally do not have sufficient storage capacity for the life of the respective plant, Generation has developed dry cask storage facilities to support operations.

As of December 31, 2019, Generation had approximately 84,700 SNF assemblies (21,000 tons) stored on site in SNF pools or dry cask storage which includes SNF assemblies at Zion Station, for which Generation retains ownership even through the responsibility for decommissioning Zion Station has been assumed by another party, and TMI, which is no longer operational. See the Decommissioning section below for additional information regarding Zion Station. All currently operating Generation-owned nuclear sites have on-site dry cask storage. TMI's on-site dry cask storage is projected to be in operation in 2021. On-site dry cask storage in concert with on-site storage pools will be capable of meeting all current and future SNF storage requirements at Generation's sites through the end of the license renewal periods and through decommissioning.

For a discussion of matters associated with Generation’s contracts with the DOE for the disposal of SNF, see Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements.

As a by-product of their operations, nuclear generating units produce LLRW. LLRW is accumulated at each generating station and permanently disposed of at licensed disposal facilities. The Federal Low-Level Radioactive Waste Policy Act of 1980 provides that states may enter into agreements to provide regional disposal facilities for LLRW and restrict use of those facilities to waste generated within the region. Illinois and Kentucky have entered into such an agreement, although neither state currently has an operational site and none is anticipated to be operational until after 2020.

Generation ships its Class A LLRW, which represents 93% of LLRW generated at its stations, to disposal facilities in Utah and South Carolina, which have enough storage capacity to store all Class A LLRW for the life of all stations in Generation's nuclear fleet. The disposal facility in South Carolina at present is only receiving LLRW from LLRW generators in South Carolina, New Jersey (which includes Salem) and Connecticut.

Generation utilizes on-site storage capacity at all its stations to store and stage for shipping Class B and Class C LLRW. Generation has a contract through 2032 to ship Class B and Class C LLRW to a disposal facility in Texas. The agreement provides for disposal of all current Class B and Class C LLRW currently stored at each station as well as the Class B and Class C LLRW generated during the term of the agreement. However, because the production of LLRW from Generation's nuclear fleet will exceed the capacity at the Texas site (3.9 million curves for 15 years beginning in 2012), Generation will still be required to utilize on-site storage at its stations for Class B and Class C LLRW. Generation currently has enough storage capacity to store all Class B and Class C LLRW for the life of all stations in Generation's nuclear fleet. Generation continues to pursue alternative disposal strategies for LLRW, including an LLRW reduction program to minimize on-site storage and cost impacts.

## Nuclear Insurance

Generation is subject to liability, property damage and other risks associated with major incidents at all of its nuclear stations. Generation has reduced its financial exposure to these risks through insurance and other industry risk-sharing provisions. See “Nuclear Insurance” within Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.

For information regarding property insurance, see ITEM 2. PROPERTIES — Generation. Generation is self-insured to the extent that any losses may exceed the amount of insurance maintained or are within the policy deductible for its insured losses. Such losses could have a material adverse effect on Exelon's and Generation's future financial statements.



## Decommissioning

NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts at the end of the life of the facility to decommission the facility. The ultimate decommissioning obligation will be funded by the NDTs. At December 31, 2019 the fair value of NDTs exceeds the balance of the Nuclear AROs. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Exelon Corporation, Executive Overview; ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OFOPERATIONS, Critical Accounting Policies and Estimates, Nuclear Decommissioning, Asset Retirement Obligations and Nuclear Decommissioning Trust Fund Investments; and Note 3 — Regulatory Matters, Note 2 — Mergers, Acquisitions and Dispositions, Note 17 — Fair Value of Financial Assets and Liabilities and Note 9 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information regarding Generation's NDT funds and its decommissioning obligations.

Zion Station Decommissioning. On September 1, 2010, Generation completed an Asset Sale Agreement (ASA) with EnergySolutions, Inc. and its wholly owned subsidiaries, EnergySolutions, LLC and ZionSolutions under which ZionSolutions has assumed responsibility for decommissioning Zion Station. See Note 9 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information.

## Fossil and Renewable Facilities (including Hydroelectric)

Generation wholly owns all of its fossil and renewable generating stations, with the exception of: (1) Wyman; (2) certain wind project entities and a biomass project entity with minority interest owners; and (3) EGRP which is owned 49% by another owner. See Note 22 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for additional information regarding EGRP which is a VIE. Generation's fossil and renewable generating stations are all operated by Generation, with the exception of Wyman, which is operated by a third party. In 2019, 2018 and 2017, electric supply (in GWh) generated from owned fossil and renewable generating facilities was 11%, 11% and 12%, respectively, of Generation's total electric supply. The majority of this output was dispatched to support Generation's wholesale and retail power marketing activities. For additional information regarding Generation's electric generating facilities, see ITEM 2. PROPERTIES.

## Licenses

Fossil and renewable generation plants are generally not licensed, and, therefore, the decision on when to retire plants is, fundamentally, a commercial one. FERC has the exclusive authority to license most non-Federal hydropower projects located on navigable waterways or Federal lands, or connected to the interstate electric grid, which include Generation's Conowingo Hydroelectric Project (Conowingo) and Muddy Run Pumped Storage Facility Project (Muddy Run). Muddy Run's license expires on December 1, 2055. On August 29, 2012, Generation submitted a hydroelectric license application to the FERC for a new license for Conowingo. Based on the FERC procedural schedule, the FERC licensing process for Conowingo was not completed prior to the expiration of the plant's license on September 1, 2014. As a result, on September 10, 2014, FERC issued an annual license for Conowingo, effective as of the expiration of the previous license. The annual license renews automatically absent any further FERC action. The stations are currently being depreciated over their estimated useful lives, which include actual and anticipated license renewal periods. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

## Insurance

Generation maintains business interruption insurance for its renewable projects, but not for its fossil and hydroelectric operations unless required by contract or financing agreements. See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on financing agreements. Generation maintains both property damage and liability insurance. For property damage and liability claims for these operations, Generation is self-insured to the extent that losses are within the policy deductible or exceed the amount of insurance maintained. Such losses could have a material adverse effect on Exelon's and Generation's future financial conditions and their results of operations and cash flows. For information regarding property insurance, see ITEM 2. PROPERTIES — Exelon Generation Company, LLC.



## Contracted Generation

In addition to energy produced by owned generation assets, Generation sources electricity from plants it does not own under long-term contracts. The following tables summarize Generation's long-term contracts to purchase unit-specific physical power with an original term in excess of one year in duration, by region, in effect as of December 31, 2019:

<table><tr><td>Region</td><td>Number of Agreements</td><td>Expiration Dates</td><td>Capacity (MW)</td></tr><tr><td>Mid-Atlantic</td><td>13</td><td>2020 - 2032</td><td>235</td></tr><tr><td>Midwest</td><td>3</td><td>2020 - 2031</td><td>332</td></tr><tr><td>ERCOT</td><td>6</td><td>2020 - 2035</td><td>1,706</td></tr><tr><td>Other Power Regions</td><td>16</td><td>2020 - 2030</td><td>2,492</td></tr><tr><td>Total</td><td>38</td><td></td><td>4,765</td></tr></table>

<table><tr><td>Capacity Expiring (MW)</td><td>2020</td><td>2021</td><td>2022</td><td>2023</td><td>2024</td><td>Thereafter</td><td>Total</td></tr><tr><td>Capacity Expiring (MW)</td><td>1,054</td><td>814</td><td>304</td><td>168</td><td>50</td><td>2,375</td><td>4,765</td></tr></table>

## Fuel

The following table shows sources of electric supply in GWh for 2019 and 2018:

<table><tr><td rowspan="2"></td><td colspan="2">Source of Electric Supply</td></tr><tr><td>2019</td><td>2018</td></tr><tr><td>Nuclear \( ^{(a)} \)</td><td>181,326</td><td>185,020</td></tr><tr><td>Purchases — non-trading portfolio</td><td>70,939</td><td>59,154</td></tr><tr><td>Fossil (primarily natural gas and oil)</td><td>21,554</td><td>21,015</td></tr><tr><td>Renewable \( ^{(b)} \)</td><td>7,777</td><td>8,469</td></tr><tr><td>Total supply</td><td>281,596</td><td>273,658</td></tr></table>

(a) Includes the proportionate share of output where Generation has an undivided ownership interest in jointly-owned generating plants and includes the total output of plants that are fully consolidated (e.g., CENG). Nuclear generation for 2019 and 2018 includes physical volumes of 35,745 GWh and 35,100 GWh, respectively, for CENG.
(b) Includes wind, hydroelectric, solar and biomass generating assets.

The cycle of production and utilization of nuclear fuel includes the mining and milling of uranium ore into uranium concentrates, the conversion of uranium concentrates to uranium hexafluoride, the enrichment of the uranium hexafluoride and the fabrication of fuel assemblies. Generation has inventory in various forms and does not anticipate difficulty in obtaining the necessary uranium concentrates or conversion, enrichment or fabrication services to meet the nuclear fuel requirements of its nuclear units.

Natural gas is procured through long-term and short-term contracts, as well as spot-market purchases. Fuel oil inventories are managed so that in the winter months sufficient volumes of fuel are available in the event of extreme weather conditions and during the remaining months to take advantage of favorable market pricing.

Generation uses financial instruments to mitigate price risk associated with certain commodity price exposures, using both over-the-counter and exchange-traded instruments. See ITEM 1A. RISK FACTORS, ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Critical Accounting Policies and Estimates and Note 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding derivative financial instruments.

## Power Marketing

Generation’s integrated business operations include physical delivery and marketing of power. Generation largely obtains physical power supply from its owned and contracted generation in multiple geographic regions. The



commodity risks associated with the output from owned and contracted generation is managed using various commodity transactions including sales to customers. The main objective is to obtain low-cost energy supply to meet physical delivery obligations to both wholesale and retail customers. Generation sells electricity, natural gas and other energy related products and solutions to various customers, including distribution utilities, municipalities, cooperatives, and commercial, industrial, governmental and residential customers in competitive markets. Where necessary, Generation may also purchase transmission service to ensure that it has reliable transmission capacity to physically move its power supplies to meet customer delivery needs.

## Price and Supply Risk Management

Generation also manages the price and supply risks for energy and fuel associated with generation assets and the risks of power marketing activities. Generation implements a three-year ratable sales plan to align its hedging strategy with its financial objectives. Generation may also enter into transactions that are outside of this ratable sales plan. Generation is exposed to commodity price risk in 2020 and beyond for portions of its electricity portfolio that are unhedged. As of December 31, 2019, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York and ERCOT reportable segments is 91%-94% and 61%-64% for 2020 and 2021, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted generation based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products and options. Equivalent sales represent all hedging products, which include economic hedges and certain non-derivative contracts, including sales to the Utility Registrants to serve their retail load. A portion of Generation's hedging strategy may be implemented through the use of fuel products based on assumed correlations between power and fuel prices. The risk management group and Exelon's RMC monitor the financial risks of the wholesale and retail power marketing activities. Generation also uses financial and commodity contracts for proprietary trading purposes, but this activity accounts for only a small portion of Generation's efforts. The proprietary trading portfolio is subject to a risk management policy that includes stringent risk management limits. See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for additional information.

## Capital Expenditures

Generation’s business is capital intensive and requires significant investments primarily in nuclear fuel and energy generation assets. Generation’s estimated capital expenditures for 2020 includes Generation’s share of the investment in the co-owned Salem plant and the total capital expenditures for CENG. See ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Liquidity and Capital Resources, for additional information regarding projected 2020 capital expenditures.



## Utility Registrants

## Utility Operations

## Service Territories and Franchise Agreements

The following table presents the size of service territories, populations of each service territory and the number of customers within each service territory for the Utility Registrants as of December 31, 2019:

<table><tr><td></td><td>ComEd</td><td>PECO</td><td>BGE</td><td>Pepco</td><td>DPL</td><td>ACE</td></tr><tr><td>Service Territories (in square miles)</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Electric</td><td>11,400</td><td>2,100</td><td>2,300</td><td>640</td><td>5,400</td><td>2,800</td></tr><tr><td>Natural Gas</td><td>n/a</td><td>1,960</td><td>3,050</td><td>n/a</td><td>270</td><td>n/a</td></tr><tr><td>Total</td><td>11,400</td><td>2,100</td><td>3,250</td><td>640</td><td>5,400</td><td>2,800</td></tr></table>

<table><tr><td>Electric</td><td>9.6</td><td>4.0</td><td>3.0</td><td>2.4</td><td>1.5</td><td>1.1</td></tr><tr><td>Natural Gas</td><td>n/a</td><td>2.5</td><td>2.9</td><td>n/a</td><td>0.6</td><td>n/a</td></tr><tr><td>Total</td><td>9.6</td><td>4.0</td><td>3.1</td><td>2.4</td><td>1.5</td><td>1.1</td></tr></table>

<table><tr><td>Main City</td><td>Chicago</td><td>Philadelphia</td><td>Baltimore</td><td>District of Columbia</td><td>Wilmington</td><td>Atlantic City</td></tr><tr><td>Main City Population</td><td>2.7</td><td>1.6</td><td>0.6</td><td>0.7</td><td>0.1</td><td>0.1</td></tr></table>

<table><tr><td>Number of Customers (in millions)</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Electric</td><td>4.1</td><td>1.7</td><td>1.3</td><td>0.9</td><td>0.5</td></tr><tr><td>Natural Gas</td><td>n/a</td><td>0.5</td><td>0.7</td><td>n/a</td><td>0.1</td></tr><tr><td>Total</td><td>4.1</td><td>1.7</td><td>1.3</td><td>0.9</td><td>0.5</td></tr></table>

The Utility Registrants have the necessary authorizations to perform their current business of providing regulated electric and natural gas distribution services in the various municipalities and territories in which they now supply such services. These authorizations include charters, franchises, permits, and certificates of public convenience issued by local and state governments and state utility commissions. ComEd's, BGE's (gas), Pepco DC's and ACE's rights are generally non-exclusive while PECO's, BGE's (electric), Pepco MD's and DPL's rights are generally exclusive. Certain authorizations are perpetual while others have varying expiration dates. The Utility Registrants anticipate working with the appropriate governmental bodies to extend or replace the authorizations prior to their expirations.

## Utility Regulations

State utility commissions regulate the Utility Registrants' electric and gas distribution rates and service, issuances of certain securities, and certain other aspects of the business. The following table outlines the state commissions responsible for utility oversight.

<table><tr><td>Registrant</td><td>Commission</td></tr><tr><td>ComEd</td><td>ICC</td></tr><tr><td>PECO</td><td>PAPUC</td></tr><tr><td>BGE</td><td>MDPSC</td></tr><tr><td>Pepco</td><td>DCPSC/MDPSC</td></tr><tr><td>DPL</td><td>DPSC/MDPSC</td></tr><tr><td>ACE</td><td>NJBPU</td></tr></table>



The Utility Registrants are public utilities under the Federal Power Act subject to regulation by FERC related to transmission rates and certain other aspects of the utilities' business. The U.S. Department of Transportation also regulates pipeline safety and other areas of gas operations for PECO, BGE and DPL. Additionally, the Utility Registrants are subject to NERC mandatory reliability standards, which protect the nation's bulk power system against potential disruptions from cyber and physical security breaches.

## Seasonality Impacts on Delivery Volumes

The Utility Registrants' electric distribution volumes are generally higher during the summer and winter months when temperature extremes create demand for either summer cooling or winter heating. For PECO, BGE and DPL, natural gas distribution volumes are generally higher during the winter months when cold temperatures create demand for winter heating.

ComEd, BGE, Pepco and DPL Maryland have electric distribution decoupling mechanisms and BGE has a natural gas decoupling mechanism that eliminate the favorable and unfavorable impacts of weather and customer usage patterns on electric distribution and natural gas delivery volumes. As a result, ComEd's, BGE's, Pepco's and DPL's Maryland electric distribution revenues and BGE's natural gas distribution revenues are not materially impacted by delivery volumes. PECO's electric distribution revenues and natural gas distribution revenues, ACE's electric distribution revenues and DPL's Delaware electric distribution and natural gas revenues are impacted by delivery volumes.

## Electric and Natural Gas Distribution Services

The Utility Registrants are allowed to recover reasonable costs and fair and prudent capital expenditures associated with electric and natural gas distribution services and earn a return on those capital expenditures, subject to commission approval. ComEd recovers costs through a performance-based rate formula. ComEd is required to file an update to the performance-based rate formula on an annual basis. PECO's, BGE's and DPL's electric and gas distribution costs and Pepco's and ACE's electric distribution costs are recovered through traditional rate case proceedings. In certain instances, the Utility Registrants use specific recovery mechanisms as approved by their respective regulatory agencies.

ComEd, Pepco and ACE customers have the choice to purchase electricity, and PECO, BGE and DPL customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers. The Utility Registrants remain the distribution service providers for all customers and are obligated to deliver electricity and natural gas to customers in their respective service territories while charging a regulated rate for distribution service. In addition, the Utility Registrants also retain significant default service obligations to provide electricity to certain groups of customers in their respective service areas who do not choose a competitive electric generation supplier. PECO and BGE also retain significant default service obligations to provide natural gas to certain groups of customers in their respective service areas who do not choose a competitive natural gas supplier. For natural gas, DPL does not retain default service obligations for its residential customers.

For customers that choose to purchase electric generation or natural gas from competitive suppliers, the Utility Registrants act as the billing agent and therefore do not record Operating revenues or Purchased power and fuel expense related to the electricity and/or natural gas. For customers that choose to purchase electric generation or natural gas from a Utility Registrant, the Utility Registrants are permitted to recover the electricity and natural gas procurement costs without mark-up and therefore record equal and offsetting amounts of Operating revenues and Purchased power and fuel expense related to the electricity and/or natural gas. As a result, fluctuations in electricity or natural gas sales and procurement costs have no impact on the Utility Registrants' Revenues net of purchased power and fuel expense, which is a non-GAAP measure used to evaluate operational performance, or Net Income.

See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Results of Operations and Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding electric and natural gas distribution services.

## Procurement-Related Proceedings

The Utility Registrants' electric supply for its customers is primarily procured through contracts as required by their respective state commissions. The Utility Registrants procure electricity supply from various approved bidders, including Generation. RTO spot market purchases and sales are utilized to balance the utility electric load and



supply as required. Charges incurred for electric supply procured through contracts with Generation are included in Purchased power from affiliates on the Utility Registrants' Statements of Operations and Comprehensive Income.

PECO's, BGE's and DPL's natural gas supplies are purchased from a number of suppliers for terms of up to three years. PECO, BGE and DPL have annual firm supply and transportation contracts of 132,000 mmcf, 129,000 mmcf and 58,000 mmcf, respectively. In addition, to supplement gas supply at times of heavy winter demands and in the event of temporary emergencies, PECO, BGE and DPL have available storage capacity from the following sources:

<table><tr><td rowspan="2"></td><td colspan="3">Peak Natural Gas Sources (in mmcf)</td></tr><tr><td>Liquefied Natural Gas Facility</td><td>Propane-Air Plant</td><td>Underground Storage Service Agreements (a)</td></tr><tr><td>PECO</td><td>1,200</td><td>150</td><td>18,000</td></tr><tr><td>BGE</td><td>1,056</td><td>550</td><td>22,000</td></tr><tr><td>DPL</td><td>250</td><td>n/a</td><td>3,900</td></tr></table>

(a) Natural gas from underground storage represents approximately 28%, 42% and 30% of PECO's, BGE's and DPL's 2019-2020 heating season planned supplies, respectively.

PECO, BGE and DPL have long-term interstate pipeline contracts and also participate in the interstate markets by releasing pipeline capacity or bundling pipeline capacity with gas for off-system sales. Off-system gas sales are low-margin direct sales of gas to wholesale suppliers of natural gas. Earnings from these activities are shared between the utilities and customers. PECO, BGE and DPL make these sales as part of a program to balance its supply and cost of natural gas. The off-system gas sales are not material to PECO, BGE and DPL.

See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK, Commodity Price Risk (All Registrants), for additional information regarding Utility Registrants' contracts to procure electric supply and natural gas.

## Energy Efficiency Programs

The Utility Registrants are generally allowed to recover costs associated with the energy efficiency and demand response programs they offer. Each commission approved program seeks to meet mandated electric consumption reduction targets and implement demand response measures to reduce peak demand. The programs are designed to meet standards required by each respective regulatory agency.

ComEd is allowed to earn a return on its energy efficiency costs. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

## Capital Investment

The Utility Registrants' businesses are capital intensive and require significant investments, primarily in electric transmission and distribution and natural gas transportation and distribution facilities, to ensure the adequate capacity, reliability and efficiency of their systems. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Liquidity and Capital Resources, for additional information regarding projected 2020 capital expenditures.

## Transmission Services

Under FERC’s open access transmission policy, the Utility Registrants, as owners of transmission facilities, are required to provide open access to their transmission facilities under filed tariffs at cost-based rates approved by FERC. The Utility Registrants and their affiliates are required to comply with FERC’s Standards of Conduct regulation governing the communication of non-public transmission information between the transmission owner’s employees and wholesale merchant employees.

PJM is the regional grid operator and operates pursuant to FERC-approved tariffs. PJM is the transmission provider under, and the administrator of, the PJM Open Access Transmission Tariff (PJM Tariff). PJM operates the PJM energy, capacity and other markets, and, through central dispatch, controls the day-to-day operations of the bulk power system for the region. The Utility Registrants are members of PJM and provide regional transmission service pursuant to the PJM Tariff. The Utility Registrants and the other transmission owners in PJM have turned over control



of their transmission facilities to PJM, and their transmission systems are under the dispatch control of PJM. Under the PJM Tariff, transmission service is provided on a region-wide, open-access basis using the transmission facilities of the PJM transmission owners at rates based on the costs of transmission service.

The Utility Registrants' transmission rates are established based on a formula that was approved by FERC as shown below:

<table><tr><td></td><td>Approval Date</td></tr><tr><td>ComEd</td><td>January 2008</td></tr><tr><td>PECO</td><td>December 2019</td></tr><tr><td>BGE</td><td>April 2006</td></tr><tr><td>Pepco</td><td>April 2006</td></tr><tr><td>DPL</td><td>April 2006</td></tr><tr><td>ACE</td><td>April 2006</td></tr></table>

## Employees

The following table presents employee information, including information about collective bargaining agreements (CBAs), as of December 31, 2019:

<table><tr><td></td><td>Total Employees</td><td>Total Employees Covered by CBAs</td><td>Number of CBAs</td><td>CBAs New and Renewed in 2019(a)</td><td>Total Employees Under CBAs New and Renewed in 2019</td></tr><tr><td>Exelon</td><td>32,713</td><td>12,310</td><td>32</td><td>6</td><td>2,593</td></tr><tr><td>Generation</td><td>13,082</td><td>3,648</td><td>20</td><td>2</td><td>189</td></tr><tr><td>ComEd</td><td>6,182</td><td>3,462</td><td>2</td><td>—</td><td>—</td></tr><tr><td>PECO</td><td>2,752</td><td>1,398</td><td>2</td><td>—</td><td>—</td></tr><tr><td>BGE</td><td>3,151</td><td>1,436</td><td>1</td><td>1</td><td>1,436</td></tr><tr><td>PHI</td><td>4,188</td><td>2,268</td><td>7</td><td>3</td><td>968</td></tr><tr><td>Pepco</td><td>1,389</td><td>953</td><td>1</td><td>1</td><td>953</td></tr><tr><td>DPL</td><td>936</td><td>652</td><td>2</td><td>—</td><td>—</td></tr><tr><td>ACE</td><td>639</td><td>398</td><td>2</td><td>—</td><td>—</td></tr></table>

(a) Does not include CBAs that were extended in 2019 while negotiations are ongoing for renewal.

## Environmental Regulation

## General

The Registrants are subject to comprehensive and complex legislation regarding environmental matters by the federal government and various state and local jurisdictions in which they operate their facilities. The Registrants are also subject to environmental regulations administered by the EPA and various state and local environmental protection agencies. Federal, state and local regulation includes the authority to regulate air, water, and solid and hazardous waste disposal.

The Exelon Board of Directors is responsible for overseeing the management of environmental matters. Exelon has a management team to address environmental compliance and strategy, including the CEO; the Senior Vice President, Corporate Strategy & Chief Innovation and Sustainability Officer; the Senior Vice President, Competitive Market Policy; and the Director, Safety & Sustainability, as well as senior management of the Registrants. Performance of those individuals directly involved in environmental compliance and strategy is reviewed and affects compensation as part of the annual individual performance review process. The Exelon Board of Directors has delegated to its Generation Oversight Committee and the Corporate Governance Committee the authority to oversee



Exelon’s compliance with health, environmental and safety laws and regulations and its strategies and efforts to protect and improve the quality of the environment, including Exelon’s internal climate change and sustainability policies and programs, as discussed in further detail below. The respective Boards of the Utility Registrants oversee environmental, health and safety issues related to these companies.

## Air Quality

Air quality regulations promulgated by the EPA and the various state and local environmental agencies impose restrictions on emission of particulates, sulfur dioxide (SO \( _{2} \) ), nitrogen oxides (NO \( _{x} \) ), mercury and other air pollutants and require permits for operation of emitting sources. Such permits have been obtained as needed by Exelon's subsidiaries. However, due to its low emitting generation fleet comprised of nuclear, natural gas, hydroelectric, wind and solar, compliance with the Federal Clean Air Act does not have a material impact on Generation's operations.

See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for additional information regarding clean air regulation in the forms of the CSAPR, regulation of hazardous air pollutants from coal- and oil-fired electric generating facilities under MATS, and regulation of GHG emissions.

## Water Quality

Under the federal Clean Water Act, NPDES permits for discharges into waterways are required to be obtained from the EPA or from the state environmental agency to which the permit program has been delegated and must be renewed periodically. Certain of Exelon's facilities discharge stormwater and industrial wastewater into waterways and are therefore subject to these regulations and operate under NPDES permits or pending applications for renewals of such permits after being granted an administrative extension. Generation is also subject to the jurisdiction of the Delaware River Basin Commission and the Susquehanna River Basin Commission, regional agencies that primarily regulate water usage.

## Section 316(b) of the Clean Water Act

Section 316(b) requires that the cooling water intake structures at electric power plants reflect the best technology available to minimize adverse environmental impacts and is implemented through state-level NPDES permit programs. All of Generation's power generation facilities with cooling water systems are subject to the regulations. Facilities without closed-cycle recirculating systems (e.g., cooling towers) are potentially most affected by recent changes to the regulations. For Generation, those facilities are Calvert Cliffs, Clinton, Dresden, Eddystone, Fairless Hills, FitzPatrick, Ginnia, Gould Street, Handley, Mystic 7, Nine Mile Point Unit 1, Peach Bottom, Quad Cities and Salem.

On October 14, 2014, the EPA's Section 316(b) rule became effective. The rule requires that a series of studies and analyses be performed to determine the best technology available to minimize adverse impacts on aquatic life, followed by an implementation period for the selected technology. The timing of the various requirements for each facility is related to the status of its current NPDES permit and the subsequent renewal period. There is no fixed compliance schedule, as this is left to the discretion of the state permitting director.

Until the compliance requirements are determined by the applicable state permitting director on a site-specific basis for each plant, Generation cannot estimate the effect that compliance with the rule will have on the operation of its generating facilities and its future results of operations, cash flows, and financial position. Should a state permitting director determine that a facility must install cooling towers to comply with the rule, that facility's economic viability could be called into question. However, the potential impact of the rule has been significantly reduced since the final rule does not mandate cooling towers as a national standard and sets forth technologies that are presumptively compliant, and the state permitting director is required to apply a cost-benefit test and can take into consideration site-specific factors, such as those that would make cooling towers infeasible.

## New York Facilities

In July 2011, the New York Department of Environmental Conservation (DEC) issued a policy regarding the best available technology for cooling water intake structures. Through its policy, the DEC established closed-cycle cooling or its equivalent as the performance goal for all existing facilities, but also provided that the DEC will select a feasible technology whose costs are not wholly disproportionate to the environmental benefits to be gained and allows for a site-specific determination where the entrainment performance goal cannot be achieved (i.e., the requirement



most likely to support cooling towers). The Ginna, Nine Mile Point Unit 1, and Fitzpatrick power generation facilities have received renewals of their state water discharge permits and cooling towers were not required. These facilities are now engaged in the required analyses to enable the environmental agency to determine the best technology available in the next permit renewal cycles.

## Salem

On July 28, 2016, the NJDEP issued a final permit for Salem that did not require the installation of cooling towers and allows Salem to continue to operate utilizing the existing cooling water system with certain required system modifications. However, the permit is being challenged by an environmental organization, and if successful, could result in additional costs for Clean Water Act compliance. Potential cooling water system modification costs could be material and could adversely impact the economic competitiveness of this facility.

## Solid and Hazardous Waste

CERCLA provides for immediate response and removal actions coordinated by the EPA in the event of threatened releases of hazardous substances and authorizes the EPA either to clean up sites at which hazardous substances have created actual or potential environmental hazards or to order persons responsible for the situation to do so. Under CERCLA, generators and transporters of hazardous substances, as well as past and present owners and operators of hazardous waste sites, are strictly, jointly and severally liable for the cleanup costs of waste at sites, most of which are listed by the EPA on the National Priorities List (NPL). These PRPs can be ordered to perform a cleanup, can be sued for costs associated with an EPA-directed cleanup, may voluntarily settle with the EPA concerning their liability for cleanup costs, or may voluntarily begin a site investigation and site remediation under state oversight prior to listing on the NPL. Various states, including Delaware, Illinois, Maryland, New Jersey and Pennsylvania and the District of Columbia have also enacted statutes that contain provisions substantially similar to CERCLA. In addition, RCRA governs treatment, storage and disposal of solid and hazardous wastes and cleanup of sites where such activities were conducted.

Generation, the Utility Registrants and their subsidiaries are, or could become in the future, parties to proceedings initiated by the EPA, state agencies and/or other responsible parties under CERCLA and RCRA with respect to a number of sites, including MGP sites, or may undertake to investigate and remediate sites for which they may be subject to enforcement actions by an agency or third-party.

See Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information related to environmental matters.

## Environmental Remediation

ComEd's and PECO's environmental liabilities primarily arise from contamination at former MGP sites. ComEd, pursuant to an ICC order, and PECO, pursuant to settlements of natural gas distribution rate cases with the PAPUC, have an on-going process to recover environmental remediation costs of the MGP sites through a provision within customer rates. BGE, ACE, Pepco and DPL do not have material contingent liabilities relating to MGP sites. The amount to be expended in 2020 for compliance with environmental remediation related to contamination at former MGP sites and other gas purification sites is expected to total $49 million which consists primarily of $45 million at ComEd. The Utility Registrants also have contingent liabilities for environmental remediation of non-MGP contaminants (e.g., PCBs). As of December 31, 2019, the Utility Registrants have established appropriate contingent liabilities for environmental remediation requirements.

The Registrants' operations have in the past, and may in the future, require substantial expenditures in order to comply with environmental laws. Additionally, under Federal and state environmental laws, the Registrants are generally liable for the costs of remediating environmental contamination of property now or formerly owned by them and of property contaminated by hazardous substances generated by them. The Registrants own or lease a number of real estate parcels, including parcels on which their operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws.

In addition, Generation and the Utility Registrants may be required to make significant additional expenditures not presently determinable for other environmental remediation costs.



See Note 3 — Regulatory Matters and Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding the Registrants' environmental remediation efforts and related impacts to the Registrants' Consolidated Financial Statements.

## Global Climate Change

Exelon has utility and generation assets, and customers, that are and will be further subject to the impacts of climate change. Accordingly, Exelon is engaged in a variety of initiatives to understand and mitigate these impacts, including investments in resiliency, partnering with federal, state and local governments to minimize impacts, and, importantly, advocating for public policy that reduces emissions that cause climate change. Exelon, as a producer of electricity from predominantly low- and zero-carbon generating facilities (such as nuclear, hydroelectric, natural gas, wind and solar photovoltaic), has a relatively small GHG emission profile, or carbon footprint, compared to other domestic generators of electricity (Exelon neither owns nor operates any coal-fueled generating assets). Exelon's natural gas and biomass fired generating plants produce GHG emissions, most notably, CO \( _2 \) . However, Generation's owned-asset emission intensity, or rate of carbon dioxide equivalent (CO \( _2 \) e) emitted per unit of electricity generated, is among the lowest in the industry. Other GHG emission sources at Exelon include natural gas (methane) leakage on the natural gas systems, sulfur hexafluoride (SF \( _6 \) ) leakage from electric transmission and distribution operations, refrigerant leakage from chilling and cooling equipment, and fossil fuel combustion in motor vehicles. Exelon facilities and operations are subject to the global impacts of climate change and Exelon believes its operations could be significantly affected by the physical risks of climate change. See ITEM 1A. RISK FACTORS for additional information.

## Climate Change Regulation

Exelon is or may become subject to additional climate change regulation or legislation at the federal, regional and state levels.

International Climate Change Agreements. At the international level, the United States is a Party to the United Nations Framework Convention on Climate Change (UNFCCC). The Parties to the UNFCCC adopted the Paris Agreement at the 21 \( ^{st} \)  session of the UNFCCC Conference of the Parties (COP 21) on December 12, 2015, and it became effective on November 4, 2016. Under the Paris Agreement, the Parties agreed to try to limit the global average temperature increase to 2°C (3.6°F) above pre-industrial levels. In doing so, Parties developed their own national reduction commitments. The United States submitted a non-binding target of 17% below 2005 emission levels by 2020 and 26% to 28% below 2005 levels by 2025. President Trump has stated his intention to withdraw the U.S. from the Paris Agreement, but no formal action has been initiated. A withdrawal would not be effective until November 2020 at the earliest.

Federal Climate Change Legislation and Regulation. It is highly unlikely that federal legislation to reduce GHG emissions will be enacted in the near-term. If such legislation is adopted, it would likely increase the value of Exelon's low-carbon fleet even though Exelon may incur costs either to further limit or offset the GHG emissions from its operations or to procure emission allowances or credits. Continued inaction could negatively impact the value of Exelon's low-carbon fleet.

Under the Obama Administration, the EPA finalized its Clean Power Plan regulations to reduce GHG emissions from fossil fuel-fired power plants. Subsequently, the Trump Administration EPA proposed regulations on October 16, 2017 to repeal the CPP on the basis that the new Administration believed that the CPP rule went beyond the EPA's authority to establish a best system of emissions reduction (BSER) for existing power plants. On August 31, 2018, EPA proposed its Affordable Clean Energy rule to replace the CPP with revised emission guidelines based on heat rate improvement measures that could be achieved within the fence line of existing power plants. In June 2019, EPA issued a final rule that repealed the CPP, and finalized the Affordable Clean Energy rule. The Affordable Clean Energy rule is currently being litigated.

Given litigation uncertainty around the final Affordable Clean Energy rule, Exelon and Generation cannot predict the impacts of regulation of existing power plants, or individual state responses to developments related to final resolution of the Affordable Clean Energy rule, or how developments will impact their future financial statements.

Regional and State Climate Change Legislation and Regulation. A number of states in which Exelon operates have state and regional programs to reduce GHG emissions, including from the power sector. As the nation's largest generator of carbon-free electricity, our fleet supports these efforts to produce safe, reliable electricity with minimal GHGs. Notably, nine northeast and mid-Atlantic states (Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New York, Rhode Island and Vermont) currently participate in the Regional Greenhouse Gas



Initiative (RGGI), which is in the process of strengthening its requirements. The program requires most fossil fuel-fired power plants in the region to hold allowances, purchased at auction, for each ton of  \( CO_{2} \)  emissions. Non-emitting resources do not have to purchase or hold these allowances.

In June 2019, New Jersey was accepted as a RGGI member effective January 2020. In October 2019, Governor Wolf of Pennsylvania issued an Executive Order that directed the Pennsylvania Department of Environmental Protection to begin a rulemaking process that will allow Pennsylvania to join the RGGI, with the goal of reducing carbon emissions from the electricity sector.

Many states in which Exelon subsidiaries operate also have state-specific programs to address GHGs, including from power plants. Most notable of these, besides RGGI, are through renewable and other portfolio standards. Additionally, in response to a court decision clarifying the obligations under the Global Warming Solutions Act, the Massachusetts Department of Environmental Protection in 2017 finalized regulations establishing a statewide cap on  \( CO_{2} \)  emissions from fossil fuel power plants (Massachusetts remains in RGGI as well). The effect of this new obligation and potential for market illiquidity in the early years represent a risk to Generation's Massachusetts fossil facilities, including Medway and Mystic. At the same time, the District of Columbia is considering a plan to incorporate the cost of carbon into electricity, via consumption, as well as directly into the cost of transportation and home heating fuels. Details remain to be developed, but the specifics could have implications for Pepco's operations.

Regardless of whether GHG regulation occurs at the local, state, or federal level, Exelon remains one of the largest, lowest-carbon electric generators in the United States, relying mainly on nuclear, natural gas, hydropower, wind, and solar. The extent that the low-carbon generating fleet will continue to be a competitive advantage for Exelon depends on resolution of the CPP and Affordable Clean Energy regulations and associated current or future litigation at the federal level, new or expanded state action on greenhouse gas emissions or direct support of clean energy technologies, including nuclear, as well as potential market reforms that value our fleet's emission-free attributes.

## Renewable and Alternative Energy Portfolio Standards

Thirty-nine states and the District of Columbia, incorporating the vast majority of Exelon operations as well as all utility operations, have adopted some form of RPS requirement. These standards impose varying levels of mandates for procurement of renewable or clean electricity (the definition of which varies by state) and/or energy efficiency. These are generally expressed as a percentage of annual electric load, often increasing by year. Exelon's utilities comply with these various requirements through purchasing qualifying renewables, implementing efficiency programs, acquiring sufficient credits (e.g., RECs), paying an alternative compliance payment, and/or a combination of these compliance alternatives. The Utility Registrants are permitted to recover from retail customers the costs of complying with their state RPS requirements, including the procurement of RECs or other alternative energy resources. New York, Illinois and New Jersey adopted standards targeted at preserving the zero-carbon attributes of certain nuclear-powered generating facilities. Generation owns multiple facilities participating in these programs within these states. Other states in which Generation and our utilities operate are considering similar programs.

See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on renewable portfolio standards.



## Information about our Executive Officers as of February 11, 2020

## Exelon

<table><tr><td>Name</td><td>Age</td><td>Position</td><td>Period</td></tr><tr><td rowspan="2">Crane, Christopher M.</td><td rowspan="2">61</td><td>Chief Executive Officer, Exelon;</td><td>2012 - Present</td></tr><tr><td>President, Exelon</td><td>2008 - Present</td></tr><tr><td rowspan="2">Cornew, Kenneth W.</td><td rowspan="2">54</td><td>Senior Executive Vice President and Chief Commercial Officer, Exelon;</td><td>2013 - Present</td></tr><tr><td>President and CEO, Generation</td><td>2013 - Present</td></tr><tr><td rowspan="3">Butler, Calvin G.</td><td rowspan="3">50</td><td>Senior Executive Vice President, Exelon; Chief Executive Officer, Exelon Utilities</td><td>2019 - Present</td></tr><tr><td>Chief Executive Officer, BGE</td><td>2014 - 2019</td></tr><tr><td>Chief Executive Officer, ComEd</td><td>2018 - Present</td></tr><tr><td rowspan="3">Dominguez, Joseph</td><td rowspan="3">57</td><td>Executive Vice President, Governmental &amp; Regulatory Affairs and Public Policy, Exelon</td><td>2015 - 2018</td></tr><tr><td>Senior Vice President, Governmental &amp; Regulatory Affairs and Public Policy, Exelon</td><td>2012 - 2015</td></tr><tr><td>Senior Vice President, Governmental &amp; Regulatory Affairs and Public Policy,</td><td>2018 - Present</td></tr><tr><td>Innocenzo, Michael A.</td><td>54</td><td>President and Chief Executive Officer, PECO</td><td>2018 - Present</td></tr><tr><td rowspan="3">Khouzami, Carim V.</td><td rowspan="3">44</td><td>Senior Vice President and Chief Operations Officer, PECO</td><td>2012 - 2018</td></tr><tr><td>Chief Executive Officer, BGE</td><td>2019 - Present</td></tr><tr><td>Senior Vice President, Chief Operating Officer, Exelon Utilities</td><td>2018 - 2019</td></tr><tr><td rowspan="3">Velazquez, David M.</td><td rowspan="3">60</td><td>Senior Vice President, Chief Financial Officer, Exelon Utilities</td><td>2016 - 2018</td></tr><tr><td>Senior Vice President, Chief Integration Officer, Exelon</td><td>2014 - 2016</td></tr><tr><td>President and Chief Executive Officer, PHI</td><td>2016 - Present</td></tr><tr><td rowspan="2">Von Hoene Jr., William A.</td><td rowspan="2">66</td><td>President and Chief Executive Officer, Pepco, DPL and ACE</td><td>2009 - Present</td></tr><tr><td>Executive Vice President, Pepco Holdings, Inc.</td><td>2009 - 2016</td></tr><tr><td>Nigro, Joseph</td><td>55</td><td>Senior Executive Vice President and Chief Strategy Officer, Exelon</td><td>2012 - Present</td></tr><tr><td rowspan="2">Aliabadi, Paymon</td><td rowspan="2">57</td><td>Senior Executive Vice President and Chief Financial Officer, Exelon</td><td>2018 - Present</td></tr><tr><td>Executive Vice President, Exelon; Chief Executive Officer, Constellation</td><td>2013 - 2018</td></tr><tr><td>Souza, Fabian E.</td><td>49</td><td>Executive Vice President and Chief Risk Officer, Exelon</td><td>2013 - Present</td></tr><tr><td rowspan="4"></td><td rowspan="4"></td><td>Senior Vice President and Corporate Controller, Exelon</td><td>2018 - Present</td></tr><tr><td>Senior Vice President and Deputy Controller, Exelon</td><td>2017 - 2018</td></tr><tr><td>Vice President, Controller and Chief Accounting Officer, The AES Corporation</td><td>2015 - 2017</td></tr><tr><td>Vice President, Internal Audit and Advisory Services, The AES Corporation</td><td>2014 - 2015</td></tr></table>



## Generation

<table><tr><td>Name</td><td>Age</td><td>Position</td><td>Period</td></tr><tr><td>Cornew, Kenneth W.</td><td>54</td><td>Senior Executive Vice President and Chief Commercial Officer, Exelon; President and Chief Executive Officer, Generation</td><td>2013 - Present</td></tr><tr><td></td><td></td><td></td><td>2013 - Present</td></tr><tr><td>Pacilio, Michael J.</td><td>59</td><td>Executive Vice President and Chief Operating Officer, Generation</td><td>2015 - Present</td></tr><tr><td></td><td></td><td>President, Exelon Nuclear; Senior Vice President and Chief Nuclear Officer, Generation</td><td>2010 - 2015</td></tr><tr><td>Hanson, Bryan C</td><td>54</td><td>President and Chief Nuclear Officer, Exelon Nuclear; Senior Vice President, Generation</td><td>2015 - Present</td></tr><tr><td>McHugh, James</td><td>48</td><td>Executive Vice President, Exelon; Chief Executive Officer, Constellation Senior Vice President, Portfolio Management &amp; Strategy, Constellation Vice President, Portfolio Management, Constellation</td><td>2018 - Present</td></tr><tr><td></td><td></td><td></td><td>2016 - 2018</td></tr><tr><td></td><td></td><td></td><td>2012 - 2016</td></tr><tr><td>Barnes, John</td><td>56</td><td>Senior Vice President, Generation; President, Exelon Power</td><td>2018 - Present</td></tr><tr><td></td><td></td><td>Senior Vice President, Generation, Senior Vice President and Chief Operating Officer, Exelon Power</td><td>2012 - 2018</td></tr><tr><td>Wright, Bryan P.</td><td>53</td><td>Senior Vice President and Chief Financial Officer, Generation</td><td>2013 - Present</td></tr><tr><td>Bauer, Matthew N.</td><td>43</td><td>Vice President and Controller, Generation</td><td>2016 - Present</td></tr><tr><td></td><td></td><td>Vice President and Controller, BGE</td><td>2014 - 2016</td></tr></table>



## ComEd

<table><tr><td>Name</td><td>Age</td><td>Position</td><td>Period</td></tr><tr><td rowspan="3">Dominguez, Joseph</td><td rowspan="3">57</td><td>Chief Executive Officer, ComEd</td><td>2018 - Present</td></tr><tr><td>Executive Vice President, Governmental &amp; Regulatory Affairs and Public Policy, Exelon</td><td>2015 - 2018</td></tr><tr><td>Senior Vice President, Governmental &amp; Regulatory Affairs and Public Policy, Exelon</td><td>2012 - 2015</td></tr><tr><td rowspan="2">Donnelly, Terence R.</td><td rowspan="2">59</td><td>President and Chief Operating Officer, ComEd</td><td>2018 - Present</td></tr><tr><td>Executive Vice President and Chief Operating Officer, ComEd</td><td>2012 - 2018</td></tr><tr><td rowspan="2">Jones, Jeanne M.</td><td rowspan="2">40</td><td>Senior Vice President, Chief Financial Officer and Treasurer, ComEd</td><td>2018 - Present</td></tr><tr><td>Vice President, Finance, Exelon Nuclear</td><td>2014 - 2018</td></tr><tr><td rowspan="3">Park, Jane</td><td rowspan="3">47</td><td>Senior Vice President, Customer Operations, ComEd</td><td>2018 - Present</td></tr><tr><td>Vice President, Regulatory Policy &amp; Strategy, ComEd</td><td>2016 - 2018</td></tr><tr><td>Director, Business Strategy &amp; Technology, ComEd</td><td>2014 - 2016</td></tr><tr><td rowspan="2">Gomez, Veronica</td><td rowspan="2">50</td><td>Senior Vice President, Regulatory and Energy Policy and General Counsel, ComEd</td><td>2017 - Present</td></tr><tr><td>Vice President and Deputy General Counsel, Litigation, Exelon</td><td>2012 - 2017</td></tr><tr><td rowspan="4">Washington, Melissa</td><td rowspan="4">50</td><td>Senior Vice President, Governmental and External Affairs, ComEd</td><td>2019 - Present</td></tr><tr><td>Vice President, Governmental and External Affairs, ComEd</td><td>2019 - 2019</td></tr><tr><td>Vice President, External Affairs and Large Customer Services, ComEd</td><td>2016 - 2019</td></tr><tr><td>Vice President, Corporate Affairs, Exelon Business Services Company</td><td>2014 - 2016</td></tr><tr><td rowspan="3">Perez, David</td><td rowspan="3">50</td><td>Senior Vice President, Distribution Operations, ComEd</td><td>2019 - Present</td></tr><tr><td>Vice President, Transmission and Substation, ComEd</td><td>2016 - 2019</td></tr><tr><td>Vice President, Regional Operations, ComEd</td><td>2010 - 2016</td></tr><tr><td>Kozel, Gerald J.</td><td>47</td><td>Vice President, Controller, ComEd</td><td>2013 - Present</td></tr></table>



## PECO

<table><tr><td>Name</td><td>Age</td><td>Position</td><td>Period</td></tr><tr><td>Innocenzo, Michael A.</td><td>54</td><td>President and Chief Executive Officer, PECO</td><td>2018 - Present</td></tr><tr><td></td><td></td><td>Senior Vice President and Chief Operations Officer, PECO</td><td>2012 - 2018</td></tr><tr><td>McDonald, John</td><td>62</td><td>Senior Vice President and Chief Operations Officer, PECO</td><td>2018 - Present</td></tr><tr><td></td><td></td><td>Vice President, Integration, PHI</td><td>2016 - 2018</td></tr><tr><td></td><td></td><td>Vice President, Technical Services</td><td>2006 - 2016</td></tr><tr><td>Stefani, Robert J.</td><td>45</td><td>Senior Vice President, Chief Financial Officer and Treasurer, PECO</td><td>2018 - Present</td></tr><tr><td></td><td></td><td>Vice President, Corporate Development, Exelon</td><td>2015 - 2018</td></tr><tr><td></td><td></td><td>Director, Corporate Development, Exelon</td><td>2012 - 2015</td></tr><tr><td>Murphy, Elizabeth A.</td><td>60</td><td>Senior Vice President, Governmental and External Affairs, PECO</td><td>2016 - Present</td></tr><tr><td></td><td></td><td>Vice President, Governmental and External Affairs, PECO</td><td>2012 - 2016</td></tr><tr><td>Webster Jr., Richard G.</td><td>58</td><td>Vice President, Regulatory Policy and Strategy, PECO</td><td>2012 - Present</td></tr><tr><td>Williamson, Olufunmilayo</td><td>41</td><td>Senior Vice President, Customer Operations, PECO</td><td>2020 - Present</td></tr><tr><td></td><td></td><td>Senior Vice President, Chief Commercial Risk Officer, Exelon</td><td>2017 - 2020</td></tr><tr><td></td><td></td><td>Vice President, Commercial Risk Management, Exelon</td><td>2015 - 2017</td></tr><tr><td>Gay, Anthony</td><td>54</td><td>Vice President and General Counsel, PECO</td><td>2019 - Present</td></tr><tr><td></td><td></td><td>Vice President, Governmental and External Affairs, PECO</td><td>2016 - 2019</td></tr><tr><td></td><td></td><td>Associate General Counsel, Exelon</td><td>2010 - 2016</td></tr><tr><td>Bailey, Scott A.</td><td>43</td><td>Vice President and Controller, PECO</td><td>2012 - Present</td></tr></table>



## BGE

<table><tr><td>Name</td><td>Age</td><td>Position</td><td>Period</td></tr><tr><td rowspan="4">Khouzami, Carim V.</td><td rowspan="4">44</td><td>Chief Executive Officer, BGE</td><td>2019 - Present</td></tr><tr><td>Senior Vice President, Chief Operating Officer, Exelon Utilities</td><td>2018 - 2019</td></tr><tr><td>Senior Vice President, Chief Financial Officer, Exelon Utilities</td><td>2016 - 2018</td></tr><tr><td>Senior Vice President, Chief Integration Officer, Exelon</td><td>2014 - 2016</td></tr><tr><td rowspan="2">Woerner, Stephen J.</td><td rowspan="2">52</td><td>President, BGE</td><td>2014 - Present</td></tr><tr><td>Chief Operating Officer, BGE</td><td>2012 - Present</td></tr><tr><td rowspan="2">Vahos, David M.</td><td rowspan="2">47</td><td>Senior Vice President, Chief Financial Officer and Treasurer, BGE</td><td>2016 - Present</td></tr><tr><td>Vice President, Chief Financial Officer and Treasurer, BGE</td><td>2014 - 2016</td></tr><tr><td rowspan="3">Núñez, Alexander G.</td><td rowspan="3">48</td><td>Senior Vice President, Regulatory Affairs and Strategy, BGE</td><td>2020 - Present</td></tr><tr><td>Senior Vice President, Regulatory and External Affairs, BGE</td><td>2016 - 2020</td></tr><tr><td>Vice President, Governmental and External Affairs, BGE</td><td>2013 - 2016</td></tr><tr><td>Case, Mark D.</td><td>58</td><td>Vice President, Strategy and Regulatory Affairs, BGE</td><td>2012 - Present</td></tr><tr><td rowspan="5">Oddoye, Rodney</td><td rowspan="5">43</td><td>Senior Vice President, Governmental and External Affairs, BGE</td><td>2020 - Present</td></tr><tr><td>Vice President, Customer Operations, BGE</td><td>2018 - 2020</td></tr><tr><td>Director, Northeast Regional Electric Operations, BGE</td><td>2016 - 2018</td></tr><tr><td>Director, Financial Operations, BGE</td><td>2015 - 2016</td></tr><tr><td>Manager, Distribution Operations, BGE</td><td>2013 - 2015</td></tr><tr><td rowspan="3">Olivier, Tamla</td><td rowspan="3">47</td><td>Senior Vice President, Customer Operations, BGE</td><td>2020 - Present</td></tr><tr><td>Senior Vice President, Constellation NewEnergy, Inc.</td><td>2016 - 2020</td></tr><tr><td>VP, Human Resources, Exelon Business Services Company</td><td>2012 - 2016</td></tr><tr><td rowspan="2">Corse, John</td><td rowspan="2">59</td><td>Vice President and General Counsel, BGE</td><td>2018 - Present</td></tr><tr><td>Associate General Counsel, Exelon</td><td>2012 - 2018</td></tr><tr><td rowspan="2">Holmes, Andrew W.</td><td rowspan="2">51</td><td>Vice President and Controller, BGE</td><td>2016 - Present</td></tr><tr><td>Director, Generation Accounting, Exelon</td><td>2013 - 2016</td></tr></table>



## PHI, Pepco, DPL and ACE

<table><tr><td>Name</td><td>Age</td><td>Position</td><td>Period</td></tr><tr><td rowspan="3">Velazquez, David M.</td><td rowspan="3">60</td><td>President and Chief Executive Officer, PHI</td><td>2016 - Present</td></tr><tr><td>Executive Vice President, Pepco Holdings, Inc.</td><td>2009 - 2016</td></tr><tr><td>President and Chief Executive Officer, Pepco, DPL and ACE</td><td>2009 - Present</td></tr><tr><td rowspan="2">Anthony, J. Tyler</td><td rowspan="2">55</td><td>Senior Vice President and Chief Operating Officer, PHI, Pepco, DPL and ACE</td><td>2016 - Present</td></tr><tr><td>Senior Vice President, Distribution Operations, ComEd</td><td>2010 - 2016</td></tr><tr><td rowspan="3">Barnett, Phillip S.</td><td rowspan="3">56</td><td>Senior Vice President, Chief Financial Officer and Treasurer, PHI, Pepco, DPL and ACE</td><td>2018 - Present</td></tr><tr><td>Senior Vice President and Chief Financial Officer, PECO</td><td>2007 - 2018</td></tr><tr><td>Treasurer, PECO</td><td>2012 - 2018</td></tr><tr><td rowspan="3">Lavinson, Melissa</td><td rowspan="3">50</td><td>Senior Vice President, Governmental &amp; External Affairs, PHI, Pepco, DPL and ACE</td><td>2018 - Present</td></tr><tr><td>Vice President, Federal Affairs and Policy and Chief Sustainability Officer, PG&amp;E Corporation</td><td>2015 - 2018</td></tr><tr><td>Vice President, Federal Affairs, PG&amp;E Corporation</td><td>2012 - 2015</td></tr><tr><td rowspan="3">Stark, Wendy E.</td><td rowspan="3">47</td><td>Senior Vice President, Legal and Regulatory Strategy and General Counsel, PHI, Pepco, DPL and ACE</td><td>2019 - Present</td></tr><tr><td>Vice President and General Counsel, PHI, Pepco DPL and ACE</td><td>2016 - 2018</td></tr><tr><td>Deputy General Counsel, Pepco Holdings, Inc.</td><td>2012 - 2016</td></tr><tr><td rowspan="2">McGowan, Kevin M.</td><td rowspan="2">58</td><td>Vice President, Regulatory Policy and Strategy, PHI, Pepco, DPL and ACE</td><td>2016 - Present</td></tr><tr><td>Vice President, Regulatory Affairs, Pepco Holdings, Inc.</td><td>2012 - 2016</td></tr><tr><td rowspan="3">Dickens, Derrick</td><td rowspan="3">55</td><td>Senior Vice President, Customer Operations, PHI</td><td>2020 - Present</td></tr><tr><td>Vice President, Technical Services, BGE</td><td>2016 - 2020</td></tr><tr><td>Director, Advanced Meter Infrastructure, PECO</td><td>2012 - 2016</td></tr><tr><td rowspan="2">Aiken, Robert</td><td rowspan="2">53</td><td>Vice President and Controller, PHI, Pepco, DPL and ACE</td><td>2016 - Present</td></tr><tr><td>Vice President and Controller, Generation</td><td>2012 - 2016</td></tr></table>

## ITEM 1A. RISK FACTORS

Each of the Registrants operates in a complex market and regulatory environment that involves significant risks, many of which are beyond that Registrant's direct control. Such risks, which could negatively affect one or more of the Registrants' consolidated financial statements, fall primarily under the categories below:

## Market and Financial Factors primarily include:

• the price of fuels, in particular the price of natural gas, which affects power prices,

• the generation resources in the markets in which the Registrants operate,



• the demand for electricity, reliability of service and affordability in the markets where the Registrants conduct their business,

• the impacts of on-going competition, and

• emerging technologies and business models.

Regulatory and Legislative Factors primarily include changes to the laws and regulations that govern:

• the design of power markets,

• zero emission credit programs,

• utility regulatory business model,

• regulations and other standards,

• environmental policy, and

• tax policy.

## Operational Factors primarily include:

• changes in the global climate could produce extreme weather events, which could put the Registrant's facilities at risk, and the effects of climate change regulation could impact the GHG emissions from the Registrant's operations,

- the safe, secure and effective operation of Generation’s nuclear facilities and the ability to effectively manage the associated decommissioning obligations,

- the ability of the Registrants to maintain the reliability, resiliency and safety of their energy delivery systems, which could affect the operating costs of the Registrants and the opinions of their customers and regulators, and

- the Registrants face physical and cyber security risks as the owner-operators of generation, transmission and distribution facilities and as participants in commodities trading.

There may be further risks and uncertainties that are not presently known or that are not currently believed by the Registrants to be material that could negatively affect its consolidated financial statements in the future.

## Market and Financial Factors

Generation is exposed to price volatility associated with both the wholesale and retail power markets and the procurement of nuclear and fossil fuel (Exelon and Generation).

Generation is exposed to commodity price risk for the unhedged portion of its electricity generation supply portfolio. Generation’s earnings and cash flows are therefore exposed to variability of spot and forward market prices in the markets in which it operates.

Price of Fuels. The spot market price of electricity for each hour is generally determined by the marginal cost of supplying the next unit of electricity to the market during that hour. Thus, the market price of power is affected by the market price of the marginal fuel used to generate the electricity unit.

Demand and Supply. The market price for electricity is also affected by changes in the demand for electricity and the available supply of electricity. Unfavorable economic conditions, milder than normal weather, and the growth of energy efficiency and demand response programs could each depress demand. In addition, in some markets, the supply of electricity could often exceed demand during some hours of the day, resulting in loss of revenue for base-load generating plants such as Generation's nuclear plants.

Retail Competition. Generation’s retail operations compete for customers in a competitive environment, which affects the margins that Generation can earn and the volumes that it is able to serve. In periods of sustained low



natural gas and power prices and low market volatility, retail competitors can aggressively pursue market share because the barriers to entry can be low and wholesale generators (including Generation) use their retail operations to hedge generation output.

The impact of sustained low market prices or depressed demand and over-supply could be emphasized given Generation’s concentration of base-load electric generating capacity within primarily two geographic market regions, namely the Midwest and the Mid-Atlantic. These impacts could adversely affect Generation’s ability to fund regulated utility growth for the benefit of customers, reduce debt and provide attractive shareholder returns. In addition, such conditions may no longer support the continued operation of certain generating facilities, which could adversely affect Generation’s financial statements primarily through accelerated depreciation and amortization expenses and one-time charges. See Note 6 — Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information.

Cost of Fuel. Generation depends on nuclear fuel and fossil fuels to operate most of its generating facilities. The supply markets for nuclear fuel, natural gas and oil are subject to price fluctuations, availability restrictions and counterparty default.

Market Designs. The wholesale markets vary from region to region with distinct rules, practices and procedures. Changes in these market rules, problems with rule implementation, or failure of any of these markets could adversely affect Generation’s business. In addition, a significant decrease in market participation could affect market liquidity and have a detrimental effect on market stability.

The Registrants are potentially affected by emerging technologies that could over time affect or transform the energy industry (All Registrants).

Some of these technologies include, but are not limited to, further development or applications of technologies related to shale gas production, renewable energy technologies, energy efficiency, distributed generation and energy storage devices. Such developments could affect the price of energy, levels of customer-owned generation, customer expectations and current business models and make portions of our electric system power supply and transmission and/or distribution facilities obsolete prior to the end of their useful lives. Such technologies could also result in further declines in commodity prices or demand for delivered energy. Each of these factors could affect the Registrants' consolidated financial statements through, among other things, reduced operating revenues, increased operating and maintenance expenses, increased capital expenditures, and potential asset impairment charges or accelerated depreciation and decommissioning expenses over shortened remaining asset useful lives.

Market performance and other factors could decrease the value of NDT funds and employee benefit plan assets and could increase the related employee benefit plan obligations, which then could require significant additional funding (All Registrants).

Disruptions in the capital markets and their actual or perceived effects on particular businesses and the greater economy could adversely affect the value of the investments held within Generation’s NDTs and Exelon’s employee benefit plan trusts. The Registrants have significant obligations in these areas and Exelon and Generation hold substantial assets in these trusts to meet those obligations. The asset values are subject to market fluctuations and will yield uncertain returns, which could fall below the Registrants’ projected return rates. A decline in the market value of the NDT fund investments could increase Generation’s funding requirements to decommission its nuclear plants. A decline in the market value of the pension and OPEB plan assets will increase the funding requirements associated with Exelon’s pension and OPEB plan obligations. Additionally, Exelon’s pension and OPEB plan liabilities are sensitive to changes in interest rates. As interest rates decrease, the liabilities increase, potentially increasing benefit costs and funding requirements. Changes in demographics, including increased numbers of retirements or changes in life expectancy assumptions or changes to Social Security or Medicare eligibility requirements could also increase the costs and funding requirements of the obligations related to the pension and OPEB plans. See Note 9 — Asset Retirement Obligations and Note 14 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information.

The Registrants could be negatively affected by unstable capital and credit markets and increased volatility in commodity markets (All Registrants).

The Registrants rely on the capital markets, particularly for publicly offered debt, as well as the banking and commercial paper markets, to meet their financial commitments and short-term liquidity needs. Disruptions in the



capital and credit markets in the United States or abroad could negatively affect the Registrants' ability to access the capital markets or draw on their respective bank revolving credit facilities. The banks may not be able to meet their funding commitments to the Registrants if they experience shortages of capital and liquidity or if they experience excessive volumes of borrowing requests within a short period of time. The inability to access capital markets or credit facilities, and longer-term disruptions in the capital and credit markets as a result of uncertainty, changing or increased regulation, reduced alternatives or failures of significant financial institutions could result in the deferral of discretionary capital expenditures, Generation's ability to hedge effectively its generation portfolio, changes to Generation's hedging strategy in order to reduce collateral posting requirements, or a reduction in dividend payments or other discretionary uses of cash. In addition, the Registrants have exposure to worldwide financial markets, including Europe, Canada and Asia. Disruptions in these markets could reduce or restrict the Registrants' ability to secure sufficient liquidity or secure liquidity at reasonable terms. As of December 31, 2019, approximately 23%, 19%, and 18% of the Registrants' available credit facilities were with European, Canadian and Asian banks, respectively. See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the credit facilities.

The strength and depth of competition in energy markets depend heavily on active participation by multiple trading parties, which could be negatively affected by disruptions in the capital and credit markets and legislative and regulatory initiatives that could affect participants in commodities transactions. Reduced capital and liquidity and failures of significant institutions that participate in the energy markets could diminish the liquidity and competitiveness of energy markets that are important to the respective businesses of the Registrants. Perceived weaknesses in the competitive strength of the energy markets could lead to pressures for greater regulation of those markets or attempts to replace market structures with other mechanisms for the sale of power, including the requirement of long-term contracts.

If any of the Registrants were to experience a downgrade in its credit ratings to below investment grade or otherwise fail to satisfy the credit standards in its agreements with its counterparties, it would be required to provide significant amounts of collateral under its agreements with counterparties and could experience higher borrowing costs (All Registrants).

Generation’s business is subject to credit quality standards that could require market participants to post collateral for their obligations. If Generation were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating) or otherwise fail to satisfy the credit standards of trading counterparties, it would be required under its hedging arrangements to provide collateral in the form of letters of credit or cash, which could have a material adverse effect upon its liquidity. The amount of collateral required to be provided by Generation at any point in time depends on a variety of factors, including (1) the notional amount of the applicable hedge, (2) the nature of counterparty and related agreements, and (3) changes in power or other commodity prices. In addition, if Generation were downgraded, it could experience higher borrowing costs as a result of the downgrade. Changes in ratings methodologies by the credit rating agencies could also have a negative impact on the ratings of Generation.

Generation has project-specific financing arrangements and must meet the requirements of various agreements relating to those financings. Failure to meet those arrangements could give rise to a project-specific financing default which, if not cured or waived, could result in the specific project being required to repay the associated debt or other borrowings earlier than otherwise anticipated, and if such repayment were not made, the lenders or security holders would generally have broad remedies, including rights to foreclose against the project assets and related collateral or to force the Exelon subsidiaries in the project-specific financings to enter into bankruptcy proceedings. The impact of bankruptcy could result in the impairment of certain project assets.

The Utility Registrants' operating agreements with PJM and PECO's, BGE's and DPL's natural gas procurement contracts contain collateral provisions that are affected by their credit rating and market prices. If certain wholesale market conditions were to exist and the Utility Registrants were to lose their investment grade credit ratings (based on their senior unsecured debt ratings), they would be required to provide collateral in the forms of letters of credit or cash, which could have a material adverse effect upon their remaining sources of liquidity. PJM collateral posting requirements will generally increase as market prices rise and decrease as market prices fall. Collateral posting requirements for PECO, BGE and DPL, with respect to their natural gas supply contracts, will generally increase as forward market prices fall and decrease as forward market prices rise. If the Utility Registrants were downgraded, they could experience higher borrowing costs as a result of the downgrade. In addition, changes in ratings methodologies by the agencies could also have an adverse negative impact on the ratings of the Utility Registrants.



The Utility Registrants conduct their respective businesses and operate under governance models and other arrangements and procedures intended to assure that the Utility Registrants are treated as separate, independent companies, distinct from Exelon and other Exelon subsidiaries in order to isolate the Utility Registrants from Exelon and other Exelon subsidiaries in the event of financial difficulty at Exelon or another Exelon subsidiary. These measures (commonly referred to as "ring-fencing") could help avoid or limit a downgrade in the credit ratings of the Utility Registrants in the event of a reduction in the credit rating of Exelon. Despite these ring-fencing measures, the credit ratings of the Utility Registrants could remain linked, to some degree, to the credit ratings of Exelon. Consequently, a reduction in the credit rating of Exelon could result in a reduction of the credit rating of some or all of the Utility Registrants. A reduction in the credit rating of a Utility Registrant could have a material adverse effect on the Utility Registrant.

See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Liquidity and Capital Resources — Credit Matters — Market Conditions and Security Ratings for additional information regarding the potential impacts of credit downgrades on the Registrants' cash flows.

Generation’s risk management policies cannot fully eliminate the risk associated with its commodity trading activities (Exelon and Generation).

Generation’s asset-based power position as well as its power marketing, fuel procurement and other commodity trading activities expose Generation to risks of commodity price movements. Generation buys and sells energy and other products and enters into financial contracts to manage risk and hedge various positions in Generation’s power generation portfolio. Generation is exposed to volatility in financial results for unhedged positions as well as the risk of ineffective hedges. Generation attempts to manage this exposure through enforcement of established risk limits and risk management procedures. These risk limits and risk management procedures may not work as planned and cannot eliminate all risks associated with these activities. Even when its policies and procedures are followed, and decisions are made based on projections and estimates of future performance, results of operations could be diminished if the judgments and assumptions underlying those decisions prove to be incorrect. Factors, such as future prices and demand for power and other energy-related commodities, become more difficult to predict and the calculations become less reliable the further into the future estimates are made. As a result, Generation cannot predict the impact that its commodity trading activities and risk management decisions could have on its consolidated financial statements.

Financial performance and load requirements could be negatively affected if Generation is unable to effectively manage its power portfolio (Exelon and Generation).

A significant portion of Generation’s power portfolio is used to provide power under procurement contracts with the Utility Registrants and other customers. To the extent portions of the power portfolio are not needed for that purpose, Generation’s output is sold in the wholesale power markets. To the extent its power portfolio is not sufficient to meet the requirements of its customers under the related agreements, Generation must purchase power in the wholesale power markets. Generation’s financial results could be negatively affected if it is unable to cost-effectively meet the load requirements of its customers, manage its power portfolio or effectively address the changes in the wholesale power markets.

The impacts of significant economic downturns or increases in customer rates, could lead to decreased volumes delivered and increased expense for uncollectible customer balances (All Registrants).

The impacts of significant economic downturns on the Utility Registrants' customers, such as less demand for products and services provided by commercial and industrial customers, and the related regulatory limitations on residential service terminations, could result in an increase in the number of uncollectible customer balances. Further, increases in customer rates, including those related to increases in purchased power and natural gas prices, could result in declines in customer usage and lower revenues for the Utility Registrants that do not have decoupling mechanisms.

Generation’s customer-facing energy delivery activities face similar economic downturn risks, such as lower volumes sold and increased expense for uncollectible customer balances.

See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for additional information of the Registrants' credit risk.



## The Registrants could be negatively affected by the impacts of weather (All Registrants).

Weather conditions directly influence the demand for electricity and natural gas and affect the price of energy commodities. Temperatures above normal levels in the summer tend to increase summer cooling electricity demand and revenues, and temperatures below normal levels in the winter tend to increase winter heating electricity and gas demand and revenues. Moderate temperatures adversely affect the usage of energy and resulting revenues at PECO, DPL Delaware and ACE. Due to revenue decoupling, BGE, Pepco and DPL Maryland recognize revenues at MDPSC and DCPSC-approved levels per customer, regardless of what actual distribution volumes are for a billing period and are not affected by actual weather with the exception of major storms. ComEd's customer rates are adjusted to eliminate the favorable and unfavorable impacts of weather and customer usage patterns on distribution revenue.

Extreme weather conditions or damage resulting from storms could stress the Utility Registrants' transmission and distribution systems, communication systems and technology, resulting in increased maintenance and capital costs and limiting each company's ability to meet peak customer demand. First and third quarter financial results, in particular, are substantially dependent on weather conditions, and could make period comparisons less relevant.

Generation’s operations are also affected by weather, which affects demand for electricity as well as operating conditions. To the extent that weather is warmer in the summer or colder in the winter than assumed, Generation could require greater resources to meet its contractual commitments. Extreme weather conditions or storms could affect the availability of generation and its transmission, limiting Generation’s ability to source or send power to where it is sold. In addition, drought-like conditions limiting water usage could impact Generation’s ability to run certain generating assets at full capacity. These conditions, which cannot be accurately predicted, could cause Generation to seek additional capacity at a time when wholesale markets are tight or to seek to sell excess capacity at a time when markets are weak.

## Long-lived assets, goodwill and other assets could become impaired (All Registrants).

Long-lived assets represent the single largest asset class on the Registrants' statements of financial position. In addition, Exelon, ComEd and PHI have material goodwill balances.

The Registrants evaluate the recoverability of the carrying value of long-lived assets to be held and used whenever events or circumstances indicating a potential impairment exist. Factors such as, but not limited to, the business climate, including current and future energy and market conditions, environmental regulation, and the condition of assets are considered.

ComEd and PHI perform an assessment for possible impairment of their goodwill at least annually or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of the reporting units below their carrying amount. Regulatory actions or changes in significant assumptions, including discount and growth rates, utility sector market performance and transactions, projected operating and capital cash flows for ComEd's, Pepco's, DPL's, and ACE's business, and the fair value of debt, could potentially result in future impairments of Exelon's, PHI's, and ComEd's goodwill.

An impairment would require the Registrants to reduce the carrying value of the long-lived asset or goodwill to fair value through a non-cash charge to expense by the amount of the impairment. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates, Note 7 — Property, Plant and Equipment, Note 11 — Asset Impairments and Note 12 — Intangible Assets of the Combined Notes to the Consolidated Financial Statements for additional information on long-lived asset and goodwill impairments.

The Registrants could incur substantial costs in the event of non-performance by third-parties under indemnification agreements, or when the Registrants have guaranteed their performance. Generation is exposed to other credit risks in the power markets that are beyond its control (All Registrants).

The Registrants have entered into various agreements with counterparties that require those counterparties to reimburse a Registrant and hold it harmless against specified obligations and claims. To the extent that any of these counterparties are affected by deterioration in their creditworthiness or the agreements are otherwise determined to be unenforceable, the affected Registrant could be held responsible for the obligations. Each of the Utility



Registrants has transferred its former generation business to a third party and in each case the transferee has agreed to assume certain obligations and to indemnify the applicable Utility Registrant for such obligations. In connection with the restructurings under which ComEd, PECO and BGE transferred their generating assets to Generation, Generation assumed certain of ComEd's, PECO's and BGE's rights and obligations with respect to their former generation businesses. Further, ComEd, PECO and BGE have entered into agreements with third parties under which the third-party agreed to indemnify ComEd, PECO or BGE for certain obligations related to their respective former generation businesses that have been assumed by Generation as part of the restructuring. If the third-party, Generation or the transferee of Pepco's, DPL's or ACE's generation facilities experienced events that reduced its creditworthiness or the indemnity arrangement became unenforceable, the applicable Utility Registrant could be liable for any existing or future claims. In addition, the Utility Registrants have residual liability under certain laws in connection with their former generation facilities.

The Registrants have issued indemnities to third parties regarding environmental or other matters in connection with purchases and sales of assets and a Registrant could incur substantial costs to fulfill its obligations under these indemnities.

The Registrants have issued guarantees of the performance of third parties, which obligate the Registrant to perform in the event that the third parties do not perform. In the event of non-performance by those third parties, a Registrant could incur substantial cost to fulfill its obligations under these guarantees.

In the bilateral markets, Generation is exposed to the risk that counterparties that owe Generation money or are obligated to purchase energy or fuel from Generation, will not perform under their obligations for operational or financial reasons. In the event the counterparties to these arrangements fail to perform, Generation could be forced to purchase or sell energy or fuel in the wholesale markets at less favorable prices and incur additional losses, to the extent of amounts, if any, were already paid to the counterparties. In the spot markets, Generation is exposed to risk as a result of default sharing mechanisms that exist within certain markets, primarily RTOs and ISOs. Generation is also a party to agreements with entities in the energy sector that have experienced rating downgrades or other financial difficulties. In addition, Generation's retail sales subject it to credit risk through competitive electricity and natural gas supply activities to serve commercial and industrial companies, governmental entities and residential customers. Retail credit risk results when customers default on their contractual obligations. This risk represents the loss that could be incurred due to the nonpayment of a customer's account balance, as well as the loss from the resale of energy previously committed to serve the customer.

## Regulatory and Legislative Factors

Federal or state legislative or regulatory actions could negatively affect the scope and functioning of the wholesale markets (Exelon and Generation).

Approximately 70% of Generation’s generating resources, which include directly owned assets and capacity obtained through long-term contracts, are located in the area encompassed by PJM. Generation’s future results of operations are impacted by (1) FERC’s and PJM’s support for policies that favor the preservation of competitive wholesale power markets and recognize the value of zero-carbon electricity and resiliency and for states’ energy objectives and policies (2) the absence of material changes to market structures that would limit or otherwise negatively affect Exelon or Generation. Generation could also be affected by state laws, regulations or initiatives to subsidize existing or new generation.

FERC’s requirements for market-based rate authority could pose a risk that Generation may no longer satisfy FERC’s tests for market-based rates.

The Registrants’ are highly regulated and could be negatively affected by regulatory and legislative actions (All Registrants).

Substantially all aspects of the businesses of the Registrants are subject to comprehensive Federal or state regulation and legislation.

Generation’s consolidated financial statements are significantly affected by its sales and purchases of commodities at market-based rates, as opposed to cost-based or other similarly regulated rates and Federal and state regulatory and legislative developments related to emissions, climate change, capacity market mitigation, energy price information, resilience, fuel diversity and RPS. Legislative and regulatory efforts in Illinois, New York and New Jersey



to preserve the environmental attributes and reliability benefits of zero-emission nuclear-powered generating facilities through ZEC programs are or could be subject to legal and regulatory challenges and, if overturned, could result in the early retirement of certain of Generation's nuclear plants. See Note 3 — Regulatory Matters and Note 6 — Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information.

The Utility Registrants' consolidated financial statements are heavily dependent on the ability of the Utility Registrants to recover their costs for the retail purchase and distribution of power and natural gas to their customers.

Fundamental changes in regulations or other adverse legislative actions affecting the Registrants' businesses would require changes in their business planning models and operations. The Registrants cannot predict when or whether legislative and regulatory proposals could become law or what their effect will be on the Registrants.

Changes in the Utility Registrants' respective terms and conditions of service, including their respective rates, are subject to regulatory approval proceedings and/or negotiated settlements that are at times contentious, lengthy and subject to appeal, which lead to uncertainty as to the ultimate result and which could introduce time delays in effectuating rate changes (Exelon and the Utility Registrants).

The Utility Registrants are required to engage in regulatory approval proceedings as a part of the process of establishing the terms and rates for their respective services. These proceedings typically involve multiple parties, including governmental bodies and officials, consumer advocacy groups and various consumers of energy, who have differing concerns but who have the common objective of limiting rate increases or even reducing rates. Decisions are subject to appeal, potentially leading to additional uncertainty associated with the approval proceedings. The potential duration of such proceedings creates a risk that rates ultimately approved by the applicable regulatory body may not be sufficient for a Utility Registrant to recover its costs by the time the rates become effective. Established rates are also subject to subsequent prudence reviews by state regulators, whereby various portions of rates could be adjusted, subject to refund or disallowed, including recovery mechanisms for costs associated with the procurement of electricity or gas, bad debt, MGP remediation, smart grid infrastructure, and energy efficiency and demand response programs. In certain instances, the Utility Registrants could agree to negotiated settlements related to various rate matters, customer initiatives or franchise agreements. These settlements are subject to regulatory approval. The ultimate outcome and timing of regulatory rate proceedings have a significant effect on the ability of the Utility Registrants to recover their costs or earn an adequate return. See Note 3 — Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for additional information.

NRC actions could negatively affect the operations and profitability of Generation’s nuclear generating fleet (Exelon and Generation).

Regulatory risk. A change in the Atomic Energy Act or the applicable regulations or licenses could require a substantial increase in capital expenditures or could result in increased operating or decommissioning costs. Events at nuclear plants owned by others, as well as those owned by Generation, could cause the NRC to initiate such actions.

Spent nuclear fuel storage. The approval of a national repository for the storage of SNF and the timing of such facility opening, will significantly affect the costs associated with storage of SNF, and the ultimate amounts received from the DOE to reimburse Generation for these costs.

Any regulatory action relating to the timing and availability of a repository for SNF could adversely affect Generation’s ability to decommission fully its nuclear units. Generation cannot predict what, if any, fee may be established in the future for SNF disposal. See Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on the SNF obligation.

The Registrants could be subject to higher costs and/or penalties related to mandatory reliability standards, including the likely exposure of the Utility Registrants to the results of PJM’s RTEP and NERC compliance requirements (All Registrants).

The Registrants as users, owners and operators of the bulk power transmission system, including Generation and the Utility Registrants, are subject to mandatory reliability standards promulgated by NERC and enforced by FERC.



PECO, BGE and DPL as operators of natural gas distribution systems, PECO, BGE and DPL are also subject to mandatory reliability standards of the U.S. Department of Transportation. The standards are based on the functions that need to be performed to ensure the bulk power system operates reliably and are guided by reliability and market interface principles. Compliance with or changes in the reliability standards could subject the Registrants to higher operating costs and/or increased capital expenditures. In addition, the ICC, PAPUC, MDPSC, DCPSC, DPSC and NJBPU impose certain distribution reliability standards on the Utility Registrants. If the Registrants were found not to be in compliance with the Federal and State mandatory reliability standards, they could be subject to remediation costs as well as sanctions, which could include substantial monetary penalties.

## The Registrants could incur substantial costs to fulfill their obligations related to environmental and other matters (All Registrants).

The businesses which the Registrants operate are subject to extensive environmental regulation and legislation by local, state and Federal authorities. These laws and regulations affect the manner in which the Registrants conduct their operations and make capital expenditures including how they handle air and water emissions and solid waste disposal. Violations of these emission and disposal requirements could subject the Registrants to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs for remediation and clean-up costs, civil penalties and exposure to third parties' claims for alleged health or property damages or operating restrictions to achieve compliance. In addition, the Registrants are subject to liability under these laws for the remediation costs for environmental contamination of property now or formerly owned by the Registrants and of property contaminated by hazardous substances they generate. Remediation activities associated with MGP operations conducted by predecessor companies are one component of such costs. Also, the Registrants are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and could be subject to additional proceedings in the future.

If application of Section 316(b) of the Clean Water Act, which establishes a national requirement for reducing the adverse impacts to aquatic organisms at existing generating stations, requires the retrofitting of cooling water intake structures at Salem or other Exelon power plants, this development could result in material costs of compliance. See ITEM 1. BUSINESS — Environmental Regulation for additional information.

The Registrants could be negatively affected by challenges to tax positions taken, tax law changes and the inherent difficulty in quantifying potential tax effects of business decisions. (All Registrants).

The Registrants are required to make judgments in order to estimate their obligations to taxing authorities. These tax obligations include income, real estate, sales and use and employment-related taxes and ongoing appeal issues related to these tax matters. These judgments include reserves established for potential adverse outcomes regarding tax positions that have been taken that could be subject to challenge by the tax authorities. See Note 1 — Significant Accounting Policies and Note 13 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.

The Registrants could be negatively affected by federal and state RPS and/or energy conservation legislation, along with energy conservation by customers (All Registrants).

Changes to current state legislation or the development of Federal legislation that requires the use of clean, renewable and alternate fuel sources could significantly impact Generation and the Utility Registrants, especially if timely cost recovery is not allowed for Utility Registrants. The impact could include increased costs and increased rates for customers.

Federal and state legislation mandating the implementation of energy conservation programs that require the implementation of new technologies, such as smart meters and smart grid, could increase capital expenditures and could significantly impact the Utility Registrants consolidated financial statements if timely cost recovery is not allowed. Furthermore, regulated energy consumption reduction targets and declines in customer energy consumption resulting from the implementation of new energy conservation technologies could lead to a decline in the revenues of the Registrants. See ITEM 1. BUSINESS — Environmental Regulation — Renewable and Alternative Energy Portfolio Standards for additional information.



Generation’s affiliation with the Utility Registrants, together with the presence of a substantial percentage of Generation’s physical asset base within the Utility Registrants’ service territories, could increase Generation’s cost of doing business to the extent future complaints or challenges regarding the Utility Registrants’ retail rates result in settlements or legislative or regulatory requirements funded in part by Generation (Exelon and Generation).

Generation has significant generating resources within the service areas of the Utility Registrants and makes significant sales to each of them. Those facts tend to cause Generation to be directly affected by developments in those markets. Government officials, legislators and advocacy groups are aware of Generation's affiliation with the Utility Registrants and its sales to each of them. In periods of rising utility rates, particularly when driven by increased costs of energy production and supply, those officials and advocacy groups could question or challenge costs and transactions incurred by the Utility Registrants with Generation, irrespective of any previous regulatory processes or approvals underlying those transactions. These challenges could increase the time, complexity and cost of the associated regulatory proceedings, and the occurrence of such challenges could subject Generation to a level of scrutiny not faced by other unaffiliated competitors in those markets. In addition, government officials and legislators could seek ways to force Generation to contribute to efforts to mitigate potential or actual rate increases, through measures such as generation-based taxes.

The Registrants could be subject to adverse publicity and reputational risks, which make them vulnerable to negative customer perception and could lead to increased regulatory oversight or other consequences (All Registrants).

The Registrants could be the subject of public criticism. Adverse publicity of this nature could render public service commissions and other regulatory and legislative authorities less likely to view energy companies such as Exelon and its subsidiaries in a favorable light, and could cause Exelon and its subsidiaries to be susceptible to less favorable legislative and regulatory outcomes, as well as increased regulatory oversight and more stringent legislative or regulatory requirements (e.g. disallowances of costs, lower ROEs).

Legal proceedings could result in a negative outcome, which the Registrants cannot predict (All Registrants).

The Registrants are involved in legal proceedings, claims and litigation arising out of their business operations. The material ones are summarized in Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements. Adverse outcomes in these proceedings could require significant expenditures, result in lost revenue or restrict existing business activities.

Generation’s financial performance could be negatively affected by risks arising from its ownership and operation of hydroelectric facilities (Exelon and Generation).

FERC has the exclusive authority to license most non-Federal hydropower projects located on navigable waterways, Federal lands or connected to the interstate electric grid. Generation cannot predict whether it will receive all the regulatory approvals for the renewed licenses of its hydroelectric facilities. If FERC does not issue new operating licenses for Generation’s hydroelectric facilities or a station cannot be operated through the end of its operating license, Generation’s results of operations could be adversely affected by increased depreciation rates and accelerated future decommissioning costs, since depreciation rates and decommissioning cost estimates currently include assumptions that license renewal will be received. Generation could also lose revenue and incur increased fuel and purchased power expense to meet supply commitments. In addition, conditions could be imposed as part of the license renewal process that could adversely affect operations, could require a substantial increase in capital expenditures, could result in increased operating costs or could render the project uneconomic. Similar effects could result from a change in the Federal Power Act or the applicable regulations due to events at hydroelectric facilities owned by others, as well as those owned by Generation.

Exelon and ComEd have received requests for information related to government investigations. The outcome of the investigations could have a material adverse effect on their reputation and consolidated financial statements (Exelon and ComEd).

Exelon and ComEd received a grand jury subpoena in the second quarter of 2019 from the U.S. Attorney’s Office for the Northern District of Illinois requiring production of information concerning their lobbying activities in the state



of Illinois. On October 4, 2019, Exelon and ComEd received a second grand jury subpoena from the U.S. Attorney's Office for the Northern District of Illinois requiring production of records of any communications with certain individuals and entities. On October 22, 2019, the SEC notified Exelon and ComEd that it has also opened an investigation into their lobbying activities. Exelon and ComEd have cooperated fully, including by providing additional information requested by the U.S. Attorney's Office and the SEC, and intend to continue to cooperate fully and expeditiously with the U.S. Attorney's Office and the SEC. The outcome of the U.S. Attorney's Office and SEC investigations cannot be predicted and could subject Exelon and ComEd to criminal or civil penalties, sanctions or other remedial measures. Any of the foregoing, as well as the appearance of non-compliance with anti-corruption and anti-bribery laws, could have an adverse impact on Exelon's and ComEd's reputation or relationship with regulatory and legislative authorities, customers and other stakeholders, as well as their consolidated financial statements.

## Operational Factors

## The Registrants are subject to risks associated with climate change (All Registrants).

Physical plants could be placed at greater risk of damage should changes in the global climate produce unusual variations in temperature and weather patterns, resulting in more intense, frequent and extreme weather events, unprecedented levels of precipitation and a change in sea level. The Registrants' operate in the Midwest and East Coast of the United States, areas that historically have been prone to various types of severe weather events, such that the Registrants have well developed response and recovery programs based on these historical events. Still disruption or failure of electric generation, transmission or distribution systems or natural gas production, transmission, storage or distribution systems in the event of a hurricane, tornado or other severe weather event, or otherwise, could prevent the Registrants from operating their business in the normal course.

The Registrants are considering ways to address the effect of GHG emissions on climate change. If carbon reduction regulation or legislation becomes effective, the Registrants could incur costs either to limit further the GHG emissions from their operations or to procure emission allowance credits for Generation’s fossil fuel-fired generation. See ITEM 1. BUSINESS — Global Climate Change.

Generation’s financial performance could be negatively affected by matters arising from its ownership and operation of nuclear facilities (Exelon and Generation).

Nuclear capacity factors. Capacity factors for nuclear generating units, significantly affect Generation’s results of operations. Lower capacity factors could decrease Generation’s revenues and increase operating costs by requiring Generation to produce additional energy from primarily its fossil facilities or purchase additional energy in the spot or forward markets in order to satisfy Generation’s obligations to committed third-party sales, including the Utility Registrants. These sources generally have higher costs than Generation incurs to produce energy from its nuclear stations.

Nuclear refueling outages. In general, refueling outages are planned to occur once every 18 to 24 months. The total number of refueling outages, along with their duration, could have a significant impact on Generation’s results of operations. When refueling outages last longer than anticipated or Generation experiences unplanned outages, capacity factors decrease, and Generation faces lower margins due to higher energy replacement costs and/or lower energy sales and higher operating and maintenance costs.

Nuclear fuel quality. The quality of nuclear fuel utilized by Generation could affect the efficiency and costs of Generation’s operations. Remediation actions could result in increased costs due to accelerated fuel amortization, increased outage costs and/or increased costs due to decreased generation capabilities.

Operational risk. Operations at any of Generation’s nuclear generation plants could degrade to the point where Generation must shut down the plant or operate at less than full capacity. If this were to happen, identifying and correcting the causes could require significant time and expense. Generation could choose to close a plant rather than incur the expense of restarting it or returning the plant to full capacity. In either event, Generation could lose revenue and incur increased fuel and purchased power expense to meet supply commitments.

For plants operated but not wholly owned by Generation, Generation could also incur liability to the co-owners. For nuclear plants not operated and not wholly owned by Generation, from which Generation receives a portion of the plants' output, Generation's results of operations are dependent on the operational performance of the operators and could be adversely affected by a significant event at those plants. Additionally, poor operating performance at



nuclear plants not owned by Generation could result in increased regulation and reduced public support for nuclear-fueled energy. In addition, closure of generating plants owned by others, or extended interruptions of generating plants or failure of transmission lines, could affect transmission systems that could adversely affect the sale and delivery of electricity in markets served by Generation.

Nuclear major incident risk and insurance. The consequences of a major incident could be severe and include loss of life and property damage. Any resulting liability from a nuclear plant major incident within the United States, owned or operated by Generation or owned by others, could exceed Generation's resources, including insurance coverage. Generation is a member of an industry mutual insurance company, NEIL, which provides property and business interruption insurance for Generation's nuclear operations. Uninsured losses and other expenses, to the extent not recovered from insurers or the nuclear industry, could be borne by Generation. Additionally, an accident or other significant event at a nuclear plant within the United States or abroad, whether owned Generation or others, could result in increased regulation and reduced public support for nuclear-fueled energy.

As required by the Price-Anderson Act, Generation carries the maximum available amount of nuclear liability insurance, $450 million for each operating site. Claims exceeding that amount are covered through mandatory participation in a financial protection pool. In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay claims exceeding the $13.9 billion limit for a single incident.

See Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information of nuclear insurance.

Decommissioning obligation and funding. NRC regulations require that licenses of nuclear generating facilities demonstrate reasonable assurance that funds will be available in certain minimum amounts at the end of the life of the facility to decommission the facility.

Generation recognizes as a liability the present value of the estimated future costs to decommission its nuclear facilities. The estimated liability is based on assumptions in the approach and timing of decommissioning the nuclear facilities, estimation of decommissioning costs and Federal and state regulatory requirements. The costs of such decommissioning may substantially exceed such liability, as facts, circumstances or our estimates may change, including changes in the approach and timing of decommissioning activities, changes in decommissioning costs, changes in Federal or state regulatory requirements on the decommissioning of such facilities, other changes in our estimates or Generation's ability to effectively execute on its planned decommissioning activities.

Generation makes contributions to certain trust funds of the former PECO units based on amounts being collected by PECO from its customers and remitted to Generation. While Generation, through PECO, has recourse to collect additional amounts from PECO customers (subject to certain limitations and thresholds), it has no recourse to collect additional amounts from utility customers for any of its other nuclear units if there is a shortfall of funds necessary for decommissioning. If circumstances changed such that Generation would be unable to continue to make contributions to the trust funds of the former PECO units based on amounts collected from PECO customers, or if Generation no longer had recourse to collect additional amounts from PECO customers if there was a shortfall of funds for decommissioning, the adequacy of the trust funds related to the former PECO units could be negatively affected.

Should the expected value of the NDT fund for any former ComEd unit fall below the amount of the expected decommissioning obligation for that unit, the accounting to offset decommissioning-related activities in the Consolidated Statement of Operations and Comprehensive Income for that unit would be discontinued, the decommissioning-related activities would be recognized in the Consolidated Statements of Operations and Comprehensive Income and the adverse impact to Exelon's and Generation's financial statements could be material. Any changes to the PECO regulatory agreements could impact Exelon's and Generation's ability to offset decommissioning-related activities within the Consolidated Statement of Operations and Comprehensive Income, and the impact to Exelon's and Generation's financial statements could be material.

Forecasting trust fund investment earnings and costs to decommission nuclear generating stations requires significant judgment, and actual results could differ significantly from current estimates. If the investments held by Generation's NDTs are not sufficient to fund the decommissioning of Generation's nuclear units, Generation could be required to take steps, such as providing financial guarantees through letters of credit or parent company guarantees or making additional contributions to the trusts, which could be significant, to ensure that the trusts are adequately funded and that current and future NRC minimum funding requirements are met.



See Note 9 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information.

The Utility Registrants' operating costs are affected by their ability to maintain the availability and reliability of their delivery and operational systems (Exelon and the Utility Registrants).

Failures of the equipment or facilities used in the Utility Registrants' delivery systems could interrupt the electric transmission and electric and natural gas delivery, which could result in a loss of revenues and an increase in maintenance and capital expenditures. Equipment or facilities failures can be due to a number of factors, including natural causes such as weather or information systems failure. Specifically, if the implementation of advanced metering infrastructure, smart grid or other technologies in the Utility Registrants' service territory fail to perform as intended or are not successfully integrated with billing and other information systems, or if any of the financial, accounting, or other data processing systems fail or have other significant shortcomings, the Utility Registrants' financial results could be negatively impacted. In addition, dependence upon automated systems could further increase the risk that operational system flaws or internal and/or external tampering or manipulation of those systems will result in losses that are difficult to detect.

Regulated utilities, which are required to provide service to all customers within their service territory, have generally been afforded liability protections against claims by customers relating to failure of service. Under Illinois law, however, ComEd could be required to pay damages to its customers in some circumstances involving extended outages affecting large numbers of its customers, which could be material.

The Registrants are subject to physical security and cybersecurity risks (All Registrants).

The Registrants face physical security and cybersecurity risks. Threat sources continue to seek to exploit potential vulnerabilities in the electric and natural gas utility industry associated with protection of sensitive and confidential information, grid infrastructure and other energy infrastructures, and such attacks and disruptions, both physical and cyber, are becoming increasingly sophisticated and dynamic. Continued implementation of advanced digital technologies increases the potentially unfavorable impacts of such attacks. A security breach of the physical assets or information systems of the Registrants, their competitors, vendors, business partners and interconnected entities in RTOs and ISOs, or regulators could impact the operation of the generation fleet and/or reliability of the transmission and distribution system or result in the theft or inappropriate release of certain types of information, including critical infrastructure information, sensitive customer, vendor and employee data, trading or other confidential data. The risk of these system-related events and security breaches occurring continues to intensify, and while the Registrants have been, and will likely continue to be, subjected to physical and cyber-attacks, to date none has directly experienced a material breach or disruption to its network or information systems or our service operations. However, as such attacks continue to increase in sophistication and frequency, the Registrants may be unable to prevent all such attacks in the future. If a significant breach were to occur, the reputation of the Registrants could be negatively affected, customer confidence in the Registrants or others in the industry could be diminished, or the Registrants could be subject to legal claims, loss of revenues, increased costs or operations shutdown. Moreover, the amount and scope of insurance maintained against losses resulting from any such events or security breaches may not be sufficient to cover losses or otherwise adequately compensate for any disruptions to business that could result.

The Utility Registrants' deployment of smart meters throughout their service territories could increase the risk of damage from an intentional disruption of the system by third parties.

In addition, new or updated security regulations or unforeseen threat sources could require changes in current measures taken by the Registrants or their business operations and could adversely affect their consolidated financial statements.

The Registrants’ employees, contractors, customers and the general public could be exposed to a risk of injury due to the nature of the energy industry (All Registrants).

Employees and contractors throughout the organization work in, and customers and the general public could be exposed to, potentially dangerous environments near the Registrants' operations. As a result, employees, contractors, customers and the general public are at some risk for serious injury, including loss of life. These risks include nuclear accidents, dam failure, gas explosions, pole strikes and electric contact cases.



Natural disasters, war, acts and threats of terrorism, pandemic and other significant events could negatively impact the Registrants' results of operations, their ability to raise capital and their future growth (All Registrants).

Generation’s fleet of power plants and the Utility Registrants’ distribution and transmission infrastructures could be affected by natural disasters and extreme weather events, which could result in increased costs, including supply chain costs. An extreme weather event within the Registrants’ service areas can also directly affect their capital assets, causing disruption in service to customers due to downed wires and poles or damage to other operating equipment. Natural disasters and other significant events increase the risk to Generation that the NRC or other regulatory or legislative bodies could change the laws or regulations governing, among other things, operations, maintenance, licensed lives, decommissioning, SNF storage, insurance, emergency planning, security and environmental and radiological matters. In addition, natural disasters could affect the availability of a secure and economical supply of water in some locations, which is essential for Generation’s continued operation, particularly the cooling of generating units.

The impact that potential terrorist attacks could have on the industry and on Exelon is uncertain. The Registrants face a risk that their operations would be direct targets or indirect casualties of an act of terror. Any retaliatory military strikes or sustained military campaign could affect their operations in unpredictable ways, such as changes in insurance markets and disruptions of fuel supplies and markets, particularly oil. Furthermore, these catastrophic events could compromise the physical or cybersecurity of Exelon’s facilities, which could adversely affect Exelon’s ability to manage its business effectively. Instability in the financial markets as a result of terrorism, war, natural disasters, pandemic, credit crises, recession or other factors also could result in a decline in energy consumption or interruption of fuel or the supply chain. In addition, the implementation of security guidelines and measures has resulted in and is expected to continue to result in increased costs.

The Registrants could be significantly affected by the outbreak of a pandemic. Exelon has plans in place to respond to a pandemic. However, depending on the severity of a pandemic and the resulting impacts to workforce and other resource availability, the ability to operate Exelon's generating and transmission and distribution assets could be affected.

In addition, Exelon maintains a level of insurance coverage consistent with industry practices against property, casualty and cybersecurity losses subject to unforeseen occurrences or catastrophic events that could damage or destroy assets or interrupt operations. However, there can be no assurance that the amount of insurance will be adequate to address such property and casualty losses.

The Registrants’ businesses are capital intensive, and their assets could require significant expenditures to maintain and are subject to operational failure, which could result in potential liability (All Registrants).

The Registrants’ businesses are capital intensive and require significant investments by Generation in electric generating facilities and by the Utility Registrants in transmission and distribution infrastructure projects. Equipment, even if maintained in accordance with good utility practices, is subject to operational failure, including events that are beyond the Registrants’ control, and could require significant expenditures to operate efficiently. The Registrants consolidated financial statements could be negatively affected if they were unable to effectively manage their capital projects or raise the necessary capital. See ITEM 1. BUSINESS for additional information regarding the Registrants’ potential future capital expenditures.

The Utility Registrants’ respective ability to deliver electricity, their operating costs and their capital expenditures could be negatively impacted by transmission congestion and failures of neighboring transmission systems (Exelon and the Utility Registrants).

Demand for electricity within the Utility Registrants' service areas could stress available transmission capacity requiring alternative routing or curtailment of electricity usage. Also, insufficient availability of electric supply to meet customer demand could jeopardize the Utility Registrants' ability to comply with reliability standards and strain customer and regulatory agency relationships. As with all utilities, potential concerns over transmission capacity or generation facility retirements could result in PJM or FERC requiring the Utility Registrants to upgrade or expand their respective transmission systems through additional capital expenditures.



PJM's systems and operations are designed to ensure the reliable operation of the transmission grid and prevent the operations of one utility from having an adverse impact on the operations of the other utilities. However, service interruptions at other utilities may cause interruptions in the Utility Registrants' service areas.

The Registrants consolidated financial statements could be negatively affected if they fail to attract and retain an appropriately qualified workforce (All Registrants).

Certain events, such as an employee strike, loss of contract resources due to a major event, and an aging workforce without appropriate replacements, could lead to operating challenges and increased costs for the Registrants. The challenges include lack of resources, loss of knowledge and a lengthy time period associated with skill development. In this case, costs, including costs for contractors to replace employees, productivity costs and safety costs, could arise. The Registrants are particularly affected due to the specialized knowledge required of the technical and support employees for their generation, transmission and distribution operations.

The Registrants could make acquisitions or investments in new business initiatives and new markets, which may not be successful or achieve the intended financial results (All Registrants).

Generation could continue to pursue growth in its existing businesses and markets and further diversification across the competitive energy value chain. This could include investment opportunities in renewables, development of natural gas generation, nuclear advisory or operating services for third parties, distributed generation, potential expansion of the existing wholesale gas businesses and entry into LNG. Such initiatives could involve significant risks and uncertainties, including distraction of management from current operations, inadequate return on capital, and unidentified issues not discovered during diligence performed prior to launching an initiative or entering a market. Additionally, it is possible that FERC, state public utility commissions or others could impose certain other restrictions on such transactions. All of these factors could result in higher costs or lower revenues than expected, resulting in lower than planned returns on investment.

The Utility Registrants face risks associated with their regulatory-mandated initiatives, such as smart grids and utility of the future. These risks include, but are not limited to, cost recovery, regulatory concerns, cybersecurity and obsolescence of technology. Such initiatives may not be successful.

The Registrants may not realize or achieve the anticipated cost savings through the cost management efforts (All Registrants).

The Registrants' future financial performance and level of profitability is dependent, in part, on various cost reduction initiatives. The Registrants may encounter challenges in executing these cost reduction initiatives and not achieve the intended cost savings.

ITEM 1B. UNRESOLVED STAFF COMMENTS

## All Registrants

None.



## Generation

The following table presents Generation’s interests in net electric generating capacity by station at December 31, 2019:

<table><tr><td>Station(a)</td><td>Location</td><td>No. of Units</td><td>Percent Owned(b)</td><td>Primary Fuel Type</td><td>Primary Dispatch Type(c)</td><td>Net Generation Capacity (MW)(d)</td></tr><tr><td>Midwest</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Braidwood</td><td>Braidwood, IL</td><td>2</td><td></td><td>Uranium</td><td>Base-load</td><td>2,386</td></tr><tr><td>Byron</td><td>Byron, IL</td><td>2</td><td></td><td>Uranium</td><td>Base-load</td><td>2.347</td></tr><tr><td>LaSalle</td><td>Seneca, IL</td><td>2</td><td></td><td>Uranium</td><td>Base-load</td><td>2,320</td></tr><tr><td>Dresden</td><td>Morris, IL</td><td>2</td><td></td><td>Uranium</td><td>Base-load</td><td>1,845</td></tr><tr><td>Quad Cities</td><td>Cordova, IL</td><td>2</td><td>75</td><td>Uranium</td><td>Base-load</td><td>1,403 (e)</td></tr><tr><td>Clinton</td><td>Clinton, IL</td><td>1</td><td></td><td>Uranium</td><td>Base-load</td><td>1,069</td></tr><tr><td>Michigan Wind 2</td><td>Sanilac Co., MI</td><td>50</td><td>51 (g)</td><td>Wind</td><td>Base-load</td><td>46 (e)</td></tr><tr><td>Beebe</td><td>Gratiot Co., MI</td><td>34</td><td>51 (g)</td><td>Wind</td><td>Base-load</td><td>42 (e)</td></tr><tr><td>Michigan Wind 1</td><td>Huron Co., MI</td><td>46</td><td>51 (g)</td><td>Wind</td><td>Base-load</td><td>35 (e)</td></tr><tr><td>Harvest 2</td><td>Huron Co., MI</td><td>33</td><td>51 (g)</td><td>Wind</td><td>Base-load</td><td>30 (e)</td></tr><tr><td>Harvest</td><td>Huron Co., MI</td><td>32</td><td>51 (g)</td><td>Wind</td><td>Base-load</td><td>27 (e)</td></tr><tr><td>Beebe 1B</td><td>Gratiot Co., MI</td><td>21</td><td>51 (g)</td><td>Wind</td><td>Base-load</td><td>26 (e)</td></tr><tr><td>Ewington</td><td>Jackson Co., MN</td><td>10</td><td>99</td><td>Wind</td><td>Base-load</td><td>20 (e)</td></tr><tr><td>City Solar</td><td>Chicago, IL</td><td>1</td><td></td><td>Solar</td><td>Base-load</td><td>9</td></tr><tr><td>Solar Ohio</td><td>Toledo, OH</td><td>2</td><td></td><td>Solar</td><td>Base-load</td><td>4</td></tr><tr><td>Blue Breezes</td><td>Faribault Co., MN</td><td>2</td><td></td><td>Wind</td><td>Base-load</td><td>3</td></tr><tr><td>CP Windfarm</td><td>Faribault Co., MN</td><td>2</td><td>51 (g)</td><td>Wind</td><td>Base-load</td><td>2 (e)</td></tr><tr><td>Southeast Chicago</td><td>Chicago, IL</td><td>8</td><td></td><td>Gas</td><td>Peaking</td><td>296 (k)</td></tr><tr><td>Clinton Battery Storage</td><td>Blanchester, OH</td><td>1</td><td></td><td>Energy Storage</td><td>Peaking</td><td>10</td></tr><tr><td>Total Midwest</td><td></td><td></td><td></td><td></td><td></td><td>11,920</td></tr><tr><td>Mid-Atlantic</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Limerick</td><td>Sanatoga, PA</td><td>2</td><td></td><td>Uranium</td><td>Base-load</td><td>2,317</td></tr><tr><td>Peach Bottom</td><td>Delta, PA</td><td>2</td><td>50</td><td>Uranium</td><td>Base-load</td><td>1,324 (e)</td></tr><tr><td>Salem</td><td>Lower Alloways Creek Township, NJ</td><td>2</td><td>42.59</td><td>Uranium</td><td>Base-load</td><td>998 (e)</td></tr><tr><td>Calvert Cliffs</td><td>Lusby, MD</td><td>2</td><td>50.01 (f)</td><td>Uranium</td><td>Base-load</td><td>895 (e)</td></tr><tr><td>Conowingo</td><td>Darlington, MD</td><td>11</td><td></td><td>Hydroelectric</td><td>Base-load</td><td>572</td></tr><tr><td>Criterion</td><td>Oakland, MD</td><td>28</td><td>51 (g)</td><td>Wind</td><td>Base-load</td><td>36 (e)</td></tr><tr><td>Fair Wind</td><td>Garrett County, MD</td><td>12</td><td></td><td>Wind</td><td>Base-load</td><td>30</td></tr><tr><td>Solar MC</td><td>Various, MD</td><td>41</td><td></td><td>Solar</td><td>Base-load</td><td>39</td></tr><tr><td>Fourmile Ridge</td><td>Garrett County, MD</td><td>16</td><td>51 (g)</td><td>Wind</td><td>Base-load</td><td>20 (e)</td></tr></table>



<table><tr><td>Station(a)</td><td>Location</td><td>No. of Units</td><td>Percent Owned(b)</td><td>Primary Fuel Type</td><td>Primary Dispatch Type(c)</td><td>Net Generation Capacity (MW)(d)</td></tr><tr><td>Solar New Jersey 1</td><td>Various, NJ</td><td>5</td><td></td><td>Solar</td><td>Base-load</td><td>18</td></tr><tr><td>Solar New Jersey 2</td><td>Various, NJ</td><td>2</td><td></td><td>Solar</td><td>Base-load</td><td>11</td></tr><tr><td>Solar Horizons</td><td>Emmitsburg, MD</td><td>1</td><td>51 (g)</td><td>Solar</td><td>Base-load</td><td>8 (e)</td></tr><tr><td>Solar Maryland</td><td>Various, MD</td><td>11</td><td></td><td>Solar</td><td>Base-load</td><td>8</td></tr><tr><td>Solar Maryland 2</td><td>Various, MD</td><td>3</td><td></td><td>Solar</td><td>Base-load</td><td>8</td></tr><tr><td>JBAB Solar</td><td>District of Columbia</td><td>4</td><td></td><td>Solar</td><td>Base-load</td><td>7</td></tr><tr><td>Gateway Solar</td><td>Berlin, MD</td><td>1</td><td></td><td>Solar</td><td>Base-load</td><td>7</td></tr><tr><td>Constellation New Energy</td><td>Gaithersburg, MD</td><td>3</td><td></td><td>Solar</td><td>Base-load</td><td>6</td></tr><tr><td>Solar Federal</td><td>Trenton, NJ</td><td>1</td><td></td><td>Solar</td><td>Base-load</td><td>5</td></tr><tr><td>Solar New Jersey 3</td><td>Middle Township, NJ</td><td>5</td><td>51 (g)</td><td>Solar</td><td>Base-load</td><td>1 (e)</td></tr><tr><td>Solar DC</td><td>District of Columbia</td><td>1</td><td></td><td>Solar</td><td>Base-load</td><td>1</td></tr><tr><td>Muddy Run</td><td>Drumore, PA</td><td>8</td><td></td><td>Hydroelectric</td><td>Intermediate</td><td>1,070</td></tr><tr><td>Eddystone 3, 4</td><td>Eddystone, PA</td><td>2</td><td></td><td>Oil/Gas</td><td>Peaking</td><td>760</td></tr><tr><td>Perryman</td><td>Aberdeen, MD</td><td>5</td><td></td><td>Oil/Gas</td><td>Peaking</td><td>404</td></tr><tr><td>Croydon</td><td>West Bristol, PA</td><td>8</td><td></td><td>Oil</td><td>Peaking</td><td>391</td></tr><tr><td>Handsome Lake</td><td>Kennerdell, PA</td><td>5</td><td></td><td>Gas</td><td>Peaking</td><td>268</td></tr><tr><td>Notch Cliff</td><td>Baltimore, MD</td><td>8</td><td></td><td>Gas</td><td>Peaking</td><td>117 (j)</td></tr><tr><td>Westport</td><td>Baltimore, MD</td><td>1</td><td></td><td>Gas</td><td>Peaking</td><td>116 (j)</td></tr><tr><td>Richmond</td><td>Philadelphia, PA</td><td>2</td><td></td><td>Oil</td><td>Peaking</td><td>98</td></tr><tr><td>Philadelphia Road</td><td>Baltimore, MD</td><td>4</td><td></td><td>Oil</td><td>Peaking</td><td>61</td></tr><tr><td>Eddystone</td><td>Eddystone, PA</td><td>4</td><td></td><td>Oil</td><td>Peaking</td><td>60</td></tr><tr><td>Fairless Hills</td><td>Fairless Hills, PA</td><td>2</td><td></td><td>Landfill Gas</td><td>Peaking</td><td>60 (j)</td></tr><tr><td>Delaware</td><td>Philadelphia, PA</td><td>4</td><td></td><td>Oil</td><td>Peaking</td><td>56</td></tr><tr><td>Southwark</td><td>Philadelphia, PA</td><td>4</td><td></td><td>Oil</td><td>Peaking</td><td>52</td></tr><tr><td>Falls</td><td>Morrisville, PA</td><td>3</td><td></td><td>Oil</td><td>Peaking</td><td>51</td></tr><tr><td>Moser</td><td>Lower Pottsgrove Twp., PA</td><td>3</td><td></td><td>Oil</td><td>Peaking</td><td>51</td></tr><tr><td>Chester</td><td>Chester, PA</td><td>3</td><td></td><td>Oil</td><td>Peaking</td><td>39</td></tr><tr><td>Schuylkill</td><td>Philadelphia, PA</td><td>2</td><td></td><td>Oil</td><td>Peaking</td><td>30</td></tr><tr><td>Salem</td><td>Lower Alloways Creek Township, NJ</td><td>1</td><td>42.59</td><td>Oil</td><td>Peaking</td><td>16 (e)</td></tr><tr><td>Pennsbury</td><td>Morrisville, PA</td><td>2</td><td></td><td>Landfill Gas</td><td>Peaking</td><td>4 (e)</td></tr><tr><td>Total Mid-Atlantic</td><td></td><td></td><td></td><td></td><td></td><td>10,015</td></tr><tr><td>ERCOT</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Whitetail</td><td>Webb County, TX</td><td>57</td><td>51 (g)</td><td>Wind</td><td>Base-load</td><td>46 (e)</td></tr><tr><td>Sendero</td><td>Jim Hogg and Zapata County, TX</td><td>39</td><td>51 (g)</td><td>Wind</td><td>Base-load</td><td>40 (e)</td></tr></table>



<table><tr><td>Station(a)</td><td>Location</td><td>No. of Units</td><td>Percent Owned(b)</td><td>Primary Fuel Type</td><td>Primary Dispatch Type(c)</td><td>Net Generation Capacity (MW)(d)</td></tr><tr><td>Constellation Solar Texas</td><td>Various, TX</td><td>11</td><td></td><td>Solar</td><td>Base-load</td><td>13</td></tr><tr><td>Colorado Bend II</td><td>Wharton, TX</td><td>3</td><td></td><td>Gas</td><td>Intermediate</td><td>1,140</td></tr><tr><td>Wolf Hollow II</td><td>Granbury, TX</td><td>3</td><td></td><td>Gas</td><td>Intermediate</td><td>1,115</td></tr><tr><td>Handley 3</td><td>Fort Worth, TX</td><td>1</td><td></td><td>Gas</td><td>Intermediate</td><td>395</td></tr><tr><td>Handley 4, 5</td><td>Fort Worth, TX</td><td>2</td><td></td><td>Gas</td><td>Peaking</td><td>870</td></tr><tr><td colspan="6">Total ERCOT</td><td>3,619</td></tr><tr><td colspan="7">New York</td></tr><tr><td>Nine Mile Point</td><td>Scriba, NY</td><td>2</td><td>50.01 (f)</td><td>Uranium</td><td>Base-load</td><td>838 (e)</td></tr><tr><td>FitzPatrick</td><td>Scriba, NY</td><td>1</td><td></td><td>Uranium</td><td>Base-load</td><td>842</td></tr><tr><td>Ginna</td><td>Ontario, NY</td><td>1</td><td>50.01 (f)</td><td>Uranium</td><td>Base-load</td><td>288 (e)</td></tr><tr><td>Solar New York</td><td>Bethlehem, NY</td><td>1</td><td></td><td>Solar</td><td>Base-load</td><td>3</td></tr><tr><td colspan="6">Total New York</td><td>1,971</td></tr><tr><td colspan="7">Other</td></tr><tr><td>Antelope Valley</td><td>Lancaster, CA</td><td>1</td><td></td><td>Solar</td><td>Base-load</td><td>242</td></tr><tr><td>Bluestem</td><td>Beaver County, OK</td><td>60</td><td>51 (g)(h)</td><td>Wind</td><td>Base-load</td><td>101 (e)</td></tr><tr><td>Shooting Star</td><td>Kiowa County, KS</td><td>65</td><td>51 (g)</td><td>Wind</td><td>Base-load</td><td>53 (e)</td></tr><tr><td>Albany Green Energy</td><td>Albany, GA</td><td>1</td><td>99 (i)</td><td>Biomass</td><td>Base-load</td><td>53</td></tr><tr><td>Solar Arizona</td><td>Various, AZ</td><td>127</td><td></td><td>Solar</td><td>Base-load</td><td>46</td></tr><tr><td>Bluegrass Ridge</td><td>King City, MO</td><td>27</td><td>51 (g)</td><td>Wind</td><td>Base-load</td><td>29 (e)</td></tr><tr><td>California PV Energy 2</td><td>Various, CA</td><td>90</td><td></td><td>Solar</td><td>Base-load</td><td>28</td></tr><tr><td>Conception</td><td>Barnard, MO</td><td>24</td><td>51 (g)</td><td>Wind</td><td>Base-load</td><td>26 (e)</td></tr><tr><td>Cow Branch</td><td>Rock Port, MO</td><td>24</td><td>51 (g)</td><td>Wind</td><td>Base-load</td><td>26 (e)</td></tr><tr><td>Solar Arizona 2</td><td>Various, AZ</td><td>56</td><td></td><td>Solar</td><td>Base-load</td><td>34</td></tr><tr><td>California PV Energy</td><td>Various, CA</td><td>53</td><td></td><td>Solar</td><td>Base-load</td><td>21</td></tr><tr><td>Mountain Home</td><td>Glenns Ferry, ID</td><td>20</td><td>51 (g)</td><td>Wind</td><td>Base-load</td><td>21 (e)</td></tr><tr><td>High Mesa</td><td>Elmore Co., ID</td><td>19</td><td>51 (g)</td><td>Wind</td><td>Base-load</td><td>20 (e)</td></tr><tr><td>Echo 1</td><td>Echo, OR</td><td>21</td><td>50.49 (g)</td><td>Wind</td><td>Base-load</td><td>17 (e)</td></tr><tr><td>Sacramento PV Energy</td><td>Sacramento, CA</td><td>4</td><td>51 (g)</td><td>Solar</td><td>Base-load</td><td>15 (e)</td></tr><tr><td>Cassia</td><td>Buhl, ID</td><td>14</td><td>51 (g)</td><td>Wind</td><td>Base-load</td><td>15 (e)</td></tr><tr><td>Wildcat</td><td>Lovington, NM</td><td>13</td><td>51 (g)</td><td>Wind</td><td>Base-load</td><td>14 (e)</td></tr><tr><td>Echo 2</td><td>Echo, OR</td><td>10</td><td>51 (g)</td><td>Wind</td><td>Base-load</td><td>10 (e)</td></tr><tr><td>High Plains</td><td>Panhandle, TX</td><td>8</td><td>99.5</td><td>Wind</td><td>Base-load</td><td>10 (e)</td></tr><tr><td>Solar Georgia 2</td><td>Various, GA</td><td>8</td><td></td><td>Solar</td><td>Base-load</td><td>10</td></tr><tr><td>Tuana Springs</td><td>Hagerman, ID</td><td>8</td><td>51 (g)</td><td>Wind</td><td>Base-load</td><td>9 (e)</td></tr><tr><td>Solar Georgia</td><td>Various, GA</td><td>10</td><td></td><td>Solar</td><td>Base-load</td><td>8</td></tr><tr><td>Greensburg</td><td>Greensburg, KS</td><td>10</td><td>51 (g)</td><td>Wind</td><td>Base-load</td><td>7 (e)</td></tr><tr><td>Solar</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Massachusetts</td><td>Various, MA</td><td>10</td><td></td><td>Solar</td><td>Base-load</td><td>7</td></tr><tr><td>Outback Solar</td><td>Christmas Valley, OR</td><td>1</td><td></td><td>Solar</td><td>Base-load</td><td>6</td></tr><tr><td>Echo 3</td><td>Echo, OR</td><td>6</td><td>50.49 (g)</td><td>Wind</td><td>Base-load</td><td>5 (e)</td></tr></table>



<table><tr><td>Station(a)</td><td>Location</td><td>No. of Units</td><td>Percent Owned(b)</td><td>Primary Fuel Type</td><td>Primary Dispatch Type(c)</td><td>Net Generation Capacity (MW)(d)</td></tr><tr><td>Holyoke Solar</td><td>Various, MA</td><td>2</td><td></td><td>Solar</td><td>Base-load</td><td>5</td></tr><tr><td>Three Mile Canyon</td><td>Boardman, OR</td><td>6</td><td>51 (g)</td><td>Wind</td><td>Base-load</td><td>5 (e)</td></tr><tr><td>Loess Hills</td><td>Rock Port, MO</td><td>4</td><td></td><td>Wind</td><td>Base-load</td><td>5</td></tr><tr><td>California PV Energy 3</td><td>Various, CA</td><td>19</td><td></td><td>Solar</td><td>Base-load</td><td>6</td></tr><tr><td>Mohave Sunrise Solar</td><td>Fort Mohave, AZ</td><td>1</td><td></td><td>Solar</td><td>Base-load</td><td>5</td></tr><tr><td>Denver Airport</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Solar</td><td>Denver, CO</td><td>1</td><td>51 (g)</td><td>Solar</td><td>Base-load</td><td>2 (e)</td></tr><tr><td>Solar Net Metering</td><td>Uxbridge, MA</td><td>1</td><td></td><td>Solar</td><td>Base-load</td><td>2</td></tr><tr><td>Solar Connecticut</td><td>Various, CT</td><td>1</td><td></td><td>Solar</td><td>Base-load</td><td>1</td></tr><tr><td>Mystic 8, 9</td><td>Charlestown, MA</td><td>6</td><td></td><td>Gas</td><td>Intermediate</td><td>1,417</td></tr><tr><td>Hillahee</td><td>Alexander City, AL</td><td>3</td><td></td><td>Gas</td><td>Intermediate</td><td>753</td></tr><tr><td>Mystic 7</td><td>Charlestown, MA</td><td>1</td><td></td><td>Oil/Gas</td><td>Intermediate</td><td>542 (i)</td></tr><tr><td>Wyman 4</td><td>Yarmouth, ME</td><td>1</td><td>5.9</td><td>Oil</td><td>Intermediate</td><td>35 (e)</td></tr><tr><td>Grand Prairie</td><td>Alberta, Canada</td><td>1</td><td></td><td>Gas</td><td>Peaking</td><td>105</td></tr><tr><td>West Medway</td><td>West Medway, MA</td><td>3</td><td></td><td>Oil</td><td>Peaking</td><td>123</td></tr><tr><td>West Medway II</td><td>West Medway, MA</td><td>2</td><td></td><td>Oil/Gas</td><td>Peaking</td><td>190</td></tr><tr><td>Framingham</td><td>Framingham, MA</td><td>3</td><td></td><td>Oil</td><td>Peaking</td><td>31</td></tr><tr><td>Mystic Jet</td><td>Charlestown, MA</td><td>1</td><td></td><td>Oil</td><td>Peaking</td><td>9 (i)</td></tr><tr><td>Total Other</td><td></td><td></td><td></td><td></td><td></td><td>4,069</td></tr><tr><td>Total</td><td></td><td></td><td></td><td></td><td></td><td>31,594</td></tr></table>

(a) All nuclear stations are boiling water reactors except Braidwood, Byron, Calvert Cliffs, Ginna, and Salem, which are pressurized water reactors.

(b) 100%, unless otherwise indicated.

(c) Base-load units are plants that normally operate to take all or part of the minimum continuous load of a system and, consequently, produce electricity at an essentially constant rate. Intermediate units are plants that normally operate to take load of a system during the daytime higher load hours and, consequently, produce electricity by cycling on and off daily. Peaking units consist of lower-efficiency, quick response steam units, gas turbines and diesels normally used during the maximum load periods.

(d) For nuclear stations, capacity reflects the annual mean rating. Fossil stations reflect a summer rating. Wind and solar facilities reflect name plate capacity.

(e) Net generation capacity is stated at proportionate ownership share.

(f) Reflects Generation’s interest in CENG, a joint venture with EDF. See ITEM 1. — BUSINESS — Exelon Generation Company, LLC — Nuclear Facilities for additional information.

(g) Reflects the prior sale of 49% of EGRP to a third party. See Note 22 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for additional information.

(h) EGRP owns 100% of the Class A membership interests and a tax equity investor owns 100% of the Class B membership interests of the entity that owns the Bluestem generating assets.

(i) Generation directly owns a 50% interest in the Albany Green Energy station and an additional 49% through the consolidation of a Variable Interest Entity.

(j) Generation has plans to retire and cease generation operations at certain plants in 2020 and 2021.

(k) Generation has deactivated the site and is evaluating for potential return of service or retirement in 2020.

The net generation capability available for operation at any time may be less due to regulatory restrictions, transmission congestion, fuel restrictions, efficiency of cooling facilities, level of water supplies or generating units being temporarily out of service for inspection, maintenance, refueling, repairs or modifications required by regulatory authorities.

Generation maintains property insurance against loss or damage to its principal plants and properties by fire or other perils, subject to certain exceptions. For additional information regarding nuclear insurance of generating



facilities, see ITEM 1. BUSINESS — Exelon Generation Company, LLC. For its insured losses, Generation is self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect in Generation’s consolidated financial condition or results of operations.

## The Utility Registrants

The Utility Registrants electric substations and a portion of their transmission rights are located on property that they own. A significant portion of their electric transmission and distribution facilities are located above or underneath highways, streets, other public places or property that others own. The Utility Registrants believe that they have satisfactory rights to use those places or property in the form of permits, grants, easements, licenses and franchise rights; however, they have not necessarily undertaken to examine the underlying title to the land upon which the rights rest.

## Transmission and Distribution

The Utility Registrants’ high voltage electric transmission lines owned and in service at December 31, 2019 were as follows:

<table><tr><td colspan="2">Voltage</td><td colspan="7">Circuit Miles</td></tr><tr><td>(Volts)</td><td>ComEd</td><td>PECO</td><td>BGE</td><td>Pepco</td><td>DPL</td><td>ACE</td><td></td><td></td></tr><tr><td>765,000</td><td>90</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>500,000 \( ^{(a)} \)</td><td>—</td><td>188</td><td>(a)</td><td>216</td><td>109</td><td>16</td><td>(a)</td><td>—</td></tr><tr><td>345,000</td><td>2,716</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>230,000</td><td>—</td><td>549</td><td>358</td><td>769</td><td>472</td><td>274</td><td></td><td></td></tr><tr><td>138,000</td><td>2,224</td><td>135</td><td>55</td><td>50</td><td>586</td><td>209</td><td></td><td></td></tr><tr><td>115,000</td><td>—</td><td>—</td><td>705</td><td>25</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>69,000</td><td>—</td><td>177</td><td>—</td><td>—</td><td>569</td><td>661</td><td></td><td></td></tr></table>

(a) In addition, PECO, DPL, and ACE have an ownership interest located in Delaware and New Jersey. See Note 8 - Jointly Owned Electric Utility Plant - for additional information.

The Utility Registrant’s electric distribution system includes the following number of circuit miles of overhead and underground lines:

<table><tr><td>Circuit Miles</td><td>ComEd</td><td>PECO</td><td>BGE</td><td>Pepco</td><td>DPL</td><td>ACE</td></tr><tr><td>Overhead</td><td>35,385</td><td>12,964</td><td>9,176</td><td>4,104</td><td>6,010</td><td>7,350</td></tr><tr><td>Underground</td><td>31,799</td><td>9,417</td><td>17,489</td><td>6,993</td><td>6,316</td><td>2,942</td></tr></table>

## Gas

The following table presents PECO’s, BGE’s and DPL’s natural gas pipeline miles at December 31, 2019:

<table><tr><td></td><td>PECO</td><td>BGE</td><td>DPL</td></tr><tr><td>Transmission</td><td>9</td><td>161</td><td>8</td></tr><tr><td>Distribution</td><td>6,932</td><td>7,386</td><td>2,114</td></tr><tr><td>Service piping</td><td>6,414</td><td>6,345</td><td>1,447</td></tr><tr><td>Total</td><td>13,355</td><td>13,892</td><td>3,569</td></tr></table>



(a) DPL has a 10% undivided interest in approximately 8 miles of natural gas transmission mains located in Delaware which are used by DPL for its natural gas operations and by 90% owner for distribution of natural gas to its electric generating facilities.

The following table presents PECO's, BGE's and DPL's natural gas facilities:

<table><tr><td>Registrant</td><td>Facility</td><td>Location</td><td>Storage Capacity (mmcf)</td><td>Send-out or Peaking Capacity (mmcf/day)</td></tr><tr><td>PECO</td><td>LNG Facility</td><td>West Conshohocken, PA</td><td></td><td></td></tr><tr><td>PECO</td><td>Propane Air Plant</td><td>Chester, PA</td><td>1,200</td><td>160</td></tr><tr><td>BGE</td><td>LNG Facility</td><td>Baltimore, MD</td><td>105</td><td>25</td></tr><tr><td>BGE</td><td>Propane Air Plant</td><td>Baltimore, MD</td><td>1,056</td><td>332</td></tr><tr><td>DPL</td><td>LNG Facility</td><td>Wilmington, DE</td><td>550</td><td>85</td></tr></table>

PECO, BGE and DPL also own 30, 32, and 10 natural gas city gate stations and direct pipeline customer delivery points at various locations throughout their gas service territory, respectively.

## First Mortgage and Insurance

The principal properties of ComEd, PECO, PEPCO, DPL, and ACE are subject to the lien of their respective Mortgages under which their respective First Mortgage Bonds are issued. See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.

The Utility Registrants maintain property insurance against loss or damage to their properties by fire or other perils, subject to certain exceptions. For their insured losses, the Utility Registrants are self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect in the consolidated financial condition or results of operations of the Utility Registrants.

## Exelon

## Security Measures

The Registrants have initiated and work to maintain security measures. On a continuing basis, the Registrants evaluate enhanced security measures at certain critical locations, enhanced response and recovery plans, long-term design changes and redundancy measures. Additionally, the energy industry has strategic relationships with governmental authorities to ensure that emergency plans are in place and critical infrastructure vulnerabilities are addressed in order to maintain the reliability of the country’s energy systems.

## ITEM 3. LEGAL PROCEEDINGS

## All Registrants

The Registrants are parties to various lawsuits and regulatory proceedings in the ordinary course of their respective businesses. For information regarding material lawsuits and proceedings, see Note 3 — Regulatory Matters and Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements. Such descriptions are incorporated herein by these references.



## All Registrants

Not Applicable to the Registrants.



## PART II

(Dollars in millions except per share data, unless otherwise noted)

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

## Exelon

Exelon’s common stock is listed on the Nasdaq (trading symbol: EXC). As of January 31, 2020, there were 974,319,565 shares of common stock outstanding and approximately 95,064 record holders of common stock.

## Stock Performance Graph

The performance graph below illustrates a five-year comparison of cumulative total returns based on an initial investment of $100 in Exelon common stock, as compared with the S&P 500 Stock Index and the S&P Utility Index, for the period 2015 through 2019.

This performance chart assumes:

• $100 invested on December 31, 2014 in Exelon common stock, the S&P 500 Stock Index and the S&P Utility Index; and

• All dividends are reinvested.



<table><tr><td colspan="7">Value of Investment at December 31,</td></tr><tr><td></td><td>2014</td><td>2015</td><td>2016</td><td>2017</td><td>2018</td><td>2019</td></tr><tr><td>Exelon Corporation</td><td>$100</td><td>$77.83</td><td>$103.37</td><td>$118.92</td><td>$140.72</td><td>$146.74</td></tr><tr><td>S&amp;P 500</td><td>$100</td><td>$101.38</td><td>$113.51</td><td>$138.29</td><td>$132.23</td><td>$173.86</td></tr><tr><td>S&amp;P Utilities</td><td>$100</td><td>$95.15</td><td>$110.65</td><td>$124.05</td><td>$129.14</td><td>$163.17</td></tr></table>



## Generation

As of January 31, 2020, Exelon indirectly held the entire membership interest in Generation.

## ComEd

As of January 31, 2020, there were 127,021,349 outstanding shares of common stock, $12.50 par value, of ComEd, of which 127,002,904 shares were indirectly held by Exelon. At January 31, 2020, in addition to Exelon, there were 296 record holders of ComEd common stock. There is no established market for shares of the common stock of ComEd.

## PECO

As of January 31, 2020, there were 170,478,507 outstanding shares of common stock, without par value, of PECO, all of which were indirectly held by Exelon.



## BGE

As of January 31, 2020, there were 1,000 outstanding shares of common stock, without par value, of BGE, all of which were indirectly held by Exelon.

## PHI

As of January 31, 2020, Exelon indirectly held the entire membership interest in PHI.

## Pepco

As of January 31, 2020, there were 100 outstanding shares of common stock, $0.01 par value, of Pepco, all of which were indirectly held by Exelon.

## DPL

As of January 31, 2020, there were 1,000 outstanding shares of common stock, $2.25 par value, of DPL, all of which were indirectly held by Exelon.

## ACE

As of January 31, 2020, there were 8,546,017 outstanding shares of common stock, $3.00 par value, of ACE, all of which were indirectly held by Exelon.

## All Registrants

## Dividends

Under applicable Federal law, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE can pay dividends only from retained, undistributed or current earnings. A significant loss recorded at Generation, ComEd, PECO, BGE, PHI, Pepco, DPL or ACE may limit the dividends that these companies can distribute to Exelon.

ComEd has agreed in connection with a financing arranged through ComEd Financing III that ComEd will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debt securities issued to ComEd Financing III; (2) it defaults on its guarantee of the payment of distributions on the preferred trust securities of ComEd Financing III; or (3) an event of default occurs under the Indenture under which the subordinated debt securities are issued. No such event has occurred.

PECO has agreed in connection with financings arranged through PEC L.P. and PECO Trust IV that PECO will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debentures which were issued to PEC L.P. or PECO Trust IV; (2) it defaults on its guarantee of the payment of distributions on the Series D Preferred Securities of PEC L.P. or the preferred trust securities of PECO Trust IV; or (3) an event of default occurs under the Indenture under which the subordinated debentures are issued. No such event has occurred.

BGE is subject to restrictions established by the MDPSC that prohibit BGE from paying a dividend on its common shares if (a) after the dividend payment, BGE's equity ratio would be below 48% as calculated pursuant to the MDPSC's ratemaking precedents or (b) BGE's senior unsecured credit rating is rated by two of the three major credit rating agencies below investment grade. No such event has occurred.

Pepco is subject to certain dividend restrictions established by settlements approved in Maryland and the District of Columbia. Pepco is prohibited from paying a dividend on its common shares if (a) after the dividend payment, Pepco's equity ratio would be 48% as equity levels are calculated under the ratemaking precedents of the MDPSC and DCPSC or (b) Pepco's senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. No such event has occurred.

DPL is subject to certain dividend restrictions established by settlements approved in Delaware and Maryland. DPL is prohibited from paying a dividend on its common shares if (a) after the dividend payment, DPL's equity ratio would be 48% as equity levels are calculated under the ratemaking precedents of the DPSC and MDPSC or (b) DPL's



senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. No such event has occurred.

ACE is subject to certain dividend restrictions established by settlements approved in New Jersey. ACE is prohibited from paying a dividend on its common shares if (a) after the dividend payment, ACE's equity ratio would be 48% as equity levels are calculated under the ratemaking precedents of the NJBPU or (b) ACE's senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. ACE is also subject to a dividend restriction which requires ACE to obtain the prior approval of the NJBPU before dividends can be paid if its equity as a percent of its total capitalization, excluding securitization debt, falls below 30%. No such events have occurred.

Exelon’s Board of Directors approved an updated dividend policy providing an increase of 5% each year for the period covering 2018 through 2020, beginning with the March 2018 dividend.

At December 31, 2019, Exelon had retained earnings of $16,267 million, including Generation’s undistributed earnings of $3,950 million, ComEd’s retained earnings of $1,517 million consisting of retained earnings appropriated for future dividends of $3,156 million, partially offset by $1,639 million of unappropriated accumulated deficits, PECO’s retained earnings of $1,412 million, BGE’s retained earnings of $1,776 million, and PHI’s undistributed losses of $10 million.

The following table sets forth Exelon’s quarterly cash dividends per share paid during 2019 and 2018:

<table><tr><td rowspan="2">(per share)</td><td colspan="6">2019</td><td colspan="6">2018</td></tr><tr><td>Fourth Quarter</td><td>Third Quarter</td><td>Second Quarter</td><td>First Quarter</td><td>Fourth Quarter</td><td>Third Quarter</td><td>Second Quarter</td><td>First Quarter</td><td></td><td></td><td></td></tr><tr><td>Exelon</td><td>$ 0.363</td><td>$ 0.363</td><td>$ 0.363</td><td>$ 0.363</td><td>$ 0</td><td>$ 0.345</td><td>$ 0.345</td><td>$ 0.345</td><td>$ 0.345</td><td>$ 0</td><td>$ 0.345</td><td>$ 0.345</td></tr></table>

The following table sets forth Generation's and PHI's quarterly distributions and ComEd's, PECO's, BGE's, Pepco's, DPL's and ACE's quarterly common dividend payments:

<table><tr><td rowspan="2">(in millions)</td><td colspan="5">2019</td><td colspan="5">2018</td></tr><tr><td>4th Quarter</td><td>3rd Quarter</td><td>2nd Quarter</td><td>1st Quarter</td><td>4th Quarter</td><td>3rd Quarter</td><td>2nd Quarter</td><td>1st Quarter</td><td></td><td></td></tr><tr><td>Generation</td><td>$ 225</td><td>$ 225</td><td>$ 224</td><td>$ 224</td><td>$ 225</td><td>$ 313</td><td>$ 311</td><td>$ 189</td><td>$ 188</td><td></td></tr><tr><td>ComEd</td><td>128</td><td>126</td><td>127</td><td>127</td><td>114</td><td>116</td><td>115</td><td>114</td><td></td><td></td></tr><tr><td>PECO</td><td>90</td><td>88</td><td>90</td><td>90</td><td>6</td><td>7</td><td>6</td><td>287</td><td></td><td></td></tr><tr><td>BGE</td><td>55</td><td>57</td><td>56</td><td>56</td><td>52</td><td>52</td><td>53</td><td>52</td><td></td><td></td></tr><tr><td>PHI</td><td>97</td><td>213</td><td>88</td><td>128</td><td>94</td><td>123</td><td>38</td><td>71</td><td></td><td></td></tr><tr><td>Pepco</td><td>40</td><td>101</td><td>48</td><td>24</td><td>41</td><td>78</td><td>25</td><td>25</td><td></td><td></td></tr><tr><td>DPL</td><td>34</td><td>35</td><td>29</td><td>41</td><td>38</td><td>18</td><td>4</td><td>36</td><td></td><td></td></tr><tr><td>ACE</td><td>24</td><td>76</td><td>12</td><td>12</td><td>13</td><td>27</td><td>10</td><td>9</td><td></td><td></td></tr></table>

## First Quarter 2020 Dividend

On January 28, 2020, the Exelon Board of Directors declared a first quarter 2020 regular quarterly dividend of $0.3825 per share on Exelon's common stock payable on March 10, 2020, to shareholders of record of Exelon at the end of the day on February 20, 2020.



## Exelon

The selected financial data presented below has been derived from the audited consolidated financial statements of Exelon. This data is qualified in its entirety by reference to and should be read in conjunction with Exelon's Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

<table><tr><td rowspan="2">(In millions, except per share data)</td><td colspan="6">For the Years Ended December 31,</td></tr><tr><td>2019</td><td>2018(a)</td><td>2017(a)</td><td>2016(b)</td><td>2015</td><td></td></tr><tr><td>Statement of Operations data:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating revenues</td><td>$ 34,438</td><td>$ 35,978</td><td>$ 33,558</td><td>$ 31,366</td><td>$ 29,447</td><td></td></tr><tr><td>Operating income</td><td>4,374</td><td>3,891</td><td>4,388</td><td>3,212</td><td>4,554</td><td></td></tr><tr><td>Net income</td><td>3,028</td><td>2,079</td><td>3,869</td><td>1,196</td><td>2,250</td><td></td></tr><tr><td>Net income attributable to common shareholders</td><td>2,936</td><td>2,005</td><td>3,779</td><td>1,121</td><td>2,269</td><td></td></tr><tr><td>Earnings per average common share (diluted):</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Net income</td><td>$ 3.01</td><td>$ 2.07</td><td>$ 3.98</td><td>$ 1.21</td><td>$ 2.54</td><td></td></tr><tr><td>Dividends per common share</td><td>$ 1.45</td><td>$ 1.38</td><td>$ 1.31</td><td>$ 1.26</td><td>$ 1.24</td><td></td></tr></table>

<table><tr><td rowspan="2">(In millions)</td><td colspan="6">December 31,</td></tr><tr><td>2019</td><td>2018(a)</td><td>2017(a)</td><td>2016</td><td>2015</td><td></td></tr><tr><td>Balance Sheet data:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Current assets</td><td>$ 12,037</td><td>$ 13,328</td><td>$ 11,872</td><td>$ 12,451</td><td>$ 15,334</td><td></td></tr><tr><td>Property, plant and equipment, net</td><td>80,233</td><td>76,707</td><td>74,202</td><td>71,555</td><td>57,439</td><td></td></tr><tr><td>Total assets</td><td>124,977</td><td>119,634</td><td>116,746</td><td>114,952</td><td>95,384</td><td></td></tr><tr><td>Current liabilities</td><td>14,185</td><td>11,404</td><td>10,798</td><td>13,463</td><td>9,118</td><td></td></tr><tr><td>Long-term debt, including long-term debt to financing trusts</td><td>31,719</td><td>34,465</td><td>32,565</td><td>32,216</td><td>24,286</td><td></td></tr><tr><td>Shareholders&#x27; equity</td><td>32,224</td><td>30,741</td><td>29,878</td><td>25,860</td><td>25,793</td><td></td></tr></table>

(a) Amounts have been revised to reflect the correction of an error related to Pepco's decoupling mechanism. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information.

(b) The 2016 financial results include the activity of PHI from the merger effective date of March 24, 2016 through December 31, 2016.



## Generation

The selected financial data presented below has been derived from the audited consolidated financial statements of Generation. This data is qualified in its entirety by reference to and should be read in conjunction with Generation's Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

<table><tr><td rowspan="2">(In millions)</td><td colspan="6">For the Years Ended December 31,</td></tr><tr><td>2019</td><td>2018</td><td>2017</td><td>2016</td><td>2015</td><td></td></tr><tr><td>Statement of Operations data:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating revenues</td><td>$ 18,924</td><td>$ 20,437</td><td>$ 18,500</td><td>$ 17,757</td><td>$ 19,135</td><td></td></tr><tr><td>Operating income</td><td>1,323</td><td>975</td><td>947</td><td>820</td><td>2,275</td><td></td></tr><tr><td>Net income</td><td>1,217</td><td>443</td><td>2,798</td><td>550</td><td>1,340</td><td></td></tr><tr><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr></table>

## ComEd

The selected financial data presented below has been derived from the audited consolidated financial statements of ComEd. This data is qualified in its entirety by reference to and should be read in conjunction with ComEd's Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

<table><tr><td rowspan="2">(In millions)</td><td colspan="6">For the Years Ended December 31,</td></tr><tr><td>2019</td><td>2018</td><td>2017</td><td>2016</td><td>2015</td><td></td></tr><tr><td>Statement of Operations data:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating revenues</td><td>$ 5,747</td><td>$ 5,882</td><td>$ 5,536</td><td>$ 5,254</td><td>$ 4,905</td><td></td></tr><tr><td>Operating income</td><td>1,171</td><td>1,146</td><td>1,323</td><td>1,205</td><td>1,017</td><td></td></tr><tr><td>Net income</td><td>688</td><td>664</td><td>567</td><td>378</td><td>426</td><td></td></tr></table>



<table><tr><td rowspan="2">(In millions)</td><td colspan="6">December 31,</td></tr><tr><td>2019</td><td>2018</td><td>2017</td><td>2016</td><td>2015</td><td></td></tr><tr><td>Balance Sheet data:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Current assets</td><td>$ 1,583</td><td>$ 1,570</td><td>$ 1,364</td><td>$ 1,554</td><td>$ 1,518</td><td></td></tr><tr><td>Property, plant and equipment, net</td><td>23,107</td><td>22,058</td><td>20,723</td><td>19,335</td><td>17,502</td><td></td></tr><tr><td>Total assets</td><td>32,765</td><td>31,213</td><td>29,726</td><td>28,335</td><td>26,532</td><td></td></tr><tr><td>Current liabilities</td><td>2,117</td><td>1,925</td><td>2,294</td><td>2,938</td><td>2,766</td><td></td></tr><tr><td>Long-term debt, including long-term debt to financing trusts</td><td>8,196</td><td>8,006</td><td>6,966</td><td>6,813</td><td>6,049</td><td></td></tr><tr><td>Shareholders&#x27; equity</td><td>10,677</td><td>10,247</td><td>9,542</td><td>8,725</td><td>8,243</td><td></td></tr></table>

## PECO

The selected financial data presented below has been derived from the audited consolidated financial statements of PECO. This data is qualified in its entirety by reference to and should be read in conjunction with PECO's Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

<table><tr><td rowspan="2">(In millions)</td><td colspan="6">For the Years Ended December 31,</td></tr><tr><td>2019</td><td>2018</td><td>2017</td><td>2016</td><td>2015</td><td></td></tr><tr><td>Statement of Operations data:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating revenues</td><td>$ 3,100</td><td>$ 3,038</td><td>$ 2,870</td><td>$ 2,994</td><td>$ 3,032</td><td></td></tr><tr><td>Operating income</td><td>713</td><td>587</td><td>655</td><td>702</td><td>630</td><td></td></tr><tr><td>Net income</td><td>528</td><td>460</td><td>434</td><td>438</td><td>378</td><td></td></tr></table>

<table><tr><td>(In millions)</td><td>2019</td><td>2018</td><td>2017</td><td>2016</td><td>2015</td></tr><tr><td>Balance Sheet data:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Current assets</td><td>$ 722</td><td>$ 782</td><td>$ 822</td><td>$ 757</td><td>$ 842</td></tr><tr><td>Property, plant and equipment, net</td><td>9,292</td><td>8,610</td><td>8,053</td><td>7,565</td><td>7,141</td></tr><tr><td>Total assets</td><td>11,469</td><td>10,642</td><td>10,170</td><td>10,831</td><td>10,367</td></tr><tr><td>Current liabilities</td><td>722</td><td>809</td><td>1,267</td><td>727</td><td>944</td></tr><tr><td>Long-term debt, including long-term debt to financing trusts</td><td>3,589</td><td>3,268</td><td>2,587</td><td>2,764</td><td>2,464</td></tr><tr><td>Shareholder&#x27;s equity</td><td>4,178</td><td>3,820</td><td>3,577</td><td>3,415</td><td>3,236</td></tr></table>

## BGE

The selected financial data presented below has been derived from the audited consolidated financial statements of BGE. This data is qualified in its entirety by reference to and should be read in conjunction with BGE's Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

<table><tr><td rowspan="2">(In millions)</td><td colspan="6">For the Years Ended December 31,</td></tr><tr><td>2019</td><td>2018</td><td>2017</td><td>2016</td><td>2015</td><td></td></tr><tr><td>Statement of Operations data:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating revenues</td><td>$ 3,106</td><td>$ 3,169</td><td>$ 3,176</td><td>$ 3,233</td><td>$ 3,135</td><td></td></tr><tr><td>Operating income</td><td>532</td><td>474</td><td>614</td><td>550</td><td>558</td><td></td></tr><tr><td>Net income</td><td>360</td><td>313</td><td>307</td><td>294</td><td>288</td><td></td></tr></table>



<table><tr><td rowspan="2">(In millions)</td><td colspan="6">December 31,</td></tr><tr><td>2019</td><td>2018</td><td>2017</td><td>2016</td><td>2015</td><td></td></tr><tr><td>Balance Sheet data:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Current assets</td><td>$ 833</td><td>$ 786</td><td>$ 811</td><td>$ 842</td><td>$ 845</td><td></td></tr><tr><td>Property, plant and equipment, net</td><td>8,990</td><td>8,243</td><td>7,602</td><td>7,040</td><td>6,597</td><td></td></tr><tr><td>Total assets</td><td>10,634</td><td>9,716</td><td>9,104</td><td>8,704</td><td>8,295</td><td></td></tr><tr><td>Current liabilities</td><td>753</td><td>774</td><td>760</td><td>707</td><td>1,134</td><td></td></tr><tr><td>Long-term debt, including long-term debt to financing trusts</td><td>3,270</td><td>2,876</td><td>2,577</td><td>2,533</td><td>1,732</td><td></td></tr><tr><td>Shareholder&#x27;s equity</td><td>3,683</td><td>3,354</td><td>3,141</td><td>2,848</td><td>2,687</td><td></td></tr></table>

## PHI

The selected financial data presented below has been derived from the audited consolidated financial statements of PHI. This data is qualified in its entirety by reference to and should be read in conjunction with PHI's Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

<table><tr><td rowspan="2"></td><td colspan="4">Successor</td><td colspan="3">Predecessor</td></tr><tr><td colspan="3">For the Years Ended December 31,</td><td rowspan="2">March 24 to December 31,</td><td rowspan="2">January 1 to March 23,</td><td rowspan="2">For the Year Ended December 31,</td><td></td></tr><tr><td>(In millions)</td><td>2019</td><td>2018(a)</td><td>2017(a)</td><td>2016</td><td>2015</td></tr><tr><td>Statement of Operations data:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating revenues</td><td>$ 4,806</td><td>$ 4,798</td><td>$ 4,672</td><td>$ 3,643</td><td></td><td>$1,153</td><td>$ 4,935</td></tr><tr><td>Operating income</td><td>722</td><td>643</td><td>762</td><td>93</td><td></td><td>105</td><td>673</td></tr><tr><td>Net income (loss) from continuing operations</td><td>477</td><td>393</td><td>355</td><td>(61)</td><td></td><td>19</td><td>318</td></tr><tr><td>Net income (loss)</td><td>477</td><td>393</td><td>355</td><td>(61)</td><td></td><td>19</td><td>327</td></tr></table>

<table><tr><td rowspan="2"></td><td colspan="4">Successor</td><td colspan="2">Predecessor</td></tr><tr><td colspan="4">December 31,</td><td></td><td></td></tr><tr><td>(In millions)</td><td>2019</td><td>2018(a)</td><td>2017(a)</td><td>2016</td><td>2015</td><td></td></tr><tr><td>Balance Sheet data:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Current assets</td><td>$ 1,480</td><td>$ 1,501</td><td>$ 1,527</td><td>$ 1,838</td><td>$ 1,474</td><td></td></tr><tr><td>Property, plant and equipment, net</td><td>14,296</td><td>13,446</td><td>12,498</td><td>11,598</td><td>10,864</td><td></td></tr><tr><td>Total assets</td><td>22,719</td><td>21,952</td><td>21,223</td><td>21,025</td><td>16,188</td><td></td></tr><tr><td>Current liabilities</td><td>1,612</td><td>1,592</td><td>1,931</td><td>2,284</td><td>2,327</td><td></td></tr><tr><td>Long-term debt</td><td>6,460</td><td>6,134</td><td>5,478</td><td>5,645</td><td>4,823</td><td></td></tr><tr><td>Preferred Stock</td><td>—</td><td>—</td><td>—</td><td>—</td><td>183</td><td></td></tr><tr><td>Member&#x27;s equity/Shareholders&#x27; equity</td><td>9,608</td><td>9,259</td><td>8,807</td><td>8,016</td><td>4,413</td><td></td></tr></table>

(a) Amounts have been revised to reflect the correction of an error related to Pepco's decoupling mechanism. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information.



## Pepco

The selected financial data presented below has been derived from the audited consolidated financial statements of Pepco. This data is qualified in its entirety by reference to and should be read in conjunction with Pepco's Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

<table><tr><td rowspan="2">(In millions)</td><td colspan="6">For the Years Ended December 31,</td></tr><tr><td>2019</td><td>2018(a)</td><td>2017(a)</td><td>2016</td><td>2015</td><td></td></tr><tr><td>Statement of Operations data:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating revenues</td><td>$ 2,260</td><td>$ 2,232</td><td>$ 2,151</td><td>$ 2,186</td><td>$ 2,129</td><td></td></tr><tr><td>Operating income</td><td>361</td><td>313</td><td>392</td><td>174</td><td>385</td><td></td></tr><tr><td>Net income</td><td>243</td><td>205</td><td>198</td><td>42</td><td>187</td><td></td></tr><tr><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr></table>

(a) Amounts have been revised to reflect the correction of an error related to Pepco's decoupling mechanism. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information.

## DPL

The selected financial data presented below has been derived from the audited consolidated financial statements of DPL. This data is qualified in its entirety by reference to and should be read in conjunction with DPL's Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

<table><tr><td rowspan="2">(In millions)</td><td colspan="6">For the Years Ended December 31,</td></tr><tr><td>2019</td><td>2018</td><td>2017</td><td>2016</td><td>2015</td><td></td></tr><tr><td>Statement of Operations data:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating revenues</td><td>$ 1,306</td><td>$ 1,332</td><td>$ 1,300</td><td>$ 1,277</td><td>$ 1,302</td><td></td></tr><tr><td>Operating income</td><td>217</td><td>190</td><td>229</td><td>50</td><td>165</td><td></td></tr><tr><td>Net income (loss)</td><td>147</td><td>120</td><td>121</td><td>(9)</td><td>76</td><td></td></tr></table>



<table><tr><td rowspan="2">(In millions)</td><td colspan="6">December 31,</td></tr><tr><td>2019</td><td>2018</td><td>2017</td><td>2016</td><td>2015</td><td></td></tr><tr><td>Balance Sheet data:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Current assets</td><td>$ 325</td><td>$ 336</td><td>$ 325</td><td>$ 370</td><td>$ 388</td><td></td></tr><tr><td>Property, plant and equipment, net</td><td>4,035</td><td>3,821</td><td>3,579</td><td>3,273</td><td>3,070</td><td></td></tr><tr><td>Total assets</td><td>4,830</td><td>4,588</td><td>4,357</td><td>4,153</td><td>3,969</td><td></td></tr><tr><td>Current liabilities</td><td>414</td><td>375</td><td>547</td><td>381</td><td>564</td><td></td></tr><tr><td>Long-term debt</td><td>1,487</td><td>1,403</td><td>1,217</td><td>1,221</td><td>1,061</td><td></td></tr><tr><td>Shareholder&#x27;s equity</td><td>1,580</td><td>1,509</td><td>1,335</td><td>1,326</td><td>1,237</td><td></td></tr></table>

## ACE

The selected financial data presented below has been derived from the audited consolidated financial statements of ACE. This data is qualified in its entirety by reference to and should be read in conjunction with ACE’s Financial Statements and ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

<table><tr><td rowspan="2">(In millions)</td><td colspan="6">For the Years Ended December 31,</td></tr><tr><td>2019</td><td>2018</td><td>2017</td><td>2016</td><td>2015</td><td></td></tr><tr><td>Statement of Operations data:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating revenues</td><td>$ 1,240</td><td>$ 1,236</td><td>$ 1,186</td><td>$ 1,257</td><td>$ 1,295</td><td></td></tr><tr><td>Operating income</td><td>151</td><td>149</td><td>157</td><td>7</td><td>134</td><td></td></tr><tr><td>Net income (loss)</td><td>99</td><td>75</td><td>77</td><td>(42)</td><td>40</td><td></td></tr><tr><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr></table>



## Exelon

## Executive Overview

Exelon is a utility services holding company engaged in the generation, delivery, and marketing of energy through Generation and the energy distribution and transmission businesses through ComEd, PECO, BGE, Pepco, DPL and ACE.

Exelon has eleven reportable segments consisting of Generation’s five reportable segments (Mid-Atlantic, Midwest, New York, ERCOT and Other Power Regions), ComEd, PECO, BGE, Pepco, DPL and ACE. During the first quarter of 2019, due to a change in economics in our New England region, Generation changed the way that information is reviewed by the CODM. The New England region is no longer regularly reviewed as a separate region by the CODM nor presented separately in any external information presented to third parties. Information for the New England region is reviewed by the CODM as part of Other Power Regions. See Note 1 — Significant Accounting Policies and Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information regarding Exelon’s principal subsidiaries and reportable segments.

Exelon’s consolidated financial information includes the results of its eight separate operating subsidiary registrants, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, which, along with Exelon, are collectively referred to as the Registrants. The following combined Management’s Discussion and Analysis of Financial Condition and Results of Operations summarizes results for the year ended December 31, 2019 compared to the year ended December 31, 2018, and is separately filed by Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE. However, none of the Registrants makes any representation as to information related solely to any of the other Registrants. For discussion of the year ended December 31, 2018 compared to the year ended December 31, 2017, refer to ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS in the 2018-Form 10-K, which was filed with the SEC on February 8, 2019.



## Financial Results of Operations

GAAP Results of Operations. The following table sets forth Exelon's GAAP consolidated Net Income attributable to common shareholders by Registrant for the year ended December 31, 2019 compared to the same period in 2018 and 2017. For additional information regarding the financial results for the years ended December 31, 2019 and 2018 see the discussions of Results of Operations by Registrant.

<table><tr><td></td><td colspan="2">2019</td><td colspan="2">2018(a)</td><td colspan="2">Favorable (unfavorable) 2019 vs. 2018 variance</td><td colspan="2">2017(a)</td><td colspan="2">Favorable (unfavorable) 2018 vs. 2017 variance</td></tr><tr><td>Exelon</td><td>$</td><td>2,936</td><td>$</td><td>2,005</td><td>$</td><td>931</td><td>$</td><td>3,779</td><td>$</td><td>(1,774)</td></tr><tr><td>Generation</td><td></td><td>1,125</td><td></td><td>370</td><td></td><td>755</td><td></td><td>2,710</td><td></td><td>(2,340)</td></tr><tr><td>ComEd</td><td></td><td>688</td><td></td><td>664</td><td></td><td>24</td><td></td><td>567</td><td></td><td>97</td></tr><tr><td>PECO</td><td></td><td>528</td><td></td><td>460</td><td></td><td>68</td><td></td><td>434</td><td></td><td>26</td></tr><tr><td>BGE</td><td></td><td>360</td><td></td><td>313</td><td></td><td>47</td><td></td><td>307</td><td></td><td>6</td></tr><tr><td>PHI</td><td></td><td>477</td><td></td><td>393</td><td></td><td>84</td><td></td><td>355</td><td></td><td>38</td></tr><tr><td>Pepco</td><td></td><td>243</td><td></td><td>205</td><td></td><td>38</td><td></td><td>198</td><td></td><td>7</td></tr><tr><td>DPL</td><td></td><td>147</td><td></td><td>120</td><td></td><td>27</td><td></td><td>121</td><td></td><td>(1)</td></tr><tr><td>ACE</td><td></td><td>99</td><td></td><td>75</td><td></td><td>24</td><td></td><td>77</td><td></td><td>(2)</td></tr><tr><td>Other \( ^{(b)} \)</td><td></td><td>(242)</td><td></td><td>(195)</td><td></td><td>(47)</td><td></td><td>(594)</td><td></td><td>399</td></tr></table>

(a) Exelon's, PHI's and Pepco's amounts have been revised to reflect the correction of an error related to Pepco's decoupling mechanism. See Note 1 - Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information.

(b) Primarily includes eliminating and consolidating adjustments, Exelon's corporate operations, shared service entities and other financing and investing activities.

Year Ended December 31, 2019 Compared to Year Ended December 31, 2018. Net income attributable to common shareholders increased by $931 million and diluted earnings per average common share increased to $3.01 in 2019 from $2.07 in 2018 primarily due to:

• Higher net unrealized and realized gains on NDT funds;

- Decreased accelerated depreciation and amortization due to the early retirement of the Oyster Creek nuclear facility in September 2018 and TMI in September 2019 and the absence of a charge associated with the remeasurement of the Oyster Creek ARO in 2018;

- Decreased Operating and maintenance expense at Generation which includes the impacts of previous cost management programs, lower pension and OPEB costs and increased NEIL insurance distributions;

- A benefit associated with the remeasurement of the TMI ARO in the first quarter of 2019 and the annual nuclear ARO update in the third quarter of 2019;

• Decreased nuclear outage days;

• Lower mark-to-market losses;

• Regulatory rate increases at PECO, BGE, Pepco, DPL, and ACE;

• Increased electric distribution, energy efficiency and transmission earnings at ComEd;

• Decreased storms costs at PECO and BGE; and

• Research and development income tax benefits.

The increases were partially offset by;



• Lower realized energy prices;

• Lower capacity prices;

• Unfavorable weather conditions at PECO, DPL and ACE; and

• Unfavorable volume at PECO.

Adjusted (non-GAAP) Operating Earnings. In addition to net income, Exelon evaluates its operating performance using the measure of Adjusted (non-GAAP) operating earnings because management believes it represents earnings directly related to the ongoing operations of the business. Adjusted (non-GAAP) operating earnings exclude certain costs, expenses, gains and losses and other specified items. This information is intended to enhance an investor's overall understanding of year-to-year operating results and provide an indication of Exelon's baseline operating performance excluding items that are considered by management to be not directly related to the ongoing operations of the business. In addition, this information is among the primary indicators management uses as a basis for evaluating performance, allocating resources, setting incentive compensation targets and planning and forecasting of future periods. Adjusted (non-GAAP) operating earnings 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.



The following table provides a reconciliation between Net income attributable to common shareholders as determined in accordance with GAAP and Adjusted (non-GAAP) operating earnings for the year ended December 31, 2019 as compared to 2018 and 2017:

<table><tr><td rowspan="3">(All amounts in millions after tax)</td><td colspan="8">For the Years Ended December 31,</td></tr><tr><td colspan="3">2019</td><td colspan="3">2018(a)</td><td colspan="2">2017(a)</td></tr><tr><td colspan="2">Earnings per Diluted Share</td><td colspan="2">Earnings per Diluted Share</td><td colspan="2">Earnings for Diluted Share</td><td colspan="2">Earnings per Diluted Share</td></tr><tr><td>Net Income Attributable to Common Shareholders</td><td>$ 2,936</td><td>$ 3.01</td><td>$ 2,005</td><td>$ 2.07</td><td>$ 3,779</td><td>$ 3.98</td><td></td><td></td></tr><tr><td>Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $66, $89 and $68, respectively)</td><td>197</td><td>0.20</td><td>252</td><td>0.26</td><td>107</td><td>0.11</td><td></td><td></td></tr><tr><td>Unrealized (Gains) Losses Related to NDT Fund Investments (net of taxes of $269, $289 and $286, respectively)(b)</td><td>(299)</td><td>(0.31)</td><td>337</td><td>0.35</td><td>(318)</td><td>(0.34)</td><td></td><td></td></tr><tr><td>Amortization of Commodity Contract Intangibles (net of taxes of $22)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>34</td><td>0.04</td><td></td><td></td></tr><tr><td>PHI Merger and Integration Costs (net of taxes of $2 and $25, respectively)</td><td>—</td><td>—</td><td>3</td><td>—</td><td>40</td><td>0.04</td><td></td><td></td></tr><tr><td>Merger Commitments (net of taxes of $137)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(137)</td><td>(0.14)</td><td></td><td></td></tr><tr><td>Asset Impairments (net of taxes of $56, $13 and $204, respectively)(c)</td><td>123</td><td>0.13</td><td>35</td><td>0.04</td><td>321</td><td>0.34</td><td></td><td></td></tr><tr><td>Plant Retirements and Divestitures (net of taxes of $9, $181, and $134, respectively)(d)</td><td>118</td><td>0.12</td><td>512</td><td>0.53</td><td>207</td><td>0.22</td><td></td><td></td></tr><tr><td>Cost Management Program (net of taxes of $17, $16, and $21, respectively)(e)</td><td>51</td><td>0.05</td><td>48</td><td>0.05</td><td>34</td><td>0.04</td><td></td><td></td></tr><tr><td>Asset Retirement Obligation (net of taxes of $9, $7, and $1, respectively)(f)</td><td>(84)</td><td>(0.09)</td><td>20</td><td>0.02</td><td>(2)</td><td>—</td><td></td><td></td></tr><tr><td>Vacation Policy Change (net of taxes of $21)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(33)</td><td>(0.03)</td><td></td><td></td></tr><tr><td>Change in Environmental Liabilities (net of taxes of $8, $0, and $17, respectively)</td><td>20</td><td>0.02</td><td>(1)</td><td>—</td><td>27</td><td>0.03</td><td></td><td></td></tr><tr><td>Bargain Purchase Gain (net of taxes of $0)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(233)</td><td>(0.25)</td><td></td><td></td></tr><tr><td>Gain on Deconsolidation of Business (net of taxes of $83)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(130)</td><td>(0.14)</td><td></td><td></td></tr><tr><td>Gain on Contract Settlement (net of taxes of $20)(g)</td><td>—</td><td>—</td><td>(55)</td><td>(0.06)</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Litigation Settlement Gain (net of taxes of $7)</td><td>(19)</td><td>(0.02)</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Income Tax-Related Adjustments (entire amount represents tax expense)(h)</td><td>5</td><td>0.01</td><td>(22)</td><td>(0.02)</td><td>(1,330)</td><td>(1.41)</td><td></td><td></td></tr><tr><td>Noncontrolling Interests (net of taxes of $26, $24, and $24, respectively)(i)</td><td>90</td><td>0.09</td><td>(113)</td><td>(0.12)</td><td>114</td><td>0.12</td><td></td><td></td></tr><tr><td>Adjusted (non-GAAP) Operating Earnings</td><td>$ 3,139</td><td>$ 3.22</td><td>$ 3,021</td><td>$ 3.12</td><td>$ 2,480</td><td>$ 2.61</td><td></td><td></td></tr></table>

Note:

Amounts may not sum due to rounding.

Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net Income and Adjusted (non-GAAP) Operating Earnings is based on the marginal statutory federal and state income tax rates for each Registrant, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part. For all items except the unrealized gains and losses related to NDT funds, the marginal statutory income tax rates for 2019 and 2018 ranged from 26.0 percent to 29.0 percent. 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 gains and losses related to NDT funds were 47.3 percent and 46.2 percent for the years ended December 31, 2019 and 2018, respectively.



(a) Net Income Attributable to Common Shareholders and Adjusted (non-GAAP) Operating Earnings have been revised to reflect the correction of an error related to Pepco's decoupling mechanism. See Note 1 - Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information.

(b) Reflects the impact of net unrealized gains and losses on Generation's NDT fund investments for Non-Regulatory and Regulatory Agreement Units. The impacts of the Regulatory Agreement Units, including the associated income taxes, are contractually eliminated, resulting in no earnings impact.

(c) In 2018, primarily reflects the impairment of certain wind projects at Generation. In 2019, primarily reflects the impairment of equity method investments in certain distributed energy companies. The impact of such impairment net of noncontrolling interest is $0.02.

(d) In 2018, primarily reflects accelerated depreciation and amortization expenses and one-time charges associated with Generation's decision to early retire the Oyster Creek and TMI nuclear facilities, a charge associated with a remeasurement of the Oyster Creek ARO, partially offset by a gain associated with Generation's sale of its electrical contracting business. In 2019, primarily reflects accelerated depreciation and amortization expenses associated with the early retirement of the TMI nuclear facility and certain fossil sites and the loss on the sale of Oyster Creek to Holtec, partially offset by net realized gains related to Oyster Creek's NDT fund investments, a net benefit associated with remeasurements of the TMI ARO and a gain on the sale of certain wind assets.

(e) Primarily represents severance and reorganization costs related to cost management programs.

(f) In 2018, reflects an increase at Pepco related primarily to asbestos identified at its Buzzard Point property. In 2019, reflects a benefit related to Generation's annual nuclear ARO update for non-regulatory units.

(g) Represents the gain on the settlement of a long-term gas supply agreement at Generation.

(h) In 2018, reflects an adjustment to the remeasurement of deferred income taxes as a result of the TCJA. In 2019, primarily reflects the adjustment to deferred income taxes due to changes in forecasted apportionment.

(i) Represents elimination from Generation’s results of the noncontrolling interests related to certain exclusion items. In 2018, primarily related to the impact of unrealized losses on NDT fund investments for CENG units. In 2019, primarily related to the impact of unrealized gains on NDT fund investments and the impact of the Generation’s annual nuclear ARO update for CENG units, partially offset by the impairment of certain equity investments in distributed energy companies.

## Significant 2019 Transactions and Developments

## Utility Rates and Base Rate Proceedings

The Utility Registrants file base rate cases with their regulatory commissions seeking increases or decreases to their electric transmission and distribution, and gas distribution rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Utility Registrants' current and future results of operations, cash flows and financial position.

The following tables show the Utility Registrants' completed and pending distribution base rate case proceedings in 2019. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on other regulatory proceedings.



## Completed Utility Distribution Base Rate Case Proceedings

<table><tr><td>Registrant/Jurisdiction</td><td>Filing Date</td><td>Requested Revenue Requirement Increase (Decrease)</td><td>Approved Revenue Requirement Increase (Decrease)</td><td>Approved ROE</td><td>Approval Date</td><td>Rate Effective Date</td></tr><tr><td>ComEd - Illinois (Electric)</td><td>April 16, 2018</td><td>$ (23)</td><td>$ (24)</td><td>8.69%</td><td>December 4, 2018</td><td>January 1, 2019</td></tr><tr><td>ComEd - Illinois (Electric)</td><td>April 8, 2019</td><td>$ (6)</td><td>$ (17)</td><td>8.91%</td><td>December 4, 2019</td><td>January 1, 2020</td></tr><tr><td>PECO - Pennsylvania (Electric)</td><td>March 29, 2018</td><td>$ 82</td><td>$ 25</td><td>N/A</td><td>December 20, 2018</td><td>January 1, 2019</td></tr><tr><td>BGE - Maryland (Natural Gas)</td><td>June 8, 2018 (amended October 12, 2018)</td><td>$ 61</td><td>43</td><td>9.8%</td><td>January 4, 2019</td><td>January 4, 2019</td></tr><tr><td>BGE - Maryland (Electric)</td><td>May 24, 2019 (amended December 17, 2019)</td><td>$ 74</td><td>$ 18</td><td>9.7%</td><td>December 17, 2019</td><td>December 17, 2019</td></tr><tr><td>BGE - Maryland (Natural Gas)</td><td>May 24, 2019 (amended December 17, 2019)</td><td>$ 59</td><td>$ 45</td><td>9.75%</td><td>December 17, 2019</td><td>December 17, 2019</td></tr><tr><td>ACE - New Jersey (Electric)</td><td>August 21, 2018 (amended November 19, 2018)</td><td>$ 122</td><td>$ 70</td><td>9.6%</td><td>March 13, 2019</td><td>April 1, 2019</td></tr><tr><td>Pepco - Maryland (Electric)</td><td>January 15, 2019 (amended May 16, 2019)</td><td>$ 27</td><td>$ 10.3</td><td>9.6%</td><td>August 12, 2019</td><td>August 13, 2019</td></tr></table>

Pending Distribution Base Rate Case Proceedings

<table><tr><td>Registrant/Jurisdiction</td><td>Filing Date</td><td>Requested Revenue Requirement Increase</td><td>Requested ROE</td><td>Expected Approval Timing</td></tr><tr><td>Pepco - District of Columbia (Electric)</td><td>May 30, 2019 (amended September 16, 2019)</td><td>$ 160</td><td>10.3%</td><td>Fourth quarter of 2020</td></tr><tr><td>DPL - Maryland (Electric)</td><td>December 5, 2019</td><td>$ 19</td><td>10.3%</td><td>Third quarter of 2020</td></tr></table>



## Transmission Formula Rate

The following total (decreases)/increases were included in ComEd's, BGE's, Pepco's, DPL's and ACE's 2019 annual electric transmission formula rate updates.

<table><tr><td>Registrant</td><td>Initial Revenue Requirement Increase/(Decrease)</td><td>Annual Reconciliation (Decrease)/Increase</td><td>Total Revenue Requirement Increase/(Decrease)</td><td>Allowed Return on Rate Base</td><td>Allowed ROE</td></tr><tr><td>ComEd</td><td>$ 21</td><td>$ (16)</td><td>$ 5</td><td>8.21%</td><td>11.50%</td></tr><tr><td>BGE</td><td>(10)</td><td>(23)</td><td>(19)</td><td>7.35%</td><td>10.50%</td></tr><tr><td>Pepco</td><td>15</td><td>11</td><td>26</td><td>7.75%</td><td>10.50%</td></tr><tr><td>DPL</td><td>17</td><td>(1)</td><td>16</td><td>7.14%</td><td>10.50%</td></tr><tr><td>ACE</td><td>11</td><td>(2)</td><td>9</td><td>7.79%</td><td>10.50%</td></tr></table>

## PECO Transmission Formula Rate

On May 1, 2017, PECO filed a request with FERC seeking approval to update its transmission rates and change the manner in which PECO's transmission rate is determined from a fixed rate to a formula rate. The formula rate will be updated annually to ensure that under this rate customers pay the actual costs of providing transmission services. PECO's initial formula rate filing included a requested increase of $22 million to PECO's annual transmission revenue requirement, which reflected a ROE of 11%, inclusive of a 50 basis point adder for being a member of a RTO. On June 27, 2017, FERC issued an Order accepting the filing and suspending the proposed rates until December 1, 2017, subject to refund, and set the matter for hearing and settlement judge procedures.

On December 5, 2019, FERC issued an Order accepting without modification the settlement agreement filed by PECO and other parties in July 2019. The settlement results in an increase of approximately $14 million with a return on rate base of 7.62% compared to PECO's initial formula rate filing and allows for an ROE of 10.35%, inclusive of a 50 basis point adder for being a member of the RTO. The settlement did not have a material impact on PECO's 2017, 2018, or 2019 annual transmission revenue requirements. PECO will update its rates in 2020 and refunds estimated overcollections totaling approximately $28 million related to the amounts billed under the proposed rates in effect since 2017.

Pursuant to the transmission formula rate request discussed above, PECO made its annual formula rate updates in May 2018 and 2019, which included a decrease of $6 million and an increase of $8 million, respectively, to the annual transmission revenue requirement. The updated transmission formula rates were effective on June 1, 2018 and 2019, respectively, subject to refund.

## Cost Management Programs

Exelon continues to be committed to managing its costs. On October 31, 2019, Exelon announced additional annual cost savings of approximately $100 million, at Generation, to be achieved by 2022. These actions are in response to the continuing economic challenges confronting Generation's business, necessitating continued focus on cost management through enhanced efficiency and productivity.

## FERC Order on the PJM MOPR

On December 19, 2019, FERC issued an order directing PJM to extend the MOPR to include new and existing resources, including nuclear, that receive state subsidies, effective as of PJM's next capacity auction. Unless Illinois and New Jersey can implement an FRR program in their PJM zones, the MOPR will apply to Generation's nuclear plants in those states receiving ZEC benefits, resulting in higher offers for those units that may not clear the capacity market. On January 21, 2020, Exelon, PJM and a number of other entities submitted individual requests for rehearing. Exelon is currently working with PJM and other stakeholders to pursue the FRR option but cannot predict whether the legislative and regulatory changes can be implemented prior to the next capacity auction in PJM. If Generation's state-supported nuclear plants in PJM or NYISO are subjected to the MOPR without compensation under an FRR or similar program, it could have a material adverse impact on Exelon's and Generation's financial



statements. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

## Early Plant Retirements

Oyster Creek. Generation permanently ceased generation operations at Oyster Creek on September 17, 2018. On July 31, 2018, Generation entered into an agreement with Holtec International and its wholly owned subsidiary, Oyster Creek Environmental Protection, LLC, for the sale and decommissioning of Oyster Creek. The sale was completed on July 1, 2019. Exelon and Generation recognized a loss on the sale in the third quarter 2019, which was immaterial. See Note 2 — Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.

Three Mile Island. Generation permanently ceased operations at TMI on September 20, 2019. As a result of the decision to early retire TMI, Exelon and Generation recorded a $176 million incremental pre-tax net charge for the year ended December 31, 2019 primarily due to accelerated depreciation of the plant assets, partially offset by a benefit associated with the remeasurement of the TMI ARO in the first quarter of 2019.

Salem. In 2017, PSEG announced that its New Jersey nuclear plants, including Salem, of which Generation owns a 42.59% ownership interest, were showing increased signs of economic distress, which could lead to an early retirement. PSEG is the operator of Salem and also has the decision-making authority to retire Salem. In 2018, New Jersey enacted legislation that established a ZEC program that provides compensation for nuclear plants that demonstrate to the NJBPU that they meet certain requirements, including that they make a significant contribution to air quality in the state and that their revenues are insufficient to cover their costs and risks. On April 18, 2019, the NJBPU approved the award of ZECs to Salem Unit 1 and Salem Unit 2. Assuming the continued effectiveness of the New Jersey ZEC program, Generation no longer considers Salem to be at heightened risk for early retirement.

Dresden, Byron and Braidwood. Generation’s Dresden, Byron and Braidwood nuclear plants in Illinois are also showing increased signs of economic distress, which could lead to an early retirement, in a market that does not currently compensate them for their unique contribution to grid resiliency and their ability to produce large amounts of energy without carbon and air pollution. The May 2018 PJM capacity auction for the 2021-2022 planning year resulted in the largest volume of nuclear capacity ever not selected in the auction, including all of Dresden, and portions of Byron and Braidwood. Exelon continues to work with stakeholders on state policy solutions, while also advocating for broader market reforms at the regional and federal level.

See Note 3 — Regulatory Matters, Note 6 — Early Plant Retirements and Note 9 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information.

## CENG Put Option

On November 20, 2019, Generation received notice of EDF's intention to exercise the put option and sell its 49.99% equity interest in CENG to Generation and the put automatically exercised on January 19, 2020 at the end of the sixty-day advance notice period. Under the terms of the Put Option, the purchase price is to be determined by agreement of the parties, or absent such agreement, by a third-party arbitration process. Any resulting sale would be subject to the approval of the NYPSC, the FERC and the NRC. The process and regulatory approvals could take one to two years or more to complete. See Note 2 - Mergers, Acquisitions and Dispositions for additional information.

## Conowingo Hydroelectric Project

In connection with Generation’s pursuit of a new FERC license for Conowingo, on October 29, 2019, Generation and MDE filed with FERC a Joint Offer of Settlement that would resolve all outstanding issues between the parties, effective upon and subject to FERC’s approval and incorporation of the terms into the new license when issued. The financial impact of this settlement, along with other anticipated and prior license commitments, would be recognized over the term of the new 50-year license and is estimated to be, on average, $11 million to $14 million per year, including capital and operating costs. The actual timing and amount of a majority of these costs are not currently fixed and will vary from year to year throughout the life of the new license. Generation cannot currently predict when FERC will issue the new license. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

## Pacific Gas & Electric Bankruptcy



Generation’s Antelope Valley, a 242 MW solar facility in Lancaster, CA, sells all of its output to PG&E through a PPA. On January 29, 2019, PG&E filed for protection under Chapter 11 of the U.S. Bankruptcy Code. As of December 31, 2019, Generation had approximately $725 million and $485 million of net long-lived assets and nonrecourse debt outstanding, respectively, related to Antelope Valley. PG&E’s bankruptcy created an event of default for Antelope Valley’s nonrecourse debt that provides the lender with a right to accelerate amounts outstanding under the loan such that they would become immediately due and payable. As a result of the ongoing event of default and the absence of a waiver from the lender foregoing their acceleration rights, the debt was reclassified as current in Exelon’s and Generation’s Consolidated Balance Sheets in the first quarter of 2019 and continues to be classified as current as of December 31, 2019.

In the first quarter of 2019, Generation assessed and determined that Antelope Valley’s long-lived assets were not impaired. Significant changes in assumptions such as the likelihood of the PPA being rejected as part of the bankruptcy proceedings could potentially result in future impairments of Antelope Valley’s net long-lived assets, which could be material. Generation is monitoring the bankruptcy proceedings for any changes in circumstances that would indicate the carrying amount of the net long-lived assets of Antelope Valley may not be recoverable.

See Note 11 — Asset Impairments and Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the PG&E bankruptcy.

## Exelon’s Strategy and Outlook for 2020 and Beyond

Exelon’s value proposition and competitive advantage come from its scope and its core strengths of operational excellence and financial discipline. Exelon leverages its integrated business model to create value. Exelon’s regulated and competitive businesses feature a mix of attributes that, when combined, offer shareholders and customers a unique value proposition:

• The Utility Registrants provide a foundation for steadily growing earnings, which translates to a stable currency in our stock.

• Generation’s competitive businesses provide free cash flow to invest primarily in the utilities and to reduce debt.

Exelon believes its strategy provides a platform for optimal success in an energy industry experiencing fundamental and sweeping change.

Exelon’s utility strategy is to improve reliability and operations and enhance the customer experience, while ensuring ratemaking mechanisms provide the utilities fair financial returns. The Utility Registrants only invest in rate base where it provides a benefit to customers and the community by improving reliability and the service experience or otherwise meeting customer needs. The Utility Registrants make these investments at the lowest reasonable cost to customers. Exelon seeks to leverage its scale and expertise across the utilities platform through enhanced standardization and sharing of resources and best practices to achieve improved operational and financial results. Additionally, the Utility Registrants anticipate making significant future investments in smart grid technology, transmission projects, gas infrastructure, and electric system improvement projects, providing greater reliability and improved service for our customers and a stable return for the company.

Generation’s competitive businesses create value for customers by providing innovative energy solutions and reliable, clean and affordable energy. Generation’s electricity generation strategy is to pursue opportunities that provide stable revenues and generation to load matching to reduce earnings volatility. Generation leverages its energy generation portfolio to deliver energy to both wholesale and retail customers. Generation’s customer-facing activities foster development and delivery of other innovative energy-related products and services for its customers. Generation operates in well-developed energy markets and employs an integrated hedging strategy to manage commodity price volatility. Its generation fleet, including its nuclear plants which consistently operate at high capacity factors, also provide geographic and supply source diversity. These factors help Generation mitigate the current challenging conditions in competitive energy markets.

Exelon’s financial priorities are to maintain investment grade credit metrics at each of the Registrants, to maintain optimal capital structure and to return value to Exelon’s shareholders with an attractive dividend throughout the energy commodity market cycle and through stable earnings growth.



As part of its strategic business planning process, Exelon routinely reviews its hedging policy, dividend policy, operating and capital costs, capital spending plans, strength of its balance sheet and credit metrics, and sufficiency of its liquidity position, by performing various stress tests with differing variables, such as commodity price movements, increases in margin-related transactions, changes in hedging practices, and the impacts of hypothetical credit downgrades.

Exelon’s Board of Directors approved a dividend policy providing a raise of 5% each year for the period covering 2018 through 2020, beginning with the March 2018 dividend.

Various market, financial, regulatory, legislative and operational factors could affect the Registrants' success in pursuing their strategies. Exelon continues to assess infrastructure, operational, commercial, policy, and legal solutions to these issues. One key issue is ensuring the ability to properly value nuclear generation assets in the market, solutions to which Exelon is actively pursuing in a variety of jurisdictions and venues. See ITEM 1A. RISK FACTORS for additional information regarding market and financial factors.

Exelon continues to be committed to managing its costs. In November 2017, Exelon announced a commitment for $250 million of cost savings, primarily at Generation, to be achieved by 2020. In November 2018, Exelon announced the elimination of an approximately additional $200 million of annual ongoing costs, through initiatives primarily at Generation and BSC, by 2021. Approximately $150 million is expected to be related to Generation, with the remaining amount related to the Utility Registrants. In October 2019, Exelon announced additional annual cost savings of approximately $100 million, at Generation, to be achieved by 2022. These actions are in response to the continuing economic challenges confronting Generation's business, necessitating continued focus on cost management through enhanced efficiency and productivity.

## Growth Opportunities

Management continually evaluates growth opportunities aligned with Exelon’s businesses, assets and markets, leveraging Exelon’s expertise in those areas and offering sustainable returns.

Regulated Energy Businesses. The Utility Registrants anticipate investing approximately $26 billion over the next four years in electric and natural gas infrastructure improvements and modernization projects, including smart grid technology, storm hardening, advanced reliability technologies, and transmission projects, which is projected to result in an increase to current rate base of approximately $13 billion by the end of 2023. The Utility Registrants invest in rate base where beneficial to customers and the community by increasing reliability and the service experience or otherwise meeting customer needs. These investments are made at the lowest reasonable cost to customers.

See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the Smart Meter and Smart Grid Investments and infrastructure development and enhancement programs.

Competitive Energy Businesses. Generation continually assesses the optimal structure and composition of its generation assets as well as explores wholesale and retail opportunities within the power and gas sectors. Generation’s long-term growth strategy is to ensure appropriate valuation of its generation assets, in part through public policy efforts, identify and capitalize on opportunities that provide generation to load matching as a means to provide stable earnings, and identify emerging technologies where strategic investments provide the option for significant future growth or influence in market development.

## Other Key Business Drivers and Management Strategies

## Utility Rates and Rate Proceedings

The Utility Registrants file rate cases with their regulatory commissions seeking increases or decreases to their electric transmission and distribution, and gas distribution rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Utility Registrants' current and future results of operations, cash flows and financial positions. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on these regulatory proceedings.



## Power Markets

## Price of Fuels

The use of new technologies to recover natural gas from shale deposits is increasing natural gas supply and reserves, which places downward pressure on natural gas prices and, therefore, on wholesale and retail power prices, which results in a reduction in Exelon's revenues. Forward natural gas prices have declined significantly over the last several years; in part reflecting an increase in supply due to strong natural gas production (due to shale gas development).

## FERC Inquiry on Resiliency

On August 23, 2017, the DOE staff released its report on the reliability of the electric grid. One aspect of the wide-ranging report is the DOE's recognition that the electricity markets do not currently value the resiliency provided by base-load generation, such as nuclear plants. On September 28, 2017, the DOE issued a Notice of Proposed Rulemaking (NOPR) that would entitle certain eligible resilient generating units (i.e., those located in organized markets, with a 90-day supply of fuel on site, not already subject to state cost of service regulation and satisfying certain other requirements) to recover fully allocated costs and earn a fair return on equity on their investment. On January 8, 2018, FERC issued an order terminating the rulemaking docket that it initiated to address the proposed rule in the DOE NOPR, concluding the proposed rule did not sufficiently demonstrate there is a resiliency issue and that it proposed a remedy that did not appear to be just, reasonable and nondiscriminatory as required under the Federal Power Act. At the same time, FERC initiated a new proceeding to consider resiliency challenges to the bulk power system and evaluate whether additional FERC action to address resiliency would be appropriate. FERC directed each RTO and ISO to respond within 60 days to 24 specific questions about how they assess and mitigate threats to resiliency. Thereafter, interested parties submitted reply comments on May 9, 2018, and a few parties submitted further replies. Exelon has been and will continue to be an active participant in these proceedings but cannot predict the final outcome or its potential financial impact, if any, on Exelon or Generation.

## Section 232 Uranium Petition

On January 16, 2018, two Canadian-owned uranium mining companies with operations in the U.S. jointly submitted a petition to the U.S. Department of Commerce (DOC) seeking relief under Section 232 of the Trade Expansion Act of 1962, as amended, (the Act) from imports of uranium products, alleging that these imports threaten national security (the Petition). The relief requested would have required U.S. nuclear reactors to purchase at least 25% of their uranium needs from domestic mines for the next 10 years or more. The Act was promulgated by Congress to protect essential national security industries whose survival is threatened by imports. As such, the Act authorizes the Secretary of Commerce (the Secretary) to conduct investigations to evaluate the effects of imports of any item on the national security of the U.S. The Petition alleges that the loss of a viable U.S. uranium mining industry would have a significant detrimental impact on the national, energy, and economic security of the U.S. and the ability of the country to sustain an independent nuclear fuel cycle.

On July 18, 2018, the Secretary announced that the DOC had initiated an investigation in response to the petition. The Secretary submitted a report to President Trump on April 14, 2019 that has not been made public. On July 12, 2019, the President issued a memorandum indicating that he did not agree with the Secretary's finding that uranium imports threaten to impair the national security of the United States, choosing not to impose any trade restrictions at this time. The President found that a fuller analysis of national security considerations with respect to the entire nuclear fuel supply chain is necessary and directed that a United States Nuclear Fuel Working Group (Working Group) be established to develop recommendations for reviving and expanding domestic nuclear fuel production. The Working Group report has not yet been issued and is not expected to be made public. The Working Group is co-chaired by the Assistant to the President for National Security Affairs and the Assistant to the President for Economic Policy. Exelon will monitor and volunteer to provide information to support the Working Group's efforts. Exelon and Generation cannot currently predict the outcome of the Working Group report and subsequent actions.

## Complaint at FERC Seeking to Alter Capacity Market Default Offer Caps

On February 21, 2019, PJM's Independent Market Monitor (IMM) filed a complaint alleging that the number of performance assessment intervals used to calculate the default offer cap for bids to supply capacity in PJM is too high, resulting in an overstated default offer cap that obviates the need for most sellers to seek unit-specific approval of their offers. The IMM claims that this allows for the exercise of market power. The IMM asks FERC to require PJM to reduce the number of performance assessment intervals used to calculate the opportunity costs of a capacity



supplier assuming a capacity obligation. This would, in turn, lower the default offer cap and allow the IMM to review more offers on a unit-specific basis. It is too early to predict the final outcome of this proceeding or its potential financial impact, if any, on Exelon or Generation.

## Energy Demand

Modest economic growth partially offset by energy efficiency initiatives is resulting in relatively flat load growth in electricity for the Utility Registrants. ComEd, PECO, BGE, Pepco, DPL and ACE are projecting load volumes to increase (decrease) by (0.3%), (0.7%), (1.2%), (0.4%), (0.5%) and (0.4%), respectively, in 2020 compared to 2019.

## Retail Competition

Generation’s retail operations compete for customers in a competitive environment, which affect the margins that Generation can earn and the volumes that it is able to serve. Forward natural gas and power prices are expected to remain low and thus we expect retail competitors to stay aggressive in their pursuit of market share, and that wholesale generators (including Generation) will continue to use their retail operations to hedge generation output.

## Hedging Strategy

Exelon’s policy to hedge commodity risk on a ratable basis over three-year periods is intended to reduce the financial impact of market price volatility. Generation is exposed to commodity price risk associated with the unhedged portion of its electricity portfolio. Generation enters into non-derivative and derivative contracts, including financially-settled swaps, futures contracts and swap options, and physical options and physical forward contracts, all with credit-approved counterparties, to hedge this anticipated exposure. As of December 31, 2019, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York and ERCOT reportable segments is 91%-94% and 61%-64% for 2020 and 2021, respectively. Generation has been and will continue to be proactive in using hedging strategies to mitigate commodity price risk.

Generation procures natural gas through long-term and short-term contracts and spot-market purchases. Nuclear fuel assemblies are obtained predominantly through long-term uranium concentrate supply contracts, contracted conversion services, contracted enrichment services, or a combination thereof, and contracted fuel fabrication services. The supply markets for uranium concentrates and certain nuclear fuel services are subject to price fluctuations and availability restrictions. Approximately 60% of Generation's uranium concentrate requirements from 2020 through 2024 are supplied by three suppliers. In the event of non-performance by these or other suppliers, Generation believes that replacement uranium concentrate can be obtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements. Non-performance by these counterparties could have a material adverse impact on Exelon's and Generation's results of operations, cash flows and financial positions.

See Note 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements and ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for additional information.

The Utility Registrants mitigate commodity price risk through regulatory mechanisms that allow them to recover procurement costs from retail customers.

## Environmental Legislative and Regulatory Developments

Exelon was actively involved in the Obama Administration’s development and implementation of environmental regulations for the electric industry, in pursuit of its business strategy to provide reliable, clean, affordable and innovative energy products. These efforts have most frequently involved air, water and waste controls for fossil-fueled electric generating units, as set forth in the discussion below. These regulations have had a disproportionate adverse impact on coal-fired power plants, requiring significant expenditures of capital and variable operating and maintenance expense, and have resulted in the retirement of older, marginal facilities. Due to its low emission generation portfolio, Generation has not been significantly affected by these regulations, representing a competitive advantage relative to electric generators that are more reliant on fossil fuel plants.

Through the issuance of a series of Executive Orders (EO), President Trump has initiated review of a number of EPA and other regulations issued during the Obama Administration, with the expectation that the Administration will seek repeal or significant revision of these rules. Under these EOs, each executive agency is required to evaluate existing regulations and make recommendations regarding repeal, replacement, or modification. The



Administration’s actions are intended to result in less stringent compliance requirements under air, water, and waste regulations. The exact nature, extent, and timing of the regulatory changes are unknown, as well as the ultimate impact on Exelon’s and its subsidiaries’ results of operations and cash flows.

In particular, the Administration has targeted existing EPA regulations for repeal, including notably the Clean Power Plan, as well as revoking many Executive Orders, reports, and guidance issued by the Obama Administration on the topic of climate change or the regulation of greenhouse gases. The Executive Order also disbanded the Interagency Working Group that developed the social cost of carbon used in rulemakings, and withdrew all technical support documents supporting the calculation. Other regulations that have been specifically identified for review are the Clean Water Act rule relating to jurisdictional waters of the U.S., the Steam Electric Effluent Guidelines relating to waste water discharges from coal-fired power plants, and the 2015 National Ambient Air Quality Standard (NAAQS) for ozone. The review of final rules could extend over several years as formal notice and comment rulemaking process proceeds.

## Air Quality

Mercury and Air Toxics Standard Rule (MATS). On December 16, 2011, the EPA signed a final rule to reduce emissions of toxic air pollutants from power plants and signed revisions to the NSPs for electric generating units. The final rule, known as MATS, requires coal-fired electric generation plants to achieve high removal rates of mercury, acid gases and other metals, and to make capital investments in pollution control equipment and incur higher operating expenses. Numerous entities challenged MATS in the D.C. Circuit Court, and Exelon intervened in support of the rule. In April 2014, the D.C. Circuit Court issued an opinion upholding MATS in its entirety. On appeal, the U.S. Supreme Court decided in June 2015 that the EPA unreasonably refused to consider costs in determining whether it is appropriate and necessary to regulate hazardous air pollutants emitted by electric utilities, but did not vacate the rule. On April 27, 2017, the D.C. Circuit Court granted EPA's motion to hold the litigation in abeyance, pending EPA's review of the MATS rule pursuant to President Trump's EO discussed above. Notwithstanding the Court's order to hold the litigation in abeyance, the MATS rule remains in effect. Exelon will continue to participate in the remanded proceedings before the D.C. Circuit Court as an intervenor in support of the rule. On December 28, 2018, the EPA proposed to revoke the "appropriate and necessary" finding underpinning the MATS rule. While the proposal would leave in place the rule, it would leave it vulnerable to future legal challenge. On February 7, 2019, EPA published its Reconsideration of Supplemental Finding and Residual Risk and Technology Review. After considering public comment, EPA transmitted a final version to the Office of Management and Budget for review prior to publication.

Clean Power Plan. On April 28, 2017, the D.C. Circuit Court issued orders in separate litigation related to the EPA’s actions under the Clean Power Plan (CPP) to amend Clean Air Act Section 111(d) regulation of existing fossil-fired electric generating units and Section 111(b) regulation of new fossil-fired electric generating units. In both cases, the Court has determined to hold the litigation in abeyance pending a determination whether the rule should be remanded to the EPA. In June 2019, EPA issued a final rule that repealed the CPP, and finalized the Affordable Clean Energy rule to replace the CPP with less stringent emissions guidelines based on heat rate improvement measures that could be achieved within the fence line of existing power plants. The Affordable Clean Energy rule is currently being litigated.

2015 Ozone National Ambient Air Quality Standards (NAAQS). On April 11, 2017, the D.C. Circuit Court ordered that the consolidated 2015 ozone NAAQS litigation be held in abeyance pending EPA’s further review of the 2015 Rule. On August 23, 2019, the D.C. Circuit Court upheld the stringency of NAAQS, but remanded certain aspects of its secondary standard to EPA for revision.

Primary SO2 National Ambient Air Quality Standards (NAAQS). EPA took final action on April 17, 2019 to retain the current primary SO2 standard without revision, leaving the standard established in 2010 in effect.

Climate Change. Exelon supports comprehensive climate change legislation or regulation, including a cap-and-trade program for GHG emissions, which balances the need to protect consumers, business and the economy with the urgent need to reduce national GHG emissions. In the absence of Federal legislation, the EPA is moving forward with the regulation of GHG emissions under the Clean Air Act. In addition, there have been recent developments in the international regulation of GHG emissions pursuant to the United Nations Framework Convention on Climate Change (“UNFCCC” or “Convention”). See ITEM 1. BUSINESS, “Global Climate Change” for additional information.



## Water Quality

Section 316(b) requires that the cooling water intake structures at electric power plants reflect the best technology available to minimize adverse environmental impacts and is implemented through state-level NPDES permit programs. All of Generation's power generation facilities with cooling water systems are subject to the regulations. Facilities without closed-cycle recirculating systems (e.g., cooling towers) are potentially most affected by recent changes to the regulations. For Generation, those facilities are Calvert Cliffs, Clinton, Dresden, Eddystone, Fairless Hills, FitzPatrick, Ginn, Gould Street, Handley, Mystic 7, Nine Mile Point Unit 1, Peach Bottom, Quad Cities, and Salem. See ITEM 1. BUSINESS, "Water Quality" for additional information.

## Clean Water Rule

In 2015, the EPA and the US Army Corps of Engineers, finalized the Clean Water Rule that significantly expanded the definition of the Waters of the United States under the Clean Water Act and resulted in increased environmental costs for some projects. On October 22, 2019, the EPA and the US Army Corps of Engineers repealed the 2015 Clean Water Rule and restored the definition of the Waters of the United States that existed prior to this rule. On January 23, 2020, a new final rule was issued by the EPA and the US Army Corps of Engineers to streamline and clarify the definition of Waters of the United States and will be effective sixty days after publication in the Federal Register. This rule represents final action by these government agencies to narrow the scope of Waters of the United States that are regulated under the federal Clean Water Act.

## Solid and Hazardous Waste

In October 2015, the first federal regulation for the disposal of coal combustion residuals (CCR) from power plants became effective. The rule classifies CCR as non-hazardous waste under RCRA. Under the regulation, CCR will continue to be regulated by most states subject to coordination with the federal regulations. Generation has previously recorded accruals consistent with state regulation for its owned coal ash sites, and as such, the regulation is not expected to impact Exelon's and Generation's financial results. Generation does not have sufficient information to reasonably assess the potential likelihood or magnitude of any remediation requirements that may be asserted under the new federal regulations for coal ash disposal sites formerly owned by Generation. For these reasons, Generation is unable to predict whether and to what extent it may ultimately be held responsible for remediation and other costs relating to formerly owned coal ash disposal sites under the new regulations.

See Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information related to environmental matters.

## Other Legislative and Regulatory Developments

## Illinois Clean Energy Progress Act

On March 14, 2019, the Clean Energy Progress Act was introduced in the Illinois General Assembly to preserve Illinois' clean energy choices arising from FEJA and empower the IPA to conduct capacity procurements outside of PJM's base residual auction process, while utilizing the fixed resource requirement provisions in PJM's tariffs which are still subject to penalties and other obligations under the PJM tariffs. The most significant provisions of the proposed legislation are as follows: (1) it allows the IPA to procure capacity directly from clean energy resources that have previously sold ZECs or RECs, including certain of Generation's nuclear plants in Illinois, or from new clean energy resources, (2) it establishes a goal of achieving 100% carbon-free power in the ComEd service territory by 2032, and (3) it implements reforms to enhance consumer protections in the state's competitive retail electricity and natural gas markets, including Generation's retail customers. Energy legislation has also been proposed by other stakeholders, including renewable resource developers, environmental advocates, and coal-fueled generators. Exelon and Generation will work with legislators and stakeholders and cannot predict the outcome or the potential financial impact, if any, on Exelon or Generation.

## Nuclear Powers Act of 2019

On April 12, 2019, the Nuclear Powers America Act of 2019 was introduced to the United States Congress, which expands the current investment tax credit to existing nuclear power plants. The proposed legislation would provide a credit equal to 30% of continued capital investment in certain nuclear energy-related expenditures, including capital expenses and nuclear fuel, starting from tax years 2019 through 2023. Thereafter, the credit rate would be reduced to 26% in 2024, 22% in 2025, and 10% in 2026 and beyond. To qualify for the credit, the plant must be



currently operational and must have applied for an operating license renewal before 2026. Exelon and Generation are working with legislators and stakeholders and cannot predict the outcome or the potential financial impact, if any, on Exelon or Generation.

## Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with GAAP requires that management apply accounting policies and make estimates and assumptions that affect results of operations and the amounts of assets and liabilities reported in the financial statements. Management believes that the accounting policies described below require significant judgment in their application, or incorporate estimates and assumptions that are inherently uncertain and that may change in subsequent periods. Additional information of the application of these accounting policies can be found in the Combined Notes to Consolidated Financial Statements.

## Nuclear Decommissioning Asset Retirement Obligations (Exelon and Generation)

Generation’s ARO associated with decommissioning its nuclear units was $10.5 billion at December 31, 2019. The authoritative guidance requires that Generation estimate its obligation for the future decommissioning of its nuclear generating plants. To estimate that liability, Generation uses an internally-developed, probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple decommissioning outcome scenarios.

As a result of recent nuclear plant retirements in the industry, nuclear operators and third-party service providers are obtaining more information about costs associated with decommissioning activities. At the same time, regulators are gaining more information about decommissioning activities which could result in changes to existing decommissioning requirements. In addition, as more nuclear plants are retired, it is possible that technological advances will be identified that could create efficiencies and lead to a reduction in decommissioning costs. The availability of NDT funds could impact the timing of the decommissioning activities. Additionally, certain factors such as changes in regulatory requirements during plant operations or the profitability of a nuclear plant could impact the timing of plant retirements. These factors could result in material changes to Generation’s current estimates as more information becomes available and could change the timing of plant retirements and the probability assigned to the decommissioning outcome scenarios.

The nuclear decommissioning obligation is adjusted on a regular basis due to the passage of time and revisions to the key assumptions for the expected timing and/or estimated amounts of the future undiscounted cash flows required to decommission the nuclear plants, based upon the following methodologies and significant estimates and assumptions:

Decommissioning Cost Studies. Generation uses unit-by-unit decommissioning cost studies to provide a marketplace assessment of the expected costs (in current year dollars) and timing of decommissioning activities, which are validated by comparison to current decommissioning projects within the industry and other estimates. Decommissioning cost studies are updated, on a rotational basis, for each of Generation's nuclear units at least every five years, unless circumstances warrant more frequent updates. As part of the annual cost study update process, Generation evaluates newly assumed costs or substantive changes in previously assumed costs to determine if the cost estimate impacts are sufficiently material to warrant application of the updated estimates to the AROs across the nuclear fleet outside of the normal five-year rotating cost study update cycle.

Cost Escalation Factors. Generation uses cost escalation factors to escalate the decommissioning costs from the decommissioning cost studies discussed above through the assumed decommissioning period for each of the units. Cost escalation studies, updated on an annual basis, are used to determine escalation factors, and are based on inflation indices for labor, equipment and materials, energy, LLRW disposal and other costs. All of the nuclear AROs are adjusted each year for the updated cost escalation factors.

Probabilistic Cash Flow Models. Generation’s probabilistic cash flow models include the assignment of probabilities to various scenarios for decommissioning cost levels, decommissioning approaches, and timing of plant shutdown on a unit-by-unit basis. Probabilities assigned to cost levels include an assessment of the likelihood of costs 20% higher (high-cost scenario) or 15% lower (low-cost scenario) than the base cost scenario. The assumed decommissioning scenarios include the following three alternatives: (1) DECON which assumes decommissioning activities begin shortly after the cessation of operation, (2) Shortened SAFSTOR generally has a 30-year delay prior to onset of decommissioning activities, and (3) SAFSTOR which assumes the nuclear facility is placed and



maintained in such condition that the nuclear facility can be safely stored and subsequently decontaminated generally within 60 years after cessation of operations. In each decommissioning scenario, spent fuel is transferred to dry cask storage as soon as possible until DOE acceptance for disposal.

The actual decommissioning approach selected once a nuclear facility is shutdown will be determined by Generation at the time of shutdown and may be influenced by multiple factors including the funding status of the nuclear decommissioning trust fund at the time of shutdown.

The assumed plant shutdown timing scenarios include the following four alternatives: (1) the probability of operating through the original 40-year nuclear license term, (2) the probability of operating through an extended 60-year nuclear license term (regardless of whether such 20-year license extension has been received for each unit), (3) the probability of a second, 20-year license renewal for some nuclear units, and (4) the probability of early plant retirement for certain sites due to changing market conditions and regulatory environments. The successful operation of nuclear plants in the U.S. beyond the initial 40-year license terms has prompted the NRC to consider regulatory and technical requirements for potential plant operations for an 80-year nuclear operating term. As power market and regulatory environment developments occur, Generation evaluates and incorporates, as necessary, the impacts of such developments into its nuclear ARO assumptions and estimates.

Generation’s probabilistic cash flow models also include an assessment of the timing of DOE acceptance of SNF for disposal. Generation currently assumes DOE will begin accepting SNF in 2030. The SNF acceptance date assumption is based on management’s estimates of the amount of time required for DOE to select a site location and develop the necessary infrastructure for long-term SNF storage. For additional information regarding the estimated date that DOE will begin accepting SNF, see Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements.

Discount Rates. The probability-weighted estimated future cash flows for the various assumed scenarios are discounted using credit-adjusted, risk-free rates (CARFR) applicable to the various businesses in which each of the nuclear units originally operated. Generation initially recognizes an ARO at fair value and subsequently adjusts it for changes to estimated costs, timing of future cash flows and modifications to decommissioning assumptions. The ARO is not required or permitted to be re-measured for changes in the CARFR that occur in isolation. Increases in the ARO as a result of upward revisions in estimated undiscounted cash flows are considered new obligations and are measured using a current CARFR as the increase creates a new cost layer within the ARO. Any decrease in the estimated undiscounted future cash flows relating to the ARO are treated as a modification of an existing ARO cost layer and, therefore, is measured using the average historical CARFR rates used in creating the initial ARO cost layers. If Generation’s future nominal cash flows associated with the ARO were to be discounted at current prevailing CARFR, the obligation would increase from approximately $10.5 billion to approximately $13.2 billion.

The following table illustrates the significant impact that changes in the CARFR, when combined with changes in projected amounts and expected timing of cash flows, can have on the valuation of the ARO (dollars in millions):

<table><tr><td>Change in the CARFR applied to the annual ARO update</td><td colspan="2">Increase (Decrease) to ARO at December 31, 2019</td></tr><tr><td>2018 CARFR rather than the 2019 CARFR</td><td>$</td><td>(820)</td></tr><tr><td>2019 CARFR increased by 50 basis points</td><td></td><td>(390)</td></tr><tr><td>2019 CARFR decreased by 50 basis points</td><td></td><td>390</td></tr></table>



ARO Sensitivities. Changes in the assumptions underlying the ARO could materially affect the decommissioning obligation. The impact to the ARO of a change in any one of these assumptions is highly dependent on how the other assumptions may correspondingly change.

The following table illustrates the effects of changing certain ARO assumptions while holding all other assumptions constant (dollars in millions):

<table><tr><td>Change in ARO Assumption</td><td>Increase to ARO at December 31, 2019</td></tr><tr><td>Cost escalation studies</td><td></td></tr><tr><td>Uniform increase in escalation rates of 50 basis points</td><td>2,250</td></tr><tr><td>Probabilistic cash flow models</td><td></td></tr><tr><td>Increase the estimated costs to decommission the nuclear plants by 10 percent</td><td>910</td></tr><tr><td>Increase the likelihood of the DECON scenario by 10 percent and decrease the likelihood of the SAFSTOR scenario by 10 percent \( ^{(a)} \)</td><td>550</td></tr><tr><td>Shorten each unit&#x27;s probability weighted operating life assumption by 10 percent \( ^{(b)} \)</td><td>1,570</td></tr><tr><td>Extend the estimated date for DOE acceptance of SNF to 2035</td><td>350</td></tr></table>

(a) Excludes any sites in which management has committed to a specific decommissioning approach.

(b) Excludes any retired sites.

See Note 1 — Significant Accounting Policies, Note 6 — Early Plant Retirements and Note 9 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information regarding accounting for nuclear AROs.

## Goodwill (Exelon, ComEd and PHI)

As of December 31, 2019, Exelon's $6.7 billion carrying amount of goodwill consists of $2.6 billion at ComEd, $4 billion at PHI and immaterial amounts at Generation and DPL. These entities are required to perform an assessment for possible impairment of their goodwill at least annually or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of the reporting units below their carrying amount. A reporting unit is an operating segment or one level below an operating segment (known as a component) and is the level at which goodwill is tested for impairment. ComEd has a single operating segment and reporting unit. PHI's operating segments and reporting units are Pepco, DPL and ACE. See Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information. Exelon's and ComEd's goodwill has been assigned entirely to the ComEd reporting unit. Exelon's and PHI's goodwill has been assigned to the Pepco, DPL and ACE reporting units in the amounts of $2.1 billion, $1.4 billion and $0.5 billion, respectively. See Note 12 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information.

Entities assessing goodwill for impairment have the option of first performing a qualitative assessment to determine whether a quantitative assessment is necessary. As part of the qualitative assessments, Exelon, ComEd and PHI evaluate, among other things, management's best estimate of projected operating and capital cash flows for their businesses, outcomes of recent regulatory proceedings, changes in certain market conditions, including the discount rate and regulated utility peer EBITDA multiples, and the passing margin from their last quantitative assessments performed.

Application of the goodwill impairment test requires management judgment, including the identification of reporting units and determining the fair value of the reporting unit, which management estimates using a weighted combination of a discounted cash flow analysis and a market multiples analysis. Significant assumptions used in these fair value analyses include discount and growth rates, utility sector market performance and transactions, projected operating and capital cash flows for ComEd's, Pepco's, DPL's and ACE's businesses and the fair value of debt. In applying the second step, if needed, management must estimate the fair value of specific assets and liabilities of the reporting unit.

While the annual assessments indicated no impairments, certain assumptions used in the assessment are highly sensitive to changes. Adverse regulatory actions or changes in significant assumptions could potentially result in future impairments of Exelon's, ComEd's or PHI's goodwill, which could be material. Based on the results of the



last annual quantitative goodwill tests performed as of November 1, 2016 and November 1, 2018 for ComEd and PHI, respectively, the estimated fair values of the ComEd, Pepco, DPL and ACE reporting units would have needed to decrease by more than 30%, 30%, 20% and 30%, respectively, for ComEd and PHI to fail the first step of their respective impairment tests.

See Note 1 — Significant Accounting Policies and Note 12 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information.

## Purchase Accounting (Exelon, Generation and PHI)

Assets acquired and liabilities assumed in an acquired business are recorded at their estimated fair values on the date of acquisition. The difference between the purchase price amount and the net fair value of assets acquired and liabilities assumed is recognized as goodwill on the balance sheet if the purchase price exceeds the estimated net fair value or as a bargain purchase gain on the income statement if the purchase price is less than the estimated net fair value. Determining the fair value of assets acquired and liabilities assumed requires management's judgment, often utilizes independent valuation experts and involves the use of significant estimates and assumptions with respect to the timing and amounts of future cash inflows and outflows, discount rates, market prices and asset lives, among other items. The judgments made in the determination of the estimated fair value assigned to the assets acquired and liabilities assumed, as well as the estimated useful life of each asset and the duration of each liability, could significantly impact the financial statements in periods after acquisition, such as through depreciation and amortization expense. The allocation of the purchase price may be modified up to one year after the acquisition date as more information is obtained about the fair value of assets acquired and liabilities assumed. If the transaction is determined to be an asset acquisition the purchase price is allocated to the assets acquired and the liabilities assumed and no goodwill or bargain purchase gain would be recorded. See Note 2 — Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.

## Unamortized Energy Contract Assets and Liabilities (Exelon, Generation and PHI)

Unamortized energy contract assets and liabilities represent the remaining unamortized balances of non-derivative energy contracts that Generation has acquired and the electricity contracts Exelon has acquired as part of the PHI merger. The initial amount recorded represents the fair value of the contracts at the time of acquisition. At Exelon and PHI, offsetting regulatory assets or liabilities where also recorded for those energy contract costs that are probable of recovery or refund through customer rates. The unamortized energy contract assets and liabilities and any corresponding regulatory assets or liabilities, respectively, are amortized over the life of the contract in relation to the expected realization of the underlying cash flows. Amortization of the unamortized energy contract assets and liabilities is recorded through purchased power and fuel expense or operating revenues, depending on the nature of the underlying contract. See Note 3 — Regulatory Matters, Note 2 — Mergers, Acquisitions and Dispositions and Note 12 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information.

## Impairment of Long-Lived Assets (All Registrants)

All Registrants regularly monitor and evaluate the carrying value of long-lived assets and asset groups for recoverability whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators of potential impairment may include a deteriorating business climate, including, but not limited to, declines in energy prices, condition of the asset, an asset remaining idle for more than a short period of time, specific regulatory disallowance, advances in technology, plans to dispose of a long-lived asset significantly before the end of its useful life, and financial distress of a third party for assets contracted with them on a long-term basis, among others.

The review of long-lived assets and asset groups for impairment utilizes significant assumptions about operating strategies and estimates of future cash flows, which require assessments of current and projected market conditions. For the generation business, forecasting future cash flows requires assumptions regarding forecasted commodity prices for the sale of power and purchases of fuel and the expected operations of assets. A variation in the assumptions used could lead to a different conclusion regarding the recoverability of an asset or asset group and, thus, could potentially result in material future impairments. An impairment evaluation is based on an undiscounted cash flow analysis at the lowest level at which cash flows of the long-lived assets or asset groups are largely independent of the cash flows of other assets and liabilities. For the generation business, the lowest level of independent cash flows is determined by the evaluation of several factors, including the geographic dispatch of the generation units and the hedging strategies related to those units as well as the associated intangible assets or



liabilities recorded on the balance sheet. The cash flows from the generating units are generally evaluated at a regional portfolio level with cash flows generated from the customer supply and risk management activities, including cash flows from related intangible assets and liabilities on the balance sheet. In certain cases, generating assets may be evaluated on an individual basis where those assets are contracted on a long-term basis with a third party and operations are independent of other generating assets (typically contracted renewables). For such assets the financial viability of the third party, including the impact of bankruptcy on the contract, may be a significant assumption in the assessment.

On a quarterly basis, Generation assesses its long-lived assets or asset groups for indicators of impairment. If indicators are present for a long-lived asset or asset group, a comparison of the undiscounted expected future cash flows to the carrying value is performed. When the undiscounted cash flow analysis indicates the carrying value of a long-lived asset or asset group is not recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. The fair value of the long-lived asset or asset group is dependent upon a market participant's view of the exit price of the assets. This includes significant assumptions of the estimated future cash flows generated by the assets and market discount rates. Events and circumstances often do not occur as expected and there will usually be differences between prospective financial information and actual results, and those differences may be material. The determination of fair value is driven by both internal assumptions that include significant unobservable inputs (Level 3) such as revenue and generation forecasts, projected capital, and maintenance expenditures and discount rates, as well as information from various public, financial and industry sources.

See Note 11 — Asset Impairments of the Combined Notes to Consolidated Financial Statements for a discussion of asset impairment assessments.

## Depreciable Lives of Property, Plant and Equipment (All Registrants)

The Registrants have significant investments in electric generation assets and electric and natural gas transmission and distribution assets. These assets are generally depreciated on a straight-line basis, using the group, composite or unitary methods of depreciation. The group approach is typically for groups of similar assets that have approximately the same useful lives and the composite approach is used for heterogeneous assets that have different lives. Under both methods, a reporting entity depreciates the assets over the average life of the assets in the group. The estimation of asset useful lives requires management judgment, supported by formal depreciation studies of historical asset retirement experience. Depreciation studies are generally completed every five years, or more frequently if required by a rate regulator or if an event, regulatory action, or change in retirement patterns indicate an update is necessary.

For the Utility Registrants, depreciation studies generally serve as the basis for amounts allowed in customer rates for recovery of depreciation costs. Generally, the Utility Registrants adjust their depreciation rates for financial reporting purposes concurrent with adjustments to depreciation rates reflected in customer rates, unless the depreciation rates reflected in customer rates do not align with management's judgment as to an appropriate estimated useful life or have not been updated on a timely basis. Depreciation expense and customer rates for ComEd, BGE, Pepco, DPL and ACE includes an estimate of the future costs of dismantling and removing plant from service upon retirement. See Note 3 – Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for information regarding regulatory liabilities and assets recorded by ComEd, BGE, Pepco, DPL and ACE related to removal costs.

PECO’s removal costs are capitalized to accumulated depreciation when incurred, and recorded to depreciation expense over the life of the new asset constructed consistent with PECO’s regulatory recovery method. Estimates for such removal costs are also evaluated in the periodic depreciation studies.

At Generation, along with depreciation study results, management considers expected future energy market conditions and generation plant operating costs and capital investment requirements in determining the estimated service lives of its generating facilities. See Note 6 — Early Plant Retirements of the Combined Notes to the Consolidated Financial Statements for additional information.

Changes in estimated useful lives of electric generation assets and of electric and natural gas transmission and distribution assets could have a significant impact on the Registrants' future results of operations. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for information regarding depreciation and estimated service lives of the property, plant and equipment of the Registrants.



## Defined Benefit Pension and Other Postretirement Employee Benefits (All Registrants)

Exelon sponsors defined benefit pension plans and other postretirement employee benefit plans for substantially all current employees. The measurement of the plan obligations and costs of providing benefits involves various factors, including the development of valuation assumptions and inputs and accounting policy elections. When developing the required assumptions, Exelon considers historical information as well as future expectations. The measurement of benefit obligations and costs is affected by several assumptions including the discount rate applied to benefit obligations, the long-term expected rate of return on plan assets, the anticipated rate of increase of health care costs, Exelon's expected level of contributions to the plans, the incidence of participant mortality, the expected remaining service period of plan participants, the level of compensation and rate of compensation increases, employee age, length of service, and the long-term expected investment rate credited to employees of certain plans, among others. The assumptions are updated annually and upon any interim remeasurement of the plan obligations. Exelon amortizes actuarial gains or losses in excess of a corridor of 10% of the greater of the projected benefit obligation or the market-related value (MRV) of plan assets over the expected average remaining service period of plan participants.

Pension and other postretirement benefit plan assets include equity securities, including U.S. and international securities, and fixed income securities, as well as certain alternative investment classes such as real estate, private equity and hedge funds.

Expected Rate of Return on Plan Assets. In determining the EROA, Exelon considers historical economic indicators (including inflation and GDP growth) that impact asset returns, as well as expectation regarding future long-term capital market performance, weighted by Exelon's target asset class allocations. Exelon calculates the amount of expected return on pension and other postretirement benefit plan assets by multiplying the EROA by the MRV of plan assets at the beginning of the year, taking into consideration anticipated contributions and benefit payments to be made during the year. In determining MRV, the authoritative guidance for pensions and postretirement benefits allows the use of either fair value or a calculated value that recognizes changes in fair value in a systematic and rational manner over not more than five years. For the majority of pension plan assets, Exelon uses a calculated value that adjusts for 20% of the difference between fair value and expected MRV of plan assets. Use of this calculated value approach enables less volatile expected asset returns to be recognized as a component of pension cost from year to year. For other postretirement benefit plan assets and certain pension plan assets, Exelon uses fair value to calculate the MRV.

Discount Rate. At December 31, 2019 and 2018, the discount rates were determined by developing a spot rate curve based on the yield to maturity of a universe of high-quality non-callable (or callable with make whole provisions) bonds with similar maturities to the related pension and other postretirement benefit obligations. The spot rates are used to discount the estimated future benefit distribution amounts under the pension and other postretirement benefit plans. The discount rate is the single level rate that produces the same result as the spot rate curve. Exelon utilizes an analytical tool developed by its actuaries to determine the discount rates.

Mortality. The mortality assumption is composed of a base table that represents the current expectation of life expectancy of the population adjusted by an improvement scale that attempts to anticipate future improvements in life expectancy. Exelon's mortality assumption is supported by an actuarial experience study of Exelon's plan participants and beginning in 2019, utilizes the Society of Actuaries' 2019 base table (Pr-2012) and MP-2019 improvement scale adjusted to a 0.75% long-term rate reached in 2035.



Sensitivity to Changes in Key Assumptions. The following tables illustrate the effects of changing certain of the actuarial assumptions discussed above, while holding all other assumptions constant (dollars in millions):

<table><tr><td rowspan="2">Actuarial Assumption</td><td colspan="2">Actual Assumption</td><td rowspan="2">Change in Assumption</td><td rowspan="2">Pension</td><td rowspan="2">OPEB</td><td rowspan="2">Total</td></tr><tr><td>Pension</td><td>OPEB</td></tr><tr><td>Change in 2019 cost:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td rowspan="2">Discount rate (a)</td><td>4.31%</td><td>4.30%</td><td>0.5%</td><td>$ (47)</td><td>$ (14)</td><td>$ (61)</td></tr><tr><td>4.31%</td><td>4.30%</td><td>(0.5)%</td><td>47</td><td>13</td><td>60</td></tr><tr><td rowspan="2">EROA</td><td>7.00%</td><td>6.67%</td><td>0.5%</td><td>(88)</td><td>(11)</td><td>(99)</td></tr><tr><td>7.00%</td><td>6.67%</td><td>(0.5)%</td><td>88</td><td>11</td><td>99</td></tr><tr><td>Change in benefit obligation at December 31, 2019:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td rowspan="2">Discount rate (a)</td><td>3.34%</td><td>3.31%</td><td>0.5%</td><td>(1,244)</td><td>(247)</td><td>(1,491)</td></tr><tr><td>3.34%</td><td>3.31%</td><td>(0.5)%</td><td>1,316</td><td>261</td><td>1,577</td></tr></table>

(a) In general, the discount rate will have a larger impact on the pension and other postretirement benefit cost and obligation as the rate moves closer to 0%. Therefore, the discount rate sensitivities above cannot necessarily be extrapolated for larger increases or decreases in the discount rate. Additionally, Exelon utilizes a liability-driven investment strategy for its pension asset portfolio. The sensitivities shown above do not reflect the offsetting impact that changes in discount rates may have on pension asset returns.

See Note 14 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information regarding the accounting for the defined benefit pension plans and other postretirement benefit plans.

## Regulatory Accounting (Exelon and Utility Registrants)

For their regulated electric and gas operations, Exelon and the Utility Registrants reflect the effects of cost-based rate regulation in their financial statements, which is required for entities with regulated operations that meet the following criteria: (1) rates are established or approved by a third-party regulator; (2) rates are designed to recover the entities' cost of providing services or products; and (3) a reasonable expectation that rates designed to recover costs can be charged to and collected from customers. Regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent (1) revenue or gains that have been deferred because it is probable such amounts will be returned to customers through future regulated rates; or (2) billings in advance of expenditures for approved regulatory programs. If it is concluded in a future period that a separable portion of operations no longer meets the criteria discussed above, Exelon and the Utility Registrants would be required to eliminate any associated regulatory assets and liabilities and the impact would be recognized in the Consolidated Statements of Operations and Comprehensive Income and could be material.

The following table illustrates the gains (losses) that could result from the elimination of regulatory assets and liabilities and charges against OCI (dollars in millions before taxes) related to deferred costs associated with Exelon's pension and other postretirement benefit plans that are recorded as regulatory assets in Exelon's Consolidated Balance Sheets:

<table><tr><td>December 31, 2019</td><td colspan="2">Exelon</td><td colspan="2">ComEd</td><td colspan="2">PECO</td><td colspan="2">BGE</td><td colspan="2">PHI</td><td colspan="2">Pepco</td><td colspan="2">DPL</td><td colspan="2">ACE</td></tr><tr><td>Gain (loss)</td><td>$</td><td>887</td><td>$</td><td>4,981</td><td>$</td><td>6</td><td>$</td><td>591</td><td>$</td><td>(696)</td><td>$</td><td>(18)</td><td>$</td><td>337</td><td>$</td><td>(43)</td></tr><tr><td>Charge against OCI \( ^{(a)} \)</td><td>$</td><td>3,864</td><td>$</td><td>—</td><td>$</td><td>—</td><td>$</td><td>—</td><td>$</td><td>—</td><td>$</td><td>—</td><td>$</td><td>—</td><td>$</td><td>—</td></tr></table>

(a) Exelon's charge against OCI (before taxes) consists of up to $2.3 billion, $176 million, $176 million, $396 million, $191 million and $86 million related to ComEd's, BGE's, PHI's, Pepco's, DPL's and ACE's respective portions of the deferred costs associated with Exelon's pension and other postretirement benefit plans. Exelon also has a net regulatory liability of $44 million (before taxes) related to PECO's portion of the deferred costs associated with Exelon's other postretirement benefit plans that would result in an increase in OCI if reversed.



See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding regulatory matters, including the regulatory assets and liabilities tables of Exelon and the Utility Registrants.

For each regulatory jurisdiction in which they conduct business, Exelon and the Utility Registrants assess whether the regulatory assets and liabilities continue to meet the criteria for probable future recovery or settlement at each balance sheet date and when regulatory events occur. This assessment includes consideration of recent rate orders, historical regulatory treatment for similar costs in each Registrant's jurisdictions, and factors such as changes in applicable regulatory and political environments. If the assessments and estimates made by Exelon and the Utility Registrants for regulatory assets and regulatory liabilities are ultimately different than actual regulatory outcomes, the impact in their consolidated financial statements could be material.

Refer to the revenue recognition discussion below for additional information on the annual revenue reconciliations associated with ICC-approved electric distribution and energy efficiency formula rates for ComEd, and FERC transmission formula rate tariffs for the Utility Registrants.

## Accounting for Derivative Instruments (All Registrants)

The Registrants use derivative instruments to manage commodity price risk, foreign currency exchange risk and interest rate risk related to ongoing business operations. The Registrants' derivative activities are in accordance with Exelon's Risk Management Policy (RMP). See Note 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.

The Registrants account for derivative financial instruments under the applicable authoritative guidance. Determining whether a contract qualifies as a derivative requires that management exercise significant judgment, including assessing market liquidity as well as determining whether a contract has one or more underlyings and one or more notional quantities. Changes in management's assessment of contracts and the liquidity of their markets, and changes in authoritative guidance, could result in previously excluded contracts becoming in scope to new authoritative guidance.

All derivatives are recognized on the balance sheet at their fair value, except for certain derivatives that qualify for, and are elected under, NPNS. Derivatives entered into for economic hedging and for proprietary trading purposes are recorded at fair value through earnings. For economic hedges that are not designated for hedge accounting for the Utility Registrants, changes in the fair value each period are generally recorded with a corresponding offsetting regulatory asset or liability given likelihood of recovering the associated costs through customer rates.

Normal Purchases and Normal Sales Exception. As part of Generation’s energy marketing business, Generation enters into contracts to buy and sell energy to meet the requirements of its customers. These contracts include short-term and long-term commitments to purchase and sell energy and energy-related products in the retail and wholesale markets with the intent and ability to deliver or take delivery. While some of these contracts are considered derivative financial instruments under the authoritative guidance, certain of these qualifying transactions have been designated by Generation as NPNS transactions, which are thus not required to be recorded at fair value, but rather on an accrual basis of accounting. Determining whether a contract qualifies for the NPNS requires judgment on whether the contract will physically deliver and requires that management ensure compliance with all of the associated qualification and documentation requirements. Revenues and expenses on contracts that qualify as NPNS are recognized when the underlying physical transaction is completed. Contracts that qualify for the NPNS are those for which physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period of time and the contract is not financially settled on a net basis. The contracts that ComEd has entered into with suppliers as part of ComEd’s energy procurement process, PECO’s full requirement contracts under the PAPUC-approved DSP program, most of PECO’s natural gas supply agreements, all of BGE’s full requirement contracts and natural gas supply agreements that are derivatives and certain Pepco, DPL and ACE full requirement contracts qualify for and are accounted for under the NPNS.

Commodity Contracts. Identification of a commodity contract as an economic hedge requires Generation to determine that the contract is in accordance with the RMP. Generation reassesses its economic hedges on a regular basis to determine if they continue to be within the guidelines of the RMP.

As a part of the authoritative guidance, the Registrants make estimates and assumptions concerning future commodity prices, load requirements, interest rates, the timing of future transactions and their probable cash flows, the fair value of contracts and the expected changes in the fair value in deciding whether or not to enter into derivative



transactions, and in determining the initial accounting treatment for derivative transactions. Under the authoritative guidance for fair value measurements, the Registrants categorize these derivatives under a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value.

Derivative contracts are traded in both exchange-based and non-exchange-based markets. Exchange-based derivatives that are valued using unadjusted quoted prices in active markets are generally categorized in Level 1 in the fair value hierarchy.

Certain derivatives' pricing is verified using indicative price quotations available through brokers or over-the-counter, on-line exchanges. The price quotations reflect the average of the bid-ask mid-point from markets that the Registrants believe provide the most liquid market for the commodity. The price quotations are reviewed and corroborated to ensure the prices are observable and representative of an orderly transaction between market participants. The Registrant's derivatives are traded predominantly at liquid trading points. The remaining derivative contracts are valued using models that consider inputs such as contract terms, including maturity, and market parameters, and assumptions of the future prices of energy, interest rates, volatility, credit worthiness and credit spread. For derivatives that trade in liquid markets, such as generic forwards, swaps and options, the model inputs are generally observable. Such instruments are categorized in Level 2.

For derivatives that trade in less liquid markets with limited pricing information, the model inputs generally would include both observable and unobservable inputs and are categorized in Level 3.

The Registrants consider nonperformance risk, including credit risk in the valuation of derivative contracts, including both historical and current market data in its assessment of nonperformance risk, including credit risk. The impacts of nonperformance and credit risk to date have generally not been material to the financial statements.

See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK and Note 17 — Fair Value of Financial Assets and Liabilities and Note 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding the Registrants' derivative instruments.

## Taxation (All Registrants)

Significant management judgment is required in determining the Registrants' provisions for income taxes, primarily due to the uncertainty related to tax positions taken, as well as deferred tax assets and liabilities and valuation allowances. The Registrants account for uncertain income tax positions using a benefit recognition model with a two-step approach including a more-likely-than-not recognition threshold and a measurement approach based on the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. Management evaluates each position based solely on the technical merits and facts and circumstances of the position, assuming the position will be examined by a taxing authority having full knowledge of all relevant information. Significant judgment is required to determine whether the recognition threshold has been met and, if so, the appropriate amount of tax benefits to be recorded in the Registrants' consolidated financial statements.

The Registrants evaluate quarterly the probability of realizing deferred tax assets by reviewing a forecast of future taxable income and their intent and ability to implement tax planning strategies, if necessary, to realize deferred tax assets. The Registrants also assess negative evidence, such as the expiration of historical operating loss or tax credit carryforwards, that could indicate the Registrant's inability to realize its deferred tax assets. Based on the combined assessment, the Registrants record valuation allowances for deferred tax assets when it is more-likely-than-not such benefit will not be realized in future periods.

Actual income taxes could vary from estimated amounts due to the future impacts of various items, including future changes in income tax laws, the Registrants' forecasted financial condition and results of operations, failure to successfully implement tax planning strategies, as well as results of audits and examinations of filed tax returns by taxing authorities. See Note 13 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.

## Accounting for Loss Contingencies (All Registrants)

In the preparation of their financial statements, the Registrants make judgments regarding the future outcome of contingent events and record liabilities for loss contingencies that are probable and can be reasonably estimated based upon available information. The amount recorded may differ from the actual expense incurred when the



uncertainty is resolved. Such difference could have a significant impact in the Registrants' consolidated financial statements.

Environmental Costs. Environmental investigation and remediation liabilities are based upon estimates with respect to the number of sites for which the Registrants will be responsible, the scope and cost of work to be performed at each site, the portion of costs that will be shared with other parties, the timing of the remediation work and changes in technology, regulations and the requirements of local governmental authorities. Annual studies and/or reviews are conducted at ComEd, PECO, BGE and DPL to determine future remediation requirements for MGP sites and estimates are adjusted accordingly. In addition, periodic reviews are performed at each of the Registrants to assess the adequacy of other environmental reserves. These matters, if resolved in a manner different from the estimate, could have a significant impact in the Registrants' consolidated financial statements. See Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.

Other, Including Personal Injury Claims. The Registrants are self-insured for general liability, automotive liability, workers' compensation, and personal injury claims to the extent that losses are within policy deductibles or exceed the amount of insurance maintained. The Registrants have reserves for both open claims asserted and an estimate of claims incurred but not reported (IBNR). The IBNR reserve is estimated based on actuarial assumptions and analysis and is updated annually. Future events, such as the number of new claims to be filed each year, the average cost of disposing of claims, as well as the numerous uncertainties surrounding litigation and possible state and national legislative measures could cause the actual costs to be higher or lower than estimated. Accordingly, these claims, if resolved in a manner different from the estimate, could have a material impact in the Registrants' consolidated financial statements.

## Revenue Recognition (All Registrants)

Sources of Revenue and Determination of Accounting Treatment. The Registrants earn revenues from various business activities including: the sale of power and energy-related products, such as natural gas, capacity, and other commodities in non-regulated markets (wholesale and retail); the sale and delivery of power and natural gas in regulated markets; and the provision of other energy-related non-regulated products and services.

The accounting treatment for revenue recognition is based on the nature of the underlying transaction and applicable authoritative guidance. The Registrants primarily apply the Revenue from Contracts with Customers, Derivative and Alternative Revenue Program (ARP) guidance to recognize revenue as discussed in more detail below.

Revenue from Contracts with Customers. The Registrants recognize revenues in the period in which the performance obligations within contracts with customers are satisfied, which generally occurs when power, natural gas, and other energy-related commodities are physically delivered to the customer. Transactions of the Registrants within the scope of Revenue from Contracts with Customers generally include non-derivative agreements, contracts that are designated as NPNS, sales to utility customers under regulated service tariffs, and spot-market energy commodity sales, including settlements with independent system operators.

The determination of Generation’s and the Utility Registrants’ retail power and natural gas sales to individual customers is based on systematic readings of customer meters, generally on a monthly basis. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated, and corresponding unbilled revenue is recorded. The measurement of unbilled revenue is affected by the following factors: daily customer usage measured by generation or gas throughput volume, customer usage by class, losses of energy during delivery to customers and applicable customer rates. Increases or decreases in volumes delivered to the utilities’ customers and favorable or unfavorable rate mix due to changes in usage patterns in customer classes in the period could be significant to the calculation of unbilled revenue. In addition, revenues may fluctuate monthly as a result of customers electing to use an alternate supplier, since unbilled commodity revenues are not recorded for these customers. Changes in the timing of meter reading schedules and the number and type of customers scheduled for each meter reading date also impact the measurement of unbilled revenue; however, total operating revenues would remain materially unchanged. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information.

Derivative Revenues. The Registrants record revenues and expenses using the mark-to-market method of accounting for transactions that are accounted for as derivatives. These derivative transactions primarily relate to commodity price risk management activities. Mark-to-market revenues and expenses include: inception gains or



losses on new transactions where the fair value is observable, unrealized gains and losses from changes in the fair value of open contracts, and realized gains and losses.

Alternative Revenue Program Accounting. Certain of the Utility Registrants' ratemaking mechanisms qualify as ARPs if they (i) are established by a regulatory order and allow for automatic adjustment to future rates, (ii) provide for additional revenues (above those amounts currently reflected in the price of utility service) that are objectively determinable and probable of recovery, and (iii) allow for the collection of those additional revenues within 24 months following the end of the period in which they were recognized. For mechanisms that meet these criteria, which include the Utility Registrants' formula rate and revenue decoupling mechanisms, the Utility Registrants adjust revenue and record an offsetting regulatory asset or liability once the condition or event allowing additional billing or refund has occurred. The ARP revenues presented in the Utility Registrants' Consolidated Statements of Operations and Comprehensive Income include both: (i) the recognition of "originating" ARP revenues (when the regulator-specified condition or event allowing for additional billing or refund has occurred) and (ii) an equal and offsetting reversal of the "originating" ARP revenues as those amounts are reflected in the price of utility service and recognized as Revenue from Contracts with Customers.

ComEd records ARP revenue for its best estimate of the electric distribution, energy efficiency, and transmission revenue impacts resulting from future changes in rates that ComEd believes are probable of approval by the ICC and FERC in accordance with its formula rate mechanisms. BGE, Pepco and DPL record ARP revenue for their best estimate of the electric and natural gas distribution revenue impacts resulting from future changes in rates that they believe are probable of approval by the MDPSC and/or DCPSC in accordance with their revenue decoupling mechanisms. PECO, BGE, Pepco, DPL and ACE record ARP revenue for their best estimate of the transmission revenue impacts resulting from future changes in rates that they believe are probable of approval by FERC in accordance with their formula rate mechanisms. Estimates of the current year revenue requirement are based on actual and/or forecasted costs and investments in rate base for the period and the rates of return on common equity and associated regulatory capital structure allowed under the applicable tariff. The estimated reconciliation can be affected by, among other things, variances in costs incurred, investments made, allowed ROE, and actions by regulators or courts.

See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

## Allowance for Uncollectible Accounts (Utility Registrants)

Utility Registrants estimate the allowance for uncollectible accounts on customer receivables by applying loss rates developed specifically for each company to the outstanding receivable balance by customer risk segment. Risk segments represent a group of customers with similar credit quality indicators that are comprised based on various attributes, including delinquency of their balances and payment history. Loss rates applied to the accounts receivable balances are based on a historical average of charge-offs as a percentage of accounts receivable in each risk segment. The Utility Registrants' customer accounts are generally considered delinquent if the amount billed is not received by the time the next bill is issued, which normally occurs on a monthly basis. Utility Registrants' customer accounts are written off consistent with approved regulatory requirements. Utility Registrants' allowances for uncollectible accounts will continue to be affected by changes in volume, prices and economic conditions as well as changes in ICC, PAPUC, MDPSC, DCPSC, DPSC and NJBPU regulations.

## Results of Operations by Registrant

The Registrants' Results of Operations includes discussion of RNF, which is a financial measure not 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. The CODM's for Exelon and Generation evaluate the performance of Generation's electric business activities and allocate resources based on RNF. Generation believes that RNF is a useful measure because it provides information that can be used to evaluate its operational performance. For the Utility Registrants, their Operating revenues reflect the full and current recovery of commodity procurement costs given the rider mechanisms approved by their respective state regulators. The commodity procurement costs, which are recorded in Purchased power and fuel expense, and the associated revenues can be volatile. Therefore, the Utility Registrants believe that RNF is a useful measure because it excludes the effect on Operating revenues caused by the volatility in these expenses.



## Results of Operations—Generation

<table><tr><td></td><td>2019</td><td>2018</td><td>Favorable (unfavorable) 2019 vs. 2018 variance</td><td>2017</td><td>Favorable (unfavorable) 2018 vs. 2017 variance</td></tr><tr><td>Operating revenues</td><td>$ 18,924</td><td>$ 20,437</td><td>$ (1,513)</td><td>$ 18,500</td><td>$ 1,937</td></tr><tr><td>Purchased power and fuel expense</td><td>10,856</td><td>11,693</td><td>837</td><td>9,690</td><td>(2,003)</td></tr><tr><td>Revenues net of purchased power and fuel expense</td><td>8,068</td><td>8,744</td><td>(676)</td><td>8,810</td><td>(66)</td></tr><tr><td>Other operating expenses</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating and maintenance</td><td>4,718</td><td>5,464</td><td>746</td><td>6,299</td><td>835</td></tr><tr><td>Depreciation and amortization</td><td>1,535</td><td>1,797</td><td>262</td><td>1,457</td><td>(340)</td></tr><tr><td>Taxes other than income taxes</td><td>519</td><td>556</td><td>37</td><td>555</td><td>(1)</td></tr><tr><td>Total other operating expenses</td><td>6,772</td><td>7,817</td><td>1,045</td><td>8,311</td><td>494</td></tr><tr><td>Gain (loss) on sales of assets and businesses</td><td>27</td><td>48</td><td>(21)</td><td>2</td><td>46</td></tr><tr><td>Bargain purchase gain</td><td>—</td><td>—</td><td>—</td><td>233</td><td>(233)</td></tr><tr><td>Gain on deconsolidation of business</td><td>—</td><td>—</td><td>—</td><td>213</td><td>(213)</td></tr><tr><td>Operating income</td><td>1,323</td><td>975</td><td>348</td><td>947</td><td>28</td></tr><tr><td>Other income and (deductions)</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Interest expense</td><td>(429)</td><td>(432)</td><td>3</td><td>(440)</td><td>8</td></tr><tr><td>Other, net</td><td>1,023</td><td>(178)</td><td>1,201</td><td>948</td><td>(1,126)</td></tr><tr><td>Total other income and (deductions)</td><td>594</td><td>(610)</td><td>1,204</td><td>508</td><td>(1,118)</td></tr><tr><td>Income before income taxes</td><td>1,917</td><td>365</td><td>1,552</td><td>1,455</td><td>(1,090)</td></tr><tr><td>Income taxes</td><td>516</td><td>(108)</td><td>(624)</td><td>(1,376)</td><td>(1,268)</td></tr><tr><td>Equity in losses of unconsolidated affiliates</td><td>(184)</td><td>(30)</td><td>(154)</td><td>(33)</td><td>3</td></tr><tr><td>Net income</td><td>1,217</td><td>443</td><td>774</td><td>2,798</td><td>(2,355)</td></tr><tr><td>Net income attributable to noncontrolling interests</td><td>92</td><td>73</td><td>(19)</td><td>88</td><td>(15)</td></tr><tr><td>Net income attributable to membership interest</td><td>$ 1,125</td><td>$ 370</td><td>$ 755</td><td>$ 2,710</td><td>(2,340)</td></tr></table>

Year Ended December 31, 2019 Compared to Year Ended December 31, 2018. Net income attributable to membership interest increased by $755 million primarily due to:

• Higher net unrealized and realized gains on NDT funds;

- Decreased accelerated depreciation and amortization due to the early retirement of the Oyster Creek nuclear facility in September 2018 and TMI in September 2019 and the absence of a charge associated with the remeasurement of the Oyster Creek ARO;

- Decreased operating and maintenance expense at Generation which includes the impacts of previous cost management programs and lower pension and OPEB costs, and increased NEIL insurance distributions;

- A benefit associated with the remeasurement of the TMI ARO in the first quarter of 2019 and the annual nuclear ARO update in the third quarter of 2019;

• Decreased nuclear outage days;

• Lower mark-to-market losses;

• Research and development income tax credits.



The increases were partially offset by;

• Lower realized energy prices; and

• Lower capacity prices.

Revenues Net of Purchased Power and Fuel Expense. The basis for Generation's reportable segments is the integrated management of its 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). Generation's hedging strategies and risk metrics are also aligned with these same geographic regions. Generation's five reportable segments are Mid-Atlantic, Midwest, New York, ERCOT and Other Power Regions. During the first quarter of 2019, due to a change in economics in our New England region, Generation changed the way that information is reviewed by the CODM. The New England region will no longer be regularly reviewed as a separate region by the CODM nor will it be presented separately in any external information presented to third parties. Information for the New England region will be reviewed by the CODM as part of Other Power Regions. See Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information on these reportable segments.

The following business activities are not allocated to a region and are reported under Other: natural gas, as well as other miscellaneous business activities that are not significant to overall operating revenues or results of operations. Further, the following activities are not allocated to a region and are reported in Other: accelerated nuclear fuel amortization associated with nuclear decommissioning; and other miscellaneous revenues.

Generation evaluates the operating performance of electric business activities using the measure of RNF. Operating revenues include all sales to third parties and affiliated sales to the Utility Registrants. 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 owned generation and fuel costs associated with tolling agreements.

For the years ended December 31, 2019 compared to 2018, RNF by region were as follows:

<table><tr><td rowspan="2"></td><td colspan="4">2019 vs. 2018</td></tr><tr><td>2019</td><td>2018</td><td>Variance</td><td>% Change</td></tr><tr><td>Mid-Atlantic(a)</td><td>2,655</td><td>3,073</td><td>(418)</td><td>(13.6)%</td></tr><tr><td>Midwest(b)</td><td>2,962</td><td>3,135</td><td>(173)</td><td>(5.5)%</td></tr><tr><td>New York</td><td>1,094</td><td>1,122</td><td>(28)</td><td>(2.5)%</td></tr><tr><td>ERCOT</td><td>308</td><td>258</td><td>50</td><td>19.4%</td></tr><tr><td>Other Power Regions</td><td>620</td><td>729</td><td>(109)</td><td>(15.0)%</td></tr><tr><td>Total electric revenues net of purchased power and fuel expense</td><td>7,639</td><td>8,317</td><td>(678)</td><td>(8.2)%</td></tr><tr><td>Mark-to-market losses</td><td>(215)</td><td>(319)</td><td>104</td><td>(32.6)%</td></tr><tr><td>Other</td><td>644</td><td>746</td><td>(102)</td><td>(13.7)%</td></tr><tr><td>Total revenue net of purchased power and fuel expense</td><td>8,068</td><td>8,744</td><td>(676)</td><td>(7.7)%</td></tr></table>

(a) Includes results of transactions with PECO, BGE, Pepco, DPL and ACE.

(b) Includes results of transactions with ComEd.



Generation’s supply sources by region are summarized below:

<table><tr><td rowspan="2">Supply Source (GWhs)</td><td rowspan="2">2019</td><td rowspan="2">2018</td><td colspan="2">2019 vs. 2018</td></tr><tr><td>Variance</td><td>% Change</td></tr><tr><td>Nuclear Generation(a)</td><td></td><td></td><td></td><td></td></tr><tr><td>Mid-Atlantic</td><td>58,347</td><td>64,099</td><td>(5,752)</td><td>(9.0)%</td></tr><tr><td>Midwest</td><td>94,890</td><td>94,283</td><td>607</td><td>0.6%</td></tr><tr><td>New York</td><td>28,088</td><td>26,640</td><td>1,448</td><td>5.4%</td></tr><tr><td>Total Nuclear Generation</td><td>181,325</td><td>185,022</td><td>(3,697)</td><td>(2.0)%</td></tr><tr><td>Fossil and Renewables</td><td></td><td></td><td></td><td></td></tr><tr><td>Mid-Atlantic</td><td>2,884</td><td>3,670</td><td>(786)</td><td>(21.4)%</td></tr><tr><td>Midwest</td><td>1,374</td><td>1,373</td><td>1</td><td>0.1%</td></tr><tr><td>New York</td><td>5</td><td>3</td><td>2</td><td>66.7%</td></tr><tr><td>ERCOT</td><td>13,572</td><td>11,180</td><td>2,392</td><td>21.4%</td></tr><tr><td>Other Power Regions</td><td>11,476</td><td>13,256</td><td>(1,780)</td><td>(13.4)%</td></tr><tr><td>Total Fossil and Renewables</td><td>29,311</td><td>29,482</td><td>(171)</td><td>(0.6)%</td></tr><tr><td>Purchased Power</td><td></td><td></td><td></td><td></td></tr><tr><td>Mid-Atlantic</td><td>14,790</td><td>6,506</td><td>8,284</td><td>127.3%</td></tr><tr><td>Midwest</td><td>1,424</td><td>996</td><td>428</td><td>43.0%</td></tr><tr><td>ERCOT</td><td>4,821</td><td>6,550</td><td>(1,729)</td><td>(26.4)%</td></tr><tr><td>Other Power Regions</td><td>48,673</td><td>44,998</td><td>3,675</td><td>8.2%</td></tr><tr><td>Total Purchased Power</td><td>69,708</td><td>59,050</td><td>10,658</td><td>18.0%</td></tr><tr><td>Total Supply/Sales by Region</td><td></td><td></td><td></td><td></td></tr><tr><td>Mid-Atlantic(b)</td><td>76,021</td><td>74,275</td><td>1,746</td><td>2.4%</td></tr><tr><td>Midwest(b)</td><td>97,688</td><td>96,652</td><td>1,036</td><td>1.1%</td></tr><tr><td>New York</td><td>28,093</td><td>26,643</td><td>1,450</td><td>5.4%</td></tr><tr><td>ERCOT</td><td>18,393</td><td>17,730</td><td>663</td><td>3.7%</td></tr><tr><td>Other Power Regions</td><td>60,149</td><td>58,254</td><td>1,895</td><td>3.3%</td></tr><tr><td>Total Supply/Sales by Region</td><td>280,344</td><td>273,554</td><td>6,790</td><td>2.5%</td></tr></table>

(a) Includes the proportionate share of output where Generation has an undivided ownership interest in jointly-owned generating plants and includes the total output of plants that are fully consolidated (e.g. CENG).

(b) Includes affiliate sales to PECO, BGE, Pepco, DPL and ACE in the Mid-Atlantic region and affiliate sales to ComEd in the Midwest region.



For the years ended December 31, 2019 compared to 2018 changes in RNF by region were as follows:

<table><tr><td rowspan="2"></td><td colspan="2">2019 vs. 2018</td></tr><tr><td>(Decrease)/Increase</td><td>Description</td></tr><tr><td>Mid-Atlantic</td><td>$ (418)</td><td>• decreased revenue due to the permanent cease of generation operations at Oyster Creek in the third quarter of 2018 and Three Mile Island in the third quarter of 2019
• lower realized energy prices
• decreased capacity prices, partially offset by
• increased ZEC revenues due to the approval of the NJ ZEC program in the second quarter of 2019</td></tr><tr><td>Midwest</td><td>(173)</td><td>• the absence of the revenue recognized in the first quarter of 2018 related to ZECs generated in Illinois from June through December 2017
• decreased capacity prices</td></tr><tr><td>New York</td><td>(28)</td><td>• lower realized energy prices
• decreased capacity prices, partially offset by
• increased ZEC revenues due to higher ZEC prices and increased nuclear output
• decreased nuclear outage days</td></tr><tr><td>ERCOT</td><td>50</td><td>• higher realized energy prices</td></tr><tr><td>Other Power Regions</td><td>(109)</td><td>• decreased capacity prices
• lower realized energy prices</td></tr><tr><td>Mark-to-market(a)</td><td>104</td><td>• losses on economic hedging activities of $215 million in 2019 compared to losses of $319 million in 2018</td></tr><tr><td>Other</td><td>(102)</td><td>• the absence of the gain on the settlement of a long-term gas supply agreement
• congestion activity, partially offset by
• decrease in accelerated nuclear fuel amortization associated with announced early plant retirements</td></tr><tr><td>Total</td><td>$ (676)</td><td></td></tr></table>

(a) See Note 15 — Derivative Financial Instruments for additional information on mark-to-market losses.

Nuclear Fleet Capacity Factor. The following table presents nuclear fleet operating data for the Generation-operated plants, which reflects ownership percentage of stations operated by Exelon, excluding Salem, which is operated by PSEG. 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 full average annual mean capacity for that time period. Generation considers capacity factor to be a useful measure to analyze the nuclear fleet performance between periods. Generation has 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.

<table><tr><td></td><td>2019</td><td>2018</td></tr><tr><td>Nuclear fleet capacity factor</td><td>95.7%</td><td>94.6%</td></tr><tr><td>Refueling outage days</td><td>209</td><td>274</td></tr><tr><td>Non-refueling outage days</td><td>51</td><td>38</td></tr></table>



The changes in Operating and maintenance expense, consisted of the following:

<table><tr><td rowspan="2">Labor, other benefits, contracting, materials(a)</td><td colspan="2">(Decrease) Increase 2019 vs. 2018</td></tr><tr><td>$</td><td>(174)</td></tr><tr><td>Nuclear refueling outage costs, including the co-owned Salem plants</td><td></td><td>(87)</td></tr><tr><td>Corporate allocations</td><td></td><td>(82)</td></tr><tr><td>Insurance(b)</td><td></td><td>(47)</td></tr><tr><td>Merger and integration costs</td><td></td><td>(4)</td></tr><tr><td>Plant retirements and divestitures(c)</td><td></td><td>(175)</td></tr><tr><td>Change in environmental liabilities</td><td></td><td>7</td></tr><tr><td>ARO update(d)</td><td></td><td>(70)</td></tr><tr><td>Asset Impairments(e)</td><td></td><td>(32)</td></tr><tr><td>Pension and non-pension postretirement benefits expense</td><td></td><td>(62)</td></tr><tr><td>Allowance for uncollectible accounts</td><td></td><td>(14)</td></tr><tr><td>Accretion expense</td><td></td><td>(77)</td></tr><tr><td>Other(f)</td><td></td><td>71</td></tr><tr><td>Decrease in operating and maintenance expense</td><td></td><td>$ (746)</td></tr></table>

(a) Primarily reflects decreased costs related to the permanent cease of generation operations at Oyster Creek, lower labor costs resulting from previous cost management programs, and lower pension and OPEB costs.

(b) Primarily reflects a supplemental NEIL insurance distribution received in the fourth quarter of 2019.

(c) Primarily due to the benefit recorded in the first quarter of 2019 for the remeasurement of the TMI ARO and the absence of a charge associated with the remeasurement of the Oyster Creek ARO in the third quarter of 2018.

(d) Primarily reflects a benefit related to Generation's annual nuclear ARO update for non-regulatory units.

(e) Primarily due to the impairment of certain wind projects recorded in the second quarter of 2018.

(f) Primarily due to the increased revenue as a result of a research and development tax refund.

Depreciation and amortization expense for the year ended December 31, 2019 compared to the year ended December 31, 2018 decreased primarily due to the permanent cessation of generation operations at Oyster Creek in the third quarter of 2018 and TMI in the fourth quarter of 2019.

Gain (loss) on sales of assets and businesses for the year ended December 31, 2019 compared to the year ended December 31, 2018 decreased primarily due to Generation's sale of Oyster Creek.

Other, net for the year ended December 31, 2019 compared to the same period in 2018 increased for the twelve months ended December 31, 2019 compared to the same period in 2018 due to activity associated with NDT funds as described in the table below.

<table><tr><td></td><td>2019</td><td>2018</td></tr><tr><td>Net unrealized gains (losses) on NDT funds \( ^{(a)} \)</td><td>411</td><td>(483)</td></tr><tr><td>Net realized gains on sale of NDT funds \( ^{(a)} \)</td><td>253</td><td>180</td></tr><tr><td>Interest and dividend income on NDT funds \( ^{(a)} \)</td><td>110</td><td>122</td></tr><tr><td>Contractual elimination of income tax expense \( ^{(b)} \)</td><td>216</td><td>(38)</td></tr><tr><td>Other</td><td>33</td><td>41</td></tr><tr><td>Total other, net</td><td>1,023</td><td>(178)</td></tr></table>

(a) Unrealized gains (losses), realized gains and interest and dividend income on the NDT funds are associated with the Non-Regulatory Agreement units.
(b) Contractual elimination of income tax expense is associated with the income taxes on the NDT funds of the Regulatory Agreement units.



Effective income tax rates were 26.9% and (29.5%) for the years ended December 31, 2019 and 2018, respectively. The change in 2019 is primarily related to research and development claims, renewable tax credits and one-time adjustments. See Note 13 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.

Equity in losses of unconsolidated affiliates for the twelve months ended December 31, 2019 compared to the same period in 2018 decreased primarily due to the impairment of equity method investments in certain distributed energy companies.

Net income attributable to noncontrolling interests for the twelve months ended December 31, 2019 compared to the same period in 2018 decreased primarily due to the offsetting noncontrolling interest impact of the impairment of equity method investments in certain distributed energy companies.



## Results of Operations—ComEd

<table><tr><td></td><td colspan="2">2019</td><td colspan="2">2018</td><td colspan="2">Favorable (unfavorable) 2019 vs. 2018 variance</td><td colspan="2">2017</td><td colspan="2">Favorable (unfavorable) 2018 vs. 2017 variance</td></tr><tr><td>Operating revenues</td><td>$</td><td>5,747</td><td>$</td><td>5,882</td><td>$</td><td>(135)</td><td>$</td><td>5,536</td><td>$</td><td>346</td></tr><tr><td>Purchased power expense</td><td></td><td>1,941</td><td></td><td>2,155</td><td></td><td>214</td><td></td><td>1,641</td><td></td><td>(514)</td></tr><tr><td>Revenues net of purchased power expense</td><td></td><td>3,806</td><td></td><td>3,727</td><td></td><td>79</td><td></td><td>3,895</td><td></td><td>(168)</td></tr><tr><td>Other operating expenses</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating and maintenance</td><td></td><td>1,305</td><td></td><td>1,335</td><td></td><td>30</td><td></td><td>1,427</td><td></td><td>92</td></tr><tr><td>Depreciation and amortization</td><td></td><td>1,033</td><td></td><td>940</td><td></td><td>(93)</td><td></td><td>850</td><td></td><td>(90)</td></tr><tr><td>Taxes other than income taxes</td><td></td><td>301</td><td></td><td>311</td><td></td><td>10</td><td></td><td>296</td><td></td><td>(15)</td></tr><tr><td>Total other operating expenses</td><td></td><td>2,639</td><td></td><td>2,586</td><td></td><td>(53)</td><td></td><td>2,573</td><td></td><td>(13)</td></tr><tr><td>Gain on sales of assets</td><td></td><td>4</td><td></td><td>5</td><td></td><td>(1)</td><td></td><td>1</td><td></td><td>4</td></tr><tr><td>Operating income</td><td></td><td>1,171</td><td></td><td>1,146</td><td></td><td>25</td><td></td><td>1,323</td><td></td><td>(177)</td></tr><tr><td>Other income and (deductions)</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Interest expense, net</td><td></td><td>(359)</td><td></td><td>(347)</td><td></td><td>(12)</td><td></td><td>(361)</td><td></td><td>14</td></tr><tr><td>Other, net</td><td></td><td>39</td><td></td><td>33</td><td></td><td>6</td><td></td><td>22</td><td></td><td>11</td></tr><tr><td>Total other income and (deductions)</td><td></td><td>(320)</td><td></td><td>(314)</td><td></td><td>(6)</td><td></td><td>(339)</td><td></td><td>25</td></tr><tr><td>Income before income taxes</td><td></td><td>851</td><td></td><td>832</td><td></td><td>19</td><td></td><td>984</td><td></td><td>(152)</td></tr><tr><td>Income taxes</td><td></td><td>163</td><td></td><td>168</td><td></td><td>5</td><td></td><td>417</td><td></td><td>249</td></tr><tr><td>Net income</td><td></td><td>$</td><td>688</td><td>$</td><td>664</td><td>$</td><td>24</td><td>$</td><td>567</td><td>$</td></tr></table>

Year Ended December 31, 2019 Compared to Year Ended December 31, 2018. Net income increased by $24 million primarily due to higher electric distribution, transmission and energy efficiency formula rate earnings (reflecting the impacts of higher rate base, partially offset by lower allowed electric distribution ROE due to a decrease in treasury rates).

Revenues Net of Purchased Power Expense. There are certain drivers of Operating revenues that are fully offset by their impact on Purchased power expense, such as commodity, REC and ZEC procurement costs and participation in customer choice programs. ComEd recovers electricity, REC and ZEC procurement costs from customers without mark-up. Therefore, fluctuations in these costs have no impact on RNF.

Customers have the choice to purchase electricity from a competitive electric generation supplier. Customer choice programs do not impact the volume of deliveries, but do impact Operating revenues related to supplied electricity.

The changes in RNF consisted of the following:

<table><tr><td></td><td>Increase (Decrease) 2019 vs. 2018</td></tr><tr><td>Electric distribution revenue</td><td>$ 47</td></tr><tr><td>Transmission revenue</td><td>32</td></tr><tr><td>Energy efficiency revenue</td><td>47</td></tr><tr><td>Uncollectible accounts recovery, net</td><td>(7)</td></tr><tr><td>Other</td><td>(40)</td></tr><tr><td>Total increase</td><td>$ 79</td></tr></table>



Revenue Decoupling. The demand for electricity is affected by weather and customer usage. Operating revenues are not impacted by abnormal weather, usage per customer or number of customers as a result of a change to the electric distribution formula rate pursuant to FEJA.

Distribution Revenue. EIMA and FEJA provide for a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs that the ICC determines are prudently and reasonably incurred in a given year. Electric distribution revenue varies from year to year based upon fluctuations in the underlying costs (e.g., severe weather and storm restoration), investments being recovered and allowed ROE. During the year ended December 31, 2019, as compared to the same period in 2018, electric distribution revenue increased primarily due to the impact of higher rate base and increased depreciation expenses, offset by lower allowed ROE due to a decrease in treasury rates. See Operating and Maintenance Expense below and Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered and the highest daily peak load, which is updated annually in January based on the prior calendar year. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. During the year ended December 31, 2019, as compared to the same period in 2018, transmission revenue increased primarily due to the impact of increased peak load, higher rate base, and higher fully recoverable costs. See Operating and Maintenance Expense below and Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Energy Efficiency Revenue. FEJA provides for a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs that the ICC determines are prudently and reasonably incurred in a given year. Under FEJA, energy efficiency revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered, and allowed ROE. Energy efficiency revenue increased for the year ended December 31, 2019, as compared to the same period in 2018, primarily due to the impact of higher rate base and increased regulatory asset amortization. See Depreciation and amortization expense discussions below and Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Uncollectible Accounts Recovery, Net represents recoveries under the uncollectible accounts tariff. See Operating and maintenance expense discussion below for additional information on this tariff.

Other revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues and recoveries of environmental costs associated with MGP sites. The decrease in Other revenue for the year ended December 31, 2019, as compared to the same period in 2018, primarily reflects absence of mutual assistance revenues associated with hurricane and winter storm restoration efforts that occurred in Q1 2018. An equal and offsetting amount was included in Operating and maintenance expense.

See Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ComEd's revenue disaggregation.

The changes in Operating and maintenance expense consisted of the following:

<table><tr><td></td><td>(Decrease) Increase 2019 vs. 2018</td></tr><tr><td>Baseline</td><td></td></tr><tr><td>Pension and non-pension postretirement benefits expense \( ^{(a)} \)</td><td>$ (36) \)</td></tr><tr><td>Labor, other benefits, contracting and materials \( ^{(b)} \)</td><td>$ (27) \)</td></tr><tr><td>Uncollectible accounts expense \( ^{(c)} \)</td><td>$ (7) \)</td></tr><tr><td>Storm costs</td><td>31</td></tr><tr><td>Other</td><td>9</td></tr><tr><td>Total decrease</td><td>$ (30) \)</td></tr></table>



(a) Primarily reflects an increase in discount rates and the favorable impacts of the merger of two of Exelon's pension plans effective in January 2019, partially offset by lower than expected asset returns in 2018.

(b) Primarily reflects absence of mutual assistance expenses and decreased contracting costs. An equal and offsetting increase has been recognized in Operating revenues for the period presented.

(c) ComEd is allowed to recover from or refund to customers the difference between its annual uncollectible accounts expense and the amounts collected in rates annually through a rider mechanism. ComEd recorded a net decrease in uncollectible accounts for the year ended December 31, 2019, as compared to the same period in 2018, primarily due to the timing of regulatory cost recovery. An equal and offsetting amount has been recognized in Operating revenues for the periods presented.

The changes in Depreciation and amortization expense consisted of the following:

<table><tr><td></td><td>Increase 2019 vs. 2018</td></tr><tr><td>Depreciation expense \( ^{(a)} \)</td><td>58</td></tr><tr><td>Regulatory asset amortization \( ^{(b)} \)</td><td>35</td></tr><tr><td>Total increase</td><td>93</td></tr></table>

(a) Reflects ongoing capital expenditures and higher depreciation rates effective January 2019.

(b) Includes amortization of ComEd's energy efficiency formula rate regulatory asset.

Effective income tax rates for the years ended December 31, 2019 and 2018, were 19.2% and 20.2%, respectively. See Note 13 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.



## Results of Operations—PECO

<table><tr><td></td><td colspan="2">2019</td><td colspan="2">2018</td><td colspan="2">Favorable (unfavorable) 2019 vs. 2018 variance</td><td colspan="2">2017</td><td colspan="2">Favorable (unfavorable) 2018 vs. 2017 variance</td></tr><tr><td>Operating revenues</td><td>$     3,100</td><td>$     3,038</td><td>$     62</td><td>$     2,870</td><td>$     168</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Purchased power and fuel expense</td><td>1,029</td><td>1,090</td><td>61</td><td>969</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Revenues net of purchased power and fuel expense</td><td>2,071</td><td>1,948</td><td>123</td><td>1,901</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Other operating expenses</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating and maintenance</td><td>861</td><td>898</td><td>37</td><td>806</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Depreciation and amortization</td><td>333</td><td>301</td><td>(32)</td><td>286</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Taxes other than income taxes</td><td>165</td><td>163</td><td>(2)</td><td>154</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Total other operating expenses</td><td>1,359</td><td>1,362</td><td>3</td><td>1,246</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Gain on sales of assets</td><td>1</td><td>1</td><td>—</td><td>—</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating income</td><td>713</td><td>587</td><td>126</td><td>655</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Other income and (deductions)</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Interest expense, net</td><td>(136)</td><td>(129)</td><td>(7)</td><td>(126)</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Other, net</td><td>16</td><td>8</td><td>8</td><td>9</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Total other income and (deductions)</td><td>(120)</td><td>(121)</td><td>1</td><td>(117)</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Income before income taxes</td><td>593</td><td>466</td><td>127</td><td>538</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Income taxes</td><td>65</td><td>6</td><td>(59)</td><td>104</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Net income</td><td>$     528</td><td>$     460</td><td>$     68</td><td>$     434</td><td>$     26</td><td></td><td></td><td></td><td></td><td></td></tr></table>

Year Ended December 31, 2019 Compared to Year Ended December 31, 2018. Net income increased by $68 million primarily due to higher electric distribution rates that became effective January 2019, higher natural gas distribution rates and lower storm costs, partially offset by unfavorable weather conditions and volume.

Revenues Net of Purchased Power and Fuel Expense. There are certain drivers of Operating revenues that are fully offset by their impact on Purchased power and fuel expenses such as commodity and REC procurement costs and participation in customer choice programs. PECO's recoveries electricity, natural gas and REC procurement costs from customers without mark-up. Therefore, fluctuations in these costs have no impact on RNF.

Customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers. Customer choice programs do not impact the volume of deliveries or RNF, but impact Operating revenues related to supplied electricity and natural gas.

The changes in RNF consisted of the following:

<table><tr><td rowspan="3"></td><td colspan="4">2019 vs. 2018</td></tr><tr><td colspan="3">(Decrease) Increase</td><td></td></tr><tr><td colspan="2">Electric</td><td>Gas</td><td>Total</td></tr><tr><td>Weather</td><td>$ (11)</td><td>$ (8)</td><td>$ (19)</td><td></td></tr><tr><td>Volume</td><td>(22)</td><td>6</td><td>(16)</td><td></td></tr><tr><td>Pricing</td><td>112</td><td>10</td><td>122</td><td></td></tr><tr><td>Regulatory required programs</td><td>42</td><td>9</td><td>51</td><td></td></tr><tr><td>Transmission Revenue</td><td>(13)</td><td>—</td><td>(13)</td><td></td></tr><tr><td>Other</td><td>(2)</td><td>—</td><td>(2)</td><td></td></tr><tr><td>Total increase</td><td>$ 106</td><td>$ 17</td><td>$ 123</td><td></td></tr></table>



Weather. The demand for electricity and natural gas is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. For the year ended December 31, 2019 compared to the same period in 2018 RNF was decreased by the impact of unfavorable weather conditions in PECO’s service territory.

Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 30-year period in PECO’s service territory. The changes in heating and cooling degree days in PECO’s service territory for the years ended December 31, 2019 and December 31, 2018 compared to the same periods in 2018 and 2017, respectively, and normal weather consisted of the following:

<table><tr><td rowspan="2"></td><td colspan="3">For the Years Ended December 31,</td><td colspan="3">% Change</td></tr><tr><td>2019</td><td>2018</td><td>Normal</td><td>2019 vs. 2018</td><td>2019 vs. Normal</td><td></td></tr><tr><td>Heating and Cooling Degree-Days</td><td>4,307</td><td>4,539</td><td>4,458</td><td>(5.1)%</td><td>(3.4)%</td><td></td></tr><tr><td>Cooling Degree-Days</td><td>1,610</td><td>1,584</td><td>1,415</td><td>1.6%</td><td>13.8%</td><td></td></tr></table>

Volume. Electric volume, exclusive of the effects of weather, for the year ended December 31, 2019 compared to the same period in 2018, decreased due to lower customer usages for residential, commercial and industrial electric classes, partially offset by the impact of customer growth. Natural gas volume for the year ended December 31, 2019 compared to the same period in 2018, increased due to customer and economic growth.

<table><tr><td>Electric Retail Deliveries to Customers (in GWhs)</td><td>2019</td><td>2018</td><td>% Change 2019 vs. 2018</td><td>Weather - Normal % Change(b)</td></tr><tr><td>Retail Deliveries (a)</td><td></td><td></td><td></td><td></td></tr><tr><td>Residential</td><td>13,650</td><td>14,005</td><td>(2.5)%</td><td>(1.4)%</td></tr><tr><td>Small commercial &amp; industrial</td><td>7,983</td><td>8,177</td><td>(2.4)%</td><td>(1.2)%</td></tr><tr><td>Large commercial &amp; industrial</td><td>14,958</td><td>15,516</td><td>(3.6)%</td><td>(3.4)%</td></tr><tr><td>Public authorities &amp; electric railroads</td><td>725</td><td>761</td><td>(4.7)%</td><td>(5.0)%</td></tr><tr><td>Total electric retail deliveries</td><td>37,316</td><td>38,459</td><td>(3.0)%</td><td>(2.3)%</td></tr></table>

(a) Reflects delivery volumes and revenue from customers purchasing electricity directly from PECO and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges.

(b) Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.

<table><tr><td rowspan="2">Number of Electric Customers</td><td colspan="2">As of December 31,</td></tr><tr><td>2019</td><td>2018</td></tr><tr><td>Residential</td><td>1,494,462</td><td>1,480,925</td></tr><tr><td>Small commercial &amp; industrial</td><td>154,000</td><td>152,797</td></tr><tr><td>Large commercial &amp; industrial</td><td>3,104</td><td>3,118</td></tr><tr><td>Public authorities &amp; electric railroads</td><td>10,039</td><td>9,565</td></tr><tr><td>Total</td><td>1,661,605</td><td>1,646,405</td></tr></table>



<table><tr><td>Natural Gas Deliveries to customers (in mmcf)</td><td>2019</td><td>2018</td><td>% Change 2019 vs. 2018</td><td>Weather - Normal % Change(b)</td></tr><tr><td>Retail Deliveries (a)</td><td></td><td></td><td></td><td></td></tr><tr><td>Residential</td><td>40,196</td><td>43,450</td><td>(7.5)%</td><td>0.9%</td></tr><tr><td>Small commercial &amp; industrial</td><td>23,828</td><td>21,997</td><td>8.3%</td><td>1.4%</td></tr><tr><td>Large commercial &amp; industrial</td><td>50</td><td>65</td><td>(23.1)%</td><td>7.4%</td></tr><tr><td>Transportation</td><td>25,822</td><td>26,595</td><td>(2.9)%</td><td>(1.3)%</td></tr><tr><td>Total natural gas deliveries</td><td>89,896</td><td>92,107</td><td>(2.4)%</td><td>0.4%</td></tr></table>

(a) Reflects delivery volumes and revenue from customers purchasing electricity directly from PECO and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges.

(b) Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.

<table><tr><td rowspan="2">Number of Gas Customers</td><td colspan="2">As of December 31,</td></tr><tr><td>2019</td><td>2018</td></tr><tr><td>Residential</td><td>487,337</td><td>482,255</td></tr><tr><td>Small commercial &amp; industrial</td><td>44,374</td><td>44,170</td></tr><tr><td>Large commercial &amp; industrial</td><td>2</td><td>1</td></tr><tr><td>Transportation</td><td>730</td><td>754</td></tr><tr><td>Total</td><td>532,443</td><td>527,180</td></tr></table>

Pricing for the year ended December 31, 2019 compared to the same period in 2018 increased primarily due to an increase in electric distribution rates charged to customers. The increase in electric distribution rates was effective January 1, 2019 in accordance with the 2018 PAPUC approved electric distribution rate case settlement. Additionally, the increase represents revenue from higher natural gas distribution rates. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency, PGC and the GSA. The riders are designed to provide full and current cost recovery as well as a return. The costs of these programs are included in Operating and maintenance expense, Depreciation and amortization expense and Income taxes.

Transmission Revenue. Under a FERC approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue for the year ended December 31, 2019 compared to the same period in 2018 decreased primarily due to lower operating and maintenance expenses and the terms of the settlement agreement approved by FERC in December 2019. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Other revenue includes rental revenue, revenue related to late payment charges and mutual assistance revenues.

See Note 5—Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of PECO's revenue disaggregation.



The changes in Operating and maintenance expense consisted of the following:

<table><tr><td></td><td>(Decrease) Increase 2019 vs. 2018</td></tr><tr><td>Baseline</td><td></td></tr><tr><td>Storm-related costs (a)</td><td>$ (30)</td></tr><tr><td>Pension and non-pension postretirement benefits expense</td><td>(5)</td></tr><tr><td>Uncollectible accounts expense</td><td>(2)</td></tr><tr><td>BSC costs</td><td>2</td></tr><tr><td>Labor, other benefits, contracting and materials</td><td>1</td></tr><tr><td>Other</td><td>(7)</td></tr><tr><td></td><td>(41)</td></tr><tr><td>Regulatory required programs</td><td></td></tr><tr><td>Energy efficiency</td><td>4</td></tr><tr><td>Decrease in operating and maintenance expense</td><td>$ (37)</td></tr></table>

(a) Reflects decreased storm costs due to the March 2018 winter storms.

The changes in Depreciation and amortization expense consisted of the following:

<table><tr><td></td><td>Increase 2019 vs. 2018</td></tr><tr><td>Depreciation expense (a)</td><td>$ 28</td></tr><tr><td>Regulatory asset amortization</td><td>4</td></tr><tr><td>Increase in depreciation and amortization expense</td><td>$ 32</td></tr></table>

(a) Depreciation expense increased due to ongoing capital expenditures.

Effective income tax rates were 11.0% and 1.3% for the years ended December 31, 2019 and 2018, respectively. See Note 13 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information of the change in effective income tax rates.



## Results of Operations—BGE

<table><tr><td></td><td>2019</td><td>2018</td><td>Favorable (unfavorable) 2019 vs. 2018 variance</td><td>2017</td><td>Favorable (unfavorable) 2018 vs. 2017 variance</td></tr><tr><td>Operating revenues</td><td>$ 3,106</td><td>$ 3,169</td><td>$ (63)</td><td>$ 3,176</td><td>$ (7)</td></tr><tr><td>Purchased power and fuel expense</td><td>1,052</td><td>1,182</td><td>130</td><td>1,133</td><td>(49)</td></tr><tr><td>Revenues net of purchased power and fuel expense</td><td>2,054</td><td>1,987</td><td>67</td><td>2,043</td><td>(56)</td></tr><tr><td>Other operating expenses</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating and maintenance</td><td>760</td><td>777</td><td>17</td><td>716</td><td>(61)</td></tr><tr><td>Depreciation and amortization</td><td>502</td><td>483</td><td>(19)</td><td>473</td><td>(10)</td></tr><tr><td>Taxes other than income taxes</td><td>260</td><td>254</td><td>(6)</td><td>240</td><td>(14)</td></tr><tr><td>Total other operating expenses</td><td>1,522</td><td>1,514</td><td>(8)</td><td>1,429</td><td>(85)</td></tr><tr><td>Gain on sales of assets</td><td>—</td><td>1</td><td>(1)</td><td>—</td><td>1</td></tr><tr><td>Operating income</td><td>532</td><td>474</td><td>58</td><td>614</td><td>(140)</td></tr><tr><td>Other income and (deductions)</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Interest expense, net</td><td>(121)</td><td>(106)</td><td>(15)</td><td>(105)</td><td>(1)</td></tr><tr><td>Other, net</td><td>28</td><td>19</td><td>9</td><td>16</td><td>3</td></tr><tr><td>Total other income and (deductions)</td><td>(93)</td><td>(87)</td><td>(6)</td><td>(89)</td><td>2</td></tr><tr><td>Income before income taxes</td><td>439</td><td>387</td><td>52</td><td>525</td><td>(138)</td></tr><tr><td>Income taxes</td><td>79</td><td>74</td><td>(5)</td><td>218</td><td>144</td></tr><tr><td>Net income</td><td>360</td><td>313</td><td>47</td><td>307</td><td>6</td></tr><tr><td>Net income attributable to common shareholder</td><td>$ 360</td><td>$ 313</td><td>$ 47</td><td>$ 307</td><td>$ 6</td></tr></table>

Year Ended December 31, 2019 Compared to Year Ended December 31, 2018. Net income attributable to common shareholder increased by $47 million primarily due to higher natural gas distribution rates that became effective January 2019 and December 2019, higher electric distribution rates that became effective December 2019, and lower storm costs, partially offset by an increase in various expenses, including interest.

Revenues Net of Purchased Power and Fuel Expense. There are certain drivers to Operating revenues that are fully offset by their impact on Purchased power and fuel expense, such as commodity procurement costs and participation in customer choice programs. BGE recovers electricity, natural gas and other procurement costs from customers without mark-up. Therefore, fluctuations in these costs have no impact on RNF.

Customers have the choice to purchase electricity and natural gas from electric generation and natural gas competitive suppliers. Customer choice programs do not impact the volume of deliveries or RNF but impact Operating revenues related to supplied electricity and natural gas.



The changes in RNF consisted of the following:

<table><tr><td rowspan="3"></td><td colspan="4">2019 vs. 2018</td></tr><tr><td colspan="3">Increase (Decrease)</td><td rowspan="2">Total</td></tr><tr><td>Electric</td><td>Gas</td><td></td></tr><tr><td>Distribution revenue</td><td>$ 11</td><td>$ 68</td><td>$ 79</td><td></td></tr><tr><td>Regulatory required programs</td><td>(6)</td><td>(4)</td><td>(10)</td><td></td></tr><tr><td>Transmission revenue</td><td>10</td><td>—</td><td>10</td><td></td></tr><tr><td>Other, net</td><td>(7)</td><td>(5)</td><td>(12)</td><td></td></tr><tr><td>Total increase</td><td>$ 8</td><td>$ 59</td><td>$ 67</td><td></td></tr></table>

Revenue Decoupling. The demand for electricity and natural gas is affected by weather and customer usage. However, Operating revenues are not impacted by abnormal weather or usage per customer as a result of a bill stabilization adjustment (BSA) that provides for a fixed distribution charge per customer by customer class. While Operating revenues are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.

<table><tr><td>Number of Electric Customers</td><td>2019</td><td>2018</td></tr><tr><td>Residential</td><td>1,177,333</td><td>1,168,372</td></tr><tr><td>Small commercial &amp; industrial</td><td>114,504</td><td>113,915</td></tr><tr><td>Large commercial &amp; industrial</td><td>12,322</td><td>12,253</td></tr><tr><td>Public authorities &amp; electric railroads</td><td>268</td><td>262</td></tr><tr><td>Total</td><td>1,304,427</td><td>1,294,802</td></tr></table>

<table><tr><td>Number of Gas Customers</td><td>2019</td><td>2018</td></tr><tr><td>Residential</td><td>639,426</td><td>633,757</td></tr><tr><td>Small commercial &amp; industrial</td><td>38,345</td><td>38,332</td></tr><tr><td>Large commercial &amp; industrial</td><td>6,037</td><td>5,954</td></tr><tr><td>Total</td><td>683,808</td><td>678,043</td></tr></table>

Distribution Revenues increased during the year ended December 31, 2019, compared to the same period in 2018, primarily due to the impact of higher natural gas distribution rates that became effective in both January 2019 and December 2019 and higher electric distribution rates that became effective in December 2019. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as conservation, demand response, STRIDE, and the POLR mechanism. The riders are designed to provide full and current cost recovery, as well as a return in certain instances. The costs of these programs are included in Operating and maintenance expense, Depreciation and amortization expense and Taxes other than income taxes.

Transmission Revenue. Under a FERC approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered and the highest daily peak load, which is updated annually in January based on the prior calendar year. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. Transmission revenue increased during the year ended December 31, 2019 compared to the same period in 2018, primarily due to increases in capital investment and operating and maintenance expense recoveries. See Operating and maintenance expense below and Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.



Other revenue includes revenue related to late payment charges, mutual assistance revenues, off-system sales and service application fees.

See Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of BGE's revenue disaggregation.

The changes in Operating and maintenance expense consisted of the following:

<table><tr><td></td><td>(Decrease) Increase 2019 vs. 2018</td></tr><tr><td>Baseline</td><td></td></tr><tr><td>Storm-related costs \( ^{(a)} \)</td><td>$ (24)</td></tr><tr><td>Uncollectible accounts expense</td><td>(2)</td></tr><tr><td>BSC costs</td><td>(1)</td></tr><tr><td>Labor, other benefits, contracting and materials</td><td>8</td></tr><tr><td>Pension and non-pension postretirement benefits expense</td><td>1</td></tr><tr><td>Other</td><td>2</td></tr><tr><td></td><td>(16)</td></tr><tr><td>Regulatory Required Programs</td><td></td></tr><tr><td></td><td>(1)</td></tr><tr><td>Total (decrease) increase</td><td>$ (17)</td></tr></table>

(a) Reflects decreased storm restoration costs due to the March 2018 winter storms.

The changes in Depreciation and amortization expense consisted of the following:

<table><tr><td></td><td>Increase (Decrease) 2019 vs. 2018</td></tr><tr><td>Depreciation expense \( ^{(a)} \)</td><td>24</td></tr><tr><td>Regulatory asset amortization</td><td>4</td></tr><tr><td>Regulatory required programs</td><td>(9)</td></tr><tr><td>Increase in depreciation and amortization expense</td><td>19</td></tr></table>

(a) Depreciation expense increased due to ongoing capital expenditures.

Interest expense, net increased during the year ended December 31, 2019 compared to the same period in 2018, primarily due to the issuances of debt in September 2018 and September 2019.

Other, net increased during the year ended December 31, 2019 compared to the same period in 2018, primarily due to higher AFUDC equity.

Effective income tax rates were 18% and 19.1% for the years ended December 31, 2019 and 2018, respectively. See Note 13 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.



## Results of Operations—PHI

PHI’s results of operations include the results of its three reportable segments, Pepco, DPL and ACE. PHI also has a business services subsidiary, PHISCO, which provides a variety of support services and the costs are directly charged or allocated to the applicable subsidiaries. Additionally, the results of PHI's corporate operations include interest costs from various financing activities. See the results of operations for Pepco, DPL, and ACE for additional information.

<table><tr><td rowspan="2"></td><td colspan="2">2019</td><td colspan="2">2018(a)</td><td colspan="2">Favorable (unfavorable) 2019 vs. 2018 variance</td><td colspan="2">2017(a)</td><td colspan="2">Favorable (unfavorable) 2018 vs. 2017 variance</td></tr><tr><td>$</td><td>477</td><td>$</td><td>393</td><td>$</td><td>84</td><td>$</td><td>355</td><td>$</td><td>38</td></tr><tr><td>PHI</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Pepco</td><td></td><td></td><td>243</td><td></td><td>205</td><td></td><td>38</td><td></td><td>198</td><td></td></tr><tr><td>DPL</td><td></td><td></td><td>147</td><td></td><td>120</td><td></td><td>27</td><td></td><td>121</td><td></td></tr><tr><td>ACE</td><td></td><td></td><td>99</td><td></td><td>75</td><td></td><td>24</td><td></td><td>77</td><td></td></tr><tr><td>Other(b)</td><td></td><td></td><td>(12)</td><td></td><td>(7)</td><td></td><td>(5)</td><td></td><td>(41)</td><td></td></tr></table>

(a) PHI's and Pepco's amounts have been revised to reflect the correction of an error related to Pepco's decoupling mechanism. See Note 1 - Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information.

(b) Primarily includes eliminating and consolidating adjustments, PHI's corporate operations, shared service entities and other financing activities.

Year Ended December 31, 2019 Compared to Year Ended December 31, 2018. Net income increased by $84 million primarily due to higher electric and natural gas distribution rates (not reflecting the impact of TCJA), higher transmission revenues due to an increase in transmission rates and the highest daily peak load, lower contracting costs, the absence of the charge associated with a remeasurement of the Buzzard Point ARO, lower uncollectible accounts expense, and lower write-offs of construction work in progress, partially offset by an increase in environmental liabilities and various expenses.



## Results of Operations—Pepco

<table><tr><td></td><td colspan="2">2019</td><td colspan="2">2018(a)</td><td colspan="2">Favorable (unfavorable) 2019 vs. 2018 variance</td><td colspan="2">2017(a)</td><td colspan="2">Favorable (unfavorable) 2018 vs. 2017 variance</td></tr><tr><td>Operating revenues</td><td>$</td><td>2,260</td><td>$</td><td>2,232</td><td>$</td><td>28</td><td>$</td><td>2,151</td><td>$</td><td>81</td></tr><tr><td>Purchased power expense</td><td></td><td>665</td><td></td><td>654</td><td></td><td>(11)</td><td></td><td>614</td><td></td><td>(40)</td></tr><tr><td>Revenues net of purchased power expense</td><td></td><td>1,595</td><td></td><td>1,578</td><td></td><td>17</td><td></td><td>1,537</td><td></td><td>41</td></tr><tr><td>Other operating expenses</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating and maintenance</td><td></td><td>482</td><td></td><td>501</td><td></td><td>19</td><td></td><td>454</td><td></td><td>(47)</td></tr><tr><td>Depreciation and amortization</td><td></td><td>374</td><td></td><td>385</td><td></td><td>11</td><td></td><td>321</td><td></td><td>(64)</td></tr><tr><td>Taxes other than income taxes</td><td></td><td>378</td><td></td><td>379</td><td></td><td>1</td><td></td><td>371</td><td></td><td>(8)</td></tr><tr><td>Total other operating expenses</td><td></td><td>1,234</td><td></td><td>1,265</td><td></td><td>31</td><td></td><td>1,146</td><td></td><td>(119)</td></tr><tr><td>Gain on sales of assets</td><td></td><td>—</td><td></td><td>—</td><td></td><td>—</td><td></td><td>1</td><td></td><td>(1)</td></tr><tr><td>Operating income</td><td></td><td>361</td><td></td><td>313</td><td></td><td>48</td><td></td><td>392</td><td></td><td>(79)</td></tr><tr><td>Other income and (deductions)</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Interest expense, net</td><td></td><td>(133)</td><td></td><td>(128)</td><td></td><td>(5)</td><td></td><td>(121)</td><td></td><td>(7)</td></tr><tr><td>Other, net</td><td></td><td>31</td><td></td><td>31</td><td></td><td>—</td><td></td><td>32</td><td></td><td>(1)</td></tr><tr><td>Total other income and (deductions)</td><td></td><td>(102)</td><td></td><td>(97)</td><td></td><td>(5)</td><td></td><td>(89)</td><td></td><td>(8)</td></tr><tr><td>Income before income taxes</td><td></td><td>259</td><td></td><td>216</td><td></td><td>43</td><td></td><td>303</td><td></td><td>(87)</td></tr><tr><td>Income taxes</td><td></td><td>16</td><td></td><td>11</td><td></td><td>(5)</td><td></td><td>105</td><td></td><td>94</td></tr><tr><td>Net income</td><td></td><td>$</td><td>243</td><td>$</td><td>205</td><td>$</td><td>38</td><td>$</td><td>198</td><td>$</td></tr></table>

(a) Amounts have been revised to reflect the correction of an error related to Pepco's decoupling mechanism. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information.

Year Ended December 31, 2019 Compared to Year Ended December 31, 2018. Net income increased by $38 million primarily due to higher electric distribution rates in Maryland that became effective August 2019 and June 2018 (not reflecting the impact of TCJA), higher electric distribution rates in the District of Columbia that became effective August 2018 (not reflecting the impact of TCJA), higher transmission revenues due to an increase in transmission rates and the highest daily peak load, the absence of the charge associated with a remeasurement of the Buzzard Point ARO, and lower contracting costs, partially offset by an increase in environmental liabilities.

Revenues Net of Purchased Power Expense. There are certain drivers of Operating revenues that are fully offset by their impact on Purchased power expense, such as commodity and REC procurement costs and participation in customer choice programs. Pepco recovers electricity and REC procurement costs from customers with a slight mark-up. Therefore, fluctuations in these costs have minimal impact on RNF.

Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries or RNF, but impact Operating revenues related to supplied electricity.



The changes in RNF consisted of the following:

<table><tr><td rowspan="2">Volume</td><td colspan="2">Increase (Decrease)</td></tr><tr><td>2019 vs. 2018</td><td></td></tr><tr><td>Distribution revenue</td><td>$     12</td><td></td></tr><tr><td>Regulatory required programs</td><td>20</td><td></td></tr><tr><td>Transmission revenues</td><td>(35)</td><td></td></tr><tr><td>Other</td><td>18</td><td></td></tr><tr><td>Total increase</td><td>2</td><td></td></tr><tr><td></td><td>$     17</td><td></td></tr></table>

Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in both Maryland and the District of Columbia are not impacted by abnormal weather or usage per customer as a result of a bill stabilization adjustment (BSA) that provides for a fixed distribution charge per customer by customer class. While Operating revenues are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.

Volume, exclusive of the effects of weather, increased for the year ended December 31, 2019 compared to the same period in 2018 primarily due to the impact of residential customer growth.

<table><tr><td rowspan="2">Number of Electric Customers</td><td colspan="2">As of December 31,</td></tr><tr><td>2019</td><td>2018</td></tr><tr><td>Residential</td><td>817,770</td><td>807,442</td></tr><tr><td>Small commercial &amp; industrial</td><td>54,265</td><td>54,306</td></tr><tr><td>Large commercial &amp; industrial</td><td>22,271</td><td>22,022</td></tr><tr><td>Public authorities &amp; electric railroads</td><td>160</td><td>150</td></tr><tr><td>Total</td><td>894,466</td><td>883,920</td></tr></table>

Distribution Revenues increased for the year ended December 31, 2019 compared to the same period in 2018 primarily due to higher electric distribution rates in Maryland that became effective in August 2019 and June 2018 (not reflecting the impact of TCJA), higher electric distribution rates (not reflecting the impact of TCJA) in the District of Columbia that became effective in August 2018, partially offset by the accelerated amortization of certain deferred income tax regulatory liabilities established upon the enactment of TCJA as the result of regulatory settlements. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, DC PLUG and SOS administrative costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Revenues from regulatory programs decreased for the year ended December 31, 2019 compared to the same period in 2018 due to lower surcharge rates effective January 2019 for energy efficiency programs that were implemented to reflect the impacts of the enactment of TCJA.

Transmission Revenues. Under a FERC approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered and the highest daily peak load, which is updated annually in January based on the prior calendar year. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. Transmission revenue increased for the year ended December 31, 2019 compared to the same period in 2018 due to rate increases and an increase in the highest daily peak load.

Other revenue includes revenue related to late payment charges, mutual assistance revenues, off-system sales and service application fees.



See Note 5 - Segment Information for the Combined Notes to Consolidated Financial Statements for the presentation of Pepco's revenue disaggregation.

The changes in Operating and maintenance expense consisted of the following:

<table><tr><td></td><td>(Decrease) Increase 2019 vs. 2018</td></tr><tr><td>Baseline</td><td></td></tr><tr><td>BSC and PHSCO costs</td><td>$ (16)</td></tr><tr><td>Labor, other benefits, contracting and materials</td><td>(11)</td></tr><tr><td>Uncollectible accounts expense</td><td>(3)</td></tr><tr><td>Pension and Non-Pension Postretirement Benefits</td><td></td></tr><tr><td>Other</td><td>6</td></tr><tr><td></td><td>8</td></tr><tr><td></td><td>(16)</td></tr><tr><td>Regulatory required programs</td><td>(3)</td></tr><tr><td>Total decrease</td><td>$ (19)</td></tr><tr><td></td><td>Increase (Decrease) 2019 vs. 2018</td></tr><tr><td>Depreciation expense(a)</td><td>$ 21</td></tr><tr><td>Regulatory asset amortization</td><td>4</td></tr><tr><td>Regulatory required programs</td><td>(36)</td></tr><tr><td>Total decrease</td><td>$ (11)</td></tr></table>

(a) Depreciation and amortization increased primarily due to ongoing capital expenditures.

Interest expense, net for the year ended December 31, 2019 compared to the same period in 2018 increased primarily due to higher outstanding debt.

Effective income tax rates for the years ended December 31, 2019 and 2018 were 6.2% and 5.1%, respectively. See Note 13 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates.



## Results of Operations—DPL

<table><tr><td></td><td colspan="2">2019</td><td colspan="2">2018</td><td colspan="2">Favorable (unfavorable) 2019 vs. 2018 variance</td><td colspan="2">2017</td><td colspan="2">Favorable (unfavorable) 2018 vs. 2017 variance</td></tr><tr><td>Operating revenues</td><td>$</td><td>1,306</td><td>$</td><td>1,332</td><td>$</td><td>(26)</td><td>$</td><td>1,300</td><td>$</td><td>32</td></tr><tr><td>Purchased power and fuel expense</td><td></td><td>526</td><td></td><td>561</td><td></td><td>35</td><td></td><td>532</td><td></td><td>(29)</td></tr><tr><td>Revenues net of purchased power and fuel expense</td><td></td><td>780</td><td></td><td>771</td><td></td><td>9</td><td></td><td>768</td><td></td><td>3</td></tr><tr><td>Other operating expenses</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating and maintenance</td><td></td><td>323</td><td></td><td>344</td><td></td><td>21</td><td></td><td>315</td><td></td><td>(29)</td></tr><tr><td>Depreciation and amortization</td><td></td><td>184</td><td></td><td>182</td><td></td><td>(2)</td><td></td><td>167</td><td></td><td>(15)</td></tr><tr><td>Taxes other than income taxes</td><td></td><td>56</td><td></td><td>56</td><td></td><td>—</td><td></td><td>57</td><td></td><td>1</td></tr><tr><td>Total other operating expenses</td><td></td><td>563</td><td></td><td>582</td><td></td><td>19</td><td></td><td>539</td><td></td><td>(43)</td></tr><tr><td>Gain on sales of assets</td><td></td><td>—</td><td></td><td>1</td><td></td><td>(1)</td><td></td><td>—</td><td></td><td>1</td></tr><tr><td>Operating income</td><td></td><td>217</td><td></td><td>190</td><td></td><td>27</td><td></td><td>229</td><td></td><td>(39)</td></tr><tr><td>Other income and (deductions)</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Interest expense, net</td><td></td><td>(61)</td><td></td><td>(58)</td><td></td><td>(3)</td><td></td><td>(51)</td><td></td><td>(7)</td></tr><tr><td>Other, net</td><td></td><td>13</td><td></td><td>10</td><td></td><td>3</td><td></td><td>14</td><td></td><td>(4)</td></tr><tr><td>Total other income and (deductions)</td><td></td><td>(48)</td><td></td><td>(48)</td><td></td><td>—</td><td></td><td>(37)</td><td></td><td>(11)</td></tr><tr><td>Income before income taxes</td><td></td><td>169</td><td></td><td>142</td><td></td><td>27</td><td></td><td>192</td><td></td><td>(50)</td></tr><tr><td>Income taxes</td><td></td><td>22</td><td></td><td>22</td><td></td><td>—</td><td></td><td>71</td><td></td><td>49</td></tr><tr><td>Net income</td><td>$</td><td>147</td><td>$</td><td>120</td><td>$</td><td>27</td><td>$</td><td>121</td><td>$</td><td>(1)</td></tr></table>

Year Ended December 31, 2019 Compared to Year Ended December 31, 2018. Net income increased by $27 million primarily due to higher transmission revenues due to an increase in the transmission rates and the highest daily peak load, higher electric distribution rates in Maryland and Delaware that became effective throughout 2018 (not reflecting the impact of TCJA), higher natural gas distribution rates in Delaware that became effective throughout 2018 (not reflecting the impact of TCJA), and lower write-offs of construction work in progress.

Revenues Net of Purchased Power and Fuel Expense. There are certain drivers to Operating revenues that are fully offset by their impact on Purchased power and fuel expense, such as commodity and REC procurement costs and participation in customer choice programs. DPL recovers electricity and REC procurement costs from customers with a slight mark-up and natural gas costs from customers without mark-up. Therefore, fluctuations in these costs have minimal impact on RNF.

Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries or RNF, but impact Operating revenues related to supplied electricity.



The changes in RNF consisted of the following:

<table><tr><td rowspan="3"></td><td colspan="5">2019 vs. 2018</td></tr><tr><td colspan="4">Increase (Decrease)</td><td rowspan="2"></td></tr><tr><td>Electric</td><td colspan="2">Gas</td><td>Total</td></tr><tr><td>Weather</td><td>$ (3)</td><td>$ (4)</td><td>$ (7)</td><td></td><td></td></tr><tr><td>Volume</td><td>1</td><td>2</td><td>3</td><td></td><td></td></tr><tr><td>Distribution revenue</td><td>2</td><td>1</td><td>3</td><td></td><td></td></tr><tr><td>Regulatory required programs</td><td>(7)</td><td>2</td><td>(5)</td><td></td><td></td></tr><tr><td>Transmission revenues</td><td>19</td><td>—</td><td>19</td><td></td><td></td></tr><tr><td>Other</td><td>(4)</td><td>—</td><td>(4)</td><td></td><td></td></tr><tr><td>Total increase</td><td>$ 8</td><td>$ 1</td><td>$ 9</td><td></td><td></td></tr></table>

Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution customers in Maryland are not affected by unseasonably warmer or colder weather because a bill stabilization adjustment (BSA) that provides for a fixed distribution charge per customer by customer class. While Operating revenues from electric distribution customers in Maryland are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.

Weather. The demand for electricity and natural gas in Delaware is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as "favorable weather conditions" because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the year ended December 31, 2019 compared to the same period in 2018, RNF related to weather decreased primarily due to unfavorable weather conditions in DPL's Delaware service territory.

Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 20-year period in DPL's Delaware electric service territory and a 30-year period in DPL's Delaware natural gas service territory. The changes in heating and cooling degree days in DPL's Delaware service territory for the year ended December 31, 2019 compared to same period in 2018 and normal weather consisted of the following:

<table><tr><td>Delaware Electric Service Territory</td><td colspan="3">For the Years Ended December 31,</td><td colspan="2">% Change</td></tr><tr><td>Heating and Cooling Degree-Days</td><td>2019</td><td>2018</td><td>Normal</td><td>2019 vs. 2018</td><td>2019 vs. Normal</td></tr><tr><td>Heating Degree-Days</td><td>4,475</td><td>4,713</td><td>4,656</td><td>(5.0)%</td><td>(3.9)%</td></tr><tr><td>Cooling Degree-Days</td><td>1,476</td><td>1,456</td><td>1,224</td><td>1.4%</td><td>20.6%</td></tr><tr><td>Delaware Natural Gas Service Territory</td><td colspan="3">For the Years Ended December 31,</td><td colspan="2">% Change</td></tr><tr><td>Heating Degree-Days</td><td>2019</td><td>2018</td><td>Normal</td><td>2019 vs. 2018</td><td>2019 vs. Normal</td></tr><tr><td>Heating Degree-Days</td><td>4,475</td><td>4,713</td><td>4,698</td><td>(5.0)%</td><td>(4.7)%</td></tr></table>

Volume, exclusive of the effects of weather, remained relatively consistent for the year ended December 31, 2019 compared to the same period in 2018.



<table><tr><td>Electric Retail Deliveries to Delaware Customers (in GWhs)</td><td>2019</td><td>2018</td><td>% Change 2019 vs. 2018</td><td>Weather - Normal % Change (b)</td></tr><tr><td>Retail Deliveries</td><td></td><td></td><td></td><td></td></tr><tr><td>Residential</td><td>3,149</td><td>3,204</td><td>(1.7)%</td><td>(0.2)%</td></tr><tr><td>Small commercial &amp; industrial</td><td>1,320</td><td>1,344</td><td>(1.8)%</td><td>(1.4)%</td></tr><tr><td>Large commercial &amp; industrial</td><td>3,424</td><td>3,636</td><td>(5.8)%</td><td>(5.7)%</td></tr><tr><td>Public authorities &amp; electric railroads</td><td>34</td><td>33</td><td>3.0 %</td><td>0.9 %</td></tr><tr><td>Total electric retail deliveries(a)</td><td>7,927</td><td>8,217</td><td>(3.5)%</td><td>(2.9)%</td></tr><tr><td></td><td></td><td></td><td colspan="2">As of December 31,</td></tr><tr><td>Number of Total Electric Customers (Maryland and Delaware)</td><td></td><td></td><td>2019</td><td>2018</td></tr><tr><td>Residential</td><td></td><td></td><td>468,162</td><td>463,670</td></tr><tr><td>Small commercial &amp; industrial</td><td></td><td></td><td>61,721</td><td>61,381</td></tr><tr><td>Large commercial &amp; industrial</td><td></td><td></td><td>1,411</td><td>1,406</td></tr><tr><td>Public authorities &amp; electric railroads</td><td></td><td></td><td>613</td><td>621</td></tr><tr><td>Total</td><td></td><td></td><td>531,907</td><td>527,078</td></tr></table>

(a) Reflects delivery volumes and revenues from customers purchasing electricity directly from DPL and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges.

(b) Reflects the change in delivery volumes assuming normalized weather based on the historical 20-year average.

<table><tr><td>Natural Gas Retail Deliveries to Delaware Customers (in mmcf)</td><td>2019</td><td>2018</td><td>% Change 2019 vs. 2018</td><td>Weather - Normal % Change(b)</td></tr><tr><td>Retail Deliveries</td><td></td><td></td><td></td><td></td></tr><tr><td>Residential</td><td>8,613</td><td>8,633</td><td>(0.2)%</td><td>4.2 %</td></tr><tr><td>Small commercial &amp; industrial</td><td>4,287</td><td>4,134</td><td>3.7 %</td><td>7.8 %</td></tr><tr><td>Large commercial &amp; industrial</td><td>1,811</td><td>1,952</td><td>(7.2)%</td><td>(7.1)%</td></tr><tr><td>Transportation</td><td>6,733</td><td>6,831</td><td>(1.4)%</td><td>(0.2)%</td></tr><tr><td>Total natural gas deliveries(a)</td><td>21,444</td><td>21,550</td><td>(0.5)%</td><td>2.5 %</td></tr><tr><td></td><td></td><td></td><td colspan="2">As of December 31,</td></tr><tr><td>Number of Delaware Gas Customers</td><td></td><td></td><td>2019</td><td>2018</td></tr><tr><td>Residential</td><td></td><td></td><td>125,873</td><td>124,183</td></tr><tr><td>Small commercial &amp; industrial</td><td></td><td></td><td>9,999</td><td>9,986</td></tr><tr><td>Large commercial &amp; industrial</td><td></td><td></td><td>17</td><td>18</td></tr><tr><td>Transportation</td><td></td><td></td><td>159</td><td>156</td></tr><tr><td>Total</td><td></td><td></td><td>136,048</td><td>134,343</td></tr></table>

(a) Reflects delivery volumes and revenues from customers purchasing natural gas directly from DPL and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges.

(b) Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.

Distribution Revenue increased for the year ended December 31, 2019 compared to the same period in 2018 primarily due to higher electric distribution rates (not reflecting the impact of TCJA) in Maryland and Delaware that became effective throughout 2018 and higher natural gas distribution rates (not reflecting the impact of TCJA) in Delaware that became effective throughout 2018, partially offset by the accelerated amortization of certain deferred income tax regulatory liabilities established upon the enactment of TCJA as the result of regulatory settlements. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.



Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, DE Renewable Portfolio Standards, SOS administrative costs and GCR costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Operating and maintenance expense, Depreciation and amortization expense and Taxes other than income taxes.

Transmission Revenues. Under a FERC approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered and the highest daily peak load, which is updated annually in January based on the prior calendar years. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. Transmission revenue increased for the year ended December 31, 2019 compared to the same period in 2018 due to rate increases and an increase in the highest daily peak load.

Other revenue includes revenue related to late payment charges, mutual assistance revenues, off-system sales and service application fees.

See Note 5 - Segment Information for the Combined Notes to Consolidated Financial Statements for the presentation of DPL's revenue disaggregation.

The changes in Operating and maintenance expense consisted of the following:

<table><tr><td></td><td>(Decrease) Increase 2019 vs. 2018</td></tr><tr><td>Baseline</td><td></td></tr><tr><td>BSC and PHISCO costs</td><td>$ (10)</td></tr><tr><td>Write-off of construction work in progress</td><td>(7)</td></tr><tr><td>Uncollectible accounts expense</td><td>(2)</td></tr><tr><td>Pension and non-pension postretirement benefits expense</td><td>4</td></tr><tr><td>Labor, other benefits, contracting and materials</td><td>2</td></tr><tr><td>Storm-related costs</td><td>(1)</td></tr><tr><td>Other</td><td>(6)</td></tr><tr><td></td><td>(20)</td></tr><tr><td>Regulatory required programs</td><td>(1)</td></tr><tr><td>Total decrease</td><td>$ (21)</td></tr></table>

The changes in Depreciation and amortization expense consisted of the following:

<table><tr><td></td><td>Increase (Decrease) 2019 vs. 2018</td></tr><tr><td>Depreciation expense \( ^{(a)} \)</td><td>$ 14</td></tr><tr><td>Regulatory asset amortization</td><td>(1)</td></tr><tr><td>Regulatory required programs</td><td>(11)</td></tr><tr><td>Total increase</td><td>$ 2</td></tr></table>

(a) Depreciation and amortization increased primarily due to ongoing capital expenditures.

Interest expense, net for the year ended December 31, 2019 compared to the same period in 2018 increased primarily due to higher outstanding debt.



Effective income tax rates for the years ended December 31, 2019 and 2018 were 13.0% and 15.5%, respectively. See Note 13 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates



## Results of Operations—ACE

<table><tr><td></td><td colspan="2">2019</td><td colspan="2">2018</td><td colspan="2">Favorable (unfavorable) 2019 vs. 2018 variance</td><td colspan="2">2017</td><td colspan="2">Favorable (unfavorable) 2018 vs. 2017 variance</td></tr><tr><td>Operating revenues</td><td>$     1,240</td><td>$     1,236</td><td>$     4</td><td>$     1,186</td><td>$     50</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Purchased power expense</td><td>608</td><td>616</td><td>8</td><td>570</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Revenues net of purchased power expense</td><td>632</td><td>620</td><td>12</td><td>616</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Other operating expenses</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating and maintenance</td><td>320</td><td>330</td><td>10</td><td>307</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Depreciation and amortization</td><td>157</td><td>136</td><td>(21)</td><td>146</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Taxes other than income taxes</td><td>4</td><td>5</td><td>1</td><td>6</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Total other operating expenses</td><td>481</td><td>471</td><td>(10)</td><td>459</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Gain on sales of assets</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Operating income</td><td>151</td><td>149</td><td>2</td><td>157</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Other income and (deductions)</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Interest expense, net</td><td>(58)</td><td>(64)</td><td>6</td><td>(61)</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Other, net</td><td>6</td><td>2</td><td>4</td><td>7</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Total other income and (deductions)</td><td>(52)</td><td>(62)</td><td>10</td><td>(54)</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Income (loss) before income taxes</td><td>99</td><td>87</td><td>12</td><td>103</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Income taxes</td><td>—</td><td>12</td><td>12</td><td>26</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Net income</td><td>$     99</td><td>$     75</td><td>$     24</td><td>$     77</td><td>$     2</td><td></td><td></td><td></td><td></td><td></td></tr></table>

Year Ended December 31, 2019 Compared to Year Ended December 31, 2018. Net income increased $24 million primarily due to higher electric distribution rates that became effective April 2019 and higher transmission revenues due to an increase in the transmission rates and the highest daily peak load, partially offset by lower average residential usage.

Revenues Net of Purchased Power Expense. There are certain drivers of Operating revenues that are fully offset by their impact on Purchased power expense, such as commodity and REC procurement costs and participation in customer choice programs. ACE recovers electricity and REC procurement costs from customers without mark-up. Therefore, fluctuations in these costs have no impact on RNF.

Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs of supplier do not impact the volume of deliveries or RNF, but impact revenues related to supplied electricity.

The changes in RNF, consisted of the following:

<table><tr><td></td><td colspan="2">(Decrease) Increase 2019 vs. 2018</td></tr><tr><td>Weather</td><td>$      (6)</td><td></td></tr><tr><td>Volume</td><td></td><td>(11)</td></tr><tr><td>Distribution revenue</td><td></td><td>36</td></tr><tr><td>Regulatory required programs</td><td></td><td>(23)</td></tr><tr><td>Transmission revenues</td><td></td><td>20</td></tr><tr><td>Other</td><td></td><td>(4)</td></tr><tr><td>Total increase</td><td>$     12</td><td></td></tr></table>



Weather. The demand for electricity is affected by weather conditions. With respect to the electric business, very warm weather in summer months and very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity. Conversely, mild weather reduces demand. During the year ended December 31, 2019 compared to the same period in 2018, RNF related to weather was lower due to the impact of unfavorable weather conditions in ACE’s service territory.

Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 20-year period in ACE's service territory. The changes in heating and cooling degree days in ACE's service territory for the year ended December 31, 2019 compared to same period in 2018, and normal weather consisted of the following:

<table><tr><td rowspan="2"></td><td colspan="3">For the Years Ended December 31,</td><td colspan="2">% Change</td></tr><tr><td>2019</td><td>2018</td><td>Normal</td><td>2019 vs. 2018</td><td>2019 vs. Normal</td></tr><tr><td>Heating and Cooling Degree-Days</td><td>4,467</td><td>4,523</td><td>4,676</td><td>(1.2)%</td><td>(4.5)%</td></tr><tr><td>Heating Degree-Days</td><td>1,374</td><td>1,535</td><td>1,158</td><td>(10.5)%</td><td>18.7%</td></tr></table>

Volume, exclusive of the effects of weather, decreased for the year ended December 31, 2019 compared to the same period in 2018, primarily due to lower average residential and commercial usage.

<table><tr><td>Electric Retail Deliveries to Customers (in GWhs)</td><td>2019</td><td>2018</td><td>% Change 2019 vs. 2018</td><td>Weather - Normal % Change(b)</td></tr><tr><td>Retail Deliveries</td><td></td><td></td><td></td><td></td></tr><tr><td>Residential</td><td>3,966</td><td>4,185</td><td>(5.2)%</td><td>(3.5)%</td></tr><tr><td>Small commercial &amp; industrial</td><td>1,346</td><td>1,361</td><td>(1.1)%</td><td>0.1%</td></tr><tr><td>Large commercial &amp; industrial</td><td>3,429</td><td>3,565</td><td>(3.8)%</td><td>(3.4)%</td></tr><tr><td>Public authorities &amp; electric railroads</td><td>47</td><td>49</td><td>(4.1)%</td><td>(2.9)%</td></tr><tr><td>Total retail deliveries(a)</td><td>8,788</td><td>9,160</td><td>(4.1)%</td><td>(2.9)%</td></tr></table>

<table><tr><td>Number of Electric Customers</td><td>2019</td><td>2018</td></tr><tr><td>Residential</td><td>494,596</td><td>490,975</td></tr><tr><td>Small commercial &amp; industrial</td><td>61,497</td><td>61,386</td></tr><tr><td>Large commercial &amp; industrial</td><td>3,392</td><td>3,515</td></tr><tr><td>Public authorities &amp; electric railroads</td><td>679</td><td>656</td></tr><tr><td>Total</td><td>560,164</td><td>556,532</td></tr></table>

(a) Reflects delivery volumes and revenues from customers purchasing electricity directly from ACE and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges.

(b) Reflects the change in delivery volumes assuming normalized weather based on the historical 20-year average.

Distribution Revenue increased for the year ended December 31, 2019 compared to the same period in 2018 primarily due to higher electric distribution base rates that became effective in April 2019, partially offset by the accelerated amortization of certain deferred income tax regulatory liabilities established upon the enactment of TCJA as the result of regulatory settlements. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, Societal Benefits Charge, Transition Bonds and BGS administrative costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Operating and maintenance expense, Depreciation and



amortization expense and Taxes other than income taxes. Revenues from regulatory programs decreased for the year ended December 31, 2019 compared to the same period in 2018 due to rate decreases effective October 2018 for the ACE Transition Bonds.

Transmission Revenues. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered and the highest daily peak load, which is updated annually in January based on the prior calendar year. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. Transmission revenue increased for the year ended December 31, 2019 compared to the same period in 2018 primarily due to rate increases and an increase in the highest daily peak load.

Other revenue includes revenue related to late payment charges, mutual assistance revenues, off-system sales and service application fees.

See Note 5 - Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ACE's revenue disaggregation.

The changes in Operating and maintenance expense consisted of the following:

<table><tr><td></td><td>(Decrease) Increase 2019 vs. 2018</td></tr><tr><td>Baseline</td><td></td></tr><tr><td>BSC and PHISCO costs</td><td>$ (8)</td></tr><tr><td>Uncollectible accounts expense \( ^{(a)} \)</td><td>(6)</td></tr><tr><td>Labor, other benefits, contracting and materials</td><td>(5)</td></tr><tr><td>Storm-related costs</td><td>2</td></tr><tr><td>Pension and non-pension postretirement benefits expense</td><td>1</td></tr><tr><td>Other</td><td>6</td></tr><tr><td>Total decrease</td><td>$ (10)</td></tr></table>

(a) ACE is allowed to recover from or refund to customers the difference between its annual uncollectible accounts expense and the amounts collected in rates annually through a rider mechanism. An equal and offsetting amount has been recognized in Operating revenues for the periods presented.

The changes in Depreciation and amortization expense consisted of the following:

<table><tr><td></td><td>Increase (Decrease) 2019 vs. 2018</td></tr><tr><td>Depreciation expense \( ^{(a)} \)</td><td>29</td></tr><tr><td>Regulatory asset amortization</td><td>6</td></tr><tr><td>Regulatory required programs</td><td>(14)</td></tr><tr><td>Total increase</td><td>21</td></tr></table>

(a) Depreciation and amortization increased primarily due to ongoing capital expenditures.

Interest expense, net for the year ended December 31, 2019 compared to the same period in 2018 decreased primarily due to lower outstanding debt.

Other, net for the year ended December 31, 2019 compared to the same period in 2018 increased primarily due to higher AFUDC equity.

Effective income tax rates were 0.0% and 13.8% for the years ended December 31, 2019 and 2018, respectively. See Note 13 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates.

## Liquidity and Capital Resources

All results included throughout the liquidity and capital resources section are presented on a GAAP basis.

The Registrants' operating and capital expenditures requirements are provided by internally generated cash flows from operations as well as funds from external sources in the capital markets and through bank borrowings. The Registrants' businesses are capital intensive and require considerable capital resources. Each of the Registrants annually evaluates its financing plan, dividend practices and credit line sizing, focusing on maintaining its investment grade ratings while meeting its cash needs to fund capital requirements, 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 its 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.). Each Registrant's access to external financing on reasonable terms depends on its credit ratings and current overall capital market business conditions, including that of the utility industry in general. If these conditions deteriorate to the extent that the Registrants no longer have access to the capital markets at reasonable terms, the



Registrants have access to credit facilities with aggregate bank commitments of $10.6 billion. The Registrants utilize their credit facilities to support their commercial paper programs, provide for other short-term borrowings and to issue letters of credit. See the "Credit Matters" section below for additional information. The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs and capital expenditure requirements.

The Registrants primarily use their capital resources, including cash, to fund capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and other postretirement benefit obligations and invest in new and existing ventures. The Registrants spend a significant amount of cash on capital improvements and construction projects that have a long-term return on investment. Additionally, ComEd, PECO, BGE, Pepco, DPL and ACE operate in rate-regulated environments in which the amount of new investment recovery may be delayed or limited and where such recovery takes place over an extended period of time. See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants' 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 to decommission the facility. These NRC minimum funding levels are 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 letters of credit or parent company guarantees or making additional cash contributions to the NDT fund to ensure sufficient funds are available. See Note 9 - Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information.

If a nuclear plant were to early retire there is a risk that it will no longer meet the NRC minimum funding requirements due to the earlier commencement of decommissioning activities and a shorter time period over which the NDT fund investments could appreciate in value. A shortfall could require that Generation address the shortfall by, among other things, obtaining a parental guarantee for Generation's share of the funding assurance. However, the amount of any guarantees or other assurance will ultimately depend on the decommissioning approach, the associated level of costs, and the NDT fund investment performance going forward.

Upon issuance of any required financial guarantees, each site would be able to utilize the respective NDT funds for radiological decommissioning costs, which represent the majority of the total expected decommissioning costs. However, the NRC must approve an exemption in order for the plant's owner(s) to utilize the NDT fund to pay for non-radiological decommissioning costs (i.e., spent fuel management and site restoration costs). If a unit does not receive this exemption, the costs would be borne by the owner(s) without reimbursement from or access to the NDT funds. The ultimate costs for spent fuel management may vary greatly and could be reduced by alternate decommissioning scenarios and/or reimbursement of certain costs under the DOE reimbursement agreements.

As of December 31, 2019, Exelon would not be required to post a parental guarantee for TMI Unit 1 under the SAFSTOR scenario which is the planned decommissioning option as described in the TMI Unit 1 PSDAR filed by Generation with the NRC on April 5, 2019. On October 16, 2019, the NRC granted Generation's exemption request to use the TMI Unit 1 NDT funds for spent fuel management costs. An additional exemption request would be required to allow the funds to be spent on site restoration costs, which are not expected to be incurred in the near term.

## Project Financing (Exelon and Generation)

Project financing is used to help mitigate risk of specific generating assets. Project financing is based upon a nonrecourse financial structure, in which project debt is paid back from the cash generated by the specific asset or portfolio of assets. Borrowings under these agreements are secured by the assets and equity of each respective project. The lenders do not have recourse against Exelon or Generation in the event of a default. If a specific project financing entity does not maintain compliance with its specific debt financing 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 was 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 satisfy its associated debt or other borrowings earlier than otherwise anticipated could lead to impairments due to a higher likelihood of disposing of the respective project-specific assets significantly before the end of their useful



lives. Additionally, project finance has credit facilities. See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on nonrecourse debt.

## Cash Flows from Operating Activities

## General

Generation’s cash flows from operating activities primarily result from the sale of electric energy and energy-related products and services to customers. Generation’s future cash flows from operating activities may be affected by future demand for and market prices of energy and its ability to continue to produce and supply power at competitive costs as well as to obtain collections from customers.

The Utility Registrants' cash flows from operating activities primarily result from the transmission and distribution of electricity and, in the case of PECO, BGE and DPL, gas distribution services. The Utility Registrants' distribution services are provided to an established and diverse base of retail customers. The Utility Registrants' future cash flows may be affected by the economy, weather conditions, future legislative initiatives, future regulatory proceedings with respect to their rates or operations, competitive suppliers, and their ability to achieve operating cost reductions.

See Note 3 — Regulatory Matters and Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information of regulatory and legal proceedings and proposed legislation.

The following table provides a summary of the change in cash provided by (used in) operating activities for the years ended December 31, 2019, 2018 and 2017:

<table><tr><td>2019 vs. 2018 Variance</td><td>Exelon</td><td>Generation</td><td>ComEd</td><td>PECO</td><td>BGE</td><td>PHI</td><td>Pepco</td><td>DPL</td><td>ACE</td></tr><tr><td>Net income</td><td>$ 949</td><td>$ 774</td><td>$ 24</td><td>$ 68</td><td>$ 47</td><td>$ 84</td><td>$ 38</td><td>$ 27</td><td>$ 24</td></tr><tr><td>Add (subtract):</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Non-cash operating activities</td><td>(778)</td><td>(835)</td><td>(34)</td><td>43</td><td>100</td><td>(12)</td><td>(1)</td><td>(26)</td><td>(3)</td></tr><tr><td>Pension and non-pension postretirement benefit contributions</td><td>(25)</td><td>(36)</td><td>(35)</td><td>—</td><td>6</td><td>49</td><td>3</td><td>(1)</td><td>5</td></tr><tr><td>Income taxes</td><td>(404)</td><td>495</td><td>33</td><td>(49)</td><td>(47)</td><td>(18)</td><td>22</td><td>10</td><td>4</td></tr><tr><td>Changes in working capital and other noncurrent assets and liabilities</td><td>(1,221)</td><td>(855)</td><td>(71)</td><td>(50)</td><td>(139)</td><td>(118)</td><td>(24)</td><td>(68)</td><td>3</td></tr><tr><td>Option premiums received (paid), net</td><td>14</td><td>14</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Collateral posted (received), net</td><td>(520)</td><td>(545)</td><td>37</td><td>—</td><td>(8)</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Net cash flows provided by (used in) operations</td><td>(1,985)</td><td>(988)</td><td>(46)</td><td>(12)</td><td>(41)</td><td>(15)</td><td>(38)</td><td>(58)</td><td>(33)</td></tr></table>

<table><tr><td>2018 vs. 2017 Variance</td><td>Exelon</td><td>Generation</td><td>ComEd</td><td>PECO</td><td>BGE</td><td>PHI</td><td>Pepco</td><td>DPL</td><td>ACE</td></tr><tr><td>Net income</td><td>$ (1,790)</td><td>$ (2,355)</td><td>$ 97</td><td>$ 26</td><td>$ 6</td><td>$ 38</td><td>$ 7</td><td>$ (1)</td><td>$ (2)</td></tr><tr><td>Add (subtract):</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Non-cash operating activities</td><td>2,133</td><td>3,116</td><td>(232)</td><td>(12)</td><td>(73)</td><td>(124)</td><td>(17)</td><td>(41)</td><td>(17)</td></tr><tr><td>Pension and non-pension postretirement benefit contributions</td><td>22</td><td>9</td><td>(1)</td><td>(4)</td><td>(1)</td><td>25</td><td>55</td><td>2</td><td>14</td></tr><tr><td>Income taxes</td><td>41</td><td>(689)</td><td>370</td><td>(19)</td><td>(80)</td><td>(45)</td><td>(94)</td><td>(24)</td><td>9</td></tr><tr><td>Changes in working capital and other noncurrent assets and liabilities</td><td>589</td><td>359</td><td>(49)</td><td>(7)</td><td>112</td><td>288</td><td>116</td><td>95</td><td>18</td></tr><tr><td>Option premiums received (paid), net</td><td>(71)</td><td>(71)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Collateral posted (received), net</td><td>240</td><td>193</td><td>37</td><td>—</td><td>4</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Net cash flows provided by (used in) operations</td><td>$ 1,164</td><td>$ 562</td><td>$ 222</td><td>$ (16)</td><td>$ (32)</td><td>$ 182</td><td>$ 67</td><td>$ 31</td><td>$ 22</td></tr></table>

Changes in Registrants' cash flows from operations for 2019, 2018 and 2017 were generally consistent with changes in each Registrant's respective results of operations, as adjusted for non-cash operating activities, and changes in working capital in the normal course of business. In addition, significant operating cash flow impacts for the Registrants for 2019, 2018 and 2017 were as follows:



- See Note 23 —Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements and the Registrants' Consolidated Statement of Cash Flows for additional information on non-cash operating activity.

- See Note 13 —Income Taxes of the Combined Notes to Consolidated Financial Statements and the Registrants' Consolidated Statement of Cash Flows for additional information on income taxes.

- Depending upon whether Generation is in a net mark-to-market liability or asset position, collateral may be required to be posted with or collected from its counterparties. In addition, the collateral posting and collection requirements differ depending on whether the transactions are on an exchange or in the OTC markets.

## Pension and Other Postretirement Benefits

Management considers 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 of 2006 (the Act), management of the pension obligation and regulatory implications. The Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification). The projected contributions below reflect a funding strategy to make levelized annual contributions with the objective of achieving 100% funded status on an Accumulated Benefit Obligation (ABO) basis over time. This level funding strategy helps minimize volatility of future period required pension contributions. Based on this funding strategy and current market conditions, which are subject to change, Exelon's estimated annual qualified pension contributions will be approximately $500 million beginning in 2020. Unlike the qualified pension plans, Exelon's non-qualified pension plans are not funded, given that they are not subject to statutory minimum contribution requirements.

While other postretirement plans are also not subject to statutory minimum contribution requirements, Exelon does fund certain of its plans. For Exelon's funded OPEB plans, contributions generally equal accounting costs, however, Exelon's management has historically considered several factors in determining the level of contributions to its OPEB plans, including liabilities management, levels of benefit claims paid and regulatory implications (amounts deemed prudent to meet regulatory expectations and best assure continued rate recovery). The amounts below include benefit payments related to unfunded plans.

The following table provides all registrants' planned contributions to the qualified pension plans, planned benefit payments to non-qualified pension plans, and planned contributions to other postretirement plans in 2020:

<table><tr><td></td><td colspan="2">Qualified Pension Plans</td><td colspan="2">Non-Qualified Pension Plans</td><td colspan="2">OPEB</td></tr><tr><td>Exelon</td><td>$</td><td>505</td><td>$</td><td>36</td><td>$</td><td>42</td></tr><tr><td>Generation</td><td></td><td>227</td><td></td><td>14</td><td></td><td>16</td></tr><tr><td>ComEd</td><td></td><td>141</td><td></td><td>2</td><td></td><td>3</td></tr><tr><td>PECO</td><td></td><td>17</td><td></td><td>1</td><td></td><td>—</td></tr><tr><td>BGE</td><td></td><td>56</td><td></td><td>2</td><td></td><td>16</td></tr><tr><td>PHI</td><td></td><td>22</td><td></td><td>9</td><td></td><td>7</td></tr><tr><td>Pepco</td><td></td><td>—</td><td></td><td>2</td><td></td><td>7</td></tr><tr><td>DPL</td><td></td><td>—</td><td></td><td>1</td><td></td><td>—</td></tr><tr><td>ACE</td><td></td><td>2</td><td></td><td>—</td><td></td><td>—</td></tr></table>

To the extent interest rates decline significantly or the pension and OPEB plans earn less than the expected asset returns, annual pension contribution requirements in future years could increase. Conversely, to the extent interest rates increase significantly or the pension and OPEB plans earn greater than the expected asset returns, annual pension and OPEB contribution requirements in future years could decrease. Additionally, expected contributions could change if Exelon changes its pension or OPEB funding strategy.



## Cash Flows from Investing Activities

The following table provides a summary of the change in cash provided by (used in) investing activities for the years ended December 31, 2019, 2018 and 2017:

<table><tr><td>2019 vs. 2018 Variance</td><td>Exelon</td><td>Generation</td><td>ComEd</td><td>PECO</td><td>BGE</td><td>PHI</td><td>Pepco</td><td>DPL</td><td>ACE</td></tr><tr><td>Capital expenditures</td><td>$ 346</td><td>$ 397</td><td>$ 211</td><td>$ (90)</td><td>$ (186)</td><td>$ 20</td><td>$ 30</td><td>$ 16</td><td>$ (40)</td></tr><tr><td>Proceeds from NDT fund sales, net</td><td>199</td><td>199</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Acquisitions of assets and businesses, net</td><td>113</td><td>113</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Proceeds from sales of assets and businesses</td><td>(38)</td><td>(38)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Changes in intercompany money pool</td><td>—</td><td>—</td><td>—</td><td>(68)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Other investing activities</td><td>(46)</td><td>(7)</td><td>—</td><td>(10)</td><td>(1)</td><td>(7)</td><td>1</td><td>(1)</td><td>(2)</td></tr><tr><td>Net cash flows provided by (used in) investing activities</td><td>$ 574</td><td>$ 664</td><td>$ 211</td><td>$ (168)</td><td>$ (187)</td><td>$ 13</td><td>$ 31</td><td>$ 15</td><td>$ (42)</td></tr></table>

<table><tr><td>2018 vs. 2017 Variance</td><td>Exelon</td><td>Generation</td><td>ComEd</td><td>PECO</td><td>BGE</td><td>PHI</td><td>Pepco</td><td>DPL</td><td>ACE</td></tr><tr><td>Capital expenditures</td><td>$ (10)</td><td>$ 17</td><td>$ 124</td><td>$ (117)</td><td>$ (77)</td><td>$ 21</td><td>$ (28)</td><td>$ 64</td><td>$ (23)</td></tr><tr><td>Proceeds from NDT fund sales, net</td><td>33</td><td>33</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Acquisitions of assets and businesses, net</td><td>54</td><td>54</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Proceeds from sales of assets and businesses</td><td>(128)</td><td>(128)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Changes in intercompany money pool</td><td>—</td><td>—</td><td>—</td><td>(131)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Other investing activities</td><td>188</td><td>155</td><td>9</td><td>5</td><td>2</td><td>5</td><td>2</td><td>3</td><td>2</td></tr><tr><td>Net cash flows provided by (used in) investing activities</td><td>$ 137</td><td>$ 131</td><td>$ 133</td><td>$ (243)</td><td>$ (75)</td><td>$ 26</td><td>$ (26)</td><td>$ 67</td><td>$ (21)</td></tr></table>

Significant investing cash flow impacts for the Registrants for 2019, 2018 and 2017 were as follows:

- Variances in capital expenditures are primarily due to the timing of cash expenditures for capital projects. Refer below for additional information on projected capital expenditure spending.

- During 2018, Exelon and Generation had expenditures of $81 million and $57 related to the acquisitions of the Everett Marine Terminal and the Handley generating station.

- During 2017, Exelon and Generation had expenditures of $23 million and $178 million related to the acquisitions of ConEdison Solutions and the FitzPatrick nuclear generating station.

- During 2018, Exelon and Generation had proceeds of $85 million relating to the sale of Generation’s interest in an electrical contracting business that primarily installs, maintains and repairs underground and high-voltage cable transmission and distribution services.

- During 2017, Exelon and Generation had proceeds of $218 million from sales of long-lived assets, primarily related to the sale back of turbine equipment.

- Changes in intercompany money pool are driven by short-term borrowing needs. Refer to more information regarding the intercompany money pool below.



## Capital Expenditure Spending

The Registrants most recent estimates of capital expenditures for plant additions and improvements for 2020 are as follows:

<table><tr><td>(in millions)</td><td>Transmission</td><td>Distribution</td><td>Gas</td><td>Total</td></tr><tr><td>Exelon</td><td>N/A</td><td>N/A</td><td>N/A</td><td>8,175</td></tr><tr><td>Generation</td><td>N/A</td><td>N/A</td><td>N/A</td><td>1,725</td></tr><tr><td>ComEd</td><td>475</td><td>1,875</td><td>N/A</td><td>2,350</td></tr><tr><td>PECO</td><td>125</td><td>700</td><td>275</td><td>1,100</td></tr><tr><td>BGE</td><td>275</td><td>575</td><td>475</td><td>1,325</td></tr><tr><td>Pepco</td><td>175</td><td>675</td><td>N/A</td><td>850</td></tr><tr><td>DPL</td><td>125</td><td>225</td><td>100</td><td>450</td></tr><tr><td>ACE</td><td>150</td><td>225</td><td>N/A</td><td>375</td></tr></table>

Projected capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors.

## Generation

Approximately 45% of projected 2020 capital expenditures at Generation are for the acquisition of nuclear fuel, with the remaining amounts reflecting additions and upgrades to existing generation facilities (including material condition improvements during nuclear refueling outages), and additional investment in new generation facilities. Generation anticipates that it will fund capital expenditures with internally generated funds and borrowings.

## Utility Registrants

Projected 2020 capital expenditures at the Utility Registrants are for continuing projects to maintain and improve operations, including enhancing reliability and adding capacity to the transmission and distribution systems such as the Utility Registrants' construction commitments under PJM's R TEP.

The Utility Registrants as transmission owners are subject to NERC compliance requirements. NERC provides guidance to transmission owners regarding assessments of transmission lines. The results of these assessments could require the Utility Registrants to incur incremental capital or operating and maintenance expenditures to ensure their transmission lines meet NERC standards. In 2010, NERC provided guidance to transmission owners that recommended the Utility Registrants perform assessments of their transmission lines. ComEd, PECO and BGE submitted their final bi-annual reports to NERC in January 2014. ComEd and PECO will be incurring incremental capital expenditures associated with this guidance following the completion of the assessments. Specific projects and expenditures are identified as the assessments are completed. ComEd's and PECO's forecasted 2020 capital expenditures above reflect capital spending for remediation to be completed through 2020. BGE, DPL and ACE are complete with their assessments and Pepco has substantially completed its assessment and thus do not expect significant capital expenditures related to this guidance in 2020.

The Utility Registrants anticipate that they will fund their capital expenditures with a combination of internally generated funds and borrowings and additional capital contributions from parent.



## Cash Flows from Financing Activities

The following tables provide a summary of the change in cash provided by (used in) financing activities for the years ended December 31, 2019, 2018 and 2017:

<table><tr><td>2019 vs. 2018 Variance</td><td colspan="2">Exelon</td><td colspan="2">Generation</td><td colspan="2">ComEd</td><td colspan="2">PECO</td><td colspan="2">BGE</td><td colspan="2">PHI</td><td colspan="2">Pepco</td><td colspan="2">DPL</td><td colspan="2">ACE</td></tr><tr><td>Changes in short-term borrowings, net</td><td>$</td><td>869</td><td>$</td><td>320</td><td>$</td><td>130</td><td>$</td><td>—</td><td>$</td><td>82</td><td>$</td><td>200</td><td>$</td><td>28</td><td>$</td><td>272</td><td>$</td><td>(100)</td></tr><tr><td>Long-term debt, net</td><td colspan="2">(665)</td><td colspan="2">(645)</td><td colspan="2">(110)</td><td colspan="2">125</td><td colspan="2">100</td><td colspan="2">(123)</td><td colspan="2">(51)</td><td colspan="2">(133)</td><td colspan="2">63</td></tr><tr><td>Changes in Exelon intercompany money pool</td><td colspan="2">—</td><td colspan="2">(146)</td><td colspan="2">—</td><td colspan="2">—</td><td colspan="2">—</td><td colspan="2" rowspan="2">12</td><td colspan="2">—</td><td colspan="2">—</td><td colspan="2">—</td><td colspan="2" rowspan="2">—</td></tr><tr><td>Common stock issued from treasury stock</td><td colspan="2">—</td><td colspan="2">—</td><td colspan="2">—</td><td colspan="2" rowspan="2">—</td><td colspan="2">—</td><td colspan="2">—</td><td>—</td><td colspan="2">—</td><td colspan="2">—</td></tr><tr><td>Dividends paid on common stock</td><td colspan="2">(76)</td><td colspan="2">—</td><td colspan="2">(49)</td><td colspan="2">(52)</td><td colspan="2">(15)</td><td colspan="2">—</td><td colspan="2">(44)</td><td colspan="2">(43)</td><td colspan="2">(65)</td></tr><tr><td>Distributions to member</td><td colspan="2">—</td><td colspan="2">102</td><td colspan="2">—</td><td colspan="2">—</td><td colspan="2">—</td><td colspan="2" rowspan="2">(200)</td><td colspan="2">—</td><td colspan="2">—</td><td colspan="2">—</td><td colspan="2" rowspan="2">—</td></tr><tr><td>Contributions from parent/member</td><td colspan="2">—</td><td colspan="2">(114)</td><td colspan="2">(250)</td><td colspan="2">99</td><td colspan="2">84</td><td colspan="2">13</td><td colspan="2">(6)</td><td colspan="2">(87)</td><td colspan="2">108</td></tr><tr><td>Sale of noncontrolling interest</td><td colspan="2">—</td><td colspan="2">—</td><td colspan="2">—</td><td colspan="2" rowspan="2">—</td><td colspan="2">—</td><td colspan="2">—</td><td>—</td><td colspan="2">—</td><td colspan="2">—</td><td colspan="2">—</td><td colspan="3">—</td></tr><tr><td>Other financing activities</td><td colspan="2">33</td><td colspan="2">4</td><td colspan="2">1</td><td colspan="2">16</td><td colspan="2">(6)</td><td colspan="2">4</td><td colspan="2">1</td><td colspan="2" rowspan="2">1</td><td colspan="2">2</td><td colspan="3"></td></tr><tr><td>Net cash flows provided by (used in) financing activities</td><td colspan="2">\)</td><td colspan="2">161</td><td colspan="2">(479)</td><td colspan="2">(278)</td><td colspan="2">\(</td><td colspan="2">188</td><td colspan="2">\)</td><td colspan="2">(94)</td><td colspan="2">(72)</td><td colspan="2">$</td><td colspan="3">8</td></tr></table>

<table><tr><td>2018 vs. 2017 Variance</td><td colspan="2">Exelon</td><td colspan="2">Generation</td><td colspan="2">ComEd</td><td colspan="2">PECO</td><td colspan="2">BGE</td><td colspan="2">PHI</td><td colspan="2">Pepco</td><td colspan="2">DPL</td><td colspan="2">ACE</td></tr><tr><td>Changes in short-term borrowings, net</td><td>$</td><td>127</td><td>$</td><td>699</td><td>$</td><td>—</td><td>$</td><td>—</td><td>$</td><td>(74)</td><td>$</td><td>1</td><td>$</td><td>11</td><td>$</td><td>(432)</td><td>$</td><td>(77)</td></tr><tr><td>Long-term debt, net</td><td colspan="2">599</td><td colspan="2">(510)</td><td colspan="2">(65)</td><td colspan="2">(125)</td><td colspan="2">291</td><td colspan="2">418</td><td colspan="2">(3)</td><td colspan="2">236</td><td colspan="2">104</td></tr><tr><td>Changes in Exelon intercompany money pool</td><td colspan="2">—</td><td colspan="2">47</td><td colspan="2">—</td><td colspan="2">—</td><td colspan="2">—</td><td colspan="2" rowspan="2">—</td><td colspan="2">—</td><td colspan="2">—</td><td>—</td><td colspan="2">—</td></tr><tr><td>Common stock issued from treasury stock</td><td colspan="2">(1,150)</td><td colspan="2">—</td><td colspan="2">—</td><td colspan="2">—</td><td colspan="2" rowspan="2">—</td><td colspan="2">—</td><td colspan="2">—</td><td>—</td><td colspan="2">—</td></tr><tr><td>Dividends paid on common stock</td><td colspan="2">(96)</td><td colspan="2">—</td><td colspan="2">(37)</td><td colspan="2">(18)</td><td colspan="2">(11)</td><td colspan="2">—</td><td colspan="2">(36)</td><td colspan="2">16</td><td colspan="2">9</td></tr><tr><td>Distributions to member</td><td colspan="2">—</td><td colspan="2">(342)</td><td colspan="2">—</td><td colspan="2">—</td><td colspan="2">—</td><td colspan="2" rowspan="2">(15)</td><td colspan="2">—</td><td colspan="2">—</td><td>—</td><td colspan="2">—</td></tr><tr><td>Contributions from parent/member</td><td colspan="2">—</td><td colspan="2">53</td><td colspan="2">(151)</td><td colspan="2">73</td><td colspan="2">(75)</td><td colspan="2">(373)</td><td colspan="2">5</td><td colspan="2">150</td><td colspan="2">67</td></tr><tr><td>Sale of noncontrolling interest</td><td colspan="2">(396)</td><td colspan="2">(396)</td><td colspan="2">—</td><td colspan="2">—</td><td colspan="2">—</td><td colspan="2" rowspan="2">—</td><td colspan="2">—</td><td colspan="2">—</td><td>—</td><td colspan="2">—</td></tr><tr><td>Other financing activities</td><td colspan="2">(70)</td><td colspan="2">(1)</td><td colspan="2">(2)</td><td colspan="2">(19)</td><td colspan="2">3</td><td colspan="2">(7)</td><td colspan="2">(3)</td><td colspan="2">(2)</td><td colspan="2">(3)</td></tr><tr><td>Net cash flows provided by (used in) financing activities</td><td>$</td><td>(986)</td><td>$</td><td>(450)</td><td>$</td><td>(255)</td><td>$</td><td>(89)</td><td>$</td><td>134</td><td>$</td><td>24</td><td>$</td><td>(26)</td><td>$</td><td>(32)</td><td>$</td><td>100</td></tr></table>

Significant investing cash flow impacts for the Registrants for 2019, 2018 and 2017 were as follows:

- Changes in short-term borrowings, net, is driven by repayments on and issuances of notes due in less than 90 days. Refer to Note 16 - Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on short-term borrowings.

- Long-term debt, net, varies due to debt issuances and redemptions each year. Refer to debt issuances and redemptions tables below for more information.

- Changes in intercompany money pool are driven by short-term borrowing needs. Refer to more information regarding the intercompany money pool below.

- Exelon issued common stock in 2017 to fund the PHI merger. Refer to Note 19 - Shareholders' Equity of the Combined Notes to Consolidated Financial statements for additional information on common stock issuances.

- Exelon’s ability to pay dividends on its common stock depends on the receipt of dividends paid by its operating subsidiaries. The payments of dividends to Exelon by its subsidiaries in turn depend on their results of operations and cash flows and other items affecting retained earnings. See Note 18 - Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on dividend restrictions. See below for quarterly dividends declared.



- The change in sale of controlling interest from 2017 to 2018 was primarily related to cash received in 2017 for the sale of a 49% interest in EGRP. Refer to Note 22 - Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for additional information on sale of controlling interest.

## Debt Issuances and Redemptions

See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants' debt issuances and retirements. Debt activity for 2019, 2018 and 2017 by Registrant was as follows:

During 2019, the following long-term debt was issued:

<table><tr><td>Company</td><td>Type</td><td>Interest Rate</td><td>Maturity</td><td>Amount</td><td>Use of Proceeds</td></tr><tr><td>Generation</td><td>Energy Efficiency Project Financing \( ^{(a)} \)</td><td>3.95%</td><td>August 31, 2020</td><td>$ 4</td><td>Funding to install energy conservation measures for the Fort Meade project.</td></tr><tr><td>Generation</td><td>Energy Efficiency Project Financing \( ^{(a)} \)</td><td>3.46%</td><td>May 1, 2020</td><td>$ 39</td><td>Funding to install energy conservation measures for the Marine Corps. Logistics Project.</td></tr><tr><td>Generation</td><td>Energy Efficiency Project Financing \( ^{(a)} \)</td><td>2.53%</td><td>April 30, 2021</td><td>$ 2</td><td>Funding to install energy conservation measures for the Fort AP Hill project.</td></tr><tr><td>ComEd</td><td>First Mortgage Bonds, Series 126</td><td>4.00%</td><td>March 1, 2049</td><td>$ 400</td><td>Repay a portion of ComEd&#x27;s outstanding commercial paper obligations and fund other general corporate purposes.</td></tr><tr><td>ComEd</td><td>First Mortgage Bonds, Series 127</td><td>3.20%</td><td>November 15, 2049</td><td>$ 300</td><td>Repay a portion of ComEd&#x27;s outstanding commercial paper obligations and fund other general corporate purposes.</td></tr><tr><td>PECO</td><td>First and Refunding Mortgage Bonds</td><td>3.00%</td><td>September 15, 2049</td><td>$ 325</td><td>Repay short-term borrowings and for general corporate purposes.</td></tr><tr><td>BGE</td><td>Senior Notes</td><td>3.20%</td><td>September 15, 2049</td><td>$ 400</td><td>Repay commercial paper obligations and for general corporate purposes.</td></tr><tr><td>Pepco</td><td>First Mortgage Bonds</td><td>3.45%</td><td>June 13, 2029</td><td>$ 150</td><td>Repay existing indebtedness and for general corporate purposes.</td></tr><tr><td>Pepco</td><td>Unsecured Tax-Exempt Bonds</td><td>1.70%</td><td>September 1, 2022</td><td>$ 110</td><td>Refinance existing indebtedness.</td></tr><tr><td>DPL</td><td>First Mortgage Bonds</td><td>4.14%</td><td>December 12, 2049</td><td>$ 75</td><td>Repay existing indebtedness and for general corporate purposes.</td></tr><tr><td>ACE</td><td>First Mortgage Bonds</td><td>3.50%</td><td>May 21, 2029</td><td>$ 100</td><td>Repay existing indebtedness and for general corporate purposes.</td></tr><tr><td>ACE</td><td>First Mortgage Bonds</td><td>4.14%</td><td>May 21, 2049</td><td>$ 50</td><td>Repay existing indebtedness and for general corporate purposes.</td></tr></table>

(a) For Energy Efficiency Project Financing, the maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt.



During 2018, the following long term debt was issued:

<table><tr><td>Company</td><td>Type</td><td>Interest Rate</td><td>Maturity</td><td>Amount</td><td>Use of Proceeds</td></tr><tr><td>Generation</td><td>Energy Efficiency Project Financing(a)</td><td>3.72%</td><td>March 31, 2019</td><td>$ 4</td><td>Funding to install energy conservation measures for the Smithsonian Zoo project.</td></tr><tr><td>Generation</td><td>Energy Efficiency Project Financing(a)</td><td>3.17%</td><td>January 31, 2019</td><td>$ 1</td><td>Funding to install energy conservation measures in Brooklyn, NY.</td></tr><tr><td>Generation</td><td>Energy Efficiency Project Financing(a)</td><td>2.61%</td><td>September 30, 2018</td><td>$ 5</td><td>Funding to install energy conservation measures for the Pensacola project.</td></tr><tr><td>Generation</td><td>Energy Efficiency Project Financing(a)</td><td>4.17%</td><td>January 31, 2019</td><td>$ 1</td><td>Funding to install energy conservation measures for the General Services Administration Philadelphia project.</td></tr><tr><td>Generation</td><td>Energy Efficiency Project Financing(a)</td><td>4.26%</td><td>May 31, 2019</td><td>$ 3</td><td>Funding to install energy conservation measures for the National Institutes of Health Multi-Buildings Phase II project.</td></tr><tr><td>ComEd</td><td>First Mortgage Bonds, Series 124</td><td>4.00%</td><td>March 1, 2048</td><td>$ 800</td><td>Refinance one series of maturing first mortgage bonds, to repay a portion of ComEd&#x27;s outstanding commercial paper obligations and to fund general corporate purposes.</td></tr><tr><td>ComEd</td><td>First Mortgage Bonds, Series 125</td><td>3.70%</td><td>August 15, 2028</td><td>$ 550</td><td>Repay a portion of ComEd&#x27;s outstanding commercial paper obligations and for general corporate purposes.</td></tr><tr><td>PECO</td><td>First and Refunding Mortgage Bonds</td><td>3.90%</td><td>March 1, 2048</td><td>$ 325</td><td>Refinance a portion of maturing mortgage bonds.</td></tr><tr><td>PECO</td><td>Loan Agreement</td><td>2.00%</td><td>June 20, 2023</td><td>$ 50</td><td>Funding to implement Electric Long-term Infrastructure Improvement Plan.</td></tr><tr><td>PECO</td><td>First and Refunding Mortgage Bonds</td><td>3.90%</td><td>March 1, 2048</td><td>$ 325</td><td>Satisfy short-term borrowings from the Exelon intercompany money pool and for general corporate purposes.</td></tr><tr><td>BGE</td><td>Senior Notes</td><td>4.25%</td><td>September 15, 2048</td><td>$ 300</td><td>Repay commercial paper obligations and for general corporate purposes.</td></tr><tr><td>Pepco</td><td>First Mortgage Bonds</td><td>4.27%</td><td>June 15, 2048</td><td>$ 100</td><td>Repay outstanding commercial paper and for general corporate purposes.</td></tr><tr><td>Pepco</td><td>First Mortgage Bonds</td><td>4.31%</td><td>November 1, 2048</td><td>$ 100</td><td>Repay outstanding commercial paper and for general corporate purposes.</td></tr><tr><td>DPL</td><td>First Mortgage Bonds</td><td>4.27%</td><td>June 15, 2048</td><td>$ 200</td><td>Repay outstanding commercial paper and for general corporate purposes.</td></tr><tr><td>ACE</td><td>First Mortgage Bonds</td><td>4.00%</td><td>October 15, 2028</td><td>$ 350</td><td>Refinance ACE&#x27;s 7.75% First Mortgage Bonds due November 15, 2018, reduce short-term borrowings and for general corporate purposes.</td></tr></table>

(a) For Energy Efficiency Project Financing, the maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt.



During 2017, the following long term-debt was issued:

<table><tr><td>Company</td><td>Type</td><td>Interest Rate</td><td>Maturity</td><td>Amount</td><td>Use of Proceeds</td></tr><tr><td>Exelon Corporate</td><td>Junior Subordinated Notes</td><td>3.50%</td><td>June 1, 2022</td><td>$ 1,150</td><td>Refinance Exelon&#x27;s Junior Subordinated Notes issued in June 2014.</td></tr><tr><td>Generation</td><td>Albany Green Energy Project Financing(a)</td><td>LIBOR + 1.25%</td><td>November 17, 2017</td><td>$ 14</td><td>Albany Green Energy biomass generation development.</td></tr><tr><td>Generation</td><td>Energy Efficiency Project Financing(a)</td><td>3.90%</td><td>February 1, 2018</td><td>$ 19</td><td>Funding to install energy conservation measures for the Naval Station Great Lakes project.</td></tr><tr><td>Generation</td><td>Energy Efficiency Project Financing(a)</td><td>3.72%</td><td>May 1, 2018</td><td>$ 5</td><td>Funding to install energy conservation measures for the Smithsonian Zoo project.</td></tr><tr><td>Generation</td><td>Energy Efficiency Project Financing(a)</td><td>2.61%</td><td>September 30, 2018</td><td>$ 13</td><td>Funding to install energy conservation measures for the Pensacola project.</td></tr><tr><td>Generation</td><td>Energy Efficiency Project Financing(a)</td><td>3.53%</td><td>April 1, 2019</td><td>$ 8</td><td>Funding to install energy conservation measures for the State Department project.</td></tr><tr><td>Generation</td><td>Senior Notes</td><td>2.95%</td><td>January 15, 2020</td><td>$ 250</td><td>Repay outstanding commercial paper obligations and for general corporate purposes.</td></tr><tr><td>Generation</td><td>Senior Notes</td><td>3.40%</td><td>March 15, 2020</td><td>$ 500</td><td>Repay outstanding commercial paper obligations and for general corporate purposes.</td></tr><tr><td>Generation</td><td>ExGen Texas Power Nonrecourse Debt(b)(c)</td><td>LIBOR + 4.75%</td><td>September 18, 2021</td><td>$ 6</td><td>General corporate purposes.</td></tr><tr><td>Generation</td><td>ExGen Renewables IV, Nonrecourse Debt(b)</td><td>LIBOR + 3.00%</td><td>November 30, 2024</td><td>$ 850</td><td>General corporate purposes.</td></tr><tr><td>ComEd</td><td>First Mortgage Bonds, Series 122</td><td>2.95%</td><td>August 15, 2027</td><td>$ 350</td><td>Refinance maturing mortgage bonds, repay a portion of ComEd&#x27;s outstanding commercial paper obligations and for general corporate purposes.</td></tr><tr><td>ComEd</td><td>First Mortgage Bonds, Series 123</td><td>3.75%</td><td>August 15, 2047</td><td>$ 650</td><td>Refinance maturing mortgage bonds, repay a portion of ComEd&#x27;s outstanding commercial paper obligations and for general corporate purposes.</td></tr><tr><td>PECO</td><td>First and Refunding Mortgage Bonds</td><td>3.70%</td><td>September 15, 2047</td><td>$ 325</td><td>General corporate purposes.</td></tr><tr><td>BGE</td><td>Senior Notes</td><td>3.75%</td><td>August 15, 2047</td><td>$ 300</td><td>Redeem $250 million in principal amount of the 6.20% Deferrable Interest Subordinated Debentures due October 15, 2043 issued by BGE&#x27;s affiliate BGE Capital Trust II, repay commercial paper obligations and for general corporate purposes.</td></tr><tr><td>Pepco</td><td>Energy Efficiency Project Financing(a)</td><td>3.30%</td><td>December 15, 2017</td><td>$ 2</td><td>Funding to install energy conservation measures for the DOE Germantown project.</td></tr><tr><td>Pepco</td><td>First Mortgage Bonds</td><td>4.15%</td><td>March 15, 2043</td><td>$ 200</td><td>Funding to repay outstanding commercial paper and for general corporate purposes.</td></tr></table>

(a) For Energy Efficiency Project Financing, the maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt.

(b) See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of nonrecourse debt.



(c) As a result of the bankruptcy filing for EGTP on November 7, 2017, the nonrecourse debt was deconsolidated from Exelon's and Generation's consolidated financial statements. See Note 2 — Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.

During 2019, the following long-term debt was retired and/or redeemed:

<table><tr><td>Company(a)</td><td>Type</td><td>Interest Rate</td><td>Maturity</td><td>Amount</td></tr><tr><td>Exelon</td><td>Long-Term Software License Agreement</td><td>3.95%</td><td>May 1, 2024</td><td>$ 18</td></tr><tr><td>Generation</td><td>Antelope Valley DOE Nonrecourse Debt(b)</td><td>2.33% - 3.56%</td><td>January 5, 2037</td><td>$ 23</td></tr><tr><td>Generation</td><td>Kennett Square Capital Lease</td><td>7.83%</td><td>September 20, 2020</td><td>$ 5</td></tr><tr><td>Generation</td><td>Continental Wind Nonrecourse Debt(b)</td><td>6.00%</td><td>February 28, 2033</td><td>$ 32</td></tr><tr><td>Generation</td><td>Pollution control notes</td><td>2.50%</td><td>March 1, 2019</td><td>$ 23</td></tr><tr><td>Generation</td><td>Renewable Power Generation Nonrecourse Debt(b)</td><td>4.11%</td><td>March 31, 2035</td><td>$ 10</td></tr><tr><td>Generation</td><td>Energy Efficiency Project Financing</td><td>3.46%</td><td>April 30, 2019</td><td>$ 39</td></tr><tr><td>Generation</td><td>ExGen Renewables IV Nonrecourse debt(b)</td><td>3mL +3%</td><td>November 30, 2024</td><td>$ 38</td></tr><tr><td>Generation</td><td>Hannie Mae, LLC Defense Financing</td><td>4.12%</td><td>November 30, 2019</td><td>$ 1</td></tr><tr><td>Generation</td><td>Energy Efficiency Project Financing</td><td>3.72%</td><td>July 31, 2019</td><td>$ 25</td></tr><tr><td>Generation</td><td>NUKEM</td><td>3.15%</td><td>September 30, 2020</td><td>$ 36</td></tr><tr><td>Generation</td><td>SolGen Nonrecourse Debt(b)</td><td>3.93%</td><td>September 30, 2036</td><td>$ 6</td></tr><tr><td>Generation</td><td>Energy Efficiency Project Financing</td><td>4.17%</td><td>October 31, 2019</td><td>$ 1</td></tr><tr><td>Generation</td><td>Energy Efficiency Project Financing</td><td>3.53%</td><td>March 31, 2020</td><td>$ 1</td></tr><tr><td>Generation</td><td>Energy Efficiency Project Financing</td><td>4.26%</td><td>September 30, 2019</td><td>$ 1</td></tr><tr><td>Generation</td><td>Senior Notes</td><td>5.20%</td><td>October 1, 2019</td><td>$ 600</td></tr><tr><td>Generation</td><td>Dominion Federal Corp</td><td>3.17%</td><td>October 31, 2019</td><td>$ 18</td></tr><tr><td>Generation</td><td>Fort Detrick Project Financing</td><td>3.55%</td><td>October 31, 2019</td><td>$ 1</td></tr><tr><td>ComEd</td><td>First Mortgage Bonds</td><td>2.15%</td><td>January 15, 2019</td><td>$ 300</td></tr><tr><td>Pepco</td><td>Secured Tax-Exempt Bonds</td><td>6.20% - 7.49%</td><td>2021 - 2022</td><td>$ 110</td></tr><tr><td>DPL</td><td>Medium Term Notes, Unsecured</td><td>7.61%</td><td>December 2, 2019</td><td>$ 12</td></tr><tr><td>ACE</td><td>Transition Bonds</td><td>5.55%</td><td>October 20, 2023</td><td>$ 18</td></tr></table>

(a) On January 15, 2020, Generation redeemed $1 billion of 2.95% Senior Notes at maturity.

(b) See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of nonrecourse debt.



During 2018, the following long-term debt was retired and/or redeemed:

<table><tr><td>Company</td><td>Type</td><td>Interest Rate</td><td>Maturity</td><td>Amount</td></tr><tr><td>Exelon Corporate</td><td>Long-Term Software License Agreement</td><td>3.95%</td><td>May 1, 2024</td><td>$ 6</td></tr><tr><td>Generation</td><td>Naval Station Great Lakes Project Financing</td><td>3.90%</td><td>June 30, 2018</td><td>$ 41</td></tr><tr><td>Generation</td><td>Smithsonian Zoo Project Financing</td><td>3.72%</td><td>March 31, 2019</td><td>$ 1</td></tr><tr><td>Generation</td><td>Pensacola Project Financing</td><td>2.61%</td><td>September 30, 2018</td><td>$ 21</td></tr><tr><td>Generation</td><td>Fort Detrick Project Financing</td><td>3.55%</td><td>June 30, 2019</td><td>$ 19</td></tr><tr><td>Generation</td><td>Holyoke Nonrecourse Debt \( ^{(a)} \)</td><td>5.25%</td><td>December 31, 2031</td><td>$ 1</td></tr><tr><td>Generation</td><td>SolGen Nonrecourse Debt \( ^{(a)} \)</td><td>3.93%</td><td>September 30, 2036</td><td>$ 10</td></tr><tr><td>Generation</td><td>Antelope Valley DOE Nonrecourse Debt \( ^{(a)} \)</td><td>2.29% - 3.56%</td><td>January 5, 2037</td><td>$ 22</td></tr><tr><td>Generation</td><td>Continental Wind Nonrecourse Debt \( ^{(a)} \)</td><td>6.00%</td><td>February 28, 2033</td><td>$ 33</td></tr><tr><td>Generation</td><td>Renewable Power Generation Nonrecourse Debt \( ^{(a)} \)</td><td>4.11%</td><td>March 31, 2035</td><td>$ 11</td></tr><tr><td>Generation</td><td>Kennett Square Capital Lease</td><td>7.83%</td><td>September 20, 2020</td><td>$ 4</td></tr><tr><td>Generation</td><td>ExGen Renewables IV Nonrecourse Debt \( ^{(a)} \)</td><td>3mL+300 bps</td><td>November 30, 2024</td><td>$ 16</td></tr><tr><td>Generation</td><td>NUKEM</td><td>3.15% - 3.35%</td><td>2018 - 2020</td><td>$ 43</td></tr><tr><td>ComEd</td><td>First Mortgage Bonds</td><td>5.80%</td><td>March 15, 2018</td><td>$ 700</td></tr><tr><td>ComEd</td><td>Notes</td><td>6.95%</td><td>July 15, 2018</td><td>$ 140</td></tr><tr><td>PECO</td><td>First Mortgage Bonds</td><td>5.35%</td><td>March 1, 2018</td><td>$ 500</td></tr><tr><td>DPL</td><td>Medium Term Notes, Unsecured</td><td>6.81%</td><td>January 9, 2018</td><td>$ 4</td></tr><tr><td>Pepco</td><td>Notes</td><td>3.30%</td><td>August 31, 2018</td><td>$ 5</td></tr><tr><td>Pepco</td><td>Third Party Financing</td><td>7.28-7.99%</td><td>2021 - 2023</td><td>$ 1</td></tr><tr><td>ACE</td><td>First Mortgage Bonds</td><td>7.75%</td><td>November 15, 2018</td><td>$ 250</td></tr><tr><td>ACE</td><td>Transition Bonds</td><td>5.05% - 5.55%</td><td>2020 - 2023</td><td>$ 31</td></tr></table>

(a) See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of nonrecourse debt.



During 2017, the following long-term debt was retired and/or redeemed:

<table><tr><td>Company</td><td>Type</td><td>Interest Rate</td><td>Maturity</td><td>Amount</td></tr><tr><td>Exelon Corporate</td><td>Long-Term Software License Agreement</td><td>3.95%</td><td>May 1, 2024</td><td>$ 24</td></tr><tr><td>Exelon Corporate</td><td>Senior Notes</td><td>1.55%</td><td>June 9, 2017</td><td>$ 550</td></tr><tr><td>Generation</td><td>Senior Notes - Exelon Wind</td><td>2.00%</td><td>July 31, 2017</td><td>$ 1</td></tr><tr><td>Generation</td><td>CEU Upstream Nonrecourse Debt \( ^{(a)} \)</td><td>LIBOR + 2.25%</td><td>January 14, 2019</td><td>$ 6</td></tr><tr><td>Generation</td><td>SolGen Nonrecourse Debt \( ^{(a)} \)</td><td>3.93%</td><td>September 30, 2036</td><td>$ 2</td></tr><tr><td>Generation</td><td>Antelope Valley DOE Nonrecourse Debt \( ^{(a)} \)</td><td>2.29% - 3.56%</td><td>January 5, 2037</td><td>$ 22</td></tr><tr><td>Generation</td><td>Kennett Square Capital Lease</td><td>7.83%</td><td>September 20, 2020</td><td>$ 2</td></tr><tr><td>Generation</td><td>Continental Wind Nonrecourse Debt \( ^{(a)} \)</td><td>6.00%</td><td>February 28, 2033</td><td>$ 31</td></tr><tr><td>Generation</td><td>PES - PGOV Notes Payable</td><td>6.70-7.60%</td><td>2017 - 2018</td><td>$ 1</td></tr><tr><td>Generation</td><td>ExGen Texas Power Nonrecourse Debt  \( ^{(a)(b)} \)</td><td>LIBOR + 4.75%</td><td>September 18, 2021</td><td>$ 665</td></tr><tr><td>Generation</td><td>Renewable Power Generation Nonrecourse Debt \( ^{(a)} \)</td><td>4.11%</td><td>March 31, 2035</td><td>$ 14</td></tr><tr><td>Generation</td><td>NUKEM</td><td>3.25% - 3.35%</td><td>June 30, 2018</td><td>$ 23</td></tr><tr><td>Generation</td><td>ExGen Renewables I, Nonrecourse Debt \( ^{(a)} \)</td><td>LIBOR + 4.25%</td><td>February 6, 2021</td><td>$ 233</td></tr><tr><td>Generation</td><td>Senior Notes</td><td>6.20%</td><td>October 1, 2017</td><td>$ 700</td></tr><tr><td>Generation</td><td>Albany Green Energy Project Financing</td><td>LIBOR + 1.25%</td><td>November 17, 2017</td><td>$ 212</td></tr><tr><td>ComEd</td><td>First Mortgage Bonds</td><td>6.15%</td><td>September 15, 2017</td><td>$ 425</td></tr><tr><td>BGE</td><td>Rate Stabilization Bonds</td><td>5.82%</td><td>April 1, 2017</td><td>$ 41</td></tr><tr><td>BGE</td><td>Capital Trust Preferred Securities</td><td>6.20%</td><td>October 15, 2043</td><td>$ 258</td></tr><tr><td>PHI</td><td>Senior Notes</td><td>6.13%</td><td>June 1, 2017</td><td>$ 81</td></tr><tr><td>DPL</td><td>Medium Term Notes, Unsecured</td><td>7.56% - 7.58%</td><td>February 1, 2017</td><td>$ 14</td></tr><tr><td>DPL</td><td>Variable Rate Demand Bonds</td><td>Variable</td><td>October 1, 2017</td><td>$ 26</td></tr><tr><td>Pepco</td><td>Third Party Financing</td><td>6.97% - 7.99%</td><td>2018 - 2022</td><td>$ 1</td></tr><tr><td>ACE</td><td>Transition Bonds</td><td>5.05% - 5.55%</td><td>2020 - 2023</td><td>$ 35</td></tr></table>

(a) See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of nonrecourse debt.

(b) As a result of the bankruptcy filing for EGTP on November 7, 2017, the nonrecourse debt was deconsolidated from Exelon's and Generation's consolidated financial statements. See Note 2 — Mergers, Acquisitions and Dispositions for additional information.

From time to time and as market conditions warrant, the Registrants may engage in long-term debt retirements via tender offers, open market repurchases or other viable options to reduce debt on their respective balance sheets.



## Dividends

Quarterly dividends declared by the Exelon Board of Directors during the year ended December 31, 2019 and for the first quarter of 2020 were as follows:

<table><tr><td>Period</td><td>Declaration Date</td><td>Shareholder of Record Date</td><td>Dividend Payable Date</td><td>Cash per Share(e)</td></tr><tr><td>First Quarter 2019</td><td>February 5, 2019</td><td>February 20, 2019</td><td>March 8, 2019</td><td>$ 0.3625</td></tr><tr><td>Second Quarter 2019</td><td>April 30, 2019</td><td>May 15, 2019</td><td>June 10, 2019</td><td>$ 0.3625</td></tr><tr><td>Third Quarter 2019</td><td>July 30, 2019</td><td>August 15, 2019</td><td>September 10, 2019</td><td>$ 0.3625</td></tr><tr><td>Fourth Quarter 2019</td><td>November 1, 2019</td><td>November 15, 2019</td><td>December 10, 2019</td><td>$ 0.3625</td></tr><tr><td>First Quarter 2020</td><td>January 28, 2020</td><td>February 20, 2020</td><td>March 10, 2020</td><td>$ 0.3825</td></tr></table>

(a) Exelon's Board of Directors approved an updated dividend policy providing an increase of 5% each year for the period covering 2018 through 2020, beginning with the March 2018 dividend.

## Other

For the year ended December 31, 2019, other financing activities primarily consists of debt issuance costs. See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements' for additional information.

## Credit Matters

## Market Conditions

The Registrants fund liquidity needs for capital investment, working capital, energy hedging and other financial commitments through cash flows from continuing operations, public debt offerings, commercial paper markets and large, diversified credit facilities. The credit facilities include $10.6 billion in aggregate total commitments of which $7.4 billion was available to support additional commercial paper as of December 31, 2019, and of which no financial institution has more than 7% of the aggregate commitments for the Registrants. The Registrants had access to the commercial paper market during 2019 to fund their short-term liquidity needs, when necessary. The Registrants routinely review the sufficiency of their 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. The Registrants have continued to 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 for additional information regarding the effects of uncertainty in the capital and credit markets.

The Registrants believe their cash flow from operating activities, access to credit markets and their credit facilities provide sufficient liquidity. If Generation lost its investment grade credit rating as of December 31, 2019, it would have been required to provide incremental collateral of $1.5 billion to meet collateral obligations for derivatives, non-derivatives, normal purchases and normal sales contracts and applicable payables and receivables, net of the contractual right of offset under master netting agreements, which is well within the $4.2 billion of available credit capacity of its revolver.



The following table presents the incremental collateral that each Utility Registrant would have been required to provide in the event each Utility Registrant lost its investment grade credit rating at December 31, 2019 and available credit facility capacity prior to any incremental collateral at December 31, 2019:

<table><tr><td></td><td colspan="2">PJM Credit Policy Collateral</td><td colspan="2">Other Incremental Collateral Required(a)</td><td colspan="2">Available Credit Facility Capacity Prior to Any Incremental Collateral</td></tr><tr><td>ComEd</td><td>$</td><td>11</td><td>$</td><td>—</td><td>$</td><td>868</td></tr><tr><td>PECO</td><td></td><td>—</td><td></td><td>44</td><td></td><td>600</td></tr><tr><td>BGE</td><td></td><td>11</td><td></td><td>50</td><td></td><td>524</td></tr><tr><td>Pepco</td><td></td><td>11</td><td></td><td>—</td><td></td><td>218</td></tr><tr><td>DPL</td><td></td><td>4</td><td></td><td>11</td><td></td><td>244</td></tr><tr><td>ACE</td><td></td><td>—</td><td></td><td>—</td><td></td><td>230</td></tr></table>

(a) Represents incremental collateral related to natural gas procurement contracts.

## Exelon Credit Facilities

Exelon Corporate, ComEd and BGE meet their short-term liquidity requirements primarily through the issuance of commercial paper. Generation and PECO meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the Exelon intercompany money pool. Pepco, DPL, and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the PHI intercompany money pool. PHI Corporate meets its short-term liquidity requirements primarily through the issuance of short-term notes and the Exelon intercompany money pool. The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit.

See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants' credit facilities and short term borrowing activity.

## Other Credit Matters

Capital Structure. At December 31, 2019, the capital structures of the Registrants consisted of the following:

<table><tr><td></td><td>Exelon</td><td>Generation</td><td>ComEd</td><td>PECO</td><td>BGE</td><td>PHI</td><td>Pepco</td><td>DPL</td><td>ACE</td></tr><tr><td>Long-term debt</td><td>50%</td><td>31%</td><td>44%</td><td>44%</td><td>47%</td><td>40%</td><td>49%</td><td>49%</td><td>50%</td></tr><tr><td>Long-term debt to affiliates \( ^{(a)} \)</td><td>1%</td><td>4%</td><td>—%</td><td>2%</td><td>—%</td><td>—%</td><td>—%</td><td>—%</td><td>—%</td></tr><tr><td>Common equity</td><td>47%</td><td>—%</td><td>55%</td><td>54%</td><td>52%</td><td>—</td><td>50%</td><td>49%</td><td>47%</td></tr><tr><td>Member&#x27;s equity</td><td>—%</td><td>64%</td><td>—%</td><td>—%</td><td>—%</td><td>59%</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Commercial paper and notes payable</td><td>2%</td><td>1%</td><td>1</td><td>—%</td><td>1%</td><td>1%</td><td>1%</td><td>2%</td><td>3%</td></tr></table>

(a) Includes approximately $390 million, $205 million and $184 million owed to unconsolidated affiliates of Exelon, ComEd, and PECO respectively. These special purpose entities were created for the sole purposes of issuing mandatorily redeemable trust preferred securities of ComEd and PECO. See Note 22 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for additional information regarding the authoritative guidance for VIEs.

## Security Ratings

The Registrants’ access to the capital markets, including the commercial paper market, and their respective financing costs in those markets, may depend on the securities ratings of the entity that is accessing the capital markets.

The Registrants’ borrowings are not subject to default or prepayment as a result of a downgrading of securities, although such a downgrading of a Registrant’s securities could increase fees and interest charges under that Registrant’s credit agreements.



As part of the normal course of business, the Registrants enter into contracts that contain express provisions or otherwise permit the Registrants and their 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 the Registrants 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 collateral. See Note 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral provisions.

## Intercompany Money Pool

To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing, both Exelon and PHI operate an intercompany money pool. Maximum amounts contributed to and borrowed from the money pool by participant and the net contribution or borrowing as of December 31, 2019, are presented in the following tables:

<table><tr><td rowspan="2">Exelon Intercompany Money Pool</td><td colspan="3">For the Year Ended December 31, 2019</td><td colspan="2">As of December 31, 2019</td></tr><tr><td>Maximum Contributed</td><td></td><td>Maximum Borrowed</td><td></td><td>Contributed (Borrowed)</td></tr><tr><td>Contributed (borrowed)</td><td>$ 467</td><td>$</td><td>—</td><td>$</td><td>121</td></tr><tr><td>Exelon Corporate</td><td>212</td><td></td><td>(235)</td><td></td><td>—</td></tr><tr><td>Generation</td><td>164</td><td></td><td>(85)</td><td></td><td>68</td></tr><tr><td>PECO</td><td>18</td><td></td><td>(383)</td><td></td><td>(232)</td></tr><tr><td>BSC</td><td>—</td><td></td><td>(12)</td><td></td><td>(12)</td></tr><tr><td>PHI Corporate</td><td>60</td><td></td><td>—</td><td></td><td>55</td></tr><tr><td>PCI</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>PHI Intercompany Money Pool</td><td colspan="3">For the Year Ended December 31, 2019</td><td colspan="2">As of December 31, 2019</td></tr><tr><td>Contributed (borrowed)</td><td>Maximum Contributed</td><td></td><td>Maximum Borrowed</td><td></td><td>Contributed (Borrowed)</td></tr><tr><td>Pepco</td><td>$ 63</td><td>$</td><td>—</td><td>$</td><td>—</td></tr><tr><td>DPL</td><td>3</td><td></td><td>(45)</td><td></td><td>—</td></tr><tr><td>ACE</td><td>—</td><td></td><td>(29)</td><td></td><td>—</td></tr><tr><td></td><td></td><td></td><td></td><td></td><td></td></tr></table>



Shelf Registration Statements. Exelon, Generation, ComEd, PECO, BGE, Pepco, DPL and ACE have a currently effective combined shelf registration statement unlimited in amount, filed with the SEC, that will expire in August 2022. The ability of each Registrant to sell securities off the shelf registration statement or to access the private placement markets will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, as applicable, the current financial condition of the Registrant, its securities ratings and market conditions.

Regulatory Authorizations. ComEd, PECO, BGE, Pepco, DPL and ACE are required to obtain short-term and long-term financing authority from Federal and State Commissions as follows:

<table><tr><td rowspan="2"></td><td colspan="3">Short-term Financing Authority(a)(b)</td><td colspan="3">Long-term Financing Authority(a)</td></tr><tr><td>Commission</td><td>Expiration Date</td><td>Amount</td><td>Commission</td><td>Expiration Date</td><td>Amount (c)</td></tr><tr><td>ComEd(c)</td><td>FERC</td><td>December 31, 2021</td><td>$ 2,500</td><td>ICC</td><td>2021 &amp; 2023</td><td>$ 1,893</td></tr><tr><td>PECO</td><td>FERC</td><td>December 31, 2021</td><td>1,500</td><td>PAPUC</td><td>December 31, 2021</td><td>1,575</td></tr><tr><td>BGE</td><td>FERC</td><td>December 31, 2021</td><td>700</td><td>MDPSC</td><td>N/A</td><td>—</td></tr><tr><td>Pepco</td><td>FERC</td><td>December 31, 2021</td><td>500</td><td>MDPSC / DCPSC</td><td>December 31, 2022</td><td>1,200</td></tr><tr><td>DPL</td><td>FERC</td><td>December 31, 2021</td><td>500</td><td>MDPSC / DPSC</td><td>December 31, 2022</td><td>475</td></tr><tr><td>ACE</td><td>NJBPU</td><td>December 31, 2021</td><td>350</td><td>NJBPU</td><td>December 31, 2020</td><td>200</td></tr></table>

(a) Generation currently has blanket financing authority it received from FERC in connection with its market-based rate authority.

(b) On October 15, 2019, ComEd, BGE, Pepco and DPL filed applications with FERC and on September 12, 2019, ACE filed an application with NJBPU for renewal of their short-term financing authority through December 31, 2021. ComEd, BGE, Pepco and DPL received approval on December 13, 2019 and ACE received approval on December 6, 2019.

(c) As of December 31, 2019, ComEd had $393 million in new money long-term debt financing authority from the ICC with an expiration date of August 1, 2021. On January 22, 2020, ComEd had an additional $1.5 billion available in new money long-term debt financing authority from the ICC with an effective date of February 1, 2020 and an expiration date of February 1, 2023.



## Contractual Obligations and Off-Balance Sheet Arrangements

The following tables summarize the Registrants' future estimated cash payments as of December 31, 2019 under existing contractual obligations, including payments due by period.

## Exelon

<table><tr><td rowspan="2"></td><td rowspan="2">Total</td><td colspan="5">Payment due within</td></tr><tr><td>2020</td><td>2021 - 2022</td><td>2023 - 2024</td><td>2025 and beyond</td><td></td></tr><tr><td>Long-term debt \( ^{(a)} \)</td><td>35,910</td><td>4,704</td><td>4,594</td><td>2,442</td><td>24,170</td><td></td></tr><tr><td>Interest payments on long-term debt \( ^{(b)} \)</td><td>22,608</td><td>1,356</td><td>2,586</td><td>2,357</td><td>16,309</td><td></td></tr><tr><td>Finance leases</td><td>40</td><td>6</td><td>11</td><td>9</td><td>14</td><td></td></tr><tr><td>Operating leases \( ^{(c)} \)</td><td>1,361</td><td>144</td><td>267</td><td>197</td><td>753</td><td></td></tr><tr><td>Purchase power obligations \( ^{(d)} \)</td><td>1,201</td><td>312</td><td>672</td><td>198</td><td>19</td><td></td></tr><tr><td>Fuel purchase agreements \( ^{(e)} \)</td><td>6,217</td><td>1,209</td><td>1,852</td><td>1,380</td><td>1,776</td><td></td></tr><tr><td>Electric supply procurement</td><td>2,049</td><td>1,310</td><td>731</td><td>8</td><td>—</td><td></td></tr><tr><td>Long-term renewable energy and REC commitments</td><td>2,284</td><td>254</td><td>534</td><td>448</td><td>1,048</td><td></td></tr><tr><td>Other purchase obligations \( ^{(f)} \)</td><td>8,308</td><td>6,189</td><td>1,139</td><td>274</td><td>706</td><td></td></tr><tr><td>DC PLUG obligation</td><td>130</td><td>30</td><td>60</td><td>40</td><td>—</td><td></td></tr><tr><td>SNF obligation</td><td>1,199</td><td>—</td><td>—</td><td>—</td><td>1,199</td><td></td></tr><tr><td>ZEC commitments</td><td>1,313</td><td>164</td><td>328</td><td>328</td><td>493</td><td></td></tr><tr><td>Pension contributions \( ^{(g)} \)</td><td>3,030</td><td>505</td><td>1,010</td><td>1,010</td><td>505</td><td></td></tr><tr><td>Total contractual obligations</td><td>85,650</td><td>16,183</td><td>13,784</td><td>8,691</td><td>46,992</td><td></td></tr></table>

(a) Includes amounts from ComEd and PECO financing trusts.

(b) Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2019 and do not reflect anticipated future refinancing, early redemptions or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2019. Includes estimated interest payments due to ComEd and PECO financing trusts.

(c) Capacity payments associated with contracted generation lease agreements are net of sublease and capacity offsets of $143 million, $98 million, $55 million, $44 million, $44 million and $223 million for 2020, 2021, 2022, 2023, 2024 and thereafter, respectively and $607 million in total.

(d) Purchase power obligations primarily include expected payments for REC purchases and payments associated with contracted generation agreements, which may be reduced based on plant availability. Expected payments exclude payments on renewable generation contracts that are contingent in nature.

(e) Represents commitments to purchase nuclear fuel, natural gas and related transportation, storage capacity and services.

(f) Represents the future estimated value at December 31, 2019 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between the Registrants and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.

(g) These amounts represent Exelon’s expected contributions to its qualified pension plans. Qualified pension contributions for years after 2025 are not included.

## Generation



<table><tr><td rowspan="2"></td><td rowspan="2">Total</td><td colspan="5">Payment due within</td></tr><tr><td>2020</td><td>2021 - 2022</td><td>2023 - 2024</td><td>2025 and beyond</td><td></td></tr><tr><td>Long-term debt</td><td>$ 7,938</td><td>$ 3,180</td><td>$ 1,024</td><td>$ 792</td><td>$ 2,942</td><td></td></tr><tr><td>Interest payments on long-term debt \( ^{(a)} \)</td><td>3,575</td><td>253</td><td>480</td><td>424</td><td>2,418</td><td></td></tr><tr><td>Finance leases</td><td>5</td><td>2</td><td>2</td><td>1</td><td>—</td><td></td></tr><tr><td>Operating leases \( ^{(b)} \)</td><td>809</td><td>60</td><td>122</td><td>109</td><td>518</td><td></td></tr><tr><td>Purchase power obligations \( ^{(c)} \)</td><td>1,201</td><td>312</td><td>672</td><td>198</td><td>19</td><td></td></tr><tr><td>Fuel purchase agreements \( ^{(d)} \)</td><td>5,056</td><td>999</td><td>1,536</td><td>1,189</td><td>1,332</td><td></td></tr><tr><td>Other purchase obligations \( ^{(e)} \)</td><td>2,536</td><td>1,516</td><td>230</td><td>126</td><td>664</td><td></td></tr><tr><td>SNF obligation</td><td>1,199</td><td>—</td><td>—</td><td>—</td><td>1,199</td><td></td></tr><tr><td>Total contractual obligations</td><td>$ 22,319</td><td>$ 6,322</td><td>$ 4,066</td><td>$ 2,839</td><td>$ 9,092</td><td></td></tr></table>

(a) Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2019 and do not reflect anticipated future refinancing, early redemptions or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2019.

(b) Capacity payments associated with contracted generation lease agreements are net of sublease and capacity offsets of $143 million, $98 million, $55 million, $44 million, $44 million and $223 million for 2020, 2021, 2022, 2023, 2024 and thereafter, respectively and $607 million in total.

(c) Purchase power obligations primarily include expected payments for REC purchases and capacity payments associated with contracted generation agreements, which may be reduced based on plant availability. Expected payments exclude payments on renewable generation contracts that are contingent in nature.

(d) Primarily represents commitments to purchase fuel supplies for nuclear and fossil generation, including those related to CENG.

(e) Represents the future estimated value at December 31, 2019 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between Generation and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.

## ComEd

<table><tr><td rowspan="2"></td><td rowspan="2">Total</td><td colspan="5">Payment due within</td></tr><tr><td>2020</td><td>2021 - 2022</td><td>2023 - 2024</td><td>2025 and beyond</td><td></td></tr><tr><td>Long-term debt \( ^{(a)} \)</td><td>$ 8,783</td><td>$ 500</td><td>$ 350</td><td>$ 250</td><td>$ 7,683</td><td></td></tr><tr><td>Interest payments on long-term debt \) ^{(b)}</td><td>6,918</td><td>345</td><td>674</td><td>665</td><td>5,234</td><td></td></tr><tr><td>Finance leases</td><td>8</td><td>—</td><td>—</td><td>—</td><td>8</td><td></td></tr><tr><td>Operating leases</td><td>12</td><td>3</td><td>6</td><td>2</td><td>1</td><td></td></tr><tr><td>Electric supply procurement</td><td>617</td><td>403</td><td>214</td><td>—</td><td>—</td><td></td></tr><tr><td>Long-term renewable energy and REC commitments</td><td>1,986</td><td>222</td><td>470</td><td>384</td><td>910</td><td></td></tr><tr><td>Other purchase obligations \( ^{(c)} \)</td><td>1,262</td><td>1,219</td><td>36</td><td>5</td><td>2</td><td></td></tr><tr><td>ZEC commitments</td><td>1,313</td><td>164</td><td>328</td><td>328</td><td>493</td><td></td></tr><tr><td>Total contractual obligations</td><td>$ 20,899</td><td>$ 2,856</td><td>$ 2,078</td><td>$ 1,634</td><td>$ 14,331</td><td></td></tr></table>

(a) Includes amounts from ComEd financing trust.

(b) Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2019 and do not reflect anticipated future refinancing, early redemptions or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2019. Includes estimated interest payments due to the ComEd financing trust.

(c) Represents the future estimated value at December 31, 2019 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between ComEd and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.



## PECO

<table><tr><td rowspan="2"></td><td rowspan="2">Total</td><td colspan="5">Payment due within</td></tr><tr><td>2020</td><td>2021 - 2022</td><td>2023 - 2024</td><td>2025 and beyond</td><td></td></tr><tr><td>Long-term debt \( ^{(a)} \)</td><td>3,634</td><td>—</td><td>650</td><td>50</td><td>2,934</td><td></td></tr><tr><td>Interest payments on long-term debt \( ^{(b)} \)</td><td>2,721</td><td>141</td><td>274</td><td>254</td><td>2,052</td><td></td></tr><tr><td>Operating leases</td><td>1</td><td>—</td><td>1</td><td>—</td><td>—</td><td></td></tr><tr><td>Fuel purchase agreements \( ^{(c)} \)</td><td>335</td><td>116</td><td>154</td><td>31</td><td>34</td><td></td></tr><tr><td>Electric supply procurement</td><td>552</td><td>441</td><td>111</td><td>—</td><td>—</td><td></td></tr><tr><td>Other purchase obligations \( ^{(d)} \)</td><td>834</td><td>727</td><td>107</td><td>—</td><td>—</td><td></td></tr><tr><td>Total contractual obligations</td><td>8,077</td><td>1,425</td><td>1,297</td><td>335</td><td>5,020</td><td></td></tr></table>

(a) Includes amounts from PECO financing trusts.

(b) Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2019 and do not reflect anticipated future refinancing, early redemptions or debt issuances. Includes estimated interest payments due to the PECO financing trust.

(c) Represents commitments to purchase natural gas and related transportation, storage capacity and services.

(d) Represents the future estimated value at December 31, 2019 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between PECO and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.

## BGE

<table><tr><td rowspan="2"></td><td rowspan="2">Total</td><td colspan="5">Payment due within</td></tr><tr><td>2020</td><td>2021 - 2022</td><td>2023 - 2024</td><td>2025 and beyond</td><td></td></tr><tr><td>Long-term debt</td><td>3,300</td><td>—</td><td>550</td><td>300</td><td>2,450</td><td></td></tr><tr><td>Interest payments on long-term debt \( ^{(a)} \)</td><td>2,241</td><td>126</td><td>238</td><td>203</td><td>1,674</td><td></td></tr><tr><td>Operating leases</td><td>100</td><td>34</td><td>47</td><td>1</td><td>18</td><td></td></tr><tr><td>Fuel purchase agreements \( ^{(b)} \)</td><td>522</td><td>60</td><td>94</td><td>92</td><td>276</td><td></td></tr><tr><td>Electric supply procurement</td><td>1,050</td><td>631</td><td>419</td><td>—</td><td>—</td><td></td></tr><tr><td>Other purchase obligations \( ^{(c)} \)</td><td>1,014</td><td>868</td><td>141</td><td>3</td><td>2</td><td></td></tr><tr><td>Total contractual obligations</td><td>8,227</td><td>1,719</td><td>1,489</td><td>599</td><td>4,420</td><td></td></tr></table>

(a) Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2019 and do not reflect anticipated future refinancing, early redemptions or debt issuances.

(b) Represents commitments to purchase natural gas and related transportation, storage capacity and services.

(c) Represents the future estimated value at December 31, 2019 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between BGE and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.



## PHI

<table><tr><td rowspan="2"></td><td rowspan="2">Total</td><td colspan="5">Payment due within</td></tr><tr><td>2020</td><td>2021 - 2022</td><td>2023 - 2024</td><td>2025 and beyond</td><td></td></tr><tr><td>Long-term debt</td><td>$ 5,967</td><td>$ 98</td><td>$ 571</td><td>$ 1,049</td><td>$ 4,249</td><td></td></tr><tr><td>Interest payments on long-term debt \( ^{(a)} \)</td><td>4,150</td><td>269</td><td>512</td><td>463</td><td>2,906</td><td></td></tr><tr><td>Finance leases</td><td>28</td><td>5</td><td>8</td><td>8</td><td>7</td><td></td></tr><tr><td>Operating leases</td><td>346</td><td>42</td><td>79</td><td>72</td><td>153</td><td></td></tr><tr><td>Fuel purchase agreements \( ^{(b)} \)</td><td>304</td><td>34</td><td>68</td><td>68</td><td>134</td><td></td></tr><tr><td>Long-term renewable energy and REC commitments</td><td>298</td><td>32</td><td>64</td><td>64</td><td>138</td><td></td></tr><tr><td>Electric supply procurement</td><td>1,787</td><td>1,040</td><td>730</td><td>17</td><td>—</td><td></td></tr><tr><td>Other purchase obligations \( ^{(c)} \)</td><td>1,181</td><td>959</td><td>184</td><td>6</td><td>32</td><td></td></tr><tr><td>DC PLUG obligation</td><td>130</td><td>30</td><td>60</td><td>40</td><td>—</td><td></td></tr><tr><td>Total contractual obligations</td><td>$ 14,219</td><td>$ 2,514</td><td>$ 2,284</td><td>$ 1,795</td><td>$ 7,626</td><td></td></tr></table>

(a) Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2019 and do not reflect anticipated future refinancing, early redemptions or debt issuances.

(b) Represents commitments to purchase natural gas and related transportation, storage capacity and services.

(c) Represents the future estimated value at December 31, 2019 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between PHI and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.

## Pepco

<table><tr><td rowspan="2"></td><td rowspan="2">Total</td><td colspan="5">Payment due within</td></tr><tr><td>2020</td><td>2021 - 2022</td><td>2023 - 2024</td><td>2025 and beyond</td><td></td></tr><tr><td>Long-term debt</td><td>$ 2,886</td><td>$ 1</td><td>$ 311</td><td>$ 399</td><td>$ 2,175</td><td></td></tr><tr><td>Interest payments on long-term debt \( ^{(a)} \)</td><td>2,385</td><td>138</td><td>271</td><td>249</td><td>1,727</td><td></td></tr><tr><td>Finance leases</td><td>11</td><td>1</td><td>2</td><td>3</td><td>5</td><td></td></tr><tr><td>Operating leases</td><td>70</td><td>8</td><td>16</td><td>12</td><td>34</td><td></td></tr><tr><td>Electric supply procurement</td><td>803</td><td>445</td><td>341</td><td>17</td><td>—</td><td></td></tr><tr><td>Other purchase obligations \( ^{(b)} \)</td><td>663</td><td>489</td><td>145</td><td>4</td><td>25</td><td></td></tr><tr><td>DC PLUG obligation</td><td>130</td><td>30</td><td>60</td><td>40</td><td>—</td><td></td></tr><tr><td>Total contractual obligations</td><td>$ 6,959</td><td>$ 1,113</td><td>$ 1,148</td><td>$ 727</td><td>$ 3,971</td><td></td></tr></table>

(a) Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2019 and do not reflect anticipated future refinancing, early redemptions or debt issuances.

(b) Represents the future estimated value at December 31, 2019 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between Pepco and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.



## DPL

<table><tr><td rowspan="2"></td><td rowspan="2">Total</td><td colspan="5">Payment due within</td></tr><tr><td>2020</td><td>2021 - 2022</td><td>2023 - 2024</td><td>2025 and beyond</td><td></td></tr><tr><td>Long-term debt</td><td>$ 1,568</td><td>$ 78</td><td>$ —</td><td>$ 500</td><td>$ 990</td><td></td></tr><tr><td>Interest payments on long-term debt \( ^{(a)} \)</td><td>1,087</td><td>60</td><td>120</td><td>99</td><td>808</td><td></td></tr><tr><td>Finance leases</td><td>10</td><td>2</td><td>4</td><td>3</td><td>1</td><td></td></tr><tr><td>Operating leases</td><td>91</td><td>11</td><td>21</td><td>18</td><td>41</td><td></td></tr><tr><td>Fuel purchase agreements \( ^{(b)} \)</td><td>304</td><td>34</td><td>68</td><td>68</td><td>134</td><td></td></tr><tr><td>Long-term renewable energy and associated REC commitments</td><td>298</td><td>32</td><td>64</td><td>64</td><td>138</td><td></td></tr><tr><td>Electric supply procurement</td><td>458</td><td>288</td><td>170</td><td>—</td><td>—</td><td></td></tr><tr><td>Other purchase obligations \( ^{(c)} \)</td><td>280</td><td>262</td><td>18</td><td>—</td><td>—</td><td></td></tr><tr><td>Total contractual obligations</td><td>$ 4,096</td><td>$ 767</td><td>$ 465</td><td>$ 752</td><td>$ 2,112</td><td></td></tr></table>

(a) Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2019 and do not reflect anticipated future refinancing, early redemptions or debt issuances.

(b) Represents commitments to purchase natural gas and related transportation, storage capacity and services.

(c) Represents the future estimated value at December 31, 2019 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between DPL and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.

## ACE

<table><tr><td rowspan="2"></td><td rowspan="2">Total</td><td colspan="5">Payment due within</td></tr><tr><td>2020</td><td>2021 - 2022</td><td>2023 - 2024</td><td>2025 and beyond</td><td></td></tr><tr><td>Long-term debt</td><td>$ 1,327</td><td>$ 19</td><td>$ 260</td><td>$ 150</td><td>$ 898</td><td></td></tr><tr><td>Interest payments on long-term debt  \( {}^{(a)} \)</td><td>503</td><td>57</td><td>93</td><td>87</td><td>266</td><td></td></tr><tr><td>Finance leases</td><td>8</td><td>1</td><td>2</td><td>2</td><td>3</td><td></td></tr><tr><td>Operating leases</td><td>20</td><td>5</td><td>8</td><td>5</td><td>2</td><td></td></tr><tr><td>Electric supply procurement</td><td>526</td><td>307</td><td>219</td><td>—</td><td>—</td><td></td></tr><tr><td>Other purchase obligations  \( {}^{(b)} \)</td><td>200</td><td>185</td><td>15</td><td>—</td><td>—</td><td></td></tr><tr><td>Total contractual obligations</td><td>$ 2,584</td><td>$ 574</td><td>$ 597</td><td>$ 244</td><td>$ 1,169</td><td></td></tr></table>

(a) Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2019 and do not reflect anticipated future refinancing, early redemptions or debt issuances.

(b) Represents the future estimated value at December 31, 2019 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between ACE and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.



See Note 18 — Commitments and Contingencies and Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants' other commitments potentially triggered by future events. Additionally, see below for where to find additional information regarding certain contractual obligations in the Combined Notes to the Consolidated Financial Statements:

<table><tr><td>Item</td><td>Location within Notes to the Consolidated Financial Statements</td></tr><tr><td>Finance Leases</td><td>Note 10 — Leases</td></tr><tr><td>Operating Leases</td><td>Note 10 — Leases</td></tr><tr><td>DC PLUG obligation</td><td>Note 3 — Regulatory Matters</td></tr><tr><td>ZEC Commitments</td><td>Note 3 — Regulatory Matters</td></tr><tr><td>REC Commitments</td><td>Note 3 — Regulatory Matters &amp; Note 15 — Derivative Financial Instruments</td></tr><tr><td>Long-term debt</td><td>Note 16 — Debt and Credit Agreements</td></tr><tr><td>Interest payments on long-term debt</td><td>Note 16 — Debt and Credit Agreements</td></tr><tr><td>Pension contributions</td><td>Note 14 — Retirement Benefits</td></tr><tr><td>SNF obligation</td><td>Note 18 — Commitments and Contingencies</td></tr></table>

## ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Registrants are exposed to market risks associated with adverse changes in commodity prices, counterparty credit, interest rates and equity prices. Exelon's RMC approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of risk exposures. The RMC is chaired by the chief executive officer and includes the chief risk officer, chief strategy officer, chief executive officer of Exelon Utilities, chief commercial officer, chief financial officer and chief executive officer of Constellation. The RMC reports to the Finance and Risk Committee of the Exelon Board of Directors on the scope of the risk management activities.

## Commodity Price Risk (All Registrants)

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 Exelon generates and purchases differs from the amount of energy it has contracted

to sell, Exelon is exposed to market fluctuations in commodity prices. Exelon seeks to mitigate its commodity price risk through the sale and purchase of electricity, fossil fuel and other commodities.

## Generation

Electricity available from Generation’s owned or contracted generation supply in excess of Generation’s obligations to customers, including portions of the Utility Registrants’ retail load, is sold into the wholesale markets. To reduce commodity price risk caused by market fluctuations, Generation enters into non-derivative contracts as well as derivative contracts, including swaps, futures, forwards and options, with approved counterparties to hedge anticipated exposures. Generation uses derivative instruments as economic hedges to mitigate exposure to fluctuations in commodity prices. Generation expects the settlement of the majority of its economic hedges will occur during 2020 through 2022.

In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on Generation's owned and contracted generation positions which have not been hedged. Exelon's hedging program involves the hedging of commodity price risk for Exelon's expected generation, typically on a ratable basis over three-year periods. As of December 31, 2019, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York and ERCOT reportable segments is 91%-94% and 61%-64% for 2020 and 2021, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted generation based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products and options. Equivalent sales represent all hedging products, which include economic hedges and certain non-derivative contracts, including Generation's sales to ComEd, PECO and BGE to serve their retail load.

A portion of Generation’s hedging strategy may be accomplished with fuel products based on assumed correlations between power and fuel prices, which routinely change in the market. Market price risk exposure is the risk of a change in the value of unhedged positions. The forecasted market price risk exposure for Generation’s entire economic hedge portfolio associated with a $5 reduction in the annual average around-the-clock energy price based on December 31, 2019 market conditions and hedged position would be decreases in pre-tax net income of approximately $25 million and $331 million, respectively, for 2020 and 2021. Power price sensitivities are derived by adjusting power price assumptions while keeping all other price inputs constant. Generation actively manages its portfolio to mitigate market price risk exposure for its unhedged position. Actual results could differ depending on the specific timing of, and markets affected by, price changes, as well as future changes in Generation’s portfolio. See Note 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.

## Fuel Procurement



through long-term uranium concentrate supply contracts, contracted conversion services, contracted enrichment services, or a combination thereof, and contracted fuel fabrication services. The supply markets for uranium concentrates and certain nuclear fuel services are subject to price fluctuations and availability restrictions. Supply market conditions may make Generation's 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. Approximately 60% of Generation's uranium concentrate requirements from 2020 through 2024 are supplied by three suppliers. In the event of non-performance by these or other suppliers, Generation believes that replacement uranium concentrates can be obtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements. Non-performance by these counterparties could have a material adverse impact on Eexlon's and Generation's financial statements.

## Utility Registrants

ComEd entered into 20-year floating-to-fixed renewable energy swap contracts beginning in June 2012, which are considered an economic hedge and have changes in fair value recorded to an offsetting regulatory asset or liability. ComEd has block energy contracts to procure electric supply that are executed through a competitive procurement process, which are considered derivatives and qualify for NPNS, and as a result are accounted for on an accrual basis of accounting. PECO, BGE, Pepco, DPL and ACE have contracts to procure electric supply that are executed through a competitive procurement process. BGE, Pepco, DPL and ACE have certain full requirements contracts,



which are considered derivatives and qualify for NPNS, and as a result are accounted for on an accrual basis of accounting. Other full requirements contracts are not derivatives.

PECO, BGE and DPL also have executed derivative natural gas contracts, which either qualify for NPNS or have no mark-to-market balances because the derivatives are index priced, to hedge their long-term price risk in the natural gas market. The hedging programs for natural gas procurement have no direct impact on their financial statements. PECO, BGE, Pepco, DPL and ACE do not execute derivatives for speculative or proprietary trading purposes.

For additional information on these contracts, see Note 3 — Regulatory Matters and Note 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements.

## Trading and Non-Trading Marketing Activities

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

The following table provides detail on changes in Exelon's, Generation's and ComEd's commodity mark-to-market net asset or liability balance sheet position from December 31, 2017 to December 31, 2019. 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 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on the balance sheet classification of the mark-to-market energy contract net assets (liabilities) recorded as of December 31, 2019 and 2018.

<table><tr><td></td><td>Exelon</td><td>Generation</td><td>ComEd</td></tr><tr><td>Total mark-to-market energy contract net assets (liabilities) at December 31, 2017(a)</td><td>$ 667</td><td>$ 923</td><td>$ (256)</td></tr><tr><td>Total change in fair value during 2018 of contracts recorded in result of operations</td><td>270</td><td>270</td><td>—</td></tr><tr><td>Reclassification to realized at settlement of contracts recorded in results of operations</td><td>(570)</td><td>(570)</td><td>—</td></tr><tr><td>Contracts received at acquisition date(d)</td><td>(19)</td><td>(19)</td><td>—</td></tr><tr><td>Changes in fair value—recorded through regulatory assets and liabilities(b)</td><td>8</td><td>—</td><td>7</td></tr><tr><td>Changes in allocated collateral</td><td>(110)</td><td>(109)</td><td>—</td></tr><tr><td>Net option premium received</td><td>43</td><td>43</td><td>—</td></tr><tr><td>Option premium amortization</td><td>(10)</td><td>(10)</td><td>—</td></tr><tr><td>Upfront payments and amortizations(c)</td><td>20</td><td>20</td><td>—</td></tr><tr><td>Total mark-to-market energy contract net assets (liabilities) at December 31, 2018(a)</td><td>299</td><td>548</td><td>(249)</td></tr><tr><td>Total change in fair value during 2019 of contracts recorded in result of operations</td><td>(427)</td><td>(427)</td><td>—</td></tr><tr><td>Reclassification to realized at settlement of contracts recorded in results of operations</td><td>226</td><td>226</td><td>—</td></tr><tr><td>Changes in fair value—recorded through regulatory assets and liabilities(b)</td><td>(52)</td><td>—</td><td>(52)</td></tr><tr><td>Changes in allocated collateral</td><td>572</td><td>572</td><td>—</td></tr><tr><td>Net option premium paid</td><td>29</td><td>29</td><td>—</td></tr><tr><td>Option premium amortization</td><td>(22)</td><td>(22)</td><td>—</td></tr><tr><td>Upfront payments and amortizations(c)</td><td>(58)</td><td>(58)</td><td>—</td></tr><tr><td>Total mark-to-market energy contract net assets (liabilities) at December 31, 2019(a)</td><td>$ 567</td><td>$ 868</td><td>$ (301)</td></tr></table>



(a) Amounts are shown net of collateral paid to and received from counterparties.

(b) For ComEd, the changes in fair value are recorded as a change in regulatory assets or liabilities. As of December 31, 2018 and 2019, ComEd recorded a regulatory liability of $249 million and $301 million, respectively, related to its mark-to-market derivative liabilities with Generation and unaffiliated suppliers. ComEd recorded $24 million of decreases in fair value and an increase for realized losses due to settlements of $17 million in purchased power expense associated with floating-to-fixed energy swap suppliers for the year ended December 31, 2018. ComEd recorded $78 million of decreases in fair value and an increase for realized losses due to settlements of $26 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2019.

(c) Includes derivative contracts acquired or sold by Generation through upfront payments or receipts of cash, excluding option premiums, and the associated amortizations.

(d) Includes fair value from contracts received at acquisition of the Everett Marine Terminal.

## Fair Values

The following tables present maturity and source of fair value for Exelon, Generation and ComEd mark-to-market commodity contract net assets (liabilities). The tables provide two fundamental pieces of information. First, the tables provide the source of fair value used in determining the carrying amount of the Registrants' total mark-to-market net assets (liabilities), net of allocated collateral. Second, the tables show the maturity, by year, of the Registrants' commodity contract net assets (liabilities) net of allocated collateral, giving an indication of when these mark-to-market amounts will settle and either generate or require cash. See Note 17 — 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.

## Exelon

<table><tr><td rowspan="2"></td><td colspan="9">Maturities Within</td><td rowspan="2">Total Fair Value</td></tr><tr><td>2020</td><td>2021</td><td>2022</td><td>2023</td><td>2024</td><td>2025 and Beyond</td><td></td><td></td><td></td></tr><tr><td>Normal Operations, Commodity derivative contracts \( ^{(a)(b)} \) :</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Actively quoted prices (Level 1)</td><td>$ (102)</td><td>$ (33)</td><td>$ (18)</td><td>$ 5</td><td>$ 8</td><td>$ —</td><td>$ (140)</td><td></td><td></td><td></td></tr><tr><td>Prices provided by external sources (Level 2)</td><td>161</td><td>39</td><td>(9)</td><td>—</td><td>—</td><td>—</td><td></td><td></td><td>191</td><td></td></tr><tr><td>Prices based on model or other valuation methods (Level 3) \( ^{(c)} \)</td><td>383</td><td>194</td><td>85</td><td>3</td><td>(18)</td><td></td><td>(131)</td><td></td><td>516</td><td></td></tr><tr><td>Total</td><td>$ 442</td><td>$ 200</td><td>$ 58</td><td>$ 8</td><td>$ (10)</td><td>$ (131)</td><td>$ 567</td><td></td><td></td><td></td></tr></table>

(a) Mark-to-market gains and losses on other economic hedge and trading derivative contracts that are recorded in 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 $929 million at December 31, 2019.

(c) Includes ComEd's net assets (liabilities) associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.



## Generation

<table><tr><td rowspan="2"></td><td colspan="9">Maturities Within</td><td rowspan="2">Total Fair Value</td></tr><tr><td>2020</td><td>2021</td><td>2022</td><td>2023</td><td>2024</td><td colspan="3">2025 and Beyond</td></tr><tr><td>Normal Operations, Commodity derivative contracts \( ^{(a)(b)} \) :</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Actively quoted prices (Level 1)</td><td>$ (102)</td><td>$ (33)</td><td>$ (18)</td><td>$ 5</td><td>$ 8</td><td>$ —</td><td>$ —</td><td>$ (140)</td><td></td><td></td></tr><tr><td>Prices provided by external sources (Level 2)</td><td>161</td><td>39</td><td>(9)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>191</td><td></td><td></td></tr><tr><td>Prices based on model or other valuation methods (Level 3)</td><td>415</td><td>223</td><td>113</td><td>30</td><td>10</td><td>26</td><td>817</td><td></td><td></td><td></td></tr><tr><td>Total</td><td>$ 474</td><td>$ 229</td><td>$ 86</td><td>$ 35</td><td>$ 18</td><td>$ 26</td><td>$ 868</td><td></td><td></td><td></td></tr></table>

(a) 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 $929 million at December 31, 2019.

## ComEd

<table><tr><td rowspan="2">Commodity derivative contracts (a)</td><td colspan="8">Maturities Within</td><td rowspan="2">Fair Value</td></tr><tr><td>2020</td><td>2021</td><td>2022</td><td>2023</td><td>2024</td><td>2025 and Beyond</td><td></td><td></td></tr><tr><td>Prices based on model or other valuation methods (Level 3)(a)</td><td>$ (32)</td><td>$ (29)</td><td>$ (28)</td><td>$ (27)</td><td>$ (28)</td><td>$ (157)</td><td>$ (301)</td><td></td><td></td></tr></table>

(a) Represents ComEd's net liabilities associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.



## Credit Risk (All Registrants)

The Registrants 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 15—Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for a detailed discussion of credit risk.

## Generation

The following tables provide information on Generation's credit exposure for all derivative instruments, normal purchases and normal sales agreements, and payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of December 31, 2019. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties and an indication of the duration of a company's credit risk by credit rating of the counterparties. The figures in the table below exclude credit risk exposure from individual retail customers, uranium procurement contracts, and exposure through RTOs, ISOs and commodity exchanges, which are discussed below.

<table><tr><td>Rating as of December 31, 2019</td><td colspan="2">Total Exposure Before Credit Collateral</td><td>Credit Collateral (a)</td><td>Net Exposure</td><td>Number of Counterparties Greater than 10% of Net Exposure</td><td>Net Exposure of Counterparties Greater than 10% of Net Exposure</td></tr><tr><td>Investment grade</td><td>$ 877</td><td>$ 20</td><td>$ 857</td><td>—</td><td>$ —</td><td>—</td></tr><tr><td>Non-investment grade</td><td>79</td><td>63</td><td>16</td><td>—</td><td>—</td><td>—</td></tr><tr><td>No external ratings</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Internally rated—investment grade</td><td>218</td><td>—</td><td>218</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Internally rated—non-investment grade</td><td>139</td><td>23</td><td>116</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Total</td><td>$ 1,313</td><td>$ 106</td><td>$ 1,207</td><td>—</td><td>$ —</td><td>—</td></tr></table>

Maturity of Credit Risk Exposure

<table><tr><td rowspan="2">Rating as of December 31, 2019</td><td colspan="5">Maturity of Credit Risk Exposure</td></tr><tr><td>Less than 2 Years</td><td>2-5 Years</td><td>Exposure Greater than 5 Years</td><td>Total Exposure Before Credit Collateral</td><td></td></tr><tr><td>Investment grade</td><td>$ 834</td><td>$ 40</td><td>$ 3</td><td>$ 877</td><td></td></tr><tr><td>Non-investment grade</td><td>78</td><td>1</td><td>—</td><td>79</td><td></td></tr><tr><td>No external ratings</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Internally rated—investment grade</td><td>162</td><td>30</td><td>26</td><td>218</td><td></td></tr><tr><td>Internally rated—non-investment grade</td><td>123</td><td>10</td><td>6</td><td>139</td><td></td></tr><tr><td>Total</td><td>$ 1,197</td><td>$ 81</td><td>$ 35</td><td>$ 1,313</td><td></td></tr><tr><td>Net Credit Exposure by Type of Counterparty</td><td></td><td></td><td></td><td>As of December 31, 2019</td><td></td></tr><tr><td>Financial institutions</td><td></td><td></td><td>$</td><td>9</td><td></td></tr><tr><td>Investor-owned utilities, marketers, power producers</td><td></td><td></td><td></td><td>930</td><td></td></tr><tr><td>Energy cooperatives and municipalities</td><td></td><td></td><td></td><td>235</td><td></td></tr><tr><td>Other</td><td></td><td></td><td></td><td>33</td><td></td></tr><tr><td>Total</td><td></td><td></td><td>$</td><td>1,207</td><td></td></tr></table>

(a) As of December 31, 2019, credit collateral held from counterparties where Generation had credit exposure included $25 million of cash and $81 million of letters of credit.



## The Utility Registrants

Credit risk for the Utility Registrants is governed by credit and collection policies, which are aligned with state regulatory requirements. The Utility Registrants are currently obligated to provide service to all electric customers within their franchised territories. The Utility Registrants record a provision for uncollectible accounts, based upon historical experience, to provide for the potential loss from nonpayment by these customers. The Utility Registrants will monitor nonpayment from customers and will make any necessary adjustments to the provision for uncollectible accounts. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for the allowance for uncollectible accounts policy. The Utility Registrants did not have any customers representing over 10% of their revenues as of December 31, 2019. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

As of December 31, 2019, ComEd, PECO, BGE, Pepco, DPL and ACE's net credit exposure to suppliers was immaterial. See Note 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements.

## Credit-Risk-Related Contingent Features (All Registrants)

## Generation

As part of the normal course of business, Generation routinely enters into physical or financial contracts for the sale and purchase of electricity, natural gas and other commodities. In accordance with the contracts and applicable law, if Generation is 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 Generation's 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 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding collateral requirements. See Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding the letters of credit supporting the cash collateral.

Generation transacts 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 Exelon's and Generation's financial statements. As market prices rise above or fall below contracted price levels, Generation is required to post collateral with purchasers; as market prices fall below contracted price levels, counterparties are required to post collateral with Generation. To post collateral, Generation depends on access to bank credit facilities, which serve as liquidity sources to fund collateral requirements. See ITEM 7. Liquidity and Capital Resources — Credit Matters — Exelon Credit Facilities for additional information.

## The Utility Registrants

As of December 31, 2019, the Utility Registrants were not required to post collateral under their energy and/or natural gas procurement contracts. See Note 3 — Regulatory Matters and Note 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.

## RTOs and ISOs (All Registrants)

All Registrants participate in all, or some, of the established, wholesale spot energy markets that are administered by PJM, ISO-NE, NYISO, CAISO, MISO, SPP, AESO, OIESO and ERCOT. ERCOT is not subject to regulation by FERC but performs a similar function in Texas to that performed by RTOs in markets regulated by FERC. In these areas, power is traded through bilateral agreements between buyers and sellers and on the spot energy markets that are administered by the RTOs or ISOs, as applicable. In areas where there is no spot energy market, electricity is purchased and sold solely through bilateral agreements. For sales into the spot markets 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 on spot energy market transactions be shared by the remaining participants.



Non-performance or non-payment by a major counterparty could result in a material adverse impact on the Registrants' financial statements.

## Exchange Traded Transactions (Exelon, Generation, PHI and DPL)

Generation enters into commodity transactions on NYMEX, ICE, NASDAQ, NGX and the Nodal exchange ("the Exchanges"). DPL enters into commodity transactions on ICE. 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 (Exelon and Generation)

Exelon and Generation use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. Exelon and Generation may also utilize interest rate swaps to manage their 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 result in approximately a $5 million decrease in Exelon pre-tax income for the year ended December 31, 2019. To manage foreign exchange rate exposure associated with international energy purchases in currencies other than U.S. dollars, Generation utilizes foreign currency derivatives, which are typically designated as economic hedges. See Note 15—Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.

## Equity Price Risk (Exelon and Generation)

Exelon and Generation maintain trust funds, as required by the NRC, to fund certain costs of decommissioning its nuclear plants. As of December 31, 2019, Generation's NDT funds are reflected at fair value in its 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 Generation 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. Generation actively monitors the investment performance of the trust funds and periodically reviews asset allocation in accordance with Generation's NDT fund investment policy. A hypothetical 10% increase in interest rates and decrease in equity prices would result in a $610 million reduction in the fair value of the trust assets. This calculation holds all other variables constant and assumes only the discussed changes in interest rates and equity prices. See Liquidity and Capital Resources section of ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for additional information of equity price risk as a result of the current capital and credit market conditions.



## Generation

## General

Generation’s integrated business consists of the generation, physical delivery and marketing of power across multiple geographical regions through its customer-facing business, Constellation, which sells electricity and natural gas to both wholesale and retail customers. Generation also sells renewable energy and other energy-related products and services. Generation has five reportable segments consisting of the Mid-Atlantic, Midwest, New York, ERCOT and Other Power Regions. These segments are discussed in further detail in ITEM 1. BUSINESS — Exelon Generation Company, LLC of this Form 10-K.

## Executive Overview

A discussion of items pertinent to Generation’s executive overview is set forth under ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Exelon Corporation — Executive Overview of this Form 10-K.

## Results of Operations

## Year Ended December 31, 2019 Compared to Year Ended December 31, 2018

A discussion of Generation’s results of operations for 2019 compared to 2018 is set forth under Results of Operations—Generation in EXELON CORPORATION — Results of Operations of this Form 10-K.

## Liquidity and Capital Resources

Generation’s business is capital intensive and requires considerable capital resources. Generation’s capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of long-term debt, commercial paper, participation in the intercompany money pool or capital contributions from Exelon. Generation’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. If these conditions deteriorate to where Generation no longer has access to the capital markets at reasonable terms, Generation has credit facilities in the aggregate of $5.3 billion that currently support its commercial paper program and issuances of letters of credit.

See EXELON CORPORATION — Liquidity and Capital Resources and Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements of this Form 10-K for additional information.

Capital resources are used primarily to fund Generation’s capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and other postretirement benefit obligations and invest in new and existing ventures. Generation spends a significant amount of cash on capital improvements and construction projects that have a long-term return on investment.

## Cash Flows from Operating Activities

A discussion of items pertinent to Generation’s cash flows from operating activities is set forth under Cash Flows from Operating Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

## Cash Flows from Investing Activities

A discussion of items pertinent to Generation’s cash flows from investing activities is set forth under Cash Flows from Investing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

## Cash Flows from Financing Activities



A discussion of items pertinent to Generation’s cash flows from financing activities is set forth under Cash Flows from Financing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

## Credit Matters

A discussion of credit matters pertinent to Generation is set forth under Credit Matters in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

## Contractual Obligations and Off-Balance Sheet Arrangements

A discussion of Generation’s contractual obligations, commercial commitments and off-balance sheet arrangements is set forth under Contractual Obligations and Off-Balance Sheet Arrangements in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

## Critical Accounting Policies and Estimates

See All Registrants — Critical Accounting Policies and Estimates above for a discussion of Generation’s critical accounting policies and estimates.

## New Accounting Pronouncements

See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for information regarding new accounting pronouncements.

## ITEM 7A.

## QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

## Generation

Generation is exposed to market risks associated with credit, interest rates and equity price. These risks are described above under Quantitative and Qualitative Disclosures about Market Risk — Exelon.



## ITEM 7.

## MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

## ComEd

## General

ComEd operates in a single business segment and its operations consist of the purchase and regulated retail sale of electricity and the provision of distribution and transmission services to retail customers in northern Illinois, including the City of Chicago. This segment is discussed in further detail in ITEM 1. BUSINESS—ComEd of this Form 10-K.

## Executive Overview

A discussion of items pertinent to ComEd's executive overview is set forth under EXELON CORPORATION—Executive Overview of this Form 10-K.

## Results of Operations

## Year Ended December 31, 2019 Compared to Year Ended December 31, 2018

A discussion of ComEd's results of operations for 2019 compared to 2018 is set forth under Results of Operations—ComEd in EXELON CORPORATION — Results of Operations of this Form 10-K.

## Liquidity and Capital Resources

ComEd's business is capital intensive and requires considerable capital resources. ComEd's capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of long-term debt, commercial paper or credit facility borrowings. ComEd's access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. At December 31, 2019, ComEd had access to a revolving credit facility with aggregate bank commitments of $1 billion.

See EXELON CORPORATION — Liquidity and Capital Resources and Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements of this Form 10-K for additional information.

Capital resources are used primarily to fund ComEd's capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and other postretirement benefit obligations and invest in new and existing ventures. ComEd spends a significant amount of cash on capital improvements and construction projects that have a long-term return on investment. Additionally, ComEd operates in rate-regulated environments in which the amount of new investment recovery may be limited and where such recovery takes place over an extended period of time.

## Cash Flows from Operating Activities

A discussion of items pertinent to ComEd's cash flows from operating activities is set forth under Cash Flows from Operating Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

## Cash Flows from Investing Activities

A discussion of items pertinent to ComEd's cash flows from investing activities is set forth under Cash Flows from Investing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

## Cash Flows from Financing Activities

A discussion of items pertinent to ComEd's cash flows from financing activities is set forth under Cash Flows from Financing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.



## Credit Matters

A discussion of credit matters pertinent to ComEd is set forth under Credit Matters in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

## Contractual Obligations and Off-Balance Sheet Arrangements

A discussion of ComEd's contractual obligations, commercial commitments and off-balance sheet arrangements is set forth under Contractual Obligations and Off-Balance Sheet Arrangements in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

## Critical Accounting Policies and Estimates

See All Registrants — Critical Accounting Policies and Estimates above for a discussion of ComEd's critical accounting policies and estimates.

## New Accounting Pronouncements

See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for information regarding new accounting pronouncements.

## ITEM 7A.

## QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

## ComEd

ComEd is exposed to market risks associated with commodity price and credit. These risks are described above under Quantitative and Qualitative Disclosures about Market Risk—Exelon.



## PECO

## General

PECO operates in a single business segment and its operations consist of the purchase and regulated retail sale of electricity and the provision of distribution and transmission services in southeastern Pennsylvania including the City of Philadelphia, and the purchase and regulated retail sale of natural gas and the provision of distribution service in Pennsylvania in the counties surrounding the City of Philadelphia. This segment is discussed in further detail in ITEM 1. BUSINESS—PECO of this Form 10-K.

## Executive Overview

A discussion of items pertinent to PECO's executive overview is set forth under EXELON CORPORATION—Executive Overview of this Form 10-K.

## Results of Operations

Year Ended December 31, 2019 Compared to Year Ended December 31, 2018

A discussion of PECO’s results of operations for 2019 compared to 2018 is set forth under Results of Operations—PECO in EXELON CORPORATION — Results of Operations of this Form 10-K.

## Liquidity and Capital Resources

PECO’s business is capital intensive and requires considerable capital resources. PECO’s capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of long-term debt, commercial paper or participation in the intercompany money pool. PECO’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. If these conditions deteriorate to where PECO no longer has access to the capital markets at reasonable terms, PECO has access to a revolving credit facility. At December 31, 2019, PECO had access to a revolving credit facility with aggregate bank commitments of $600 million.

See EXELON CORPORATION — Liquidity and Capital Resources and Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements of this Form 10-K for additional information.

Capital resources are used primarily to fund PECO's capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and other postretirement benefit obligations and invest in new and existing ventures. PECO spends a significant amount of cash on capital improvements and construction projects that have a long-term return on investment. Additionally, PECO operates in a rate-regulated environment in which the amount of new investment recovery may be limited and where such recovery takes place over an extended period of time.

## Cash Flows from Operating Activities

A discussion of items pertinent to PECO’s cash flows from operating activities is set forth under Cash Flows from Operating Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

## Cash Flows from Investing Activities

A discussion of items pertinent to PECO’s cash flows from investing activities is set forth under Cash Flows from Investing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

## Cash Flows from Financing Activities

A discussion of items pertinent to PECO’s cash flows from financing activities is set forth under Cash Flows from Financing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.



## Credit Matters

A discussion of credit matters pertinent to PECO is set forth under Credit Matters in “EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

## Contractual Obligations and Off-Balance Sheet Arrangements

A discussion of PECO's contractual obligations, commercial commitments and off-balance sheet arrangements is set forth under Contractual Obligations and Off-Balance Sheet Arrangements in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

## Critical Accounting Policies and Estimates

See All Registrants — Critical Accounting Policies and Estimates above for a discussion of PECO's critical accounting policies and estimates.

## New Accounting Pronouncements

See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for information regarding new accounting pronouncements.

## ITEM 7A.

## QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

## PECO

PECO is exposed to market risks associated with credit and interest rates. These risks are described above under Quantitative and Qualitative Disclosures about Market Risk—Exelon.



## BGE

## General

BGE operates in a single business segment and its operations consist of the purchase and regulated retail sale of electricity and the provision of distribution and transmission services in central Maryland, including the City of Baltimore, and the purchase and regulated retail sale of natural gas and the provision of distribution service in central Maryland, including the City of Baltimore. This segment is discussed in further detail in ITEM 1. BUSINESS—BGE of this Form 10-K.

## Executive Overview

A discussion of items pertinent to BGE’s executive overview is set forth under EXELON CORPORATION — Executive Overview of this Form 10-K.

## Results of Operations

## Year Ended December 31, 2019 Compared to Year Ended December 31, 2018

A discussion of BGE’s results of operations for 2019 compared to 2018 is set forth under Results of Operations—BGE in EXELON CORPORATION — Results of Operations of this Form 10-K.

## Liquidity and Capital Resources

BGE’s business is capital intensive and requires considerable capital resources. BGE’s capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of long-term debt or commercial paper. BGE’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. If these conditions deteriorate to where BGE no longer has access to the capital markets at reasonable terms, BGE has access to a revolving credit facility. At December 31, 2019, BGE had access to a revolving credit facility with aggregate bank commitments of $600 million.

See EXELON CORPORATION — Liquidity and Capital Resources and Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements of this Form 10-K for additional information.

Capital resources are used primarily to fund BGE’s capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and other postretirement benefit obligations and invest in new and existing ventures. BGE spends a significant amount of cash on capital improvements and construction projects that have a long-term return on investment. Additionally, BGE operates in a rate-regulated environment in which the amount of new investment recovery may be limited and where such recovery takes place over an extended period of time.

## Cash Flows from Operating Activities

A discussion of items pertinent to BGE’s cash flows from operating activities is set forth under Cash Flows from Operating Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

## Cash Flows from Investing Activities

A discussion of items pertinent to BGE’s cash flows from investing activities is set forth under “Cash Flows from Investing Activities” in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

## Cash Flows from Financing Activities

A discussion of items pertinent to BGE’s cash flows from financing activities is set forth under “Cash Flows from Financing Activities” in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.



## Credit Matters

A discussion of credit matters pertinent to BGE is set forth under Credit Matters in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

## Contractual Obligations and Off-Balance Sheet Arrangements

A discussion of BGE’s contractual obligations, commercial commitments and off-balance sheet arrangements is set forth under Contractual Obligations and Off-Balance Sheet Arrangements in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

## Critical Accounting Policies and Estimates

See All Registrants — Critical Accounting Policies and Estimates above for a discussion of BGE’s critical accounting policies and estimates.

## New Accounting Pronouncements

See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for information regarding new accounting pronouncements.

## ITEM 7A.

## QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

## BGE

BGE is exposed to market risks associated with credit and interest rates. These risks are described above under Quantitative and Qualitative Disclosures about Market Risk—Exelon.



## PHI

## General

PHI has three reportable segments Pepco, DPL, and ACE. Its operations consist of the purchase and regulated retail sale of electricity and the provision of distribution and transmission services, and to a lesser extent, the purchase and regulated retail sale and supply of natural gas in Delaware. This segment is discussed in further detail in ITEM 1. BUSINESS — PHI of this Form 10-K.

## Executive Overview

A discussion of items pertinent to PHI's executive overview is set forth under EXELON CORPORATION — Executive Overview of this Form 10-K.

## Results of Operations

## Year Ended December 31, 2019 Compared to Year Ended December 31, 2018

A discussion of PHI's results of operations for 2019 compared to 2018 is set forth under Results of Operations—PHI in EXELON CORPORATION — Results of Operations of this Form 10-K.

## Liquidity and Capital Resources

PHI's business is capital intensive and requires considerable capital resources. PHI's capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of long-term debt or commercial paper, borrowings from the Exelon money pool or capital contributions from Exelon. PHI's access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general.

See EXELON CORPORATION — Liquidity and Capital Resources and Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements of this Form 10-K for additional information.

Capital resources are used primarily to fund PHI's capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and other postretirement benefit obligations and invest in new and existing ventures. PHI spends a significant amount of cash on capital improvements and construction projects that have a long-term return on investment.

## Cash Flows from Operating Activities

A discussion of items pertinent to PHI's cash flows from operating activities is set forth under Cash Flows from Operating Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

## Cash Flows from Investing Activities

A discussion of items pertinent to PHI's cash flows from investing activities is set forth under "Cash Flows from Investing Activities" in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

## Cash Flows from Financing Activities

A discussion of items pertinent to PHI's cash flows from financing activities is set forth under "Cash Flows from Financing Activities" in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.



## Credit Matters

A discussion of credit matters pertinent to PHI is set forth under Credit Matters in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

## Contractual Obligations and Off-Balance Sheet Arrangements

A discussion of PHI's contractual obligations, commercial commitments and off-balance sheet arrangements is set forth under Contractual Obligations and Off-Balance Sheet Arrangements in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

## Critical Accounting Policies and Estimates

See All Registrants — Critical Accounting Policies and Estimates above for a discussion of PHI's critical accounting policies and estimates.

## New Accounting Pronouncements

See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for information regarding new accounting pronouncements.

## ITEM 7A.

## QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

## PHI

PHI is exposed to market risks associated with credit and interest rates. These risks are described above under Quantitative and Qualitative Disclosures about Market Risk — Exelon.



## Pepco

## General

Pepco operates in a single business segment and its operations consist of the purchase and regulated retail sale of electricity and the provision of distribution and transmission services to retail customers in District of Columbia and major portions of Prince George's County and Montgomery County in Maryland. This segment is discussed in further detail in ITEM 1. BUSINESS — Pepco of this Form 10-K.

## Executive Overview

A discussion of items pertinent to Pepco’s executive overview is set forth under EXELON CORPORATION — Executive Overview of this Form 10-K.

## Results of Operations

Year Ended December 31, 2019 Compared to Year Ended December 31, 2018

A discussion of Pepco’s results of operations for 2019 compared to 2018 is set forth under Results of Operations—Pepco in EXELON CORPORATION — Results of Operations of this Form 10-K.

## Liquidity and Capital Resources

Pepco's business is capital intensive and requires considerable capital resources. Pepco's capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of long-term debt, commercial paper or credit facility borrowings. Pepco's access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. At December 31, 2019, Pepco had access to a revolving credit facility with aggregate bank commitments of $300 million.

See EXELON CORPORATION — Liquidity and Capital Resources and Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements of this Form 10-K for additional information.

Capital resources are used primarily to fund Pepco's capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and other postretirement benefit obligations and invest in new and existing ventures. Pepco spends a significant amount of cash on capital improvements and construction projects that have a long-term return on investment. Additionally, Pepco operates in rate-regulated environments in which the amount of new investment recovery may be limited and where such recovery takes place over an extended period of time.

## Cash Flows from Operating Activities

A discussion of items pertinent to Pepco’s cash flows from operating activities is set forth under Cash Flows from Operating Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

## Cash Flows from Investing Activities

A discussion of items pertinent to Pepco’s cash flows from investing activities is set forth under Cash Flows from Investing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

## Cash Flows from Financing Activities

A discussion of items pertinent to Pepco’s cash flows from financing activities is set forth under Cash Flows from Financing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.



## Credit Matters

A discussion of credit matters pertinent to Pepco is set forth under Credit Matters in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

## Contractual Obligations and Off-Balance Sheet Arrangements

A discussion of Pepco's contractual obligations, commercial commitments and off-balance sheet arrangements is set forth under Contractual Obligations and Off-Balance Sheet Arrangements in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

## Critical Accounting Policies and Estimates

See All Registrants — Critical Accounting Policies and Estimates above for a discussion of Pepco's critical accounting policies and estimates.

## New Accounting Pronouncements

See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for information regarding new accounting pronouncements.

## ITEM 7A.

## QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

## Pepco

Pepco is exposed to market risks associated with credit and interest rates. These risks are described above under Quantitative and Qualitative Disclosures about Market Risk—Exelon.



## DPL

## General

DPL operates in a single business segment and its operations consist of the purchase and regulated retail sale of electricity and the provision of distribution and transmission services in portions of Maryland and Delaware, and the purchase and regulated retail sale and supply of natural gas in New Castle County, Delaware. This segment is discussed in further detail in ITEM 1. BUSINESS — DPL of this Form 10-K.

## Executive Overview

A discussion of items pertinent to DPL’s executive overview is set forth under EXELON CORPORATION — Executive Overview of this Form 10-K.

## Results of Operations

Year Ended December 31, 2019 Compared to Year Ended December 31, 2018

A discussion of DPL’s results of operations for 2019 compared to 2018 is set forth under Results of Operations—DPL in EXELON CORPORATION — Results of Operations of this Form 10-K.

## Liquidity and Capital Resources

DPL's business is capital intensive and requires considerable capital resources. DPL's capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of long-term debt or commercial paper. DPL's access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. If these conditions deteriorate to where DPL no longer has access to the capital markets at reasonable terms, DPL has access to a revolving credit facility. At December 31, 2019, DPL had access to a revolving credit facility with aggregate bank commitments of $300 million.

See EXELON CORPORATION — Liquidity and Capital Resources and Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements of this Form 10-K for additional information.

Capital resources are used primarily to fund DPL’s capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and other postretirement benefit obligations and invest in new and existing ventures. DPL spends a significant amount of cash on capital improvements and construction projects that have a long-term return on investment. Additionally, DPL operates in a rate-regulated environment in which the amount of new investment recovery may be limited and where such recovery takes place over an extended period of time.

## Cash Flows from Operating Activities

A discussion of items pertinent to DPL’s cash flows from operating activities is set forth under Cash Flows from Operating Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

## Cash Flows from Investing Activities

A discussion of items pertinent to DPL’s cash flows from investing activities is set forth under Cash Flows from Investing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

## Cash Flows from Financing Activities

A discussion of items pertinent to DPL’s cash flows from financing activities is set forth under Cash Flows from Financing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.



## Credit Matters

A discussion of credit matters pertinent to DPL is set forth under Credit Matters in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

## Contractual Obligations and Off-Balance Sheet Arrangements

A discussion of DPL's contractual obligations, commercial commitments and off-balance sheet arrangements is set forth under Contractual Obligations and Off-Balance Sheet Arrangements in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

## Critical Accounting Policies and Estimates

See All Registrants — Critical Accounting Policies and Estimates above for a discussion of DPL's critical accounting policies and estimates.

## New Accounting Pronouncements

See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for information regarding new accounting pronouncements.

## ITEM 7A.

## QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

## DPL

DPL is exposed to market risks associated with credit and interest rates. These risks are described above under Quantitative and Qualitative Disclosures about Market Risk—Exelon.



## ACE

## General

ACE operates in a single business segment and its operations consist of the purchase and regulated retail sale of electricity and the provision of distribution and transmission services to retail customers in portions of southern New Jersey. This segment is discussed in further detail in ITEM 1. BUSINESS — ACE of this Form 10-K.

## Executive Overview

A discussion of items pertinent to ACE’s executive overview is set forth under EXELON CORPORATION — Executive Overview of this Form 10-K.

## Results of Operations

Year Ended December 31, 2019 Compared to Year Ended December 31, 2018

A discussion of ACE’s results of operations for 2019 compared to 2018 is set forth under Results of Operations—ACE in EXELON CORPORATION — Results of Operations of this Form 10-K.

## Liquidity and Capital Resources

ACE’s business is capital intensive and requires considerable capital resources. ACE’s capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of long-term debt, commercial paper or credit facility borrowings. ACE’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. At December 31, 2019, ACE had access to a revolving credit facility with aggregate bank commitments of $300 million.

See EXELON CORPORATION — Liquidity and Capital Resources and Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements of this Form 10-K for additional information.

Capital resources are used primarily to fund ACE’s capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and other postretirement benefit obligations and invest in new and existing ventures. ACE spends a significant amount of cash on capital improvements and construction projects that have a long-term return on investment. Additionally, ACE operates in rate-regulated environments in which the amount of new investment recovery may be limited and where such recovery takes place over an extended period of time.

## Cash Flows from Operating Activities

A discussion of items pertinent to ACE’s cash flows from operating activities is set forth under Cash Flows from Operating Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

## Cash Flows from Investing Activities

A discussion of items pertinent to ACE’s cash flows from investing activities is set forth under Cash Flows from Investing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

## Cash Flows from Financing Activities

A discussion of items pertinent to ACE’s cash flows from financing activities is set forth under Cash Flows from Financing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.



## Credit Matters

A discussion of credit matters pertinent to ACE is set forth under Credit Matters in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

## Contractual Obligations and Off-Balance Sheet Arrangements

A discussion of ACE’s contractual obligations, commercial commitments and off-balance sheet arrangements is set forth under Contractual Obligations and Off-Balance Sheet Arrangements in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.

## Critical Accounting Policies and Estimates

See All Registrants — Critical Accounting Policies and Estimates above for a discussion of ACE’s critical accounting policies and estimates.

## New Accounting Pronouncements

See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for information regarding new accounting pronouncements.

## ITEM 7A.

## QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

## ACE

ACE is exposed to market risks associated with credit and interest rates. These risks are described above under Quantitative and Qualitative Disclosures about Market Risk—Exelon.



## ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

## Management’s Report on Internal Control Over Financial Reporting

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

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

Exelon’s management conducted an assessment of the effectiveness of Exelon’s internal control over financial reporting as of December 31, 2019. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, Exelon’s management concluded that, as of December 31, 2019, Exelon’s internal control over financial reporting was effective.

The effectiveness of Exelon’s internal control over financial reporting as of December 31, 2019, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.

February 11, 2020



## Management’s Report on Internal Control Over Financial Reporting

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

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

Generation’s management conducted an assessment of the effectiveness of Generation’s internal control over financial reporting as of December 31, 2019. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, Generation’s management concluded that, as of December 31, 2019, Generation’s internal control over financial reporting was effective.

February 11, 2020



## Management’s Report on Internal Control Over Financial Reporting

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

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

ComEd’s management conducted an assessment of the effectiveness of ComEd’s internal control over financial reporting as of December 31, 2019. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, ComEd’s management concluded that, as of December 31, 2019, ComEd’s internal control over financial reporting was effective.

February 11, 2020



## Management’s Report on Internal Control Over Financial Reporting

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

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

PECO's management conducted an assessment of the effectiveness of PECO's internal control over financial reporting as of December 31, 2019. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, PECO's management concluded that, as of December 31, 2019, PECO's internal control over financial reporting was effective.

February 11, 2020



## Management’s Report on Internal Control Over Financial Reporting

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

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

BGE’s management conducted an assessment of the effectiveness of BGE’s internal control over financial reporting as of December 31, 2019. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, BGE’s management concluded that, as of December 31, 2019, BGE’s internal control over financial reporting was effective.

February 11, 2020



## Management’s Report on Internal Control Over Financial Reporting

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

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

PHI's management conducted an assessment of the effectiveness of PHI's internal control over financial reporting as of December 31, 2019. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, PHI's management concluded that, as of December 31, 2019, PHI's internal control over financial reporting was effective.

February 11, 2020



## Management’s Report on Internal Control Over Financial Reporting

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

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

Pepco’s management conducted an assessment of the effectiveness of Pepco’s internal control over financial reporting as of December 31, 2019. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, Pepco’s management concluded that, as of December 31, 2019, Pepco’s internal control over financial reporting was effective.

February 11, 2020



## Management’s Report on Internal Control Over Financial Reporting

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

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

DPL’s management conducted an assessment of the effectiveness of DPL’s internal control over financial reporting as of December 31, 2019. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, DPL’s management concluded that, as of December 31, 2019, DPL’s internal control over financial reporting was effective.

February 11, 2020



## Management’s Report on Internal Control Over Financial Reporting

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

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

ACE’s management conducted an assessment of the effectiveness of ACE’s internal control over financial reporting as of December 31, 2019. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, ACE’s management concluded that, as of December 31, 2019, ACE’s internal control over financial reporting was effective.

February 11, 2020



# Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of Exelon Corporation

## Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(1)(i), and the financial statement schedules listed in the index appearing under Item 15(a)(1)(ii), of Exelon Corporation and its subsidiaries (the "Company") (collectively referred to as the "consolidated financial statements"). We also have audited the Company's internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.

## Change in Accounting Principle

As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for leases in 2019.

## Basis for Opinions

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

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

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

## Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail,



accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

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

## Critical Audit Matters

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

## Annual Nuclear Decommissioning Asset Retirement Obligations (ARO) Assessment

As described in Notes 1 and 9 to the consolidated financial statements, Exelon Generation has a legal obligation to decommission its nuclear generation stations following the expiration of their operating licenses. To estimate its decommissioning obligation related to its nuclear generating stations for financial accounting and reporting purposes, management uses a probability-weighted cash flow model, which on a unit-by-unit basis, considers multiple scenarios that include significant estimates and assumptions such as decommissioning cost studies, cost escalation rates, probabilistic cash flow models and discount rates. Management updates its ARO annually, unless circumstances warrant more frequent updates, based on its review of updated cost studies and its annual evaluation of cost escalation factors and probabilities assigned to various scenarios. As of December 31, 2019, the nuclear decommissioning asset retirement obligation was approximately $10.5 billion.

The principal considerations for our determination that performing procedures relating to Exelon Generation’s annual ARO assessment is a critical audit matter are there was a significant amount of judgment by management when estimating its decommissioning obligation. This in turn led to significant auditor judgment, subjectivity, and effort in performing procedures to evaluate management’s cash flow model and significant assumptions, including the decommissioning cost studies. In addition, the audit effort involved the use of professionals with specialized skill and knowledge to assist in evaluating the audit evidence obtained from these procedures.

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

## Impairment Assessment of Long-Lived Generation Assets

As described in Notes 1 and 11 to the consolidated financial statements, Exelon Generation evaluates the carrying value of long-lived assets or asset groups for recoverability whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators of impairment may include a deteriorating business climate, including, but not limited to, declines in energy prices, condition of the asset, or plans to dispose of a long-lived asset significantly before the end of its useful life. Management determines if long-lived assets and asset groups are impaired by comparing the undiscounted expected future



cash flows to the carrying value. When the undiscounted cash flow analysis indicates a long-lived asset or asset group is not recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. The undiscounted expected future cash flows include significant unobservable inputs including revenue and generation forecasts and projected capital and maintenance expenditures. As of December 31, 2019, the total carrying value of long-lived generation assets subject to this evaluation was approximately $24.2 billion.

The principal considerations for our determination that performing procedures relating to Exelon Generation’s impairment assessment of long-lived generation assets is a critical audit matter are there was a significant amount of judgment by management in assessing the recoverability of these assets or asset groups. This in turn led to significant auditor judgment, subjectivity and effort in performing procedures to evaluate the audit evidence related to the reasonableness of management’s significant assumptions used in management’s estimates, including revenue and generation forecasts. In addition, the audit effort involved the use of professionals with specialized skills and knowledge to assist in evaluating the audit evidence obtained from these procedures.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s development of the inputs, assumptions, and model used to estimate the recoverability of Exelon Generation’s long-lived generation assets or asset groups. These procedures also included, among others, testing management’s process for developing undiscounted expected future cash flows for long-lived generation assets by evaluating the appropriateness of the future cash flow model, testing the completeness and accuracy of the data used by management, and evaluating the reasonableness of management’s significant assumptions, including revenue and generation forecasts. Professionals with specialized skill and knowledge were used to assist in evaluating the reasonableness of revenue forecasts.

## Level 3 Derivatives Significant Assumptions

As described in Notes 1, 15 and 17 to the consolidated financial statements, Exelon Generation has derivative instruments that include both observable and unobservable inputs. When valuing Level 3 derivatives, management utilizes various inputs and assumptions including forward commodity prices, commodity price volatility, contractual volumes, delivery location, interest rates, credit quality of counterparties and credit enhancements. Those derivatives with significant unobservable inputs are classified as Level 3. As of December 31, 2019, the Company had a level 3 fair value derivative asset position of $957 million and a level 3 fair value derivative liability position of $140 million.

The principal considerations for our determination that performing procedures relating to the significant assumptions used to value Exelon Generation’s Level 3 derivatives is a critical audit matter are there was a significant amount of judgment by management in determining the inputs and assumptions used to estimate the fair value of the Level 3 derivatives. This in turn led to significant auditor judgment, subjectivity, and effort in performing procedures to evaluate audit evidence related to the reasonableness of management’s significant assumptions used in management’s estimates, including forward commodity prices. In addition, the audit effort involved the use of professionals with specialized skill and knowledge to assist in evaluating the audit evidence obtained from these procedures.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s development of the inputs, assumptions, and model used to estimate the fair value of Level 3 derivatives. These procedures also included, among others, testing management’s process for valuing the Level 3 derivatives by evaluating the appropriateness of management’s model, testing the completeness and accuracy of data used by management, and evaluating the reasonableness of management’s significant assumptions, including forward commodity prices. Professionals with specialized skill and knowledge were used to assist in evaluating the reasonableness of forward commodity prices.

## Accounting for the Effects of Rate Regulation

As described in Notes 1 and 3 to the consolidated financial statements, the Company applies the authoritative guidance for accounting for certain types of regulation, which requires management to record in their consolidated financial statements the effects of cost-based rate regulation for entities with regulated operations



that meet the following criteria, (i) rates are established or approved by a third-party regulator; (ii) rates are designed to recover the entity's cost of providing services or products; and (iii) there is a reasonable expectation that rates designed to recover costs can be charged to and collected from customers. The Company accounts for its regulated operations in accordance with regulatory and legislative guidance from the regulatory authorities having jurisdiction under state public utility laws and the FERC under various Federal laws. Upon updates in material regulatory and legislative proceedings, where applicable, management will record new regulatory assets or liabilities and will assess whether it is probable that its currently recorded regulatory assets and liabilities will be recovered and settled, respectively, in future rates. As of December 31, 2019, there were $9.5 billion of regulatory assets and $10.4 billion of regulatory liabilities.

The principal considerations for our determination that performing procedures relating to accounting for the effects of rate regulation is a critical audit matter are there was a significant amount of judgment by management when assessing the impact of updates in regulation on accounting for new and existing regulatory assets and liabilities and the evaluation of whether the regulatory assets and liabilities will be recovered and settled, respectively. This in turn led to significant auditor judgment and audit effort to perform procedures relating to the accounting for the impact of regulatory and legislative proceedings on new and existing regulatory assets and liabilities.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to the implementation of new regulatory matters and evaluation of existing regulatory assets and liabilities. These procedures also included, among others, obtaining the Company's correspondence with regulators, evaluating the reasonableness of management's judgments regarding new and updated regulatory guidance and proceedings and the related accounting implications, and calculating regulatory assets and liabilities based on provisions and formulas outlined in rate orders and other correspondence with regulators.

/s/ PricewaterhouseCoopers LLP

Chicago, Illinois
February 11, 2020

We have served as the Company's auditor since 2000.



# Report of Independent Registered Public Accounting Firm

To the Board of Directors and Member of Exelon Generation Company, LLC

## Opinion on the Financial Statements

We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(2)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(2)(ii), of Exelon Generation Company, LLC and its subsidiaries (the "Company") (collectively referred to as the "consolidated financial statements"). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019 in conformity with accounting principles generally accepted in the United States of America.

## Change in Accounting Principle

As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for leases in 2019.

## Basis for Opinion

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

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

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

/s/ PricewaterhouseCoopers LLP

Baltimore, Maryland

February 11, 2020

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



# Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of Commonwealth Edison Company

## Opinion on the Financial Statements

We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(3)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(3)(ii), of Commonwealth Edison Company and its subsidiaries (the "Company") (collectively referred to as the "consolidated financial statements"). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019 in conformity with accounting principles generally accepted in the United States of America.

## Basis for Opinion

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

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

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

/s/ PricewaterhouseCoopers LLP

Chicago, Illinois

February 11, 2020

We have served as the Company's auditor since 2000.



# Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholder of PECO Energy Company

## Opinion on the Financial Statements

We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(4)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(4)(ii), of PECO Energy Company and its subsidiaries (the "Company") (collectively referred to as the "consolidated financial statements"). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019 in conformity with accounting principles generally accepted in the United States of America.

## Basis for Opinion

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

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

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

/s/ PricewaterhouseCoopers LLP

Philadelphia, Pennsylvania

February 11, 2020

We have served as the Company's auditor since 1932.



# Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholder of Baltimore Gas and Electric Company

## Opinion on the Financial Statements

We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(5)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(5)(ii), of Baltimore Gas and Electric Company and its subsidiaries (the "Company") (collectively referred to as the "consolidated financial statements"). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019 in conformity with accounting principles generally accepted in the United States of America.

## Change in Accounting Principle

As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for leases in 2019.

## Basis for Opinion

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

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

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

/s/ PricewaterhouseCoopers LLP

Baltimore, Maryland

February 11, 2020

We have served as the Company’s auditor since at least 1993. We have not been able to determine the specific year we began serving as auditor of the Company.



# Report of Independent Registered Public Accounting Firm

To the Board of Directors and Member of Pepco Holdings LLC

## Opinion on the Financial Statements

We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(6)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(6)(ii), of Pepco Holdings LLC and its subsidiaries (the "Company") (collectively referred to as the "consolidated financial statements"). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019 in conformity with accounting principles generally accepted in the United States of America.

## Change in Accounting Principle

As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for leases in 2019.

## Basis for Opinion

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

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

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

/s/ PricewaterhouseCoopers LLP

Washington, DC

February 11, 2020

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



# Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholder of Potomac Electric Power Company

## Opinion on the Financial Statements

We have audited the financial statements, including the related notes, as listed in the index appearing under Item 15(a)(7)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(7)(ii), of Potomac Electric Power Company (the "Company") (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019 in conformity with accounting principles generally accepted in the United States of America.

## Change in Accounting Principle

As discussed in Note 1 to the financial statements, the Company changed the manner in which it accounts for leases in 2019.

## Basis for Opinion

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

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

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

/s/ PricewaterhouseCoopers LLP

Washington, DC
February 11, 2020

We have served as the Company's auditor since at least 1993. We have not been able to determine the specific year we began serving as auditor of the Company.



# Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholder of Delmarva Power & Light Company

## Opinion on the Financial Statements

We have audited the financial statements, including the related notes, as listed in the index appearing under Item 15(a)(8)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(8)(ii), of Delmarva Power & Light Company (the "Company") (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019 in conformity with accounting principles generally accepted in the United States of America.

## Change in Accounting Principle

As discussed in Note 1 to the financial statements, the Company changed the manner in which it accounts for leases in 2019.

## Basis for Opinion

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

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

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

/s/ PricewaterhouseCoopers LLP

Washington, DC
February 11, 2020

We have served as the Company's auditor since at least 1993. We have not been able to determine the specific year we began serving as auditor of the Company.



# Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholder of Atlantic City Electric Company

## Opinion on the Financial Statements

We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(9)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(9)(ii), of Atlantic City Electric Company and its subsidiary (the "Company") (collectively referred to as the "consolidated financial statements"). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019 in conformity with accounting principles generally accepted in the United States of America.

## Change in Accounting Principle

As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for leases in 2019.

## Basis for Opinion

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

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

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

/s/ PricewaterhouseCoopers LLP

Washington, DC

February 11, 2020

We have served as the Company's auditor since 1998.



## Exelon Corporation and Subsidiary Companies
Consolidated Statements of Operations and Comprehensive Income

<table><tr><td colspan="5">(In millions, except per share data)</td></tr><tr><td></td><td>2019</td><td>2018</td><td>2017</td><td></td></tr><tr><td>Operating revenues</td><td></td><td></td><td></td><td></td></tr><tr><td>Competitive businesses revenues</td><td>$ 17,754</td><td>$ 19,168</td><td>$ 17,394</td><td></td></tr><tr><td>Rate-regulated utility revenues</td><td>16,839</td><td>16,879</td><td>15,964</td><td></td></tr><tr><td>Revenues from alternative revenue programs</td><td>(155)</td><td>(69)</td><td>200</td><td></td></tr><tr><td>Total operating revenues</td><td>34,438</td><td>35,978</td><td>33,558</td><td></td></tr><tr><td>Operating expenses</td><td></td><td></td><td></td><td></td></tr><tr><td>Competitive businesses purchased power and fuel</td><td>10,849</td><td>11,679</td><td>9,668</td><td></td></tr><tr><td>Rate-regulated utility purchased power and fuel</td><td>4,648</td><td>4,991</td><td>4,367</td><td></td></tr><tr><td>Operating and maintenance</td><td>8,615</td><td>9,337</td><td>10,025</td><td></td></tr><tr><td>Depreciation and amortization</td><td>4,252</td><td>4,353</td><td>3,828</td><td></td></tr><tr><td>Taxes other than income taxes</td><td>1,732</td><td>1,783</td><td>1,731</td><td></td></tr><tr><td>Total operating expenses</td><td>30,096</td><td>32,143</td><td>29,619</td><td></td></tr><tr><td>Gain on sales of assets and businesses</td><td>31</td><td>56</td><td>3</td><td></td></tr><tr><td>Bargain purchase gain</td><td>—</td><td>—</td><td>233</td><td></td></tr><tr><td>Gain on deconsolidation of business</td><td>1</td><td>—</td><td>213</td><td></td></tr><tr><td>Operating income</td><td>4,374</td><td>3,891</td><td>4,388</td><td></td></tr><tr><td>Other income and (deductions)</td><td></td><td></td><td></td><td></td></tr><tr><td>Interest expense, net</td><td>(1,591)</td><td>(1,529)</td><td>(1,524)</td><td></td></tr><tr><td>Interest expense to affiliates</td><td>(25)</td><td>(25)</td><td>(36)</td><td></td></tr><tr><td>Other, net</td><td>1,227</td><td>(112)</td><td>947</td><td></td></tr><tr><td>Total other income and (deductions)</td><td>(389)</td><td>(1,666)</td><td>(613)</td><td></td></tr><tr><td>Income before income taxes</td><td>3,985</td><td>2,225</td><td>3,775</td><td></td></tr><tr><td>Income taxes</td><td>774</td><td>118</td><td>(126)</td><td></td></tr><tr><td>Equity in losses of unconsolidated affiliates</td><td>(183)</td><td>(28)</td><td>(32)</td><td></td></tr><tr><td>Net income</td><td>3,028</td><td>2,079</td><td>3,869</td><td></td></tr><tr><td>Net income attributable to noncontrolling interests</td><td>92</td><td>74</td><td>90</td><td></td></tr><tr><td>Net income attributable to common shareholders</td><td>$ 2,936</td><td>$ 2,005</td><td>$ 3,779</td><td></td></tr><tr><td>Comprehensive income, net of income taxes</td><td></td><td></td><td></td><td></td></tr><tr><td>Net income</td><td>$ 3,028</td><td>$ 2,079</td><td>$ 3,869</td><td></td></tr><tr><td>Other comprehensive income (loss), net of income taxes</td><td></td><td></td><td></td><td></td></tr><tr><td>Pension and non-pension postretirement benefit plans:</td><td></td><td></td><td></td><td></td></tr><tr><td>Prior service benefit reclassified to periodic benefit cost</td><td>(65)</td><td>(66)</td><td>(56)</td><td></td></tr><tr><td>Actuarial loss reclassified to periodic benefit cost</td><td>149</td><td>247</td><td>197</td><td></td></tr><tr><td>Pension and non-pension postretirement benefit plan valuation adjustment</td><td>(289)</td><td>(143)</td><td>10</td><td></td></tr><tr><td>Unrealized gain on cash flow hedges</td><td>—</td><td>12</td><td>3</td><td></td></tr><tr><td>Unrealized gain on marketable securities</td><td>—</td><td>—</td><td>6</td><td></td></tr><tr><td>Unrealized gain on investments in unconsolidated affiliates</td><td>1</td><td>2</td><td>4</td><td></td></tr><tr><td>Unrealized gain (loss) on foreign currency translation</td><td>6</td><td>(10)</td><td>7</td><td></td></tr><tr><td>Other comprehensive income</td><td>(198)</td><td>42</td><td>171</td><td></td></tr><tr><td>Comprehensive income</td><td>2,830</td><td>2,121</td><td>4,040</td><td></td></tr><tr><td>Comprehensive income attributable to noncontrolling interests</td><td>93</td><td>75</td><td>88</td><td></td></tr><tr><td>Comprehensive income attributable to common shareholders</td><td>$ 2,737</td><td>$ 2,046</td><td>$ 3,952</td><td></td></tr><tr><td>Average shares of common stock outstanding:</td><td></td><td></td><td></td><td></td></tr><tr><td>Basic</td><td>973</td><td>967</td><td>947</td><td></td></tr><tr><td>Assumed exercise and/or distributions of stock-based awards</td><td>1</td><td>2</td><td>2</td><td></td></tr><tr><td>Diluted(a)</td><td>974</td><td>969</td><td>949</td><td></td></tr><tr><td>Earnings per average common share:</td><td></td><td></td><td></td><td></td></tr><tr><td>Basic</td><td>$ 3.02</td><td>$ 2.07</td><td>$ 3.99</td><td></td></tr></table>



(a) The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was immaterial for the year ended December 31, 2019 and approximately 3 million and 8 million for the years ended December 31, 2018 and 2017, respectively.

See the Combined Notes to Consolidated Financial Statements



## Exelon Corporation and Subsidiary Companies
Consolidated Statements of Cash Flows

<table><tr><td rowspan="2">(In millions)</td><td colspan="4">For the Years Ended December 31,</td></tr><tr><td>2019</td><td>2018</td><td>2017</td><td></td></tr><tr><td>Cash flows from operating activities</td><td></td><td></td><td></td><td></td></tr><tr><td>Net income</td><td>$ 3,028</td><td>$ 2,079</td><td>$ 3,869</td><td></td></tr><tr><td>Adjustments to reconcile net income to net cash flows provided by operating activities:</td><td></td><td></td><td></td><td></td></tr><tr><td>Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization</td><td>5,780</td><td>5,971</td><td>5,427</td><td></td></tr><tr><td>Asset impairments</td><td>201</td><td>50</td><td>573</td><td></td></tr><tr><td>Gain on sales of assets and businesses</td><td>(27)</td><td>(56)</td><td>(3)</td><td></td></tr><tr><td>Bargain purchase gain</td><td>—</td><td>—</td><td>(233)</td><td></td></tr><tr><td>Gain on deconsolidation of business</td><td>—</td><td>—</td><td>(213)</td><td></td></tr><tr><td>Deferred income taxes and amortization of investment tax credits</td><td>681</td><td>(108)</td><td>(362)</td><td></td></tr><tr><td>Net fair value changes related to derivatives</td><td>222</td><td>294</td><td>151</td><td></td></tr><tr><td>Net realized and unrealized (gains) losses on NDT funds</td><td>(663)</td><td>303</td><td>(616)</td><td></td></tr><tr><td>Other non-cash operating activities</td><td>613</td><td>1,131</td><td>728</td><td></td></tr><tr><td>Changes in assets and liabilities:</td><td></td><td></td><td></td><td></td></tr><tr><td>Accounts receivable</td><td>(243)</td><td>(565)</td><td>(470)</td><td></td></tr><tr><td>Inventories</td><td>(87)</td><td>(37)</td><td>(72)</td><td></td></tr><tr><td>Accounts payable and accrued expenses</td><td>(425)</td><td>551</td><td>(388)</td><td></td></tr><tr><td>Option premiums (paid) received, net</td><td>(29)</td><td>(43)</td><td>28</td><td></td></tr><tr><td>Collateral (posted) received, net</td><td>(438)</td><td>82</td><td>(158)</td><td></td></tr><tr><td>Income taxes</td><td>(64)</td><td>340</td><td>299</td><td></td></tr><tr><td>Pension and non-pension postretirement benefit contributions</td><td>(408)</td><td>(383)</td><td>(405)</td><td></td></tr><tr><td>Other assets and liabilities</td><td>(1,482)</td><td>(965)</td><td>(675)</td><td></td></tr><tr><td>Net cash flows provided by operating activities</td><td>6,659</td><td>8,644</td><td>7,480</td><td></td></tr><tr><td>Cash flows from investing activities</td><td></td><td></td><td></td><td></td></tr><tr><td>Capital expenditures</td><td>(7,248)</td><td>(7,594)</td><td>(7,584)</td><td></td></tr><tr><td>Proceeds from NDT fund sales</td><td>10,051</td><td>8,762</td><td>7,845</td><td></td></tr><tr><td>Investment in NDT funds</td><td>(10,087)</td><td>(8,997)</td><td>(8,113)</td><td></td></tr><tr><td>Reduction of restricted cash from deconsolidation of business</td><td>—</td><td>—</td><td>(87)</td><td></td></tr><tr><td>Acquisitions of assets and businesses, net</td><td>(41)</td><td>(154)</td><td>(208)</td><td></td></tr><tr><td>Proceeds from sales of assets and businesses</td><td>53</td><td>91</td><td>219</td><td></td></tr><tr><td>Other investing activities</td><td>12</td><td>58</td><td>(43)</td><td></td></tr><tr><td>Net cash flows used in investing activities</td><td>(7,260)</td><td>(7,834)</td><td>(7,971)</td><td></td></tr><tr><td>Cash flows from financing activities</td><td></td><td></td><td></td><td></td></tr><tr><td>Changes in short-term borrowings</td><td>781</td><td>(338)</td><td>(261)</td><td></td></tr><tr><td>Proceeds from short-term borrowings with maturities greater than 90 days</td><td>—</td><td>126</td><td>621</td><td></td></tr><tr><td>Repayments on short-term borrowings with maturities greater than 90 days</td><td>(125)</td><td>(1)</td><td>(700)</td><td></td></tr><tr><td>Issuance of long-term debt</td><td>1,951</td><td>3,115</td><td>3,470</td><td></td></tr><tr><td>Retirement of long-term debt</td><td>(1,287)</td><td>(1,786)</td><td>(2,490)</td><td></td></tr><tr><td>Retirement of long-term debt to financing trust</td><td>—</td><td>—</td><td>(250)</td><td></td></tr><tr><td>Common stock issued from treasury stock</td><td>—</td><td>—</td><td>1,150</td><td></td></tr><tr><td>Dividends paid on common stock</td><td>(1,408)</td><td>(1,332)</td><td>(1,236)</td><td></td></tr><tr><td>Proceeds from employee stock plans</td><td>112</td><td>105</td><td>150</td><td></td></tr><tr><td>Sale of noncontrolling interests</td><td>—</td><td>—</td><td>396</td><td></td></tr><tr><td>Other financing activities</td><td>(82)</td><td>(108)</td><td>(83)</td><td></td></tr><tr><td>Net cash flows (used in) provided by financing activities</td><td>(58)</td><td>(219)</td><td>767</td><td></td></tr><tr><td>(Decrease) increase in cash, cash equivalents and restricted cash</td><td>(659)</td><td>591</td><td>276</td><td></td></tr><tr><td>Cash, cash equivalents and restricted cash at beginning of period</td><td>1,781</td><td>1,190</td><td>914</td><td></td></tr><tr><td>Cash, cash equivalents and restricted cash at end of period</td><td>$ 1,122</td><td>$ 1,781</td><td>$ 1,190</td><td></td></tr></table>



<table><tr><td>(Decrease) increase in capital expenditures not paid</td><td>$</td><td>(7)</td><td>$</td><td>(69)</td><td>$</td><td>42</td></tr><tr><td>Increase (decrease) in PPE related to ARO update</td><td></td><td>968</td><td></td><td>(107)</td><td></td><td>29</td></tr></table>

See the Combined Notes to Consolidated Financial Statements



## Exelon Corporation and Subsidiary Companies
Consolidated Balance Sheets

<table><tr><td rowspan="2">(In millions)</td><td colspan="3">December 31,</td></tr><tr><td>2019</td><td>2018</td><td></td></tr><tr><td>ASSETS</td><td></td><td></td><td></td></tr><tr><td>Current assets</td><td></td><td></td><td></td></tr><tr><td>Cash and cash equivalents</td><td>$     587</td><td>$     1,349</td><td></td></tr><tr><td>Restricted cash and cash equivalents</td><td>358</td><td>247</td><td></td></tr><tr><td>Accounts receivable, net</td><td></td><td></td><td></td></tr><tr><td>Customer (net of allowance for uncollectible accounts of $243 and $283 as of December 31, 2019 and 2018, respectively)</td><td></td><td></td><td></td></tr><tr><td></td><td>4,592</td><td>4,607</td><td></td></tr><tr><td>Other (net of allowance for uncollectible accounts of $48 and $36 as of December 31, 2019 and 2018, respectively)</td><td>1,583</td><td>1,256</td><td></td></tr><tr><td>Mark-to-market derivative assets</td><td>679</td><td>804</td><td></td></tr><tr><td>Unamortized energy contract assets</td><td>47</td><td>48</td><td></td></tr><tr><td>Inventories, net</td><td></td><td></td><td></td></tr><tr><td>Fossil fuel and emission allowances</td><td>312</td><td>334</td><td></td></tr><tr><td>Materials and supplies</td><td>1,456</td><td>1,351</td><td></td></tr><tr><td>Regulatory assets</td><td>1,170</td><td>1,190</td><td></td></tr><tr><td>Assets held for sale</td><td>—</td><td>904</td><td></td></tr><tr><td>Other</td><td>1,253</td><td>1,238</td><td></td></tr><tr><td>Total current assets</td><td>12,037</td><td>13,328</td><td></td></tr><tr><td>Property, plant and equipment (net of accumulated depreciation and amortization of $23,979 and $22,902 as of December 31, 2019 and 2018, respectively)</td><td>80,233</td><td>76,707</td><td></td></tr><tr><td>Deferred debits and other assets</td><td></td><td></td><td></td></tr><tr><td>Regulatory assets</td><td>8,335</td><td>8,237</td><td></td></tr><tr><td>Nuclear decommissioning trust funds</td><td>13,190</td><td>11,661</td><td></td></tr><tr><td>Investments</td><td>464</td><td>625</td><td></td></tr><tr><td>Goodwill</td><td>6,677</td><td>6,677</td><td></td></tr><tr><td>Mark-to-market derivative assets</td><td>508</td><td>452</td><td></td></tr><tr><td>Unamortized energy contract assets</td><td>336</td><td>372</td><td></td></tr><tr><td>Other</td><td>3,197</td><td>1,575</td><td></td></tr><tr><td>Total deferred debits and other assets</td><td>32,707</td><td>29,599</td><td></td></tr><tr><td>Total assets(a)</td><td>$     124,977</td><td>$     119,634</td><td></td></tr></table>

See the Combined Notes to Consolidated Financial Statements



## Exelon Corporation and Subsidiary Companies
Consolidated Balance Sheets

<table><tr><td rowspan="2">(In millions)</td><td colspan="2">December 31,</td></tr><tr><td>2019</td><td>2018</td></tr><tr><td>LIABILITIES AND SHAREHOLDERS&#x27; EQUITY</td><td></td><td></td></tr><tr><td>Current liabilities</td><td></td><td></td></tr><tr><td>Short-term borrowings</td><td>$ 1,370</td><td>$ 714</td></tr><tr><td>Long-term debt due within one year</td><td>4,710</td><td>1,349</td></tr><tr><td>Accounts payable</td><td>3,560</td><td>3,800</td></tr><tr><td>Accrued expenses</td><td>1,981</td><td>2,112</td></tr><tr><td>Payables to affiliates</td><td>5</td><td>5</td></tr><tr><td>Regulatory liabilities</td><td>406</td><td>644</td></tr><tr><td>Mark-to-market derivative liabilities</td><td>247</td><td>475</td></tr><tr><td>Unamortized energy contract liabilities</td><td>132</td><td>149</td></tr><tr><td>Renewable energy credit obligation</td><td>443</td><td>344</td></tr><tr><td>Liabilities held for sale</td><td>—</td><td>777</td></tr><tr><td>Other</td><td>1,331</td><td>1,035</td></tr><tr><td>Total current liabilities</td><td>14,185</td><td>11,404</td></tr><tr><td>Long-term debt</td><td>31,329</td><td>34,075</td></tr><tr><td>Long-term debt to financing trusts</td><td>390</td><td>390</td></tr><tr><td>Deferred credits and other liabilities</td><td></td><td></td></tr><tr><td>Deferred income taxes and unamortized investment tax credits</td><td>12,351</td><td>11,321</td></tr><tr><td>Asset retirement obligations</td><td>10,846</td><td>9,679</td></tr><tr><td>Pension obligations</td><td>4,247</td><td>3,988</td></tr><tr><td>Non-pension postretirement benefit obligations</td><td>2,076</td><td>1,928</td></tr><tr><td>Spent nuclear fuel obligation</td><td>1,199</td><td>1,171</td></tr><tr><td>Regulatory liabilities</td><td>9,986</td><td>9,559</td></tr><tr><td>Mark-to-market derivative liabilities</td><td>393</td><td>479</td></tr><tr><td>Unamortized energy contract liabilities</td><td>338</td><td>463</td></tr><tr><td>Other</td><td>3,064</td><td>2,130</td></tr><tr><td>Total deferred credits and other liabilities</td><td>44,500</td><td>40,718</td></tr><tr><td>Total liabilities(a)</td><td>90,404</td><td>86,587</td></tr><tr><td>Commitments and contingencies</td><td></td><td></td></tr><tr><td>Shareholders&#x27; equity</td><td></td><td></td></tr><tr><td>Common stock (No par value, 2,000 shares authorized, 973 shares and 968 shares outstanding at December 31, 2019 and 2018, respectively)</td><td>19,274</td><td>19,116</td></tr><tr><td>Treasury stock, at cost (2 shares at December 31, 2019 and 2018)</td><td>(123)</td><td>(123)</td></tr><tr><td>Retained earnings</td><td>16,267</td><td>14,743</td></tr><tr><td>Accumulated other comprehensive loss, net</td><td>(3,194)</td><td>(2,995)</td></tr><tr><td>Total shareholders&#x27; equity</td><td>32,224</td><td>30,741</td></tr><tr><td>Noncontrolling interests</td><td>2,349</td><td>2,306</td></tr><tr><td>Total equity</td><td>34,573</td><td>33,047</td></tr><tr><td>Total liabilities and shareholders&#x27; equity</td><td>$ 124,977</td><td>$ 119,634</td></tr></table>

(a) Exelon's consolidated assets include $9,532 million and $9,667 million at December 31, 2019 and 2018, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon's consolidated liabilities include $3,473 million and $3,548 million at December 31, 2019 and 2018, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 22–Variable Interest Entities for additional information.



## Exelon Corporation and Subsidiary Companies
Consolidated Statements of Changes in Equity

<table><tr><td rowspan="2">(In millions, shares in thousands)</td><td colspan="7">Shareholders&#x27; Equity</td></tr><tr><td>Issued Shares</td><td>Common Stock</td><td>Treasury Stock</td><td>Retained Earnings</td><td>Accumulated Other Comprehensive Loss</td><td>Noncontrolling Interests</td><td>Total Equity</td></tr><tr><td>Balance, December 31, 2016</td><td>958,778</td><td>$ 18,794</td><td>$ (2,327)</td><td>$ 12,042</td><td>$ (2,660)</td><td>$ 1,780</td><td>$ 27,629</td></tr><tr><td>Net income</td><td>—</td><td>—</td><td>—</td><td>3,779</td><td>—</td><td>90</td><td>3,869</td></tr><tr><td>Long-term incentive plan activity</td><td>5,066</td><td>56</td><td>—</td><td>—</td><td>—</td><td>—</td><td>56</td></tr><tr><td>Employee stock purchase plan issuances</td><td>1,324</td><td>150</td><td>—</td><td>—</td><td>—</td><td>—</td><td>150</td></tr><tr><td>Common stock issued from treasury stock</td><td>—</td><td>—</td><td>2,204</td><td>(1,054)</td><td>—</td><td>—</td><td>1,150</td></tr><tr><td>Sale of noncontrolling interests</td><td>—</td><td>(36)</td><td>—</td><td>—</td><td>—</td><td>443</td><td>407</td></tr><tr><td>Changes in equity of noncontrolling interests</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(20)</td><td>(20)</td></tr><tr><td>Common stock dividends ($1.31/common share)</td><td>—</td><td>—</td><td>—</td><td>(1,243)</td><td>—</td><td>—</td><td>(1,243)</td></tr><tr><td>Other comprehensive income (loss), net of income taxes</td><td>—</td><td>—</td><td>—</td><td>—</td><td>173</td><td>(2)</td><td>171</td></tr><tr><td>Impact of adoption of Reclassification of Certain Tax Effects from AOCI standard</td><td>—</td><td>—</td><td>—</td><td>539</td><td>(539)</td><td>—</td><td>—</td></tr><tr><td>Balance, December 31, 2017</td><td>965,168</td><td>$ 18,964</td><td>$ (123)</td><td>$ 14,063</td><td>$ (3,026)</td><td>$ 2,291</td><td>$ 32,169</td></tr><tr><td>Net income</td><td>—</td><td>—</td><td>—</td><td>2,005</td><td>—</td><td>74</td><td>2,079</td></tr><tr><td>Long-term incentive plan activity</td><td>3,534</td><td>41</td><td>—</td><td>—</td><td>—</td><td>—</td><td>41</td></tr><tr><td>Employee stock purchase plan issuances</td><td>1,318</td><td>105</td><td>—</td><td>—</td><td>—</td><td>—</td><td>105</td></tr><tr><td>Sale of noncontrolling interests</td><td>—</td><td>6</td><td>—</td><td>—</td><td>—</td><td>—</td><td>6</td></tr><tr><td>Changes in equity of noncontrolling interests</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(60)</td><td>(60)</td></tr><tr><td>Common stock dividends ($1.38/common share)</td><td>—</td><td>—</td><td>—</td><td>(1,339)</td><td>—</td><td>—</td><td>(1,339)</td></tr><tr><td>Other comprehensive income, net of income taxes</td><td>—</td><td>—</td><td>—</td><td>—</td><td>41</td><td>1</td><td>42</td></tr><tr><td>Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard</td><td>—</td><td>—</td><td>—</td><td>14</td><td>(10)</td><td>—</td><td>4</td></tr><tr><td>Balance, December 31, 2018</td><td>970,020</td><td>$ 19,116</td><td>$ (123)</td><td>$ 14,743</td><td>$ (2,995)</td><td>$ 2,306</td><td>$ 33,047</td></tr><tr><td>Net income</td><td>—</td><td>—</td><td>—</td><td>2,936</td><td>—</td><td>92</td><td>3,028</td></tr><tr><td>Long-term incentive plan activity</td><td>3,111</td><td>40</td><td>—</td><td>—</td><td>—</td><td>—</td><td>40</td></tr><tr><td>Employee stock purchase plan issuances</td><td>1,285</td><td>112</td><td>—</td><td>—</td><td>—</td><td>—</td><td>112</td></tr><tr><td>Sale of noncontrolling interests</td><td>—</td><td>6</td><td>—</td><td>—</td><td>—</td><td>—</td><td>6</td></tr><tr><td>Changes in equity of noncontrolling interests</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(48)</td><td>(48)</td></tr><tr><td>Common stock dividends ($1.45/common share)</td><td>—</td><td>—</td><td>—</td><td>(1,412)</td><td>—</td><td>—</td><td>(1,412)</td></tr><tr><td>Other comprehensive income, net of income taxes</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(199)</td><td>(1)</td><td>(200)</td></tr><tr><td>Balance, December 31, 2019</td><td>974,416</td><td>$ 19,274</td><td>$ (123)</td><td>$ 16,267</td><td>$ (3,194)</td><td>$ 2,349</td><td>$ 34,573</td></tr></table>

See the Combined Notes to Consolidated Financial Statements



## Exelon Generation Company, LLC and Subsidiary Companies
Consolidated Statements of Operations and Comprehensive Income

<table><tr><td rowspan="2">(In millions)</td><td colspan="4">For the Years Ended December 31,</td></tr><tr><td>2019</td><td>2018</td><td>2017</td><td></td></tr><tr><td>Operating revenues</td><td></td><td></td><td></td><td></td></tr><tr><td>Operating revenues</td><td>$ 17,752</td><td>$ 19,169</td><td>$ 17,385</td><td></td></tr><tr><td>Operating revenues from affiliates</td><td>1,172</td><td>1,268</td><td>1,115</td><td></td></tr><tr><td>Total operating revenues</td><td>18,924</td><td>20,437</td><td>18,500</td><td></td></tr><tr><td>Operating expenses</td><td></td><td></td><td></td><td></td></tr><tr><td>Purchased power and fuel</td><td>10,849</td><td>11,679</td><td>9,671</td><td></td></tr><tr><td>Purchased power and fuel from affiliates</td><td>7</td><td>14</td><td>19</td><td></td></tr><tr><td>Operating and maintenance</td><td>4,131</td><td>4,803</td><td>5,602</td><td></td></tr><tr><td>Operating and maintenance from affiliates</td><td>587</td><td>661</td><td>697</td><td></td></tr><tr><td>Depreciation and amortization</td><td>1,535</td><td>1,797</td><td>1,457</td><td></td></tr><tr><td>Taxes other than income taxes</td><td>519</td><td>556</td><td>555</td><td></td></tr><tr><td>Total operating expenses</td><td>17,628</td><td>19,510</td><td>18,001</td><td></td></tr><tr><td>Gain on sales of assets and businesses</td><td>27</td><td>48</td><td>2</td><td></td></tr><tr><td>Bargain purchase gain</td><td>—</td><td>—</td><td>233</td><td></td></tr><tr><td>Gain on deconsolidation of business</td><td>—</td><td>—</td><td>213</td><td></td></tr><tr><td>Operating income</td><td>1,323</td><td>975</td><td>947</td><td></td></tr><tr><td>Other income and (deductions)</td><td></td><td></td><td></td><td></td></tr><tr><td>Interest expense, net</td><td>(394)</td><td>(396)</td><td>(401)</td><td></td></tr><tr><td>Interest expense to affiliates</td><td>(35)</td><td>(36)</td><td>(39)</td><td></td></tr><tr><td>Other, net</td><td>1,023</td><td>(178)</td><td>948</td><td></td></tr><tr><td>Total other income and (deductions)</td><td>594</td><td>(610)</td><td>508</td><td></td></tr><tr><td>Income before income taxes</td><td>1,917</td><td>365</td><td>1,455</td><td></td></tr><tr><td>Income taxes</td><td>516</td><td>(108)</td><td>(1,376)</td><td></td></tr><tr><td>Equity in losses of unconsolidated affiliates</td><td>(184)</td><td>(30)</td><td>(33)</td><td></td></tr><tr><td>Net income</td><td>1,217</td><td>443</td><td>2,798</td><td></td></tr><tr><td>Net income attributable to noncontrolling interests</td><td>92</td><td>73</td><td>88</td><td></td></tr><tr><td>Net income attributable to membership interest</td><td>$ 1,125</td><td>$ 370</td><td>$ 2,710</td><td></td></tr><tr><td>Comprehensive income, net of income taxes</td><td></td><td></td><td></td><td></td></tr><tr><td>Net income</td><td>$ 1,217</td><td>$ 443</td><td>$ 2,798</td><td></td></tr><tr><td>Other comprehensive income (loss), net of income taxes</td><td></td><td></td><td></td><td></td></tr><tr><td>Unrealized gain on cash flow hedges</td><td>—</td><td>12</td><td>3</td><td></td></tr><tr><td>Unrealized gain on marketable securities</td><td>—</td><td>—</td><td>1</td><td></td></tr><tr><td>Unrealized gain on investments in unconsolidated affiliates</td><td>1</td><td>1</td><td>4</td><td></td></tr><tr><td>Unrealized gain (loss) on foreign currency translation</td><td>6</td><td>(10)</td><td>7</td><td></td></tr><tr><td>Other comprehensive income</td><td>7</td><td>3</td><td>15</td><td></td></tr><tr><td>Comprehensive income</td><td>$ 1,224</td><td>$ 446</td><td>$ 2,813</td><td></td></tr><tr><td>Comprehensive income attributable to noncontrolling interests</td><td>93</td><td>74</td><td>86</td><td></td></tr><tr><td>Comprehensive income attributable to membership interest</td><td>$ 1,131</td><td>$ 372</td><td>$ 2,727</td><td></td></tr></table>

See the Combined Notes to Consolidated Financial Statements



## Exelon Generation Company, LLC and Subsidiary Companies
Consolidated Statements of Cash Flows

<table><tr><td rowspan="2">(In millions)</td><td colspan="4">For the Years Ended December 31,</td></tr><tr><td>2019</td><td>2018</td><td>2017</td><td></td></tr><tr><td>Cash flows from operating activities</td><td></td><td></td><td></td><td></td></tr><tr><td>Net income</td><td>$ 1,217</td><td>$ 443</td><td>$ 2,798</td><td></td></tr><tr><td>Adjustments to reconcile net income to net cash flows provided by operating activities:</td><td></td><td></td><td></td><td></td></tr><tr><td>Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization</td><td>3,063</td><td>3,415</td><td>3,056</td><td></td></tr><tr><td>Asset impairments</td><td>201</td><td>50</td><td>510</td><td></td></tr><tr><td>Gain on sales of assets and businesses</td><td>(27)</td><td>(48)</td><td>(2)</td><td></td></tr><tr><td>Bargain purchase gain</td><td>—</td><td>—</td><td>(233)</td><td></td></tr><tr><td>Gain on deconsolidation of business</td><td>—</td><td>—</td><td>(213)</td><td></td></tr><tr><td>Deferred income taxes and amortization of investment tax credits</td><td>361</td><td>(451)</td><td>(2,023)</td><td></td></tr><tr><td>Net fair value changes related to derivatives</td><td>228</td><td>307</td><td>167</td><td></td></tr><tr><td>Net realized and unrealized (gains) losses on NDT fund investments</td><td>(663)</td><td>303</td><td>(616)</td><td></td></tr><tr><td>Other non-cash operating activities</td><td>(124)</td><td>298</td><td>112</td><td></td></tr><tr><td>Changes in assets and liabilities:</td><td></td><td></td><td></td><td></td></tr><tr><td>Accounts receivable</td><td>(186)</td><td>(359)</td><td>(320)</td><td></td></tr><tr><td>Receivables from and payables to affiliates, net</td><td>(52)</td><td>8</td><td>(7)</td><td></td></tr><tr><td>Inventories</td><td>(47)</td><td>(12)</td><td>(29)</td><td></td></tr><tr><td>Accounts payable and accrued expenses</td><td>(248)</td><td>376</td><td>4</td><td></td></tr><tr><td>Option premiums (paid) received, net</td><td>(29)</td><td>(43)</td><td>28</td><td></td></tr><tr><td>Collateral (posted) received, net</td><td>(481)</td><td>64</td><td>(129)</td><td></td></tr><tr><td>Income taxes</td><td>302</td><td>(193)</td><td>496</td><td></td></tr><tr><td>Pension and non-pension postretirement benefit contributions</td><td>(175)</td><td>(139)</td><td>(148)</td><td></td></tr><tr><td>Other assets and liabilities</td><td>(467)</td><td>(158)</td><td>(152)</td><td></td></tr><tr><td>Net cash flows provided by operating activities</td><td>2,873</td><td>3,861</td><td>3,299</td><td></td></tr><tr><td>Cash flows from investing activities</td><td></td><td></td><td></td><td></td></tr><tr><td>Capital expenditures</td><td>(1,845)</td><td>(2,242)</td><td>(2,259)</td><td></td></tr><tr><td>Proceeds from NDT fund sales</td><td>10,051</td><td>8,762</td><td>7,845</td><td></td></tr><tr><td>Investment in NDT funds</td><td>(10,087)</td><td>(8,997)</td><td>(8,113)</td><td></td></tr><tr><td>Reduction of restricted cash from deconsolidation of business</td><td>—</td><td>—</td><td>(87)</td><td></td></tr><tr><td>Proceeds from sales of assets and businesses</td><td>52</td><td>90</td><td>218</td><td></td></tr><tr><td>Acquisitions of assets and businesses, net</td><td>(41)</td><td>(154)</td><td>(208)</td><td></td></tr><tr><td>Other investing activities</td><td>3</td><td>10</td><td>(58)</td><td></td></tr><tr><td>Net cash flows used in investing activities</td><td>(1,867)</td><td>(2,531)</td><td>(2,662)</td><td></td></tr><tr><td>Cash flows from financing activities</td><td></td><td></td><td></td><td></td></tr><tr><td>Change in short-term borrowings</td><td>320</td><td>—</td><td>(620)</td><td></td></tr><tr><td>Proceeds from short-term borrowings with maturities greater than 90 days</td><td>—</td><td>—</td><td>121</td><td></td></tr><tr><td>Repayments of short-term borrowings with maturities greater than 90 days</td><td>—</td><td>—</td><td>(200)</td><td></td></tr><tr><td>Issuance of long-term debt</td><td>42</td><td>15</td><td>1,645</td><td></td></tr><tr><td>Retirement of long-term debt</td><td>(813)</td><td>(141)</td><td>(1,261)</td><td></td></tr><tr><td>Changes in Exelon intercompany money pool</td><td>(100)</td><td>46</td><td>(1)</td><td></td></tr><tr><td>Distributions to member</td><td>(899)</td><td>(1,001)</td><td>(659)</td><td></td></tr><tr><td>Contributions from member</td><td>41</td><td>155</td><td>102</td><td></td></tr><tr><td>Sale of noncontrolling interests</td><td>—</td><td>—</td><td>396</td><td></td></tr><tr><td>Other financing activities</td><td>(51)</td><td>(55)</td><td>(54)</td><td></td></tr><tr><td>Net cash flows used in financing activities</td><td>(1,460)</td><td>(981)</td><td>(531)</td><td></td></tr><tr><td>(Decrease) increase in cash, cash equivalents and restricted cash</td><td>(454)</td><td>349</td><td>106</td><td></td></tr><tr><td>Cash, cash equivalents and restricted cash at beginning of period</td><td>903</td><td>554</td><td>448</td><td></td></tr><tr><td>Cash, cash equivalents and restricted cash at end of period</td><td>$ 449</td><td>$ 903</td><td>$ 554</td><td></td></tr></table>



<table><tr><td>(Decrease) increase in capital expenditures not paid</td><td>$</td><td>(34)</td><td>$</td><td>(199)</td><td>$</td><td>73</td></tr><tr><td>Increase (decrease) in PPE related to ARO update</td><td></td><td>959</td><td></td><td>(130)</td><td></td><td>29</td></tr></table>

See the Combined Notes to Consolidated Financial Statements



## Exelon Generation Company, LLC and Subsidiary Companies
Consolidated Balance Sheets

<table><tr><td rowspan="2">(In millions)</td><td colspan="2">December 31,</td></tr><tr><td>2019</td><td>2018</td></tr><tr><td>ASSETS</td><td></td><td></td></tr><tr><td>Current assets</td><td></td><td></td></tr><tr><td>Cash and cash equivalents</td><td>$     303</td><td>$     750</td></tr><tr><td>Restricted cash and cash equivalents</td><td></td><td>146</td></tr><tr><td>Accounts receivable, net</td><td></td><td></td></tr><tr><td>Customer (net of allowance for uncollectible accounts of $80 and $103 as of December 31, 2019 and 2018, respectively)</td><td></td><td>2,893</td></tr><tr><td>Other (net of allowance for uncollectible accounts of $0 and $1 as of December 31, 2019 and 2018, respectively)</td><td></td><td>619</td></tr><tr><td>Mark-to-market derivative assets</td><td></td><td>675</td></tr><tr><td>Receivables from affiliates</td><td></td><td>190</td></tr><tr><td>Unamortized energy contract assets</td><td></td><td>47</td></tr><tr><td>Inventories, net</td><td></td><td></td></tr><tr><td>Fossil fuel and emission allowances</td><td></td><td>236</td></tr><tr><td>Materials and supplies</td><td></td><td>1,026</td></tr><tr><td>Assets held for sale</td><td></td><td>—</td></tr><tr><td>Other</td><td></td><td>941</td></tr><tr><td>Total current assets</td><td></td><td>7,076</td></tr><tr><td>Property, plant and equipment (net of accumulated depreciation and amortization of $12,017 and $12,206 as of December 31, 2019 and 2018, respectively)</td><td></td><td>24,193</td></tr><tr><td>Deferred debits and other assets</td><td></td><td></td></tr><tr><td>Nuclear decommissioning trust funds</td><td></td><td>13,190</td></tr><tr><td>Investments</td><td></td><td>235</td></tr><tr><td>Goodwill</td><td></td><td>47</td></tr><tr><td>Mark-to-market derivative assets</td><td></td><td>508</td></tr><tr><td>Prepaid pension asset</td><td></td><td>1,438</td></tr><tr><td>Unamortized energy contract assets</td><td></td><td>336</td></tr><tr><td>Deferred income taxes</td><td></td><td>12</td></tr><tr><td>Other</td><td></td><td>1,960</td></tr><tr><td>Total deferred debits and other assets</td><td></td><td>17,726</td></tr><tr><td>Total assets(a)</td><td></td><td>48,995</td></tr></table>

See the Combined Notes to Consolidated Financial Statements



## Exelon Generation Company, LLC and Subsidiary Companies
Consolidated Balance Sheets

<table><tr><td rowspan="2">(In millions)</td><td colspan="3">December 31,</td></tr><tr><td>2019</td><td>2018</td><td></td></tr><tr><td>LIABILITIES AND EQUITY</td><td></td><td></td><td></td></tr><tr><td>Current liabilities</td><td></td><td></td><td></td></tr><tr><td>Short-term borrowings</td><td>$     320</td><td>$      —</td><td></td></tr><tr><td>Long-term debt due within one year</td><td>2,624</td><td>906</td><td></td></tr><tr><td>Long-term debt to affiliates due within one year</td><td>558</td><td>—</td><td></td></tr><tr><td>Accounts payable</td><td>1,692</td><td>1,847</td><td></td></tr><tr><td>Accrued expenses</td><td>786</td><td>898</td><td></td></tr><tr><td>Payables to affiliates</td><td>117</td><td>139</td><td></td></tr><tr><td>Borrowings from Exelon intercompany money pool</td><td>—</td><td>100</td><td></td></tr><tr><td>Mark-to-market derivative liabilities</td><td>215</td><td>449</td><td></td></tr><tr><td>Unamortized energy contract liabilities</td><td>17</td><td>31</td><td></td></tr><tr><td>Renewable energy credit obligation</td><td>443</td><td>343</td><td></td></tr><tr><td>Liabilities held for sale</td><td>—</td><td>777</td><td></td></tr><tr><td>Other</td><td>517</td><td>279</td><td></td></tr><tr><td>Total current liabilities</td><td>7,289</td><td>5,769</td><td></td></tr><tr><td>Long-term debt</td><td>4,464</td><td>6,989</td><td></td></tr><tr><td>Long-term debt to affiliates</td><td>328</td><td>898</td><td></td></tr><tr><td>Deferred credits and other liabilities</td><td></td><td></td><td></td></tr><tr><td>Deferred income taxes and unamortized investment tax credits</td><td>3,752</td><td>3,383</td><td></td></tr><tr><td>Asset retirement obligations</td><td>10,603</td><td>9,450</td><td></td></tr><tr><td>Non-pension postretirement benefit obligations</td><td>878</td><td>900</td><td></td></tr><tr><td>Spent nuclear fuel obligation</td><td>1,199</td><td>1,171</td><td></td></tr><tr><td>Payables to affiliates</td><td>3,103</td><td>2,606</td><td></td></tr><tr><td>Mark-to-market derivative liabilities</td><td>123</td><td>252</td><td></td></tr><tr><td>Unamortized energy contract liabilities</td><td>11</td><td>20</td><td></td></tr><tr><td>Other</td><td>1,415</td><td>610</td><td></td></tr><tr><td>Total deferred credits and other liabilities</td><td>21,084</td><td>18,392</td><td></td></tr><tr><td>Total liabilities(a)</td><td>33,165</td><td>32,048</td><td></td></tr><tr><td>Commitments and contingencies</td><td></td><td></td><td></td></tr><tr><td>Equity</td><td></td><td></td><td></td></tr><tr><td>Member&#x27;s equity</td><td></td><td></td><td></td></tr><tr><td>Membership interest</td><td>9,566</td><td>9,518</td><td></td></tr><tr><td>Undistributed earnings</td><td>3,950</td><td>3,724</td><td></td></tr><tr><td>Accumulated other comprehensive loss, net</td><td>(32)</td><td>(38)</td><td></td></tr><tr><td>Total member&#x27;s equity</td><td>13,484</td><td>13,204</td><td></td></tr><tr><td>Noncontrolling interests</td><td>2,346</td><td>2,304</td><td></td></tr><tr><td>Total equity</td><td>15,830</td><td>15,508</td><td></td></tr><tr><td>Total liabilities and equity</td><td>$     48,995</td><td>$     47,556</td><td></td></tr></table>

(a) Generation’s consolidated assets include $9,512 million and $9,634 million at December 31, 2019 and 2018, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $3,429 million and $3,480 million at December 31, 2019 and 2018, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 22–Variable Interest Entities for additional information.



Exelon Generation Company, LLC and Subsidiary Companies Consolidated Statements of Changes in Equity

<table><tr><td rowspan="2">(In millions)</td><td colspan="6">Member&#x27;s Equity</td></tr><tr><td>Membership Interest</td><td>Undistributed Earnings</td><td>Accumulated Other Comprehensive Loss, net</td><td>Noncontrolling Interests</td><td>Total Equity</td><td></td></tr><tr><td>Balance, December 31, 2016</td><td>$ 9,261</td><td>$ 2,298</td><td>$ (54)</td><td>$ 1,779</td><td>$ 13,284</td><td></td></tr><tr><td>Net income</td><td>—</td><td>2,710</td><td>—</td><td>88</td><td>2,798</td><td></td></tr><tr><td>Sale of noncontrolling interests</td><td>(36)</td><td>—</td><td>—</td><td>443</td><td>407</td><td></td></tr><tr><td>Changes in equity of noncontrolling interests</td><td>—</td><td>—</td><td>—</td><td>(18)</td><td>(18)</td><td></td></tr><tr><td>Distribution of net retirement benefit obligation to member</td><td>33</td><td>—</td><td>—</td><td>—</td><td>33</td><td></td></tr><tr><td>Distributions to member</td><td>—</td><td>(659)</td><td>—</td><td>—</td><td>(659)</td><td></td></tr><tr><td>Contributions from member</td><td>99</td><td>—</td><td>—</td><td>—</td><td>99</td><td></td></tr><tr><td>Other comprehensive income (loss), net of income taxes</td><td>—</td><td>—</td><td>17</td><td>(2)</td><td>15</td><td></td></tr><tr><td>Balance, December 31, 2017</td><td>$ 9,357</td><td>$ 4,349</td><td>$ (37)</td><td>$ 2,290</td><td>$ 15,959</td><td></td></tr><tr><td>Net income</td><td>—</td><td>370</td><td>—</td><td>73</td><td>443</td><td></td></tr><tr><td>Sale of noncontrolling interests</td><td>6</td><td>—</td><td>—</td><td>—</td><td>6</td><td></td></tr><tr><td>Changes in equity of noncontrolling interests</td><td>—</td><td>—</td><td>—</td><td>(60)</td><td>(60)</td><td></td></tr><tr><td>Distributions to member</td><td>—</td><td>(1,001)</td><td>—</td><td>—</td><td>(1,001)</td><td></td></tr><tr><td>Contributions from member</td><td>155</td><td>—</td><td>—</td><td>—</td><td>155</td><td></td></tr><tr><td>Other comprehensive income, net of income taxes</td><td>—</td><td>—</td><td>2</td><td>1</td><td>3</td><td></td></tr><tr><td>Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard</td><td>—</td><td>6</td><td>(3)</td><td>—</td><td>3</td><td></td></tr><tr><td>Balance, December 31, 2018</td><td>$ 9,518</td><td>$ 3,724</td><td>$ (38)</td><td>$ 2,304</td><td>$ 15,508</td><td></td></tr><tr><td>Net income</td><td>—</td><td>1,125</td><td>—</td><td>92</td><td>1,217</td><td></td></tr><tr><td>Sale of noncontrolling interests</td><td>7</td><td>—</td><td>—</td><td>—</td><td>7</td><td></td></tr><tr><td>Changes in equity of noncontrolling interests</td><td>—</td><td>—</td><td>—</td><td>(48)</td><td>(48)</td><td></td></tr><tr><td>Distributions to member</td><td>—</td><td>(899)</td><td>—</td><td>—</td><td>(899)</td><td></td></tr><tr><td>Contributions from member</td><td>41</td><td>—</td><td>—</td><td>—</td><td>41</td><td></td></tr><tr><td>Other comprehensive income, net of income taxes</td><td>—</td><td>—</td><td>6</td><td>(2)</td><td>4</td><td></td></tr><tr><td>Balance, December 31, 2019</td><td>$ 9,566</td><td>$ 3,950</td><td>$ (32)</td><td>$ 2,346</td><td>$ 15,830</td><td></td></tr></table>

See the Combined Notes to Consolidated Financial Statements



## Commonwealth Edison Company and Subsidiary Companies
Consolidated Statements of Operations and Comprehensive Income

<table><tr><td rowspan="2">(In millions)</td><td colspan="4">For the Years Ended December 31,</td></tr><tr><td>2019</td><td>2018</td><td>2017</td><td></td></tr><tr><td>Operating revenues</td><td></td><td></td><td></td><td></td></tr><tr><td>Electric operating revenues</td><td>$     5,850</td><td>$     5,884</td><td>$     5,478</td><td></td></tr><tr><td>Revenues from alternative revenue programs</td><td>(133)</td><td>(29)</td><td>43</td><td></td></tr><tr><td>Operating revenues from affiliates</td><td>30</td><td>27</td><td>15</td><td></td></tr><tr><td>Total operating revenues</td><td>5,747</td><td>5,882</td><td>5,536</td><td></td></tr><tr><td>Operating expenses</td><td></td><td></td><td></td><td></td></tr><tr><td>Purchased power</td><td>1,565</td><td>1,626</td><td>1,533</td><td></td></tr><tr><td>Purchased power from affiliates</td><td>376</td><td>529</td><td>108</td><td></td></tr><tr><td>Operating and maintenance</td><td>1,041</td><td>1,068</td><td>1,157</td><td></td></tr><tr><td>Operating and maintenance from affiliates</td><td>264</td><td>267</td><td>270</td><td></td></tr><tr><td>Depreciation and amortization</td><td>1,033</td><td>940</td><td>850</td><td></td></tr><tr><td>Taxes other than income taxes</td><td>301</td><td>311</td><td>296</td><td></td></tr><tr><td>Total operating expenses</td><td>4,580</td><td>4,741</td><td>4,214</td><td></td></tr><tr><td>Gain on sales of assets</td><td>4</td><td>5</td><td>1</td><td></td></tr><tr><td>Operating income</td><td>1,171</td><td>1,146</td><td>1,323</td><td></td></tr><tr><td>Other income and (deductions)</td><td></td><td></td><td></td><td></td></tr><tr><td>Interest expense, net</td><td>(346)</td><td>(334)</td><td>(348)</td><td></td></tr><tr><td>Interest expense to affiliates</td><td>(13)</td><td>(13)</td><td>(13)</td><td></td></tr><tr><td>Other, net</td><td>39</td><td>33</td><td>22</td><td></td></tr><tr><td>Total other income and (deductions)</td><td>(320)</td><td>(314)</td><td>(339)</td><td></td></tr><tr><td>Income before income taxes</td><td>851</td><td>832</td><td>984</td><td></td></tr><tr><td>Income taxes</td><td>163</td><td>168</td><td>417</td><td></td></tr><tr><td>Net income</td><td>$     688</td><td>$     664</td><td>$     567</td><td></td></tr><tr><td>Comprehensive income</td><td>$     688</td><td>$     664</td><td>$     567</td><td></td></tr></table>

See the Combined Notes to Consolidated Financial Statements



## Commonwealth Edison Company and Subsidiary Companies
Consolidated Statements of Cash Flows

<table><tr><td rowspan="2">(In millions)</td><td colspan="4">For the Years Ended December 31,</td></tr><tr><td>2019</td><td>2018</td><td>2017</td><td></td></tr><tr><td>Cash flows from operating activities</td><td></td><td></td><td></td><td></td></tr><tr><td>Net income</td><td>$     688</td><td>$     664</td><td>$     567</td><td></td></tr><tr><td>Adjustments to reconcile net income to net cash flows provided by operating activities:</td><td></td><td></td><td></td><td></td></tr><tr><td>Depreciation, amortization and accretion</td><td>1,033</td><td>940</td><td>850</td><td></td></tr><tr><td>Deferred income taxes and amortization of investment tax credits</td><td>109</td><td>259</td><td>659</td><td></td></tr><tr><td>Other non-cash operating activities</td><td>265</td><td>242</td><td>164</td><td></td></tr><tr><td>Changes in assets and liabilities:</td><td></td><td></td><td></td><td></td></tr><tr><td>Accounts receivable</td><td>(34)</td><td>(136)</td><td>(59)</td><td></td></tr><tr><td>Receivables from and payables to affiliates, net</td><td>(12)</td><td>26</td><td>8</td><td></td></tr><tr><td>Inventories</td><td>(16)</td><td>1</td><td>4</td><td></td></tr><tr><td>Accounts payable and accrued expenses</td><td>(51)</td><td>70</td><td>(297)</td><td></td></tr><tr><td>Counterparty collateral received (posted), net and cash deposits</td><td>48</td><td>11</td><td>(26)</td><td></td></tr><tr><td>Income taxes</td><td>95</td><td>62</td><td>(308)</td><td></td></tr><tr><td>Pension and non-pension postretirement benefit contributions</td><td>(77)</td><td>(42)</td><td>(41)</td><td></td></tr><tr><td>Other assets and liabilities</td><td>(345)</td><td>(348)</td><td>6</td><td></td></tr><tr><td>Net cash flows provided by operating activities</td><td>1,703</td><td>1,749</td><td>1,527</td><td></td></tr><tr><td>Cash flows from investing activities</td><td></td><td></td><td></td><td></td></tr><tr><td>Capital expenditures</td><td>(1,915)</td><td>(2,126)</td><td>(2,250)</td><td></td></tr><tr><td>Other investing activities</td><td>29</td><td>29</td><td>20</td><td></td></tr><tr><td>Net cash flows used in investing activities</td><td>(1,886)</td><td>(2,097)</td><td>(2,230)</td><td></td></tr><tr><td>Cash flows from financing activities</td><td></td><td></td><td></td><td></td></tr><tr><td>Changes in short-term borrowings</td><td>130</td><td>—</td><td>—</td><td></td></tr><tr><td>Issuance of long-term debt</td><td>700</td><td>1,350</td><td>1,000</td><td></td></tr><tr><td>Retirement of long-term debt</td><td>(300)</td><td>(840)</td><td>(425)</td><td></td></tr><tr><td>Dividends paid on common stock</td><td>(508)</td><td>(459)</td><td>(422)</td><td></td></tr><tr><td>Contributions from parent</td><td>250</td><td>500</td><td>651</td><td></td></tr><tr><td>Other financing activities</td><td>(16)</td><td>(17)</td><td>(15)</td><td></td></tr><tr><td>Net cash flows provided by financing activities</td><td>256</td><td>534</td><td>789</td><td></td></tr><tr><td>Increase in cash, cash equivalents and restricted cash</td><td>73</td><td>186</td><td>86</td><td></td></tr><tr><td>Cash, cash equivalents and restricted cash at beginning of period</td><td>330</td><td>144</td><td>58</td><td></td></tr><tr><td>Cash, cash equivalents and restricted cash at end of period</td><td>$     403</td><td>$     330</td><td>$     144</td><td></td></tr><tr><td>Supplemental cash flow information</td><td></td><td></td><td></td><td></td></tr><tr><td>(Decrease) increase in capital expenditures not paid</td><td>$      (37)</td><td>$     11</td><td>$      (61)</td><td></td></tr><tr><td>Increase in PPE related to ARO update</td><td>7</td><td>7</td><td>—</td><td></td></tr></table>

See the Combined Notes to Consolidated Financial Statements



## Commonwealth Edison Company and Subsidiary Companies
Consolidated Balance Sheets

<table><tr><td rowspan="2">(In millions)</td><td colspan="3">December 31,</td></tr><tr><td>2019</td><td>2018</td><td></td></tr><tr><td>ASSETS</td><td></td><td></td><td></td></tr><tr><td>Current assets</td><td></td><td></td><td></td></tr><tr><td>Cash and cash equivalents</td><td>$     90</td><td>$     135</td><td></td></tr><tr><td>Restricted cash and cash equivalents</td><td>150</td><td>29</td><td></td></tr><tr><td>Accounts receivable, net</td><td></td><td></td><td></td></tr><tr><td>Customer (net of allowance for uncollectible accounts of $59 and $61 as of December 31, 2019 and December 31, 2018, respectively)</td><td>545</td><td>539</td><td></td></tr><tr><td>Other (net of allowance for uncollectible accounts of $20 as of both December 31, 2019 and December 31, 2018, respectively)</td><td>286</td><td>320</td><td></td></tr><tr><td>Receivables from affiliates</td><td>28</td><td>20</td><td></td></tr><tr><td>Inventories, net</td><td>159</td><td>148</td><td></td></tr><tr><td>Regulatory assets</td><td>281</td><td>293</td><td></td></tr><tr><td>Other</td><td>44</td><td>86</td><td></td></tr><tr><td>Total current assets</td><td>1,583</td><td>1,570</td><td></td></tr><tr><td>Property, plant and equipment (net of accumulated depreciation and amortization of $5,168 and $4,684 as of December 31, 2019 and December 31, 2018, respectively)</td><td>23,107</td><td>22,058</td><td></td></tr><tr><td>Deferred debits and other assets</td><td></td><td></td><td></td></tr><tr><td>Regulatory assets</td><td>1,480</td><td>1,307</td><td></td></tr><tr><td>Investments</td><td>6</td><td>6</td><td></td></tr><tr><td>Goodwill</td><td>2,625</td><td>2,625</td><td></td></tr><tr><td>Receivables from affiliates</td><td>2,622</td><td>2,217</td><td></td></tr><tr><td>Prepaid pension asset</td><td>995</td><td>1,035</td><td></td></tr><tr><td>Other</td><td>347</td><td>395</td><td></td></tr><tr><td>Total deferred debits and other assets</td><td>8,075</td><td>7,585</td><td></td></tr><tr><td>Total assets</td><td>$     32,765</td><td>$     31,213</td><td></td></tr></table>

See the Combined Notes to Consolidated Financial Statements



## Commonwealth Edison Company and Subsidiary Companies
Consolidated Balance Sheets

<table><tr><td rowspan="2">(In millions)</td><td colspan="2">December 31,</td></tr><tr><td>2019</td><td>2018</td></tr><tr><td>LIABILITIES AND SHAREHOLDERS&#x27; EQUITY</td><td></td><td></td></tr><tr><td>Current liabilities</td><td></td><td></td></tr><tr><td>Short-term borrowings</td><td>$     130</td><td>$      —</td></tr><tr><td>Long-term debt due within one year</td><td>500</td><td>300</td></tr><tr><td>Accounts payable</td><td>527</td><td>607</td></tr><tr><td>Accrued expenses</td><td>385</td><td>373</td></tr><tr><td>Payables to affiliates</td><td>103</td><td>119</td></tr><tr><td>Customer deposits</td><td>118</td><td>111</td></tr><tr><td>Regulatory liabilities</td><td>200</td><td>293</td></tr><tr><td>Mark-to-market derivative liability</td><td>32</td><td>26</td></tr><tr><td>Other</td><td>122</td><td>96</td></tr><tr><td>Total current liabilities</td><td>2,117</td><td>1,925</td></tr><tr><td>Long-term debt</td><td>7,991</td><td>7,801</td></tr><tr><td>Long-term debt to financing trust</td><td>205</td><td>205</td></tr><tr><td>Deferred credits and other liabilities</td><td></td><td></td></tr><tr><td>Deferred income taxes and unamortized investment tax credits</td><td>4,021</td><td>3,813</td></tr><tr><td>Asset retirement obligations</td><td>128</td><td>118</td></tr><tr><td>Non-pension postretirement benefits obligations</td><td>180</td><td>201</td></tr><tr><td>Regulatory liabilities</td><td>6,542</td><td>6,050</td></tr><tr><td>Mark-to-market derivative liability</td><td>269</td><td>223</td></tr><tr><td>Other</td><td>635</td><td>630</td></tr><tr><td>Total deferred credits and other liabilities</td><td>11,775</td><td>11,035</td></tr><tr><td>Total liabilities</td><td>22,088</td><td>20,966</td></tr><tr><td>Commitments and contingencies</td><td></td><td></td></tr><tr><td>Shareholders&#x27; equity</td><td></td><td></td></tr><tr><td>Common stock ($12.50 par value, 250 shares authorized, 127 shares outstanding at December 31, 2019 and 2018)</td><td>1,588</td><td>1,588</td></tr><tr><td>Other paid-in capital</td><td>7,572</td><td>7,322</td></tr><tr><td>Retained deficit unappropriated</td><td>(1,639)</td><td>(1,639)</td></tr><tr><td>Retained earnings appropriated</td><td>3,156</td><td>2,976</td></tr><tr><td>Total shareholders&#x27; equity</td><td>10,677</td><td>10,247</td></tr><tr><td>Total liabilities and shareholders&#x27; equity</td><td>$     32,765</td><td>$     31,213</td></tr></table>

See the Combined Notes to Consolidated Financial Statements



Commonwealth Edison Company and Subsidiary Companies Consolidated Statements of Changes in Shareholders' Equity

<table><tr><td>(In millions)</td><td>Common Stock</td><td>Other Paid-In Capital</td><td>Retained Deficit Unappropriated</td><td>Retained Earnings Appropriated</td><td>Total Shareholders&#x27; Equity</td></tr><tr><td>Balance, December 31, 2016</td><td>$ 1,588</td><td>$ 6,150</td><td>$ (1,639)</td><td>$ 2,626</td><td>$ 8,725</td></tr><tr><td>Net income</td><td>—</td><td>—</td><td>567</td><td>—</td><td>567</td></tr><tr><td>Appropriation of retained earnings for future dividends</td><td>—</td><td>—</td><td>(567)</td><td>567</td><td>—</td></tr><tr><td>Common stock dividends</td><td>—</td><td>—</td><td>—</td><td>(422)</td><td>(422)</td></tr><tr><td>Contributions from parent</td><td>—</td><td>651</td><td>—</td><td>—</td><td>651</td></tr><tr><td>Parent tax matter indemnification</td><td>—</td><td>21</td><td>—</td><td>—</td><td>21</td></tr><tr><td>Balance, December 31, 2017</td><td>$ 1,588</td><td>$ 6,822</td><td>$ (1,639)</td><td>$ 2,771</td><td>$ 9,542</td></tr><tr><td>Net income</td><td>—</td><td>—</td><td>664</td><td>—</td><td>664</td></tr><tr><td>Appropriation of retained earnings for future dividends</td><td>—</td><td>—</td><td>(664)</td><td>664</td><td>—</td></tr><tr><td>Common stock dividends</td><td>—</td><td>—</td><td>—</td><td>(459)</td><td>(459)</td></tr><tr><td>Contributions from parent</td><td>—</td><td>500</td><td>—</td><td>—</td><td>500</td></tr><tr><td>Balance, December 31, 2018</td><td>$ 1,588</td><td>$ 7,322</td><td>$ (1,639)</td><td>$ 2,976</td><td>$ 10,247</td></tr><tr><td>Net income</td><td>—</td><td>—</td><td>688</td><td>—</td><td>688</td></tr><tr><td>Appropriation of retained earnings for future dividends</td><td>—</td><td>—</td><td>(688)</td><td>688</td><td>—</td></tr><tr><td>Common stock dividends</td><td>—</td><td>—</td><td>—</td><td>(508)</td><td>(508)</td></tr><tr><td>Contributions from parent</td><td>—</td><td>250</td><td>—</td><td>—</td><td>250</td></tr><tr><td>Balance, December 31, 2019</td><td>$ 1,588</td><td>$ 7,572</td><td>$ (1,639)</td><td>$ 3,156</td><td>$ 10,677</td></tr></table>

See the Combined Notes to Consolidated Financial Statements



## PECO Energy Company and Subsidiary Companies
Consolidated Statements of Operations and Comprehensive Income

<table><tr><td rowspan="2">(In millions)</td><td colspan="4">For the Years Ended December 31,</td></tr><tr><td>2019</td><td>2018</td><td>2017</td><td></td></tr><tr><td>Operating revenues</td><td></td><td></td><td></td><td></td></tr><tr><td>Electric operating revenues</td><td>$ 2,505</td><td>$ 2,469</td><td>$ 2,369</td><td></td></tr><tr><td>Natural gas operating revenues</td><td>610</td><td>568</td><td>494</td><td></td></tr><tr><td>Revenues from alternative revenue programs</td><td>(21)</td><td>(7)</td><td>—</td><td></td></tr><tr><td>Operating revenues from affiliates</td><td>6</td><td>8</td><td>7</td><td></td></tr><tr><td>Total operating revenues</td><td>3,100</td><td>3,038</td><td>2,870</td><td></td></tr><tr><td>Operating expenses</td><td></td><td></td><td></td><td></td></tr><tr><td>Purchased power</td><td>610</td><td>734</td><td>648</td><td></td></tr><tr><td>Purchased fuel</td><td>262</td><td>230</td><td>186</td><td></td></tr><tr><td>Purchased power from affiliates</td><td>157</td><td>126</td><td>135</td><td></td></tr><tr><td>Operating and maintenance</td><td>707</td><td>742</td><td>657</td><td></td></tr><tr><td>Operating and maintenance from affiliates</td><td>154</td><td>156</td><td>149</td><td></td></tr><tr><td>Depreciation and amortization</td><td>333</td><td>301</td><td>286</td><td></td></tr><tr><td>Taxes other than income taxes</td><td>165</td><td>163</td><td>154</td><td></td></tr><tr><td>Total operating expenses</td><td>2,388</td><td>2,452</td><td>2,215</td><td></td></tr><tr><td>Gain on sales of assets</td><td>1</td><td>1</td><td>—</td><td></td></tr><tr><td>Operating income</td><td>713</td><td>587</td><td>655</td><td></td></tr><tr><td>Other income and (deductions)</td><td></td><td></td><td></td><td></td></tr><tr><td>Interest expense, net</td><td>(124)</td><td>(115)</td><td>(115)</td><td></td></tr><tr><td>Interest expense to affiliates, net</td><td>(12)</td><td>(14)</td><td>(11)</td><td></td></tr><tr><td>Other, net</td><td>16</td><td>8</td><td>9</td><td></td></tr><tr><td>Total other income and (deductions)</td><td>(120)</td><td>(121)</td><td>(117)</td><td></td></tr><tr><td>Income before income taxes</td><td>593</td><td>466</td><td>538</td><td></td></tr><tr><td>Income taxes</td><td>65</td><td>6</td><td>104</td><td></td></tr><tr><td>Net income</td><td>$ 528</td><td>$ 460</td><td>$ 434</td><td></td></tr><tr><td>Comprehensive income</td><td>$ 528</td><td>$ 460</td><td>$ 434</td><td></td></tr></table>

See the Combined Notes to Consolidated Financial Statements



## PECO Energy Company and Subsidiary Companies
Consolidated Statements of Cash Flows

<table><tr><td rowspan="2">(In millions)</td><td colspan="4">For the Years Ended December 31,</td></tr><tr><td>2019</td><td>2018</td><td>2017</td><td></td></tr><tr><td>Cash flows from operating activities</td><td></td><td></td><td></td><td></td></tr><tr><td>Net income</td><td>$     528</td><td>$     460</td><td>$     434</td><td></td></tr><tr><td>Adjustments to reconcile net income to net cash flows provided by operating activities:</td><td></td><td></td><td></td><td></td></tr><tr><td>Depreciation, amortization and accretion</td><td>333</td><td>301</td><td>286</td><td></td></tr><tr><td>Gain on sale of assets</td><td>(1)</td><td>—</td><td>—</td><td></td></tr><tr><td>Deferred income taxes and amortization of investment tax credits</td><td>20</td><td>(5)</td><td>19</td><td></td></tr><tr><td>Other non-cash operating activities</td><td>38</td><td>51</td><td>54</td><td></td></tr><tr><td>Changes in assets and liabilities:</td><td></td><td></td><td></td><td></td></tr><tr><td>Accounts receivable</td><td>(29)</td><td>(74)</td><td>(44)</td><td></td></tr><tr><td>Receivables from and payables to affiliates, net</td><td>(5)</td><td>7</td><td>(6)</td><td></td></tr><tr><td>Inventories</td><td>4</td><td>(14)</td><td>1</td><td></td></tr><tr><td>Accounts payable and accrued expenses</td><td>(11)</td><td>(3)</td><td>6</td><td></td></tr><tr><td>Income taxes</td><td>(34)</td><td>15</td><td>34</td><td></td></tr><tr><td>Pension and non-pension postretirement benefit contributions</td><td>(28)</td><td>(28)</td><td>(24)</td><td></td></tr><tr><td>Other assets and liabilities</td><td>(64)</td><td>29</td><td>(5)</td><td></td></tr><tr><td>Net cash flows provided by operating activities</td><td>751</td><td>739</td><td>755</td><td></td></tr><tr><td>Cash flows from investing activities</td><td></td><td></td><td></td><td></td></tr><tr><td>Capital expenditures</td><td>(939)</td><td>(849)</td><td>(732)</td><td></td></tr><tr><td>Changes in intercompany money pool</td><td>(68)</td><td>—</td><td>131</td><td></td></tr><tr><td>Other investing activities</td><td>(1)</td><td>9</td><td>4</td><td></td></tr><tr><td>Net cash flows used in investing activities</td><td>(1,008)</td><td>(840)</td><td>(597)</td><td></td></tr><tr><td>Cash flows from financing activities</td><td></td><td></td><td></td><td></td></tr><tr><td>Issuance of long-term debt</td><td>325</td><td>700</td><td>325</td><td></td></tr><tr><td>Retirement of long-term debt</td><td>—</td><td>(500)</td><td>—</td><td></td></tr><tr><td>Dividends paid on common stock</td><td>(358)</td><td>(306)</td><td>(288)</td><td></td></tr><tr><td>Contributions from parent</td><td>188</td><td>89</td><td>16</td><td></td></tr><tr><td>Other financing activities</td><td>(6)</td><td>(22)</td><td>(3)</td><td></td></tr><tr><td>Net cash flows provided by (used in) financing activities</td><td>149</td><td>(39)</td><td>50</td><td></td></tr><tr><td>(Decrease) increase in cash, cash equivalents and restricted cash</td><td>(108)</td><td>(140)</td><td>208</td><td></td></tr><tr><td>Cash, cash equivalents and restricted cash at beginning of period</td><td>135</td><td>275</td><td>67</td><td></td></tr><tr><td>Cash, cash equivalents and restricted cash at end of period</td><td>$     27</td><td>$     135</td><td>$     275</td><td></td></tr><tr><td>Supplemental cash flow information</td><td></td><td></td><td></td><td></td></tr><tr><td>Increase (decrease) in capital expenditures not paid</td><td>$     40</td><td>$     12</td><td>$     22</td><td></td></tr></table>

See the Combined Notes to Consolidated Financial Statements



## PECO Energy Company and Subsidiary Companies
Consolidated Balance Sheets

<table><tr><td rowspan="2">(In millions)</td><td colspan="3">December 31,</td></tr><tr><td>2019</td><td>2018</td><td></td></tr><tr><td>ASSETS</td><td></td><td></td><td></td></tr><tr><td>Current assets</td><td></td><td></td><td></td></tr><tr><td>Cash and cash equivalents</td><td>$     21</td><td>$     130</td><td></td></tr><tr><td>Restricted cash and cash equivalents</td><td>6</td><td>5</td><td></td></tr><tr><td>Accounts receivable, net</td><td></td><td></td><td></td></tr><tr><td>Customer (net of allowance for uncollectible accounts of $55 and $53 as of December 31, 2019 and 2018, respectively)</td><td>357</td><td>321</td><td></td></tr><tr><td>Other (net of allowance for uncollectible accounts of $7 and $8 as of December 31, 2019 and 2018, respectively)</td><td>138</td><td>151</td><td></td></tr><tr><td>Receivables from affiliates</td><td>1</td><td>—</td><td></td></tr><tr><td>Receivable from Exelon intercompany pool</td><td>68</td><td>—</td><td></td></tr><tr><td>Inventories, net</td><td></td><td></td><td></td></tr><tr><td>Fossil fuel</td><td>36</td><td>38</td><td></td></tr><tr><td>Materials and supplies</td><td>35</td><td>37</td><td></td></tr><tr><td>Regulatory assets</td><td>41</td><td>81</td><td></td></tr><tr><td>Other</td><td>19</td><td>19</td><td></td></tr><tr><td>Total current assets</td><td>722</td><td>782</td><td></td></tr><tr><td>Property, plant and equipment (net of accumulated depreciation and amortization of $3,718 and $3,561 as of December 31, 2019 and 2018, respectively)</td><td>9,292</td><td>8,610</td><td></td></tr><tr><td>Deferred debits and other assets</td><td></td><td></td><td></td></tr><tr><td>Regulatory assets</td><td>554</td><td>460</td><td></td></tr><tr><td>Investments</td><td>27</td><td>25</td><td></td></tr><tr><td>Receivables from affiliates</td><td>480</td><td>389</td><td></td></tr><tr><td>Prepaid pension asset</td><td>365</td><td>349</td><td></td></tr><tr><td>Other</td><td>29</td><td>27</td><td></td></tr><tr><td>Total deferred debits and other assets</td><td>1,455</td><td>1,250</td><td></td></tr><tr><td>Total assets</td><td>$     11,469</td><td>$     10,642</td><td></td></tr></table>

See the Combined Notes to Consolidated Financial Statements



## PECO Energy Company and Subsidiary Companies
Consolidated Balance Sheets

<table><tr><td rowspan="2">(In millions)</td><td colspan="2">December 31,</td></tr><tr><td>2019</td><td>2018</td></tr><tr><td>LIABILITIES AND SHAREHOLDER&#x27;S EQUITY</td><td></td><td></td></tr><tr><td>Current liabilities</td><td></td><td></td></tr><tr><td>Accounts payable</td><td>$     387</td><td>$     370</td></tr><tr><td>Accrued expenses</td><td>101</td><td>113</td></tr><tr><td>Payables to affiliates</td><td>55</td><td>59</td></tr><tr><td>Customer deposits</td><td>69</td><td>68</td></tr><tr><td>Regulatory liabilities</td><td>91</td><td>175</td></tr><tr><td>Other</td><td>19</td><td>24</td></tr><tr><td>Total current liabilities</td><td>722</td><td>809</td></tr><tr><td>Long-term debt</td><td>3,405</td><td>3,084</td></tr><tr><td>Long-term debt to financing trusts</td><td>184</td><td>184</td></tr><tr><td>Deferred credits and other liabilities</td><td></td><td></td></tr><tr><td>Deferred income taxes and unamortized investment tax credits</td><td>2,080</td><td>1,933</td></tr><tr><td>Asset retirement obligations</td><td>28</td><td>27</td></tr><tr><td>Non-pension postretirement benefits obligations</td><td>288</td><td>288</td></tr><tr><td>Regulatory liabilities</td><td>510</td><td>421</td></tr><tr><td>Other</td><td>74</td><td>76</td></tr><tr><td>Total deferred credits and other liabilities</td><td>2,980</td><td>2,745</td></tr><tr><td>Total liabilities</td><td>7,291</td><td>6,822</td></tr><tr><td>Commitments and contingencies</td><td></td><td></td></tr><tr><td>Shareholder&#x27;s equity</td><td></td><td></td></tr><tr><td>Common stock (No par value, 500 shares authorized, 170 shares outstanding at December 31, 2019 and 2018)</td><td>2,766</td><td>2,578</td></tr><tr><td>Retained earnings</td><td>1,412</td><td>1,242</td></tr><tr><td>Total shareholder&#x27;s equity</td><td>4,178</td><td>3,820</td></tr><tr><td>Total liabilities and shareholder&#x27;s equity</td><td>$     11,469</td><td>$     10,642</td></tr></table>

See the Combined Notes to Consolidated Financial Statements



PECO Energy Company and Subsidiary Companies Consolidated Statements of Changes in Shareholder's Equity

<table><tr><td>(In millions)</td><td>Common Stock</td><td>Retained Earnings</td><td>Accumulated Other Comprehensive Income</td><td>Total Shareholder&#x27;s Equity</td></tr><tr><td>Balance, December 31, 2016</td><td>$ 2,473</td><td>$ 941</td><td>$ 1</td><td>$ 3,415</td></tr><tr><td>Net income</td><td>—</td><td>434</td><td>—</td><td>434</td></tr><tr><td>Common stock dividends</td><td>—</td><td>(288)</td><td>—</td><td>(288)</td></tr><tr><td>Contributions from parent</td><td>16</td><td>—</td><td>—</td><td>16</td></tr><tr><td>Balance, December 31, 2017</td><td>$ 2,489</td><td>$ 1,087</td><td>$ 1</td><td>$ 3,577</td></tr><tr><td>Net income</td><td>—</td><td>460</td><td>—</td><td>460</td></tr><tr><td>Common stock dividends</td><td>—</td><td>(306)</td><td>—</td><td>(306)</td></tr><tr><td>Contributions from parent</td><td>89</td><td>—</td><td>—</td><td>89</td></tr><tr><td>Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard</td><td>—</td><td>1</td><td>(1)</td><td>—</td></tr><tr><td>Balance, December 31, 2018</td><td>$ 2,578</td><td>$ 1,242</td><td>$ —</td><td>$ 3,820</td></tr><tr><td>Net income</td><td>—</td><td>528</td><td>—</td><td>528</td></tr><tr><td>Common stock dividends</td><td>—</td><td>(358)</td><td>—</td><td>(358)</td></tr><tr><td>Contributions from parent</td><td>188</td><td>—</td><td>—</td><td>188</td></tr><tr><td>Balance, December 31, 2019</td><td>$ 2,766</td><td>$ 1,412</td><td>$ —</td><td>$ 4,178</td></tr></table>

See the Combined Notes to Consolidated Financial Statements



## Baltimore Gas and Electric Company and Subsidiary Companies Consolidated Statements of Operations and Comprehensive Income

<table><tr><td rowspan="2">(In millions)</td><td colspan="4">For the Years Ended December 31,</td></tr><tr><td>2019</td><td>2018</td><td>2017</td><td></td></tr><tr><td>Operating revenues</td><td></td><td></td><td></td><td></td></tr><tr><td>Electric operating revenues</td><td>$ 2,368</td><td>$ 2,428</td><td>$ 2,384</td><td></td></tr><tr><td>Natural gas operating revenues</td><td>700</td><td>738</td><td>652</td><td></td></tr><tr><td>Revenues from alternative revenue programs</td><td>12</td><td>(26)</td><td>124</td><td></td></tr><tr><td>Operating revenues from affiliates</td><td>26</td><td>29</td><td>16</td><td></td></tr><tr><td>Total operating revenues</td><td>3,106</td><td>3,169</td><td>3,176</td><td></td></tr><tr><td>Operating expenses</td><td></td><td></td><td></td><td></td></tr><tr><td>Purchased power</td><td>585</td><td>671</td><td>566</td><td></td></tr><tr><td>Purchased fuel</td><td>181</td><td>254</td><td>183</td><td></td></tr><tr><td>Purchased power from affiliates</td><td>286</td><td>257</td><td>384</td><td></td></tr><tr><td>Operating and maintenance</td><td>600</td><td>615</td><td>563</td><td></td></tr><tr><td>Operating and maintenance from affiliates</td><td>160</td><td>162</td><td>153</td><td></td></tr><tr><td>Depreciation and amortization</td><td>502</td><td>483</td><td>473</td><td></td></tr><tr><td>Taxes other than income taxes</td><td>260</td><td>254</td><td>240</td><td></td></tr><tr><td>Total operating expenses</td><td>2,574</td><td>2,696</td><td>2,562</td><td></td></tr><tr><td>Gain on sales of assets</td><td>—</td><td>1</td><td>—</td><td></td></tr><tr><td>Operating income</td><td>532</td><td>474</td><td>614</td><td></td></tr><tr><td>Other income and (deductions)</td><td></td><td></td><td></td><td></td></tr><tr><td>Interest expense, net</td><td>(121)</td><td>(106)</td><td>(95)</td><td></td></tr><tr><td>Interest expense to affiliates</td><td>—</td><td>—</td><td>(10)</td><td></td></tr><tr><td>Other, net</td><td>28</td><td>19</td><td>16</td><td></td></tr><tr><td>Total other income and (deductions)</td><td>(93)</td><td>(87)</td><td>(89)</td><td></td></tr><tr><td>Income before income taxes</td><td>439</td><td>387</td><td>525</td><td></td></tr><tr><td>Income taxes</td><td>79</td><td>74</td><td>218</td><td></td></tr><tr><td>Net income</td><td>360</td><td>313</td><td>307</td><td></td></tr><tr><td>Comprehensive income</td><td>$ 360</td><td>$ 313</td><td>$ 307</td><td></td></tr></table>



## Baltimore Gas and Electric Company and Subsidiary Companies
Consolidated Statements of Cash Flows

<table><tr><td rowspan="2">(In millions)</td><td colspan="4">For the Years Ended December 31,</td></tr><tr><td>2019</td><td>2018</td><td>2017</td><td></td></tr><tr><td>Cash flows from operating activities</td><td></td><td></td><td></td><td></td></tr><tr><td>Net income</td><td>$     360</td><td>$     313</td><td>$     307</td><td></td></tr><tr><td>Adjustments to reconcile net income to net cash flows provided by operating activities:</td><td></td><td></td><td></td><td></td></tr><tr><td>Depreciation and amortization</td><td>502</td><td>483</td><td>473</td><td></td></tr><tr><td>Impairment losses on long-lived assets and regulatory assets</td><td>—</td><td>—</td><td>7</td><td></td></tr><tr><td>Deferred income taxes and amortization of investment tax credits</td><td>130</td><td>76</td><td>145</td><td></td></tr><tr><td>Other non-cash operating activities</td><td>85</td><td>58</td><td>65</td><td></td></tr><tr><td>Changes in assets and liabilities:</td><td></td><td></td><td></td><td></td></tr><tr><td>Accounts receivable</td><td>25</td><td>8</td><td>(5)</td><td></td></tr><tr><td>Receivables from and payables to affiliates, net</td><td>1</td><td>12</td><td>(4)</td><td></td></tr><tr><td>Inventories</td><td>(1)</td><td>2</td><td>(9)</td><td></td></tr><tr><td>Accounts payable and accrued expenses</td><td>(43)</td><td>(1)</td><td>(15)</td><td></td></tr><tr><td>Collateral (posted) received, net</td><td>(4)</td><td>4</td><td>—</td><td></td></tr><tr><td>Income taxes</td><td>(67)</td><td>(20)</td><td>60</td><td></td></tr><tr><td>Pension and non-pension postretirement benefit contributions</td><td>(48)</td><td>(54)</td><td>(53)</td><td></td></tr><tr><td>Other assets and liabilities</td><td>(192)</td><td>(92)</td><td>(150)</td><td></td></tr><tr><td>Net cash flows provided by operating activities</td><td>748</td><td>789</td><td>821</td><td></td></tr><tr><td>Cash flows from investing activities</td><td></td><td></td><td></td><td></td></tr><tr><td>Capital expenditures</td><td>(1,145)</td><td>(959)</td><td>(882)</td><td></td></tr><tr><td>Other investing activities</td><td>8</td><td>9</td><td>7</td><td></td></tr><tr><td>Net cash flows used in investing activities</td><td>(1,137)</td><td>(950)</td><td>(875)</td><td></td></tr><tr><td>Cash flows from financing activities</td><td></td><td></td><td></td><td></td></tr><tr><td>Changes in short-term borrowings</td><td>40</td><td>(42)</td><td>32</td><td></td></tr><tr><td>Issuance of long-term debt</td><td>400</td><td>300</td><td>300</td><td></td></tr><tr><td>Retirement of long-term debt</td><td>—</td><td>—</td><td>(41)</td><td></td></tr><tr><td>Retirement of long-term debt to financing trust</td><td>—</td><td>—</td><td>(250)</td><td></td></tr><tr><td>Dividends paid on common stock</td><td>(224)</td><td>(209)</td><td>(198)</td><td></td></tr><tr><td>Contributions from parent</td><td>193</td><td>109</td><td>184</td><td></td></tr><tr><td>Other financing activities</td><td>(8)</td><td>(2)</td><td>(5)</td><td></td></tr><tr><td>Net cash flows provided by financing activities</td><td>401</td><td>156</td><td>22</td><td></td></tr><tr><td>Increase (Decrease) in cash, cash equivalents and restricted cash</td><td>12</td><td>(5)</td><td>(32)</td><td></td></tr><tr><td>Cash, cash equivalents and restricted cash at beginning of period</td><td>13</td><td>18</td><td>50</td><td></td></tr><tr><td>Cash, cash equivalents and restricted cash at end of period</td><td>$     25</td><td>$     13</td><td>$     18</td><td></td></tr><tr><td>Supplemental cash flow information</td><td></td><td></td><td></td><td></td></tr><tr><td>Increase in capital expenditures not paid</td><td>$     6</td><td>$     50</td><td>$     23</td><td></td></tr></table>

See the Combined Notes to Consolidated Financial Statements



## Baltimore Gas and Electric Company
Balance Sheets

<table><tr><td rowspan="2">(In millions)</td><td colspan="2">December 31,</td></tr><tr><td>2019</td><td>2018</td></tr><tr><td>ASSETS</td><td></td><td></td></tr><tr><td>Current assets</td><td></td><td></td></tr><tr><td>Cash and cash equivalents</td><td>$     24</td><td>$     7</td></tr><tr><td>Restricted cash and cash equivalents</td><td></td><td>1</td></tr><tr><td>Accounts receivable, net</td><td></td><td></td></tr><tr><td>Customer (net of allowance for uncollectible accounts of $12 and $16 as of December 31, 2019 and 2018, respectively)</td><td></td><td></td></tr><tr><td></td><td>317</td><td>353</td></tr><tr><td>Other (net of allowance for uncollectible accounts of $5 and $4 as December 31, 2019 and 2018, respectively)</td><td>147</td><td>90</td></tr><tr><td>Receivables from affiliates</td><td>1</td><td>1</td></tr><tr><td>Inventories, net</td><td></td><td></td></tr><tr><td>Gas held in storage</td><td>30</td><td>36</td></tr><tr><td>Materials and supplies</td><td>46</td><td>39</td></tr><tr><td>Prepaid utility taxes</td><td>78</td><td>74</td></tr><tr><td>Regulatory assets</td><td>183</td><td>177</td></tr><tr><td>Other</td><td>6</td><td>3</td></tr><tr><td>Total current assets</td><td>833</td><td>786</td></tr><tr><td>Property, plant and equipment (net of accumulated depreciation and amortization of $3,834 and $3,633 as of December 31, 2019 and 2018, respectively)</td><td>8,990</td><td>8,243</td></tr><tr><td>Deferred debits and other assets</td><td></td><td></td></tr><tr><td>Regulatory assets</td><td>454</td><td>398</td></tr><tr><td>Investments</td><td>7</td><td>5</td></tr><tr><td>Prepaid pension asset</td><td>264</td><td>279</td></tr><tr><td>Other</td><td>86</td><td>5</td></tr><tr><td>Total deferred debits and other assets</td><td>811</td><td>687</td></tr><tr><td>Total assets</td><td>$     10,634</td><td>$     9,716</td></tr></table>

See the Combined Notes to Consolidated Financial Statements



## Baltimore Gas and Electric Company
Balance Sheets

<table><tr><td rowspan="2">(In millions)</td><td colspan="2">December 31,</td></tr><tr><td>2019</td><td>2018</td></tr><tr><td>LIABILITIES AND SHAREHOLDER&#x27;S EQUITY</td><td></td><td></td></tr><tr><td>Current liabilities</td><td></td><td></td></tr><tr><td>Short-term borrowings</td><td>$     76</td><td>$     35</td></tr><tr><td>Accounts payable</td><td>243</td><td>295</td></tr><tr><td>Accrued expenses</td><td>152</td><td>155</td></tr><tr><td>Payables to affiliates</td><td>66</td><td>65</td></tr><tr><td>Customer deposits</td><td>120</td><td>120</td></tr><tr><td>Regulatory liabilities</td><td>33</td><td>77</td></tr><tr><td>Other</td><td>63</td><td>27</td></tr><tr><td>Total current liabilities</td><td>753</td><td>774</td></tr><tr><td>Long-term debt</td><td>3,270</td><td>2,876</td></tr><tr><td>Deferred credits and other liabilities</td><td></td><td></td></tr><tr><td>Deferred income taxes and unamortized investment tax credits</td><td>1,396</td><td>1,222</td></tr><tr><td>Asset retirement obligations</td><td>22</td><td>24</td></tr><tr><td>Non-pension postretirement benefits obligations</td><td>199</td><td>201</td></tr><tr><td>Regulatory liabilities</td><td>1,195</td><td>1,192</td></tr><tr><td>Other</td><td>116</td><td>73</td></tr><tr><td>Total deferred credits and other liabilities</td><td>2,928</td><td>2,712</td></tr><tr><td>Total liabilities</td><td>6,951</td><td>6,362</td></tr><tr><td>Commitments and contingencies</td><td></td><td></td></tr><tr><td>Shareholder&#x27;s equity</td><td></td><td></td></tr><tr><td>Common stock (No par value, 0 shares \( ^{(a)} \)  authorized, 0 shares \( ^{(a)} \)  outstanding at December 31, 2019 and 2018)</td><td>1,907</td><td>1,714</td></tr><tr><td>Retained earnings</td><td>1,776</td><td>1,640</td></tr><tr><td>Total shareholder&#x27;s equity</td><td>3,683</td><td>3,354</td></tr><tr><td>Total liabilities and shareholder&#x27;s equity</td><td>$     10,634</td><td>$     9,716</td></tr></table>

(a) In millions, shares round to zero. Number of shares is 1,500 authorized and 1,000 outstanding at December 31, 2019 and 2018.

See the Combined Notes to Consolidated Financial Statements



Baltimore Gas and Electric Company and Subsidiary Companies Consolidated Statements of Changes in Shareholder's Equity

<table><tr><td>(In millions)</td><td>Common Stock</td><td>Retained Earnings</td><td>Total Shareholder&#x27;s Equity</td></tr><tr><td>Balance, December 31, 2016</td><td>$ 1,421</td><td>$ 1,427</td><td>$ 2,848</td></tr><tr><td>Net income</td><td>—</td><td>307</td><td>307</td></tr><tr><td>Common stock dividends</td><td>—</td><td>(198)</td><td>(198)</td></tr><tr><td>Contributions from parent</td><td>184</td><td>—</td><td>184</td></tr><tr><td>Balance, December 31, 2017</td><td>$ 1,605</td><td>$ 1,536</td><td>$ 3,141</td></tr><tr><td>Net income</td><td>—</td><td>313</td><td>313</td></tr><tr><td>Common stock dividends</td><td>—</td><td>(209)</td><td>(209)</td></tr><tr><td>Contributions from parent</td><td>109</td><td>—</td><td>109</td></tr><tr><td>Balance, December 31, 2018</td><td>$ 1,714</td><td>$ 1,640</td><td>$ 3,354</td></tr><tr><td>Net income</td><td>—</td><td>360</td><td>360</td></tr><tr><td>Common stock dividends</td><td>—</td><td>(224)</td><td>(224)</td></tr><tr><td>Contributions from parent</td><td>193</td><td>—</td><td>193</td></tr><tr><td>Balance, December 31, 2019</td><td>$ 1,907</td><td>$ 1,776</td><td>$ 3,683</td></tr></table>

See the Combined Notes to Consolidated Financial Statements



## Pepco Holdings LLC and Subsidiary Companies
Consolidated Statements of Operations and Comprehensive Income

<table><tr><td rowspan="2">(In millions)</td><td colspan="4">For the Years Ended December 31,</td></tr><tr><td>2019</td><td>2018</td><td>2017</td><td></td></tr><tr><td>Operating revenues</td><td></td><td></td><td></td><td></td></tr><tr><td>Electric operating revenues</td><td>$     4,639</td><td>$     4,609</td><td>$     4,428</td><td></td></tr><tr><td>Natural gas operating revenues</td><td>167</td><td>181</td><td>161</td><td></td></tr><tr><td>Revenues from alternative revenue programs</td><td>(14)</td><td>(7)</td><td>33</td><td></td></tr><tr><td>Operating revenues from affiliates</td><td>14</td><td>15</td><td>50</td><td></td></tr><tr><td>Total operating revenues</td><td>4,806</td><td>4,798</td><td>4,672</td><td></td></tr><tr><td>Operating expenses</td><td></td><td></td><td></td><td></td></tr><tr><td>Purchased power</td><td>1,371</td><td>1,387</td><td>1,182</td><td></td></tr><tr><td>Purchased fuel</td><td>75</td><td>89</td><td>71</td><td></td></tr><tr><td>Purchased power from affiliates</td><td>352</td><td>355</td><td>463</td><td></td></tr><tr><td>Operating and maintenance</td><td>939</td><td>978</td><td>918</td><td></td></tr><tr><td>Operating and maintenance from affiliates</td><td>143</td><td>152</td><td>150</td><td></td></tr><tr><td>Depreciation, amortization and accretion</td><td>754</td><td>740</td><td>675</td><td></td></tr><tr><td>Taxes other than income taxes</td><td>450</td><td>455</td><td>452</td><td></td></tr><tr><td>Total operating expenses</td><td>4,084</td><td>4,156</td><td>3,911</td><td></td></tr><tr><td>Gain on sales of assets</td><td>—</td><td>1</td><td>1</td><td></td></tr><tr><td>Operating income</td><td>722</td><td>643</td><td>762</td><td></td></tr><tr><td>Other income and (deductions)</td><td></td><td></td><td></td><td></td></tr><tr><td>Interest expense, net</td><td>(263)</td><td>(261)</td><td>(245)</td><td></td></tr><tr><td>Other, net</td><td>55</td><td>43</td><td>54</td><td></td></tr><tr><td>Total other income and (deductions)</td><td>(208)</td><td>(218)</td><td>(191)</td><td></td></tr><tr><td>Income before income taxes</td><td>514</td><td>425</td><td>571</td><td></td></tr><tr><td>Income taxes</td><td>38</td><td>33</td><td>217</td><td></td></tr><tr><td>Equity in earnings of unconsolidated affiliates</td><td>1</td><td>1</td><td>1</td><td></td></tr><tr><td>Net income</td><td>477</td><td>393</td><td>355</td><td></td></tr><tr><td>Comprehensive income</td><td>$     477</td><td>$     393</td><td>$     355</td><td></td></tr></table>

See the Combined Notes to Consolidated Financial Statements



## Pepco Holdings LLC and Subsidiary Companies
Consolidated Statements of Cash Flows

<table><tr><td rowspan="2">(In millions)</td><td colspan="4">For the Years Ended December 31,</td></tr><tr><td>2019</td><td>2018</td><td>2017</td><td></td></tr><tr><td>Cash flows from operating activities</td><td></td><td></td><td></td><td></td></tr><tr><td>Net income</td><td>$     477</td><td>$     393</td><td>$     355</td><td></td></tr><tr><td>Adjustments to reconcile net income (loss) to net cash from operating activities:</td><td></td><td></td><td></td><td></td></tr><tr><td>Depreciation and amortization</td><td>754</td><td>740</td><td>675</td><td></td></tr><tr><td>Impairment losses on intangibles and regulatory assets</td><td>—</td><td>—</td><td>52</td><td></td></tr><tr><td>Deferred income taxes and amortization of investment tax credits</td><td>(7)</td><td>30</td><td>252</td><td></td></tr><tr><td>Other non-cash operating activities</td><td>161</td><td>150</td><td>65</td><td></td></tr><tr><td>Changes in assets and liabilities:</td><td></td><td></td><td></td><td></td></tr><tr><td>Accounts receivable</td><td>(39)</td><td>(2)</td><td>(26)</td><td></td></tr><tr><td>Receivables from and payables to affiliates, net</td><td>3</td><td>8</td><td>(2)</td><td></td></tr><tr><td>Inventories</td><td>(27)</td><td>(14)</td><td>(37)</td><td></td></tr><tr><td>Accounts payable and accrued expenses</td><td>(17)</td><td>45</td><td>(106)</td><td></td></tr><tr><td>Income taxes</td><td>16</td><td>34</td><td>79</td><td></td></tr><tr><td>Pension and non-pension postretirement benefit contributions</td><td>(25)</td><td>(74)</td><td>(99)</td><td></td></tr><tr><td>Other assets and liabilities</td><td>(179)</td><td>(178)</td><td>(258)</td><td></td></tr><tr><td>Net cash flows provided by operating activities</td><td>1,117</td><td>1,132</td><td>950</td><td></td></tr><tr><td>Cash flows from investing activities</td><td></td><td></td><td></td><td></td></tr><tr><td>Capital expenditures</td><td>(1,355)</td><td>(1,375)</td><td>(1,396)</td><td></td></tr><tr><td>Other investing activities</td><td>(3)</td><td>4</td><td>(1)</td><td></td></tr><tr><td>Net cash flows used in investing activities</td><td>(1,358)</td><td>(1,371)</td><td>(1,397)</td><td></td></tr><tr><td>Cash flows from financing activities</td><td></td><td></td><td></td><td></td></tr><tr><td>Changes in short-term borrowings</td><td>154</td><td>(296)</td><td>328</td><td></td></tr><tr><td>Proceeds from short-term borrowings with maturities greater than 90 days</td><td>—</td><td>125</td><td>—</td><td></td></tr><tr><td>Repayments of short-term borrowings with maturities greater than 90 days</td><td>(125)</td><td>—</td><td>(500)</td><td></td></tr><tr><td>Issuance of long-term debt</td><td>485</td><td>750</td><td>202</td><td></td></tr><tr><td>Retirement of long-term debt</td><td>(157)</td><td>(299)</td><td>(169)</td><td></td></tr><tr><td>Change in Exelon intercompany money pool</td><td>12</td><td>—</td><td>—</td><td></td></tr><tr><td>Distributions to member</td><td>(526)</td><td>(326)</td><td>(311)</td><td></td></tr><tr><td>Contributions from member</td><td>398</td><td>385</td><td>758</td><td></td></tr><tr><td>Other financing activities</td><td>(5)</td><td>(9)</td><td>(2)</td><td></td></tr><tr><td>Net cash flows provided by financing activities</td><td>236</td><td>330</td><td>306</td><td></td></tr><tr><td>(Decrease) increase in cash, cash equivalents and restricted cash</td><td>(5)</td><td>91</td><td>(141)</td><td></td></tr><tr><td>Cash, cash equivalents and restricted cash at beginning of period</td><td>186</td><td>95</td><td>236</td><td></td></tr><tr><td>Cash, cash equivalents and restricted cash at end of period</td><td>$     181</td><td>$     186</td><td>$     95</td><td></td></tr><tr><td>Supplemental cash flow information</td><td></td><td></td><td></td><td></td></tr><tr><td>Increase (decrease) in capital expenditures not paid</td><td>$     2</td><td>$     93</td><td>$      (12)</td><td></td></tr></table>

See the Combined Notes to Consolidated Financial Statements



## Pepco Holdings LLC and Subsidiary Companies
Consolidated Balance Sheets

<table><tr><td rowspan="2">(In millions)</td><td colspan="3">December 31,</td></tr><tr><td>2019</td><td>2018</td><td></td></tr><tr><td>ASSETS</td><td></td><td></td><td></td></tr><tr><td>Current assets</td><td></td><td></td><td></td></tr><tr><td>Cash and cash equivalents</td><td>$     131</td><td>$     124</td><td></td></tr><tr><td>Restricted cash and cash equivalents</td><td></td><td>36</td><td>43</td></tr><tr><td>Accounts receivable, net</td><td></td><td></td><td></td></tr><tr><td>Customer (net of allowance for uncollectible accounts of $37 and $50 as of December 31, 2019 and 2018, respectively)</td><td></td><td>479</td><td>453</td></tr><tr><td>Other (net of allowance for uncollectible accounts of $16 and $3 as of December 31, 2019 and 2018, respectively)</td><td></td><td>174</td><td>177</td></tr><tr><td>Receivable from affiliates</td><td></td><td>1</td><td>—</td></tr><tr><td>Inventories, net</td><td></td><td></td><td></td></tr><tr><td>Fossil Fuel</td><td></td><td>8</td><td>9</td></tr><tr><td>Materials and supplies</td><td></td><td>190</td><td>163</td></tr><tr><td>Regulatory assets</td><td></td><td>412</td><td>457</td></tr><tr><td>Other</td><td></td><td>49</td><td>75</td></tr><tr><td>Total current assets</td><td></td><td>1,480</td><td>1,501</td></tr><tr><td>Property, plant and equipment (net of accumulated depreciation and amortization of $1,213 and $841 as of December 31, 2019 and 2018, respectively)</td><td></td><td>14,296</td><td>13,446</td></tr><tr><td>Deferred debits and other assets</td><td></td><td></td><td></td></tr><tr><td>Regulatory assets</td><td></td><td>2,061</td><td>2,312</td></tr><tr><td>Investments</td><td></td><td>135</td><td>130</td></tr><tr><td>Goodwill</td><td></td><td>4,005</td><td>4,005</td></tr><tr><td>Prepaid pension asset</td><td></td><td>406</td><td>486</td></tr><tr><td>Deferred income taxes</td><td></td><td>13</td><td>12</td></tr><tr><td>Other</td><td></td><td>323</td><td>60</td></tr><tr><td>Total deferred debits and other assets</td><td></td><td>6,943</td><td>7,005</td></tr><tr><td>Total assets(a)</td><td></td><td>$     22,719</td><td>$     21,952</td></tr></table>

See the Combined Notes to Consolidated Financial Statements



## Pepco Holdings LLC and Subsidiary Companies
Consolidated Balance Sheets

<table><tr><td rowspan="2">(In millions)</td><td colspan="2">December 31,</td></tr><tr><td>2019</td><td>2018</td></tr><tr><td>LIABILITIES AND EQUITY</td><td></td><td></td></tr><tr><td>Current liabilities</td><td></td><td></td></tr><tr><td>Short-term borrowings</td><td>$     208</td><td>$     179</td></tr><tr><td>Long-term debt due within one year</td><td>103</td><td>125</td></tr><tr><td>Accounts payable</td><td>462</td><td>496</td></tr><tr><td>Accrued expenses</td><td>296</td><td>256</td></tr><tr><td>Payables to affiliates</td><td>98</td><td>94</td></tr><tr><td>Borrowings from Exelon intercompany money pool</td><td>12</td><td>—</td></tr><tr><td>Customer deposits</td><td>117</td><td>116</td></tr><tr><td>Regulatory liabilities</td><td>70</td><td>84</td></tr><tr><td>Unamortized energy contract liabilities</td><td>115</td><td>119</td></tr><tr><td>Other</td><td>131</td><td>123</td></tr><tr><td>Total current liabilities</td><td>1,612</td><td>1,592</td></tr><tr><td>Long-term debt</td><td>6,460</td><td>6,134</td></tr><tr><td>Deferred credits and other liabilities</td><td></td><td></td></tr><tr><td>Deferred income taxes and unamortized investment tax credits</td><td>2,278</td><td>2,137</td></tr><tr><td>Asset retirement obligations</td><td>57</td><td>52</td></tr><tr><td>Non-pension postretirement benefit obligations</td><td>93</td><td>103</td></tr><tr><td>Regulatory liabilities</td><td>1,707</td><td>1,864</td></tr><tr><td>Unamortized energy contract liabilities</td><td>327</td><td>442</td></tr><tr><td>Other</td><td>577</td><td>369</td></tr><tr><td>Total deferred credits and other liabilities</td><td>5,039</td><td>4,967</td></tr><tr><td>Total liabilities(a)</td><td>13,111</td><td>12,693</td></tr><tr><td>Commitments and contingencies</td><td></td><td></td></tr><tr><td>Member&#x27;s equity</td><td></td><td></td></tr><tr><td>Membership interest</td><td>9,618</td><td>9,220</td></tr><tr><td>Undistributed (losses) gains</td><td>(10)</td><td>39</td></tr><tr><td>Total member&#x27;s equity</td><td>9,608</td><td>9,259</td></tr><tr><td>Total liabilities and member&#x27;s equity</td><td>$     22,719</td><td>$     21,952</td></tr></table>

(a) PHI's consolidated total assets include $20 million and $33 million at December 31, 2019 and 2018, respectively, of PHI's consolidated VIE that can only be used to settle the liabilities of the VIE. PHI's consolidated total liabilities include $44 million and $69 million at December 31, 2019 and 2018, respectively, of PHI's consolidated VIE for which the VIE creditors do not have recourse to PHI. See Note 22 - Variable Interest Entities for additional information.

See the Combined Notes to Consolidated Financial Statements



Pepco Holdings LLC and Subsidiary Companies
Consolidated Statements of Changes in Equity

<table><tr><td>(In millions)</td><td>Membership Interest</td><td>Undistributed (Losses)/Gains</td><td>Total Member&#x27;s Equity</td></tr><tr><td>Balance, December 31, 2016</td><td>$ 8,077</td><td>$ (72)</td><td>$ 8,005</td></tr><tr><td>Net income</td><td>—</td><td>355</td><td>355</td></tr><tr><td>Distribution to member</td><td>—</td><td>(311)</td><td>(311)</td></tr><tr><td>Contributions from member</td><td>758</td><td>—</td><td>758</td></tr><tr><td>Balance, December 31, 2017</td><td>$ 8,835</td><td>$ (28)</td><td>$ 8,807</td></tr><tr><td>Net Income</td><td>—</td><td>393</td><td>393</td></tr><tr><td>Distribution to member</td><td>—</td><td>(326)</td><td>(326)</td></tr><tr><td>Contributions from member</td><td>385</td><td>—</td><td>385</td></tr><tr><td>Balance, December 31, 2018</td><td>$ 9,220</td><td>$ 39</td><td>$ 9,259</td></tr><tr><td>Net income</td><td>—</td><td>477</td><td>477</td></tr><tr><td>Distribution to member</td><td>—</td><td>(526)</td><td>(526)</td></tr><tr><td>Contributions from member</td><td>398</td><td>—</td><td>398</td></tr><tr><td>Balance, December 31, 2019</td><td>$ 9,618</td><td>$ (10)</td><td>$ 9,608</td></tr></table>



## Potomac Electric Power Company
Statements of Operations and Comprehensive Income

<table><tr><td rowspan="2">(In millions)</td><td colspan="4">For the Years Ended December 31,</td></tr><tr><td>2019</td><td>2018</td><td>2017</td><td></td></tr><tr><td>Operating revenues</td><td></td><td></td><td></td><td></td></tr><tr><td>Electric operating revenues</td><td>$     2,258</td><td>$     2,233</td><td>$     2,126</td><td></td></tr><tr><td>Revenues from alternative revenue programs</td><td>(3)</td><td>(7)</td><td>19</td><td></td></tr><tr><td>Operating revenues from affiliates</td><td>5</td><td>6</td><td>6</td><td></td></tr><tr><td>Total operating revenues</td><td>2,260</td><td>2,232</td><td>2,151</td><td></td></tr><tr><td>Operating expenses</td><td></td><td></td><td></td><td></td></tr><tr><td>Purchased power</td><td>401</td><td>448</td><td>359</td><td></td></tr><tr><td>Purchased power from affiliates</td><td>264</td><td>206</td><td>255</td><td></td></tr><tr><td>Operating and maintenance</td><td>273</td><td>275</td><td>396</td><td></td></tr><tr><td>Operating and maintenance from affiliates</td><td>209</td><td>226</td><td>58</td><td></td></tr><tr><td>Depreciation and amortization</td><td>374</td><td>385</td><td>321</td><td></td></tr><tr><td>Taxes other than income taxes</td><td>378</td><td>379</td><td>371</td><td></td></tr><tr><td>Total operating expenses</td><td>1,899</td><td>1,919</td><td>1,760</td><td></td></tr><tr><td>Gain on sales of assets</td><td>—</td><td>—</td><td>1</td><td></td></tr><tr><td>Operating income</td><td>361</td><td>313</td><td>392</td><td></td></tr><tr><td>Other income and (deductions)</td><td></td><td></td><td></td><td></td></tr><tr><td>Interest expense, net</td><td>(133)</td><td>(128)</td><td>(121)</td><td></td></tr><tr><td>Other, net</td><td>31</td><td>31</td><td>32</td><td></td></tr><tr><td>Total other income and (deductions)</td><td>(102)</td><td>(97)</td><td>(89)</td><td></td></tr><tr><td>Income before income taxes</td><td>259</td><td>216</td><td>303</td><td></td></tr><tr><td>Income taxes</td><td>16</td><td>11</td><td>105</td><td></td></tr><tr><td>Net income</td><td>$     243</td><td>$     205</td><td>$     198</td><td></td></tr><tr><td>Comprehensive income</td><td>$     243</td><td>$     205</td><td>$     198</td><td></td></tr></table>

See the Combined Notes to Consolidated Financial Statements



## Potomac Electric Power Company
Statements of Cash Flows

<table><tr><td rowspan="2">(In millions)</td><td colspan="4">For the Years Ended December 31,</td></tr><tr><td>2019</td><td>2018</td><td>2017</td><td></td></tr><tr><td>Cash flows from operating activities</td><td></td><td></td><td></td><td></td></tr><tr><td>Net income</td><td>$     243</td><td>$     205</td><td>$     198</td><td></td></tr><tr><td>Adjustments to reconcile net income to net cash flows provided by operating activities:</td><td></td><td></td><td></td><td></td></tr><tr><td>Depreciation and amortization</td><td>374</td><td>385</td><td>321</td><td></td></tr><tr><td>Impairment losses on regulatory assets</td><td>—</td><td>—</td><td>14</td><td></td></tr><tr><td>Deferred income taxes and amortization of investment tax credits</td><td>1</td><td>(20)</td><td>113</td><td></td></tr><tr><td>Other non-cash operating activities</td><td>56</td><td>67</td><td>1</td><td></td></tr><tr><td>Changes in assets and liabilities:</td><td></td><td></td><td></td><td></td></tr><tr><td>Accounts receivable</td><td>(22)</td><td>(5)</td><td>(20)</td><td></td></tr><tr><td>Receivables from and payables to affiliates, net</td><td>5</td><td>(17)</td><td>—</td><td></td></tr><tr><td>Inventories</td><td>(19)</td><td>(6)</td><td>(24)</td><td></td></tr><tr><td>Accounts payable and accrued expenses</td><td>(39)</td><td>59</td><td>(63)</td><td></td></tr><tr><td>Income taxes</td><td>9</td><td>(13)</td><td>81</td><td></td></tr><tr><td>Pension and non-pension postretirement benefit contributions</td><td>(14)</td><td>(17)</td><td>(72)</td><td></td></tr><tr><td>Other assets and liabilities</td><td>(82)</td><td>(164)</td><td>(142)</td><td></td></tr><tr><td>Net cash flows provided by operating activities</td><td>512</td><td>474</td><td>407</td><td></td></tr><tr><td>Cash flows from investing activities</td><td></td><td></td><td></td><td></td></tr><tr><td>Capital expenditures</td><td>(626)</td><td>(656)</td><td>(628)</td><td></td></tr><tr><td>Other investing activities</td><td>3</td><td>2</td><td>—</td><td></td></tr><tr><td>Net cash flows used in investing activities</td><td>(623)</td><td>(654)</td><td>(628)</td><td></td></tr><tr><td>Cash flows from financing activities</td><td></td><td></td><td></td><td></td></tr><tr><td>Changes in short-term borrowings</td><td>42</td><td>14</td><td>3</td><td></td></tr><tr><td>Issuance of long-term debt</td><td>260</td><td>200</td><td>202</td><td></td></tr><tr><td>Retirement of long-term debt</td><td>(125)</td><td>(14)</td><td>(13)</td><td></td></tr><tr><td>Dividends paid on common stock</td><td>(213)</td><td>(169)</td><td>(133)</td><td></td></tr><tr><td>Contributions from parent</td><td>160</td><td>166</td><td>161</td><td></td></tr><tr><td>Other financing activities</td><td>(3)</td><td>(4)</td><td>(1)</td><td></td></tr><tr><td>Net cash flows provided by financing activities</td><td>121</td><td>193</td><td>219</td><td></td></tr><tr><td>Increase (decrease) in cash, cash equivalents and restricted cash</td><td>10</td><td>13</td><td>(2)</td><td></td></tr><tr><td>Cash, cash equivalents and restricted cash at beginning of period</td><td>53</td><td>40</td><td>42</td><td></td></tr><tr><td>Cash, cash equivalents and restricted cash at end of period</td><td>$     63</td><td>$     53</td><td>$     40</td><td></td></tr><tr><td>Supplemental cash flow information</td><td></td><td></td><td></td><td></td></tr><tr><td>Increase in capital expenditures not paid</td><td>$     39</td><td>$     20</td><td>$     5</td><td></td></tr></table>

See the Combined Notes to Consolidated Financial Statements



## Potomac Electric Power Company
Balance Sheets

<table><tr><td rowspan="2">(In millions)</td><td colspan="2">December 31,</td></tr><tr><td>2019</td><td>2018</td></tr><tr><td>ASSETS</td><td></td><td></td></tr><tr><td>Current assets</td><td></td><td></td></tr><tr><td>Cash and cash equivalents</td><td>$     30</td><td>$     16</td></tr><tr><td>Restricted cash and cash equivalents</td><td></td><td>33</td></tr><tr><td>Accounts receivable, net</td><td></td><td></td></tr><tr><td>Customer (net of allowance for uncollectible accounts of $13 and $20 as of December 31, 2019 and 2018, respectively)</td><td></td><td>231</td></tr><tr><td>Other (net of allowance for uncollectible accounts of $7 and $1 as of December 31, 2019 and 2018, respectively)</td><td></td><td>91</td></tr><tr><td>Receivables from affiliates</td><td></td><td>—</td></tr><tr><td>Inventories, net</td><td></td><td>112</td></tr><tr><td>Regulatory assets</td><td></td><td>188</td></tr><tr><td>Other</td><td></td><td>11</td></tr><tr><td>Total current assets</td><td></td><td>696</td></tr><tr><td>Property, plant and equipment (net of accumulated depreciation and amortization of $3,517 and $3,354 as of December 31, 2019 and 2018, respectively)</td><td></td><td>6,909</td></tr><tr><td>Deferred debits and other assets</td><td></td><td></td></tr><tr><td>Regulatory assets</td><td></td><td>584</td></tr><tr><td>Investments</td><td></td><td>110</td></tr><tr><td>Prepaid pension asset</td><td></td><td>296</td></tr><tr><td>Other</td><td></td><td>66</td></tr><tr><td>Total deferred debits and other assets</td><td></td><td>1,056</td></tr><tr><td>Total assets</td><td>$     8,661</td><td>$     8,267</td></tr></table>

See the Combined Notes to Consolidated Financial Statements



## Potomac Electric Power Company
Balance Sheets

<table><tr><td rowspan="2">(In millions)</td><td colspan="2">December 31,</td></tr><tr><td>2019</td><td>2018</td></tr><tr><td>LIABILITIES AND SHAREHOLDER&#x27;S EQUITY</td><td></td><td></td></tr><tr><td>Current liabilities</td><td></td><td></td></tr><tr><td>Short-term borrowings</td><td>$     82</td><td>$     40</td></tr><tr><td>Long-term debt due within one year</td><td>2</td><td>15</td></tr><tr><td>Accounts payable</td><td>195</td><td>214</td></tr><tr><td>Accrued expenses</td><td>156</td><td>126</td></tr><tr><td>Payables to affiliates</td><td>66</td><td>62</td></tr><tr><td>Customer deposits</td><td>57</td><td>54</td></tr><tr><td>Regulatory liabilities</td><td>8</td><td>7</td></tr><tr><td>Merger related obligation</td><td>39</td><td>38</td></tr><tr><td>Current portion of DC PLUG obligation</td><td>30</td><td>30</td></tr><tr><td>Other</td><td>22</td><td>42</td></tr><tr><td>Total current liabilities</td><td>657</td><td>628</td></tr><tr><td>Long-term debt</td><td>2,862</td><td>2,704</td></tr><tr><td>Deferred credits and other liabilities</td><td></td><td></td></tr><tr><td>Deferred income taxes and unamortized investment tax credits</td><td>1,131</td><td>1,055</td></tr><tr><td>Asset retirement obligations</td><td>41</td><td>37</td></tr><tr><td>Non-pension postretirement benefit obligations</td><td>20</td><td>29</td></tr><tr><td>Regulatory liabilities</td><td>746</td><td>822</td></tr><tr><td>Other</td><td>297</td><td>275</td></tr><tr><td>Total deferred credits and other liabilities</td><td>2,235</td><td>2,218</td></tr><tr><td>Total liabilities</td><td>5,754</td><td>5,550</td></tr><tr><td>Commitments and contingencies</td><td></td><td></td></tr><tr><td>Shareholder&#x27;s equity</td><td></td><td></td></tr><tr><td>Common stock ($0.01 par value, 200 shares authorized, 0 shares(a) outstanding at December 31, 2019 and 2018)</td><td>1,796</td><td>1,636</td></tr><tr><td>Retained earnings</td><td>1,111</td><td>1,081</td></tr><tr><td>Total shareholder&#x27;s equity</td><td>2,907</td><td>2,717</td></tr><tr><td>Total liabilities and shareholder&#x27;s equity</td><td>$     8,661</td><td>$     8,267</td></tr></table>

(a) In millions, shares round to zero. Number of shares is 100 outstanding at December 31, 2019 and 2018.



Potomac Electric Power Company
Statements of Changes in Shareholder's Equity

<table><tr><td>(In millions)</td><td colspan="2">Common Stock</td><td>Retained Earnings</td><td>Total Shareholder&#x27;s Equity</td></tr><tr><td>Balance, December 31, 2016</td><td>$</td><td>1,309</td><td>$</td><td>980</td></tr><tr><td>Net income</td><td></td><td>—</td><td>198</td><td>198</td></tr><tr><td>Common stock dividends</td><td></td><td>—</td><td>(133)</td><td>(133)</td></tr><tr><td>Contributions from parent</td><td></td><td>161</td><td>—</td><td>161</td></tr><tr><td>Balance, December 31, 2017</td><td>$</td><td>1,470</td><td>$</td><td>1,045</td></tr><tr><td>Net income</td><td></td><td>—</td><td>205</td><td>205</td></tr><tr><td>Common stock dividends</td><td></td><td>—</td><td>(169)</td><td>(169)</td></tr><tr><td>Contributions from parent</td><td></td><td>166</td><td>—</td><td>166</td></tr><tr><td>Balance, December 31, 2018</td><td>$</td><td>1,636</td><td>$</td><td>1,081</td></tr><tr><td>Net income</td><td></td><td>—</td><td>243</td><td>243</td></tr><tr><td>Common stock dividends</td><td></td><td>—</td><td>(213)</td><td>(213)</td></tr><tr><td>Contributions from parent</td><td></td><td>160</td><td>—</td><td>160</td></tr><tr><td>Balance, December 31, 2019</td><td>$</td><td>1,796</td><td>$</td><td>1,111</td></tr></table>

See the Combined Notes to Consolidated Financial Statements



Delmarva Power & Light Company
Statements of Operations and Comprehensive Income

<table><tr><td rowspan="2">(In millions)</td><td colspan="4">For the Years Ended December 31,</td></tr><tr><td>2019</td><td>2018</td><td>2017</td><td></td></tr><tr><td>Operating revenues</td><td></td><td></td><td></td><td></td></tr><tr><td>Electric operating revenues</td><td>$     1,143</td><td>$     1,139</td><td>$     1,125</td><td></td></tr><tr><td>Natural gas operating revenues</td><td>167</td><td>181</td><td>161</td><td></td></tr><tr><td>Revenues from alternative revenue programs</td><td>(11)</td><td>4</td><td>6</td><td></td></tr><tr><td>Operating revenues from affiliates</td><td>7</td><td>8</td><td>8</td><td></td></tr><tr><td>Total operating revenues</td><td>1,306</td><td>1,332</td><td>1,300</td><td></td></tr><tr><td>Operating expenses</td><td></td><td></td><td></td><td></td></tr><tr><td>Purchased power</td><td>381</td><td>352</td><td>282</td><td></td></tr><tr><td>Purchased fuel</td><td>75</td><td>89</td><td>71</td><td></td></tr><tr><td>Purchased power from affiliates</td><td>70</td><td>120</td><td>179</td><td></td></tr><tr><td>Operating and maintenance</td><td>171</td><td>182</td><td>283</td><td></td></tr><tr><td>Operating and maintenance from affiliates</td><td>152</td><td>162</td><td>32</td><td></td></tr><tr><td>Depreciation and amortization</td><td>184</td><td>182</td><td>167</td><td></td></tr><tr><td>Taxes other than income taxes</td><td>56</td><td>56</td><td>57</td><td></td></tr><tr><td>Total operating expenses</td><td>1,089</td><td>1,143</td><td>1,071</td><td></td></tr><tr><td>Gain on sales of assets</td><td>—</td><td>1</td><td>—</td><td></td></tr><tr><td>Operating income</td><td>217</td><td>190</td><td>229</td><td></td></tr><tr><td>Other income and (deductions)</td><td></td><td></td><td></td><td></td></tr><tr><td>Interest expense, net</td><td>(61)</td><td>(58)</td><td>(51)</td><td></td></tr><tr><td>Other, net</td><td>13</td><td>10</td><td>14</td><td></td></tr><tr><td>Total other income and (deductions)</td><td>(48)</td><td>(48)</td><td>(37)</td><td></td></tr><tr><td>Income before income taxes</td><td>169</td><td>142</td><td>192</td><td></td></tr><tr><td>Income taxes</td><td>22</td><td>22</td><td>71</td><td></td></tr><tr><td>Net income</td><td>$     147</td><td>$     120</td><td>$     121</td><td></td></tr><tr><td>Comprehensive income</td><td>$     147</td><td>$     120</td><td>$     121</td><td></td></tr></table>

See the Combined Notes to Consolidated Financial Statements



## Delmarva Power & Light Company
Statements of Cash Flows

<table><tr><td rowspan="2">(In millions)</td><td colspan="4">For the Years Ended December 31,</td></tr><tr><td>2019</td><td>2018</td><td>2017</td><td></td></tr><tr><td>Cash flows from operating activities</td><td></td><td></td><td></td><td></td></tr><tr><td>Net income</td><td>$     147</td><td>$     120</td><td>$     121</td><td></td></tr><tr><td>Adjustments to reconcile net income (loss) to net cash flows provided by operating activities:</td><td></td><td></td><td></td><td></td></tr><tr><td>Depreciation and amortization</td><td>184</td><td>182</td><td>167</td><td></td></tr><tr><td>Impairment losses on regulatory assets</td><td>—</td><td>—</td><td>6</td><td></td></tr><tr><td>Deferred income taxes and amortization of investment tax credits</td><td>(7)</td><td>24</td><td>89</td><td></td></tr><tr><td>Other non-cash operating activities</td><td>27</td><td>24</td><td>9</td><td></td></tr><tr><td>Changes in assets and liabilities:</td><td></td><td></td><td></td><td></td></tr><tr><td>Accounts receivable</td><td>(5)</td><td>8</td><td>(22)</td><td></td></tr><tr><td>Receivables from and payables to affiliates, net</td><td>(5)</td><td>(9)</td><td>11</td><td></td></tr><tr><td>Inventories</td><td>(6)</td><td>(3)</td><td>(5)</td><td></td></tr><tr><td>Accounts payable and accrued expenses</td><td>3</td><td>11</td><td>(8)</td><td></td></tr><tr><td>Income taxes</td><td>12</td><td>2</td><td>26</td><td></td></tr><tr><td>Pension and non-pension postretirement benefit contributions</td><td>(1)</td><td>—</td><td>(2)</td><td></td></tr><tr><td>Other assets and liabilities</td><td>(55)</td><td>(7)</td><td>(71)</td><td></td></tr><tr><td>Net cash flows provided by operating activities</td><td>294</td><td>352</td><td>321</td><td></td></tr><tr><td>Cash flows from investing activities</td><td></td><td></td><td></td><td></td></tr><tr><td>Capital expenditures</td><td>(348)</td><td>(364)</td><td>(428)</td><td></td></tr><tr><td>Other investing activities</td><td>1</td><td>2</td><td>(1)</td><td></td></tr><tr><td>Net cash flows used in investing activities</td><td>(347)</td><td>(362)</td><td>(429)</td><td></td></tr><tr><td>Cash flows from financing activities</td><td></td><td></td><td></td><td></td></tr><tr><td>Change in short-term borrowings</td><td>56</td><td>(216)</td><td>216</td><td></td></tr><tr><td>Issuance of long-term debt</td><td>75</td><td>200</td><td>—</td><td></td></tr><tr><td>Retirement of long-term debt</td><td>(12)</td><td>(4)</td><td>(40)</td><td></td></tr><tr><td>Dividends paid on common stock</td><td>(139)</td><td>(96)</td><td>(112)</td><td></td></tr><tr><td>Contributions from parent</td><td>63</td><td>150</td><td>—</td><td></td></tr><tr><td>Other financing activities</td><td>(1)</td><td>(2)</td><td>—</td><td></td></tr><tr><td>Net cash flows provided by financing activities</td><td>42</td><td>32</td><td>64</td><td></td></tr><tr><td>(Decrease) increase in cash, cash equivalents and restricted cash</td><td>(11)</td><td>22</td><td>(44)</td><td></td></tr><tr><td>Cash, cash equivalents and restricted cash at beginning of period</td><td>24</td><td>2</td><td>46</td><td></td></tr><tr><td>Cash, cash equivalents and restricted cash at end of period</td><td>$     13</td><td>$     24</td><td>$     2</td><td></td></tr><tr><td>Supplemental cash flow information</td><td></td><td></td><td></td><td></td></tr><tr><td>(Decrease) increase in capital expenditures not paid</td><td>$      (4)</td><td>$     22</td><td>$     4</td><td></td></tr></table>

See the Combined Notes to Consolidated Financial Statements



Delmarva Power & Light Company
Balance Sheets

<table><tr><td rowspan="2">(In millions)</td><td colspan="3">December 31,</td></tr><tr><td>2019</td><td>2018</td><td></td></tr><tr><td>ASSETS</td><td></td><td></td><td></td></tr><tr><td>Current assets</td><td></td><td></td><td></td></tr><tr><td>Cash and cash equivalents</td><td>$     13</td><td>$     23</td><td></td></tr><tr><td>Restricted cash and cash equivalents</td><td>—</td><td>1</td><td></td></tr><tr><td>Accounts receivable, net</td><td></td><td></td><td></td></tr><tr><td>Customer (net of allowance for uncollectible accounts of $11 and $12 as of December 31, 2019 and 2018, respectively)</td><td>141</td><td>134</td><td></td></tr><tr><td>Other (net of allowance for uncollectible accounts of $4 and $1 as of December 31, 2019 and 2018, respectively)</td><td>38</td><td>46</td><td></td></tr><tr><td>Inventories, net</td><td></td><td></td><td></td></tr><tr><td>Fossil Fuel</td><td>8</td><td>9</td><td></td></tr><tr><td>Materials and supplies</td><td>44</td><td>37</td><td></td></tr><tr><td>Prepaid utility taxes</td><td>18</td><td>17</td><td></td></tr><tr><td>Regulatory assets</td><td>52</td><td>59</td><td></td></tr><tr><td>Other</td><td>11</td><td>10</td><td></td></tr><tr><td>Total current assets</td><td>325</td><td>336</td><td></td></tr><tr><td>Property, plant and equipment, (net of accumulated depreciation and amortization of $1,425 and $1,329 as of December 31, 2019 and 2018, respectively)</td><td>4,035</td><td>3,821</td><td></td></tr><tr><td>Deferred debits and other assets</td><td></td><td></td><td></td></tr><tr><td>Regulatory assets</td><td>222</td><td>231</td><td></td></tr><tr><td>Goodwill</td><td>8</td><td>8</td><td></td></tr><tr><td>Prepaid pension asset</td><td>171</td><td>186</td><td></td></tr><tr><td>Other</td><td>69</td><td>6</td><td></td></tr><tr><td>Total deferred debits and other assets</td><td>470</td><td>431</td><td></td></tr><tr><td>Total assets</td><td>$     4,830</td><td>$     4,588</td><td></td></tr></table>

See the Combined Notes to Consolidated Financial Statements



## Delmarva Power & Light Company
Balance Sheets

<table><tr><td rowspan="2">(In millions)</td><td colspan="2">December 31,</td></tr><tr><td>2019</td><td>2018</td></tr><tr><td>LIABILITIES AND SHAREHOLDER&#x27;S EQUITY</td><td></td><td></td></tr><tr><td>Current liabilities</td><td></td><td></td></tr><tr><td>Short-term borrowings</td><td>$     56</td><td>$      —</td></tr><tr><td>Long-term debt due within one year</td><td>80</td><td>91</td></tr><tr><td>Accounts payable</td><td>112</td><td>111</td></tr><tr><td>Accrued expenses</td><td>46</td><td>39</td></tr><tr><td>Payables to affiliates</td><td>32</td><td>33</td></tr><tr><td>Customer deposits</td><td>36</td><td>35</td></tr><tr><td>Regulatory liabilities</td><td>37</td><td>59</td></tr><tr><td>Other</td><td>15</td><td>7</td></tr><tr><td>Total current liabilities</td><td>414</td><td>375</td></tr><tr><td>Long-term debt</td><td>1,487</td><td>1,403</td></tr><tr><td>Deferred credits and other liabilities</td><td></td><td></td></tr><tr><td>Deferred income taxes and unamortized investment tax credits</td><td>655</td><td>628</td></tr><tr><td>Non-pension postretirement benefit obligations</td><td>16</td><td>17</td></tr><tr><td>Regulatory liabilities</td><td>574</td><td>606</td></tr><tr><td>Other</td><td>104</td><td>50</td></tr><tr><td>Total deferred credits and other liabilities</td><td>1,349</td><td>1,301</td></tr><tr><td>Total liabilities</td><td>3,250</td><td>3,079</td></tr><tr><td>Commitments and contingencies</td><td></td><td></td></tr><tr><td>Shareholder&#x27;s equity</td><td></td><td></td></tr><tr><td>Common stock ($2.25 par value, 0 shares(a) authorized, 0 shares(a) outstanding at December 31, 2019 and 2018, respectively)</td><td>977</td><td>914</td></tr><tr><td>Retained earnings</td><td>603</td><td>595</td></tr><tr><td>Total shareholder&#x27;s equity</td><td>1,580</td><td>1,509</td></tr><tr><td>Total liabilities and shareholder&#x27;s equity</td><td>$     4,830</td><td>$     4,588</td></tr></table>

(a) In millions, shares round to zero. Number of shares is 1,000 authorized and 1,000 outstanding at December 31, 2019 and 2018.

See the Combined Notes to Consolidated Financial Statements



Delmarva Power & Light Company
Statements of Changes in Shareholder's Equity

<table><tr><td>(In millions)</td><td colspan="2">Common Stock</td><td colspan="2">Retained Earnings</td><td colspan="2">Total Shareholder&#x27;s Equity</td></tr><tr><td>Balance, December 31, 2016</td><td>$</td><td>764</td><td>$</td><td>562</td><td>$</td><td>1,326</td></tr><tr><td>Net income</td><td></td><td>—</td><td></td><td>121</td><td></td><td>121</td></tr><tr><td>Common stock dividends</td><td></td><td>—</td><td></td><td>(112)</td><td></td><td>(112)</td></tr><tr><td>Balance, December 31, 2017</td><td>$</td><td>764</td><td>$</td><td>571</td><td>$</td><td>1,335</td></tr><tr><td>Net income</td><td></td><td>—</td><td></td><td>120</td><td></td><td>120</td></tr><tr><td>Common stock dividends</td><td></td><td>—</td><td></td><td>(96)</td><td></td><td>(96)</td></tr><tr><td>Contributions from parent</td><td></td><td>150</td><td></td><td>—</td><td></td><td>150</td></tr><tr><td>Balance, December 31, 2018</td><td>$</td><td>914</td><td>$</td><td>595</td><td>$</td><td>1,509</td></tr><tr><td>Net income</td><td></td><td>—</td><td></td><td>147</td><td></td><td>147</td></tr><tr><td>Common stock dividends</td><td></td><td>—</td><td></td><td>(139)</td><td></td><td>(139)</td></tr><tr><td>Contributions from parent</td><td></td><td>63</td><td></td><td>—</td><td></td><td>63</td></tr><tr><td>Balance, December 31, 2019</td><td>$</td><td>977</td><td>$</td><td>603</td><td>$</td><td>1,580</td></tr></table>

See the Combined Notes to Consolidated Financial Statements



## Atlantic City Electric Company and Subsidiary Company
Consolidated Statements of Operations and Comprehensive Income

<table><tr><td rowspan="2">(In millions)</td><td colspan="4">For the Years Ended December 31,</td></tr><tr><td>2019</td><td>2018</td><td>2017</td><td></td></tr><tr><td>Operating revenues</td><td></td><td></td><td></td><td></td></tr><tr><td>Electric operating revenues</td><td>$ 1,237</td><td>$ 1,237</td><td>$ 1,176</td><td></td></tr><tr><td>Revenues from alternative revenue programs</td><td>—</td><td>(4)</td><td>8</td><td></td></tr><tr><td>Operating revenues from affiliates</td><td>3</td><td>3</td><td>2</td><td></td></tr><tr><td>Total operating revenues</td><td>1,240</td><td>1,236</td><td>1,186</td><td></td></tr><tr><td>Operating expenses</td><td></td><td></td><td></td><td></td></tr><tr><td>Purchased power</td><td>589</td><td>587</td><td>541</td><td></td></tr><tr><td>Purchased power from affiliates</td><td>19</td><td>29</td><td>29</td><td></td></tr><tr><td>Operating and maintenance</td><td>187</td><td>188</td><td>279</td><td></td></tr><tr><td>Operating and maintenance from affiliates</td><td>133</td><td>142</td><td>28</td><td></td></tr><tr><td>Depreciation and amortization</td><td>157</td><td>136</td><td>146</td><td></td></tr><tr><td>Taxes other than income taxes</td><td>4</td><td>5</td><td>6</td><td></td></tr><tr><td>Total operating expenses</td><td>1,089</td><td>1,087</td><td>1,029</td><td></td></tr><tr><td>Operating income</td><td>151</td><td>149</td><td>157</td><td></td></tr><tr><td>Other income and (deductions)</td><td></td><td></td><td></td><td></td></tr><tr><td>Interest expense, net</td><td>(58)</td><td>(64)</td><td>(61)</td><td></td></tr><tr><td>Other, net</td><td>6</td><td>2</td><td>7</td><td></td></tr><tr><td>Total other income and (deductions)</td><td>(52)</td><td>(62)</td><td>(54)</td><td></td></tr><tr><td>Income before income taxes</td><td>99</td><td>87</td><td>103</td><td></td></tr><tr><td>Income taxes</td><td>—</td><td>12</td><td>26</td><td></td></tr><tr><td>Net income</td><td>$ 99</td><td>$ 75</td><td>$ 77</td><td></td></tr><tr><td>Comprehensive income</td><td>$ 99</td><td>$ 75</td><td>$ 77</td><td></td></tr></table>

See the Combined Notes to Consolidated Financial Statements



## Atlantic City Electric Company and Subsidiary Company
Consolidated Statements of Cash Flows

<table><tr><td rowspan="2">(In millions)</td><td colspan="4">For the Years Ended December 31,</td></tr><tr><td>2019</td><td>2018</td><td>2017</td><td></td></tr><tr><td>Cash flows from operating activities</td><td></td><td></td><td></td><td></td></tr><tr><td>Net income</td><td>$     99</td><td>$     75</td><td>$     77</td><td></td></tr><tr><td>Adjustments to reconcile net income (loss) to net cash from operating activities:</td><td></td><td></td><td></td><td></td></tr><tr><td>Depreciation and amortization</td><td>157</td><td>136</td><td>146</td><td></td></tr><tr><td>Impairment losses on regulatory assets</td><td>—</td><td>—</td><td>7</td><td></td></tr><tr><td>Deferred income taxes and amortization of investment tax credits</td><td>3</td><td>25</td><td>32</td><td></td></tr><tr><td>Other non-cash operating activities</td><td>22</td><td>24</td><td>17</td><td></td></tr><tr><td>Changes in assets and liabilities:</td><td></td><td></td><td></td><td></td></tr><tr><td>Accounts receivable</td><td>(13)</td><td>(8)</td><td>14</td><td></td></tr><tr><td>Receivables from and payables to affiliates, net</td><td>(6)</td><td>1</td><td>—</td><td></td></tr><tr><td>Inventories</td><td>(1)</td><td>(4)</td><td>(7)</td><td></td></tr><tr><td>Accounts payable and accrued expenses</td><td>26</td><td>(7)</td><td>(2)</td><td></td></tr><tr><td>Income taxes</td><td>2</td><td>(2)</td><td>(11)</td><td></td></tr><tr><td>Pension and non-pension postretirement benefit contributions</td><td>(1)</td><td>(6)</td><td>(20)</td><td></td></tr><tr><td>Other assets and liabilities</td><td>(27)</td><td>(6)</td><td>(47)</td><td></td></tr><tr><td>Net cash flows provided by operating activities</td><td>261</td><td>228</td><td>206</td><td></td></tr><tr><td>Cash flows from investing activities</td><td></td><td></td><td></td><td></td></tr><tr><td>Capital expenditures</td><td>(375)</td><td>(335)</td><td>(312)</td><td></td></tr><tr><td>Other investing activities</td><td>(1)</td><td>1</td><td>(1)</td><td></td></tr><tr><td>Net cash flows used in investing activities</td><td>(376)</td><td>(334)</td><td>(313)</td><td></td></tr><tr><td>Cash flows from financing activities</td><td></td><td></td><td></td><td></td></tr><tr><td>Change in short-term borrowings</td><td>56</td><td>(94)</td><td>108</td><td></td></tr><tr><td>Proceeds from short-term borrowings with maturities greater than 90 days</td><td>—</td><td>125</td><td>—</td><td></td></tr><tr><td>Repayments of short-term borrowings with maturities greater than 90 days</td><td>(125)</td><td>—</td><td>—</td><td></td></tr><tr><td>Issuance of long-term debt</td><td>150</td><td>350</td><td>—</td><td></td></tr><tr><td>Retirement of long-term debt</td><td>(18)</td><td>(281)</td><td>(35)</td><td></td></tr><tr><td>Dividends paid on common stock</td><td>(124)</td><td>(59)</td><td>(68)</td><td></td></tr><tr><td>Contributions from parent</td><td>175</td><td>67</td><td>—</td><td></td></tr><tr><td>Other financing activities</td><td>(1)</td><td>(3)</td><td>—</td><td></td></tr><tr><td>Net cash flows provided by financing activities</td><td>113</td><td>105</td><td>5</td><td></td></tr><tr><td>Decrease in cash, cash equivalents and restricted cash</td><td>(2)</td><td>(1)</td><td>(102)</td><td></td></tr><tr><td>Cash, cash equivalents and restricted cash at beginning of period</td><td>30</td><td>31</td><td>133</td><td></td></tr><tr><td>Cash, cash equivalents and restricted cash at end of period</td><td>$     28</td><td>$     30</td><td>$     31</td><td></td></tr><tr><td>Supplemental cash flow information</td><td></td><td></td><td></td><td></td></tr><tr><td>(Decrease) increase in capital expenditures not paid</td><td>$      (29)</td><td>$     46</td><td>$      (13)</td><td></td></tr></table>

See the Combined Notes to Consolidated Financial Statements



## Atlantic City Electric Company and Subsidiary Company
Consolidated Balance Sheets

<table><tr><td rowspan="2">(In millions)</td><td colspan="3">December 31,</td></tr><tr><td>2019</td><td>2018</td><td></td></tr><tr><td>ASSETS</td><td></td><td></td><td></td></tr><tr><td>Current assets</td><td></td><td></td><td></td></tr><tr><td>Cash and cash equivalents</td><td>$ 12</td><td>$ 7</td><td></td></tr><tr><td>Restricted cash and cash equivalents</td><td>2</td><td>4</td><td></td></tr><tr><td>Accounts receivable, net</td><td></td><td></td><td></td></tr><tr><td>Customer (net of allowance for uncollectible accounts of $13 and $18 as of December 31, 2019 and 2018, respectively)</td><td>108</td><td>95</td><td></td></tr><tr><td>Other (net of allowance for uncollectible accounts of $5 and $1 as of December 31, 2019 and 2018, respectively)</td><td>48</td><td>55</td><td></td></tr><tr><td>Receivables from affiliates</td><td>4</td><td>1</td><td></td></tr><tr><td>Inventories, net</td><td>34</td><td>33</td><td></td></tr><tr><td>Regulatory assets</td><td>57</td><td>40</td><td></td></tr><tr><td>Other</td><td>5</td><td>5</td><td></td></tr><tr><td>Total current assets</td><td>270</td><td>240</td><td></td></tr><tr><td>Property, plant and equipment, (net of accumulated depreciation and amortization of $1,210 and $1,137 as of December 31, 2019 and 2018, respectively)</td><td>3,190</td><td>2,966</td><td></td></tr><tr><td>Deferred debits and other assets</td><td></td><td></td><td></td></tr><tr><td>Regulatory assets</td><td>368</td><td>386</td><td></td></tr><tr><td>Prepaid pension asset</td><td>52</td><td>67</td><td></td></tr><tr><td>Other</td><td>53</td><td>40</td><td></td></tr><tr><td>Total deferred debits and other assets</td><td>473</td><td>493</td><td></td></tr><tr><td>Total assets(a)</td><td>$ 3,933</td><td>$ 3,699</td><td></td></tr></table>

See the Combined Notes to Consolidated Financial Statements



## Atlantic City Electric Company and Subsidiary Company
Consolidated Balance Sheets

<table><tr><td rowspan="2">(In millions)</td><td colspan="2">December 31,</td></tr><tr><td>2019</td><td>2018</td></tr><tr><td>LIABILITIES AND SHAREHOLDER&#x27;S EQUITY</td><td></td><td></td></tr><tr><td>Current liabilities</td><td></td><td></td></tr><tr><td>Short-term borrowings</td><td>$     70</td><td>$     139</td></tr><tr><td>Long-term debt due within one year</td><td>20</td><td>18</td></tr><tr><td>Accounts payable</td><td>144</td><td>154</td></tr><tr><td>Accrued expenses</td><td>42</td><td>35</td></tr><tr><td>Payables to affiliates</td><td>25</td><td>28</td></tr><tr><td>Customer deposits</td><td>25</td><td>26</td></tr><tr><td>Regulatory liabilities</td><td>25</td><td>18</td></tr><tr><td>Other</td><td>9</td><td>4</td></tr><tr><td>Total current liabilities</td><td>360</td><td>422</td></tr><tr><td>Long-term debt</td><td>1,307</td><td>1,170</td></tr><tr><td>Deferred credits and other liabilities</td><td></td><td></td></tr><tr><td>Deferred income taxes and unamortized investment tax credits</td><td>577</td><td>535</td></tr><tr><td>Non-pension postretirement benefit obligations</td><td>17</td><td>17</td></tr><tr><td>Regulatory liabilities</td><td>357</td><td>402</td></tr><tr><td>Other</td><td>39</td><td>27</td></tr><tr><td>Total deferred credits and other liabilities</td><td>990</td><td>981</td></tr><tr><td>Total liabilities(a)</td><td>2,657</td><td>2,573</td></tr><tr><td>Commitments and contingencies</td><td></td><td></td></tr><tr><td>Shareholder&#x27;s equity</td><td></td><td></td></tr><tr><td>Common stock ($3 par value, 25 shares authorized, 9 shares outstanding at December 31, 2019 and 2018)</td><td>1,154</td><td>979</td></tr><tr><td>Retained earnings</td><td>122</td><td>147</td></tr><tr><td>Total shareholder&#x27;s equity</td><td>1,276</td><td>1,126</td></tr><tr><td>Total liabilities and shareholder&#x27;s equity</td><td>$     3,933</td><td>$     3,699</td></tr></table>

(a) ACE’s consolidated assets include $17 million and $23 million at December 31, 2019 and 2018, respectively, of ACE’s consolidated VIE that can only be used to settle the liabilities of the VIE. ACE’s consolidated liabilities include $41 million and $59 million at December 31, 2019 and 2018, respectively, of ACE’s consolidated VIE for which the VIE creditors do not have recourse to ACE. See Note 22 - Variable Interest Entities for additional information.



Atlantic City Electric Company and Subsidiary Company Consolidated Statements of Changes in Shareholder's Equity

<table><tr><td>(In millions)</td><td colspan="2">Common Stock</td><td colspan="2">Retained Earnings</td><td>Total Shareholder&#x27;s Equity</td></tr><tr><td>Balance, December 31, 2016</td><td>$</td><td>912</td><td>$</td><td>122</td><td>$ 1,034</td></tr><tr><td>Net income</td><td></td><td>—</td><td></td><td>77</td><td>77</td></tr><tr><td>Common stock dividends</td><td></td><td>—</td><td></td><td>(68)</td><td>(68)</td></tr><tr><td>Balance, December 31, 2017</td><td>$</td><td>912</td><td>$</td><td>131</td><td>$ 1,043</td></tr><tr><td>Net income</td><td></td><td>—</td><td></td><td>75</td><td>75</td></tr><tr><td>Common stock dividends</td><td></td><td>—</td><td></td><td>(59)</td><td>(59)</td></tr><tr><td>Contributions from parent</td><td></td><td>67</td><td></td><td>—</td><td>67</td></tr><tr><td>Balance, December 31, 2018</td><td>$</td><td>979</td><td>$</td><td>147</td><td>$ 1,126</td></tr><tr><td>Net income</td><td></td><td>—</td><td></td><td>99</td><td>99</td></tr><tr><td>Common stock dividends</td><td></td><td>—</td><td></td><td>(124)</td><td>(124)</td></tr><tr><td>Contributions from parent</td><td></td><td>175</td><td></td><td>—</td><td>175</td></tr><tr><td>Balance, December 31, 2019</td><td>$</td><td>1,154</td><td>$</td><td>122</td><td>$ 1,276</td></tr></table>



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

## 1. Significant Accounting Policies (All Registrants)

## Description of Business (All Registrants)

Exelon is a utility services holding company engaged in the generation, delivery and marketing of energy through Generation and the energy distribution and transmission businesses through ComEd, PECO, BGE, Pepco, DPL and ACE.

<table><tr><td>Name of Registrant</td><td>Business</td><td>Service Territories</td></tr><tr><td>Exelon Generation Company, LLC</td><td>Generation, physical delivery and marketing of power across multiple geographical regions through its customer-facing business, Constellation, which sells electricity to both wholesale and retail customers. Generation also sells natural gas, renewable energy and other energy-related products and services.</td><td>Five reportable segments: Mid-Atlantic, Midwest, New York, ERCOT and Other Power Regions</td></tr><tr><td>Commonwealth Edison Company</td><td>Purchase and regulated retail sale of electricity</td><td>Northern Illinois, including the City of Chicago</td></tr><tr><td></td><td>Transmission and distribution of electricity to retail customers</td><td></td></tr><tr><td>PECO Energy Company</td><td>Purchase and regulated retail sale of electricity and natural gas</td><td>Southeastern Pennsylvania, including the City of Philadelphia (electricity)</td></tr><tr><td></td><td>Transmission and distribution of electricity and distribution of natural gas to retail customers</td><td>Pennsylvania counties surrounding the City of Philadelphia (natural gas)</td></tr><tr><td>Baltimore Gas and Electric Company</td><td>Purchase and regulated retail sale of electricity and natural gas</td><td>Central Maryland, including the City of Baltimore (electricity and natural gas)</td></tr><tr><td></td><td>Transmission and distribution of electricity and distribution of natural gas to retail customers</td><td></td></tr><tr><td>Pepco Holdings LLC</td><td>Utility services holding company engaged, through its reportable segments Pepco, DPL and ACE</td><td>Service Territories of Pepco, DPL and ACE</td></tr><tr><td>Potomac Electric Power Company</td><td>Purchase and regulated retail sale of electricity</td><td>District of Columbia, and major portions of Montgomery and Prince George&#x27;s Counties, Maryland.</td></tr><tr><td></td><td>Transmission and distribution of electricity to retail customers</td><td></td></tr><tr><td>Delmarva Power &amp; Light Company</td><td>Purchase and regulated retail sale of electricity and natural gas</td><td>Portions of Delaware and Maryland (electricity)</td></tr><tr><td></td><td>Transmission and distribution of electricity and distribution of natural gas to retail customers</td><td>Portions of New Castle County, Delaware (natural gas)</td></tr><tr><td>Atlantic City Electric Company</td><td>Purchase and regulated retail sale of electricity</td><td>Portions of Southern New Jersey</td></tr><tr><td></td><td>Transmission and distribution of electricity to retail customers</td><td></td></tr></table>

## Basis of Presentation (All Registrants)

This is a combined annual report of all Registrants. The Notes to the Consolidated Financial Statements apply to the Registrants as indicated above in the Index to Combined Notes to Consolidated Financial Statements and parenthetically next to each corresponding disclosure. When appropriate, the Registrants are named specifically for their related activities and disclosures. Each of the Registrant's Consolidated Financial Statements includes the accounts of its subsidiaries. All intercompany transactions have been eliminated.

Through its business services subsidiary, BSC, Exelon provides its subsidiaries with a variety of support services at cost, including legal, human resources, financial, information technology and supply management services. PHI also has a business services subsidiary, PHISCO, which provides a variety of support services at cost, including legal, accounting, engineering, customer operations, distribution and transmission planning, asset management, system operations, and power procurement, to PHI operating companies. The costs of BSC and PHISCO are directly charged or allocated to the applicable subsidiaries. The results of Exelon's corporate operations are presented as "Other" within the consolidated financial statements and include intercompany eliminations unless otherwise disclosed.



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 1 — Significant Accounting Policies

Exelon owns 100% of Generation, PECO, BGE and PHI and more than 99% of ComEd. PHI owns 100% of Pepco, DPL and ACE. Generation owns 100% of its significant consolidated subsidiaries, either directly or indirectly, except for certain consolidated VIEs, including CENG and EGRP, of which Generation holds a 50.01% and 51% interest, respectively. The remaining interests in these consolidated VIEs are included in noncontrolling interests on Exelon's and Generation's Consolidated Balance Sheets. See Note 22 — Variable Interest Entities for additional information of Exelon's and Generation's consolidated VIEs.

The Registrants consolidate the accounts of entities in which a Registrant has a controlling financial interest, after the elimination of intercompany transactions. Where the Registrants do not have a controlling financial interest in an entity, proportionate consolidation, equity method accounting or accounting for investments in equity securities without readily determinable fair value is applied. The Registrants apply proportionate consolidation when they have an undivided interest in an asset and are proportionately liable for their share of each liability associated with the asset. The Registrants proportionately consolidate their undivided ownership interests in jointly owned electric plants and transmission facilities. Under proportionate consolidation, the Registrants separately record their proportionate share of the assets, liabilities, revenues and expenses related to the undivided interest in the asset. The Registrants apply equity method accounting when they have significant influence over an investee through an ownership in common stock, which generally approximates a 20% to 50% voting interest. The Registrants apply equity method accounting to certain investments and joint ventures, including certain financing trusts of ComEd and PECO. Under equity method accounting, the Registrants report their interest in the entity as an investment and the Registrants' percentage share of the earnings from the entity as single line items in their financial statements. The Registrants use accounting for investments in equity securities without readily determinable fair values if they lack significant influence, which generally results when they hold less than 20% of the common stock of an entity. Under accounting for investments in equity securities without readily determinable fair values, the Registrants report their investments at cost adjusted for changes from observable transactions for identical or similar investments of the same issuer, less impairment. Changes in measurement are reported in earnings.

The accompanying consolidated financial statements have been prepared in accordance with GAAP for annual financial statements and in accordance with the instructions to Form 10-K and Regulation S-X promulgated by the SEC.

## Use of Estimates (All Registrants)

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

## Prior Period Adjustments and Reclassifications (Exelon, PHI and Pepco)

In the fourth quarter 2019, management identified an error related to an overstatement of the regulatory asset associated with Pepco's decoupling mechanism for Maryland that originated in 2007 upon the inception of the program. Management has concluded that the error was not material to previously issued consolidated financial statements and the error was corrected through a revision to Exelon's, PHI's and Pepco's consolidated financial statements contained herein for the years ended December 31, 2018 and 2017. The impact of the error correction was an $11 million reduction to Exelon's, PHI's and Pepco's opening Retained earnings as of January 1, 2017 with a corresponding reduction to current Regulatory assets of $18 million and Deferred income taxes and unamortized investment tax credits of $7 million. In addition, Exelon's, PHI's and Pepco's Total operating revenues decreased by $7 million for the years ended December 31, 2018 and 2017 and Net income decreased by $5 million and $7 million for the years ended December 31, 2018 and 2017, respectively, from originally reported amounts. The error did not impact net cash flows provided by operating activities, net cash flows used in investing activities or net cash flows provided by financing activities for the years ended December 31, 2018 and 2017 for Exelon, PHI and Pepco. Exelon's diluted earnings per share of common stock remained unchanged from the originally reported amount for the year ended December 31, 2018. Exelon's basic earnings per share of common stock for the year ended December 31, 2018 and basic and diluted earnings per share of common stock for the year ended December 31, 2017 decreased by $0.01 from the originally reported amount.



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 1 — Significant Accounting Policies

## Accounting for the Effects of Regulation (Exelon and the Utility Registrants)

For their regulated electric and gas operations, Exelon and the Utility Registrants reflect the effects of cost-based rate regulation in their financial statements, which is required for entities with regulated operations that meet the following criteria: 1) rates are established or approved by a third-party regulator; (2) rates are designed to recover the entities' cost of providing services or products; and (3) there is a reasonable expectation that rates designed to recover costs can be charged to and collected from customers. Exelon and the Utility Registrants account for their regulated operations in accordance with regulatory and legislative guidance from the regulatory authorities having jurisdiction, principally the ICC, FPAC, MDPSC, DCPSC, DPSC and NJBPU, under state public utility laws and the FERC under various Federal laws. Regulatory assets and liabilities are amortized and the related expense or revenue is recognized in the Consolidated Statements of Operations consistent with the recovery or refund included in customer rates. Exelon's regulatory assets and liabilities as of the balance sheet date are probable of being recovered or settled in future rates. If a separable portion of the Registrants' business was no longer able to meet the criteria discussed above, the affected entities would be required to eliminate from their consolidated financial statements the effects of regulation for that portion, which could have a material impact on their financial statements. See Note 3 — Regulatory Matters for additional information.

With the exception of income tax-related regulatory assets and liabilities, Exelon and the Utility Registrants classify regulatory assets and liabilities with a recovery or settlement period greater than one year as both current and non-current in their Consolidated Balance Sheets, with the current portion representing the amount expected to be recovered from or settled to customers over the next twelve-month period as of the balance sheet date. Income tax-related regulatory assets and liabilities are classified entirely as non-current in Exelon's and the Utility Registrants' Consolidated Balance Sheets to align with the classification of the related deferred income tax balances.

Exelon and the Utility Registrants treat the impacts of a final rate order received after the balance sheet date but prior to the issuance of the financial statements as a non-recognized subsequent event, as the receipt of a final rate order is a separate and distinct event that has future impacts on the parties affected by the order.

## Revenues (All Registrants)

Operating Revenues. The Registrants' operating revenues generally consist of revenues from contracts with customers involving the sale and delivery of energy commodities and related products and services, utility revenues from ARP, and realized and unrealized revenues recognized under mark-to-market energy commodity derivative contracts. The Registrants recognize revenue from contracts with customers to depict the transfer of goods or services to customers in an amount that the entities expect to be entitled to in exchange for those goods or services. Generation's primary sources of revenue include competitive sales of power, natural gas, and other energy-related products and services. The Utility Registrants' primary sources of revenue include regulated electric and natural gas tariff sales, distribution and transmission services. At the end of each month, the Registrants accrue an estimate for the unbilled amount of energy delivered or services provided to customers.

ComEd records ARP revenue for its best estimate of the electric distribution, energy efficiency, and transmission revenue impacts resulting from future changes in rates that ComEd believes are probable of approval by the ICC and FERC in accordance with its formula rate mechanisms. BGE, Pepco and DPL record ARP revenue for their best estimate of the electric and natural gas distribution revenue impacts resulting from future changes in rates that they believe are probable of approval by the MDPSC and/or DCPSC in accordance with their revenue decoupling mechanisms. PECO, BGE, Pepco, DPL and ACE record ARP revenue for their best estimate of the transmission revenue impacts resulting from future changes in rates that they believe are probable of approval by FERC in accordance with their formula rate mechanisms. See Note 3 — Regulatory Matters for additional information.

Option Contracts, Swaps and Commodity Derivatives. Certain option contracts and swap arrangements that meet the definition of derivative instruments are recorded at fair value with subsequent changes in fair value recognized as revenue or expense. The classification of revenue or expense is based on the intent of the transaction. To the extent a Utility Registrant receives full cost recovery for energy procurement and related costs from retail customers, it records the fair value of its energy swap contracts with unaffiliated suppliers as well as an offsetting regulatory asset or liability in its Consolidated Balance Sheets. See Note 3 — Regulatory Matters and Note 15 — Derivative Financial Instruments for additional information.

Taxes Directly Imposed on Revenue-Producing Transactions. The Registrants collect certain taxes from customers such as sales and gross receipts taxes, along with other taxes, surcharges and fees, that are levied by



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 1 — Significant Accounting Policies

state or local governments on the sale or distribution of gas and electricity. Some of these taxes are imposed on the customer, but paid by the Registrants, while others are imposed on the Registrants. Where these taxes are imposed on the customer, such as sales taxes, they are reported on a net basis with no impact to the Consolidated Statements of Operations and Comprehensive Income. However, where these taxes are imposed on the Registrants, such as gross receipts taxes or other surcharges or fees, they are reported on a gross basis. Accordingly, revenues are recognized for the taxes collected from customers along with an offsetting expense. See Note 23 — Supplemental Financial Information for Generation's, ComEd's, PECO's, BGE's, Pepco's, DPL's and ACE's utility taxes that are presented on a gross basis.

## Leases (All Registrants)

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

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

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

The Registrants’ operating leases consist primarily of contracted generation, real estate including office buildings, and vehicles and equipment. The Registrants generally account for contracted generation in which the generating asset is not renewable as a lease if the customer has dispatch rights and obtains substantially all of the economic benefits. For new agreements entered after January 1, 2019, the Registrants generally do not account for contracted generation in which the generating asset is renewable as a lease if the customer does not design the generating asset. The Registrants account for land right arrangements that provide for exclusive use as leases while shared use land arrangements are generally not leases. The Registrants do not account for secondary use pole attachments as leases.

See Note 10 — Leases for additional information.

## Income Taxes (All Registrants)

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



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 1 — Significant Accounting Policies

benefits in Interest expense or Other income and deductions (interest income) and recognize penalties related to unrecognized tax benefits in Other, net in their Consolidated Statements of Operations and Comprehensive Income.

## Cash and Cash Equivalents (All Registrants)

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

## Restricted Cash and Cash Equivalents (All Registrants)

Restricted cash and cash equivalents represent funds that are restricted to satisfy designated current liabilities. As of December 31, 2019 and 2018, the Registrants' restricted cash and cash equivalents primarily represented the following items:

<table><tr><td>Registrant</td><td>Description</td></tr><tr><td>Exelon</td><td>Payment of medical, dental, vision and long-term disability benefits, in addition to the items listed for Generation and the Utility Registrants.</td></tr><tr><td>Generation</td><td>Project-specific nonrecourse financing structures for debt service and financing of operations of the underlying entities.</td></tr><tr><td>ComEd</td><td>Collateral held from suppliers associated with energy and REC procurement contracts, any over-recovered RPS costs and alternative compliance payments received from RES pursuant to FEA and costs for the remediation of an MGP site.</td></tr><tr><td>PECO</td><td>Proceeds from the sales of assets that were subject to PECO&#x27;s mortgage indenture.</td></tr><tr><td>BGE</td><td>Proceeds from the loan program for the completion of certain energy efficiency measures and collateral held from energy suppliers.</td></tr><tr><td>PHI</td><td>Payment of merger commitments, collateral held from its energy suppliers associated with procurement contracts and repayment of transition bonds.</td></tr><tr><td>Pepco</td><td>Payment of merger commitments and collateral held from energy suppliers.</td></tr><tr><td>DPL</td><td>Collateral held from energy suppliers.</td></tr><tr><td>ACE</td><td>Repayment of transition bonds and collateral held from energy suppliers.</td></tr></table>

Restricted cash and cash equivalents not available to satisfy current liabilities are classified as noncurrent assets. As of December 31, 2019 and 2018, the Registrants' noncurrent restricted cash and cash equivalents primarily represented ComEd's over-recovered RPS costs and alternative compliance payments received from RES pursuant to FEJA and costs for the remediation of an MGP site, and ACE's repayment of transition bonds.

See Note 23 — Supplemental Financial Information for additional information.

## Allowance for Uncollectible Accounts (All Registrants)

The allowance for uncollectible accounts reflects the Registrants' best estimates of losses on the customers' accounts receivable balances. For Generation, the allowance is based on accounts receivable aging historical experience and other currently available information. Utility Registrants estimate the allowance by applying loss rates developed specifically for each company to the outstanding receivable balance by customer risk segment. Utility Registrants' customer accounts are written off consistent with approved regulatory requirements. See Note 3 — Regulatory Matters for additional information regarding the regulatory recovery of uncollectible accounts receivable at ComEd and ACE.

## Variable Interest Entities (Exelon, Generation, PHI and ACE)

Exelon accounts for its investments in and arrangements with VIEs based on the following specific requirements:

• requires an entity to qualitatively assess whether it should consolidate a VIE based on whether the entity has a controlling financial interest,

• requires an ongoing reconsideration of this assessment instead of only upon certain triggering events, and

• requires the entity that consolidates a VIE (the primary beneficiary) to disclose (1) the assets of the consolidated VIE, if they can be used to only settle specific obligations of the consolidated VIE, and (2) the



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 1 — Significant Accounting Policies

liabilities of a consolidated VIE for which creditors do not have recourse to the general credit of the primary beneficiary.

See Note 22 — Variable Interest Entities for additional information.

## Inventories (All Registrants)

Inventory is recorded at the lower of weighted average cost or net realizable value. Provisions are recorded for excess and obsolete inventory. Fossil fuel, materials and supplies, and emissions allowances are generally included in inventory when purchased. Fossil fuel and emissions allowances are expensed to purchased power and fuel expense when used or sold. Materials and supplies generally includes transmission, distribution and generating plant materials and are expensed to operating and maintenance or capitalized to property, plant and equipment, as appropriate, when installed or used.

## Debt and Equity Security Investments (Exelon and Generation)

Debt Security Investments. Debt securities are reported at fair value and classified as available-for-sale securities. Unrealized gains and losses, net of tax, are reported in OCI.

Equity Security Investments without Readily Determinable Fair Values. Exelon has certain equity securities without readily determinable fair values. Exelon has elected to use the practicability exception to measure these investments, defined as cost adjusted for changes from observable transactions for identical or similar investments of the same issuer, less impairment. Changes in measurement are reported in earnings.

Equity Security Investments with Readily Determinable Fair Values. Equity securities held in the NDT funds are classified as equity securities with readily determinable fair values. Realized and unrealized gains and losses, net of tax, on Generation's NDT funds associated with the Regulatory Agreement Units are included in regulatory liabilities at Exelon, ComEd and PECO, in Noncurrent payables to affiliates at Generation and in Noncurrent receivables from affiliates at ComEd and PECO. Realized and unrealized gains and losses, net of tax, on Generation's NDT funds associated with the Non-Regulatory Agreement Units are included in earnings at Exelon and Generation. Exelon's and Generation's NDT funds are classified as current or noncurrent assets, depending on the timing of the decommissioning activities and income taxes on trust earnings. See Note 3 — Regulatory Matters for additional information regarding ComEd's and PECO's regulatory assets and liabilities and Note 17 — Fair Value of Financial Assets and Liabilities and Note 9 — Asset Retirement Obligations for additional information regarding marketable securities held by NDT funds.

## Property, Plant and Equipment (All Registrants)

Property, plant and equipment is recorded at original cost. Original cost includes construction-related direct labor and material costs. The Utility Registrants also include indirect construction costs including labor and related costs of departments associated with supporting construction activities. When appropriate, original cost also includes capitalized interest for Generation, Exelon Corporate and PHI and AFUDC for regulated property at the Utility Registrants. The cost of repairs and maintenance, including planned major maintenance activities and minor replacements of property, is charged to Operating and maintenance expense as incurred.

Third parties reimburse the Utility Registrants for all or a portion of expenditures for certain capital projects. Such contributions in aid of construction costs (CIAC) are recorded as a reduction to Property, plant and equipment, net. DOE SGIG and other funds reimbursed to the Utility Registrants have been accounted for as CIAC.

For Generation, upon retirement, the cost of property is generally charged to accumulated depreciation in accordance with the composite and group methods of depreciation. Upon replacement of an asset, the costs to remove the asset, net of salvage, are capitalized to gross plant when incurred as part of the cost of the newly-installed asset and recorded to depreciation expense over the life of the new asset. Removal costs, net of salvage, incurred for property that will not be replaced is charged to Operating and maintenance expense as incurred.

For the Utility Registrants, upon retirement, the cost of property, net of salvage, is charged to accumulated depreciation consistent with the composite and group methods of depreciation. Depreciation expense at ComEd, BGE, Pepco, DPL and ACE includes the estimated cost of dismantling and removing plant from service upon retirement. Actual incurred removal costs are applied against a related regulatory liability or recorded to a regulatory asset if in excess of previously collected removal costs. PECO's removal costs are capitalized to accumulated



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 1 — Significant Accounting Policies

depreciation when incurred, and recorded to depreciation expense over the life of the new asset constructed consistent with PECO's regulatory recovery method.

Capitalized Software. Certain costs, such as design, coding, and testing incurred during the application development stage of software projects that are internally developed or purchased for operational use are capitalized within Property, plant and equipment. Similar costs incurred for cloud-based solutions treated as service arrangements are capitalized within Other Current Assets and Deferred Debits and Other Assets. Such capitalized amounts are amortized ratably over the expected lives of the projects when they become operational, generally not to exceed five years. Certain other capitalized software costs are being amortized over longer lives based on the expected life or pursuant to prescribed regulatory requirements.

Capitalized Interest and AFUDC. During construction, Exelon and Generation capitalize the costs of debt funds used to finance non-regulated construction projects. Capitalization of debt funds is recorded as a charge to construction work in progress and as a non-cash credit to interest expense.

AFUDC is the cost, during the period of construction, of debt and equity funds used to finance construction projects for regulated operations. AFUDC is recorded to construction work in progress and as a non-cash credit to an allowance that is included in interest expense for debt-related funds and other income and deductions for equity-related funds. The rates used for capitalizing AFUDC are computed under a method prescribed by regulatory authorities.

See Note 7 — Property, Plant and Equipment, Note 8 — Jointly Owned Electric Utility Plant and Note 23 — Supplemental Financial Information for additional information regarding property, plant and equipment.

## Nuclear Fuel (Exelon and Generation)

The cost of nuclear fuel is capitalized within Property, plant and equipment and charged to fuel expense using the unit-of-production method. Any potential future SNF disposal fees will be expensed through fuel expense. Additionally, certain on-site SNF storage costs are being reimbursed by the DOE since a DOE (or government-owned) long-term storage facility has not been completed. See Note 18 — Commitments and Contingencies for additional information regarding the cost of SNF storage and disposal.

## Nuclear Outage Costs (Exelon and Generation)

Costs associated with nuclear outages, including planned major maintenance activities, are expensed to Operating and maintenance expense or capitalized to Property, plant and equipment (based on the nature of the activities) in the period incurred.

## Depreciation and Amortization (All Registrants)

Except for the amortization of nuclear fuel, depreciation is generally recorded over the estimated service lives of property, plant and equipment on a straight-line basis using the group, composite or unitary methods of depreciation. The group approach is typically for groups of similar assets that have approximately the same useful lives and the composite approach is used for dissimilar assets that have different lives. Under both methods, a reporting entity depreciates the assets over the average life of the assets in the group. The Utility Registrants' depreciation expense includes the estimated cost of dismantling and removing plant from service upon retirement, which is consistent with each utility's regulatory recovery method. The estimated service lives for the Registrants are based on a combination of depreciation studies, historical retirements, site licenses and management estimates of operating costs and expected future energy market conditions. See Note 6 — Early Plant Retirements for additional information on the impacts of expected and potential early plant retirements.

See Note 7 — Property, Plant and Equipment for additional information regarding depreciation.

Amortization of regulatory assets and liabilities are recorded over the recovery or refund period specified in the related legislation or regulatory order or agreement. When the recovery or refund period is less than one year, amortization is recorded to the line item in which the deferred cost or income would have originally been recorded in the Utility Registrants' Consolidated Statements of Operations and Comprehensive Income. Amortization of ComEd's electric distribution and energy efficiency formula rate regulatory assets and the Utility Registrants' transmission formula rate regulatory assets is recorded to Operating revenues.



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 1 — Significant Accounting Policies

Amortization of income tax related regulatory assets and liabilities is generally recorded to Income tax expense. With the exception of the regulatory assets and liabilities discussed above, when the recovery period is more than one year, the amortization is generally recorded to Depreciation and amortization in the Registrants' Consolidated Statements of Operations and Comprehensive Income.

See Note 3 — Regulatory Matters and Note 23 — Supplemental Financial Information for additional information regarding Generation’s nuclear fuel and ARC, and the amortization of the Utility Registrants’ regulatory assets.

## Asset Retirement Obligations (All Registrants)

Generation estimates and recognizes a liability for its legal obligation to perform asset retirement activities even though the timing and/or methods of settlement may be conditional on future events. Generation generally updates its nuclear decommissioning ARO annually, unless circumstances warrant more frequent updates, based on its annual evaluation of cost escalation factors and probabilities assigned to the multiple outcome scenarios within its probability-weighted discounted cash flow models. Generation's multiple outcome scenarios are generally based on decommissioning cost studies which are updated, on a rotational basis, for each of Generation's nuclear units at least every five years, unless circumstances warrant more frequent updates. AROs are accreted throughout each year to reflect the time value of money for these present value obligations through a charge to Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income for Non-Regulatory Agreement Units and through a decrease to regulatory liabilities for Regulatory Agreement Units or, in the case of the Utility Registrants' accretion, through an increase to regulatory assets. See Note 9 — Asset Retirement Obligations for additional information.

## Guarantees (All Registrants)

The Registrants recognize, at the inception of a guarantee, a liability for the fair market value of the obligations they have undertaken by issuing the guarantee, including the ongoing obligation to perform over the term of the guarantee in the event that the specified triggering events or conditions occur.

The liability that is initially recognized at the inception of the guarantee is reduced or eliminated as the Registrants are released from risk under the guarantee. Depending on the nature of the guarantee, the release from risk of the Registrant may be recognized only upon the expiration or settlement of the guarantee or by a systematic and rational amortization method over the term of the guarantee. See Note 18 — Commitments and Contingencies for additional information.

## Asset Impairments

Long-Lived Assets (All Registrants). The Registrants regularly monitor and evaluate the carrying value of long-lived assets and asset groups for recoverability whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators of impairment may include a deteriorating business climate, including, but not limited to, declines in energy prices, condition of the asset, specific regulatory disallowance, or plans to dispose of a long-lived asset significantly before the end of its useful life. The Registrants determine if long-lived assets and asset groups are impaired by comparing the undiscounted expected future cash flows to the carrying value. When the undiscounted cash flow analysis indicates a long-lived asset or asset group is not recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. See Note 11 — Asset Impairments for additional information.

Goodwill (Exelon, ComEd and PHI). Goodwill represents the excess of the purchase price paid over the estimated fair value of the net assets acquired and liabilities assumed in the acquisition of a business. Goodwill is not amortized, but is tested for impairment at least annually or on an interim basis if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. See Note 12 — Intangible Assets for additional information.

Equity Method Investments (Exelon and Generation). Exelon and Generation regularly monitor and evaluate equity method investments to determine whether they are impaired. An impairment is recorded when the investment has experienced a decline in value that is other-than-temporary in nature. Additionally, if the entity in which Generation holds an investment recognizes an impairment loss, Exelon and Generation would record their proportionate share of that impairment loss and evaluate the investment for an other-than-temporary decline in value.



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 1 — Significant Accounting Policies

Debt Security Investments (Exelon and Generation). Declines in the fair value of debt security investments below the cost basis are reviewed to determine if such decline is other-than-temporary. If the decline is determined to be other-than-temporary, the amount of the impairment loss is included in earnings.

Equity Security Investments (Exelon and Generation). Equity investments with readily determinable fair values are measured and recorded at fair value with any changes in fair value recorded through earnings. Investments in equity securities without readily determinable fair values are qualitatively assessed for impairment each reporting period. If it is determined that the equity security is impaired on the basis of the qualitative assessment, an impairment loss will be recognized in earnings to the amount by which the security's carrying amount exceeds its fair value.

## Derivative Financial Instruments (All Registrants)

All derivatives are recognized on the balance sheet at their fair value unless they qualify for certain exceptions, including the NPNS. For derivatives intended to serve as economic hedges, changes in fair value are recognized in earnings each period. Amounts classified in earnings are included in Operating revenue, Purchased power and fuel, Interest expense or Other, net in the Consolidated Statements of Operations and Comprehensive Income based on the activity the transaction is economically hedging. While the majority of the derivatives serve as economic hedges, there are also derivatives entered into for proprietary trading purposes, subject to Exelon's Risk Management Policy, and changes in the fair value of those derivatives are recorded in revenue in the Consolidated Statements of Operations and Comprehensive Income. At the Utility Registrants, changes in fair value may be recorded as a regulatory asset or liability if there is an ability to recover or return the associated costs. Cash inflows and outflows related to derivative instruments are included as a component of operating, investing or financing cash flows in the Consolidated Statements of Cash Flows, depending on the nature of each transaction. On July 1, 2018, Exelon and Generation de-designated its fair value and cash flow hedges. See Note 3 — Regulatory Matters and Note 15 — Derivative Financial Instruments for additional information.

As part of Generation’s energy marketing business, Generation enters into contracts to buy and sell energy to meet the requirements of its customers. These contracts include short-term and long-term commitments to purchase and sell energy and energy-related products in the energy markets with the intent and ability to deliver or take delivery of the underlying physical commodity. NPNS are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period of time and will not be financially settled. Revenues and expenses on derivative contracts that qualify, and are designated, as NPNS are recognized when the underlying physical transaction is completed. While these contracts are considered derivative financial instruments, they are not required to be recorded at fair value, but rather are recorded on an accrual basis of accounting. See Note 15 — Derivative Financial Instruments for additional information.

## Retirement Benefits (All Registrants)

Exelon sponsors defined benefit pension plans and OPEB plans for essentially all employees.

The plan obligations and costs of providing benefits under these plans are measured as of December 31. The measurement involves various factors assumptions, and accounting elections. The impact of assumption changes or experience different from that assumed on pension and OPEB obligations is recognized over time rather than immediately recognized in the Consolidated Statements of Operations and Comprehensive Income. Gains or losses in excess of the greater of ten percent of the projected benefit obligation or the MRV of plan assets are amortized over the expected average remaining service period of plan participants. See Note 14 — Retirement Benefits for additional information.

## New Accounting Standards (All Registrants)

New Accounting Standards Adopted in 2019: In 2019, the Registrants adopted the following new authoritative accounting guidance issued by the FASB.

Cloud Computing Arrangements (Issued August 2018). Aligns the requirements for capitalizing costs incurred to implement a cloud computing arrangement with the internal-use software guidance. As a result, certain implementation costs incurred in a cloud computing arrangement that are currently expensed as incurred will be deferred and amortized over the non-cancellable term of the arrangement plus any reasonably certain renewal periods. The standard was effective January 1, 2020 and can be applied using either a prospective or retrospective transition approach. A retrospective approach requires a cumulative-effect adjustment to retained earnings as of



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 1 — Significant Accounting Policies

the beginning of the period of adoption. The Registrants early adopted this standard using a prospective approach as of January 1, 2019. The new guidance did not have a material impact on the Registrants' financial statements.

Leases (Issued February 2016). The Registrants applied the new guidance with the following transition practical expedients:

• a "package of three" expedients that must be taken together and allow entities to (1) not reassess whether existing contracts contain leases, (2) carry forward the existing lease classification, and (3) not reassess initial direct costs associated with existing leases,

• an implementation expedient which allows the requirements of the standard in the period of adoption with no restatement of prior periods, and

• a land easement expedient which allows entities to not evaluate land easements under the new standard at adoption if they were not previously accounted for as leases.

The standard resulted in the Registrants recording ROU assets and lease liabilities for operating leases in their Consolidated Balance Sheets but did not have a material impact in the Registrants' Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and Consolidated Statements of Changes in Shareholders' Equity. The operating ROU assets and lease liabilities recognized upon adoption are materially consistent with the balances presented in the Combined Notes to the Consolidated Financial Statements, excluding 2019 expense and payment activity. See Note 10 — Leases for additional information.

New Accounting Standards Adopted as of January 1, 2020: The following new authoritative accounting guidance issued by the FASB was adopted as of January 1, 2020 and will be reflected by the Registrants in their consolidated financial statements beginning in the first quarter of 2020.

Impairment of Financial Instruments (Issued June 2016). Provides for a new Current Expected Credit Loss (CECL) impairment model for specified financial instruments including loans, trade receivables, debt securities classified as held-to-maturity investments and net investments in leases recognized by a lessor. Under the new guidance, on initial recognition and at each reporting period, an entity is required to recognize an allowance that reflects its current estimate of credit losses expected to be incurred over the life of the financial instrument based on historical experience, current conditions and reasonable and supportable forecasts. The standard was effective January 1, 2020 and requires a modified retrospective transition approach through a cumulative-effect adjustment to retained earnings as of the beginning of the period of adoption. This standard is primarily applicable to Generation's and the Utility Registrants' trade accounts receivables balances. The guidance did not have a significant impact on the Registrants' consolidated financial statements.

Goodwill Impairment (Issued January 2017). Simplifies the accounting for goodwill impairment by removing Step 2 of the current test, which requires calculation of a hypothetical purchase price allocation. Under the revised guidance, goodwill impairment will be measured as the amount by which a reporting unit's carrying value exceeds its fair value, not to exceed the carrying amount of goodwill (currently Step 1 of the two-step impairment test). Entities will continue to have the option to perform a qualitative assessment to determine if a quantitative impairment test is necessary. The standard was effective January 1, 2020 and must be applied on a prospective basis. Exelon, Generation, ComEd, PHI and DPL will apply the new guidance for their goodwill impairment assessments in 2020 and do not expect the updated guidance to have a material impact to their financial statements.

## 2. Mergers, Acquisitions and Dispositions (Exelon and Generation)

## CENG Put Option (Exelon and Generation)

Generation owns a 50.01% membership interest in CENG, a joint venture with EDF, which wholly owns the Calvert Cliffs and Ginna nuclear stations and Nine Mile Point Unit 1, in addition to an 82% undivided ownership interest in Nine Mile Point Unit 2. CENG is 100% consolidated in Exelon's and Generation's financial statements. See Note 22 — Variable Interest Entities for additional information.

On April 1, 2014, Generation and EDF entered into various agreements including a Nuclear Operating Services Agreement, an amended LLC Operating Agreement, an Employee Matters Agreement, and a Put Option Agreement, among others. Under the amended Operating Agreement, CENG made a $400 million special distribution to EDF



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 2 — Mergers, Acquisitions and Dispositions

and committed to make preferred distributions to Generation until Generation has received aggregate distributions of $400 million plus a return of 8.50% per annum. Under the Put Option Agreement, EDF has the option to sell its 49.99% equity interest in CENG to Generation exercisable beginning on January 1, 2016 and thereafter until June 30, 2022. On November 20, 2019, Generation received notice of EDF's intention to exercise the put option to sell its interest in CENG to Generation and the put automatically exercised on January 19, 2020 at the end of the sixty-day advance notice period.

Under the terms of the Put Option Agreement, the purchase price is to be determined by agreement of the parties, or absent such agreement, by a third-party arbitration process. The third parties determining fair market value of EDF's 49.99% interest are to take into consideration all rights and obligations under the LLC Operating Agreement and Employee Matters Agreement including but not limited to Generation's rights with respect to any unpaid aggregate preferred distributions and the related return. As of December 31, 2019, the total unpaid aggregate preferred distributions and related return owed to Generation is $571 million. At this time, Generation cannot reasonably predict the ultimate purchase price that will be paid to EDF for its interest in CENG. The transaction will require approval by the NYPSC, the FERC and the NRC. The process and regulatory approvals could take one to two years or more to complete.

## Acquisition of James A. FitzPatrick Nuclear Generating Station (Exelon and Generation)

On March 31, 2017, Generation acquired the single-unit James A. FitzPatrick (FitzPatrick) nuclear generating station located in Scriba, New York from Entergy Nuclear FitzPatrick LLC (Entergy) for a total purchase price of $289 million, which consisted of a cash purchase price of $110 million and a net cost reimbursement to and on behalf of Entergy of $179 million. As part of the transaction, Generation received the FitzPatrick NDT fund assets and assumed the obligation to decommission FitzPatrick. The NRC license for FitzPatrick expires in 2034. An after-tax bargain purchase gain of $233 million was included within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income which primarily reflects differences in strategies between Generation and Entergy for the intended use and ultimate decommissioning of the plant.

Exelon and Generation incurred $57 million of merger and integration related costs for FitzPatrick for the year ended December 31, 2017 which are included within Operating and maintenance expense in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.

## Disposition of Oyster Creek (Exelon and Generation)

On July 31, 2018, Generation entered into an agreement with Holtec International (Holtec) and its indirect wholly owned subsidiary, Oyster Creek Environmental Protection, LLC (OCEP), for the sale and decommissioning of Oyster Creek located in Forked River, New Jersey, which permanently ceased generation operations on September 17, 2018. Completion of the transaction contemplated by the sale agreement was subject to the satisfaction of several closing conditions, including approval of the license transfer from the NRC and other regulatory approvals, and a private letter ruling from the IRS, which were satisfied in the second quarter 2019. The sale was completed on July 1, 2019. Exelon and Generation recognized a loss on the sale in the third quarter, which was immaterial.

Under the terms of the transaction, Generation transferred to OCEP substantially all the assets associated with Oyster Creek, including assets held in NDT funds, along with the assumption of liability for all responsibility for the site, including full decommissioning and ongoing management of spent fuel until the spent fuel is moved offsite. The terms of the transaction also include various forms of performance assurance for the obligations of OCEP to timely complete the required decommissioning, including a parental guaranty from Holtec for all performance and payment obligations of OCEP, and a requirement for Holtec to deliver a letter of credit to Generation upon the occurrence of specified events.

As a result of the transaction, in the third quarter of 2018, Exelon and Generation reclassified certain Oyster Creek assets and liabilities in Exelon's and Generation's Consolidated Balance Sheets as held for sale at their respective fair values. Exelon and Generation had $897 million and $777 million of Assets and Liabilities held for sale, respectively, at December 31, 2018. Upon remeasurement of the Oyster Creek ARO, Exelon and Generation recognized an $84 million and a $9 million pre-tax charge to Operating and maintenance expense in the third quarter of 2018 and in the second quarter of 2019, respectively. See Note 9 — Asset Retirement Obligations for additional information.



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 2 — Mergers, Acquisitions and Dispositions

## Disposition of EGTP and Acquisition of Handley Generating Station (Exelon and Generation)

EGTP, a Delaware limited liability company, was formed in 2014 with the purpose of financing a portfolio of assets comprised of two combined-cycle gas turbines (CCGTs) and three peaking/simple cycle facilities consisting of approximately 3.4 GW of generation capacity in ERCOT North and Houston Zones. EGTP was an indirect wholly owned subsidiary of Exelon and Generation.

EGTP's operating cash flows were negatively impacted by certain market conditions and the seasonality of its cash flows. On May 2, 2017, as a result of the negative impacts of certain market conditions and the seasonality of its cash flows, EGTP entered into a consent agreement with its lenders to permit EGTP to draw on its revolving credit facility and initiate an orderly sales process to sell the assets of its wholly owned subsidiaries. As a result, Exelon and Generation classified certain of EGTP assets and liabilities as held for sale at their respective fair values less costs to sell and recorded a $460 million pre-tax impairment loss. See Note 16 — Debt and Credit Agreements for details regarding the nonrecourse debt associated with EGTP and Note 11 — Asset Impairments for additional information.

On November 7, 2017, EGTP and all of its wholly owned subsidiaries filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Code in the United States Bankruptcy Court for the District of Delaware, which resulted in Exelon and Generation deconsolidating EGTP's assets and liabilities from their consolidated financial statements in the fourth quarter of 2017 that resulted in a pre-tax gain upon deconsolidation of $213 million. Concurrently with the Chapter 11 filings, Generation entered into an asset purchase agreement to acquire one of EGTP's generating plants, the Handley Generating Station, subject to a potential adjustment for fuel oil and assumption of certain liabilities. In the Chapter 11 Filings, EGTP requested that the proposed acquisition of the Handley Generating Station be consummated through a court-approved and supervised sales process. The acquisition closed on April 4, 2018 for a purchase price of $62 million. The Chapter 11 bankruptcy proceedings were finalized on April 17, 2018, resulting in the ownership of EGTP assets (other than the Handley Generating Station) being transferred to EGTP's lenders.

## Disposition of Electrical Contracting Business (Exelon and Generation)

On February 28, 2018, Generation completed the sale of its interest in an electrical contracting business that primarily installs, maintains and repairs underground and high-voltage cable transmission and distribution systems for $87 million, resulting in a pre-tax gain which is included within Gain on sales of assets and businesses in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2018.



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

## 3. Regulatory Matters (All Registrants)

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

Utility Regulatory Matters (Exelon and the Utility Registrants)

Distribution Base Rate Case Proceedings

The following tables show the completed and pending distribution base rate case proceedings in 2019.

Completed Distribution Base Rate Case Proceedings

<table><tr><td>Registrant/Jurisdiction</td><td>Filing Date</td><td>Requested Revenue Requirement (Decrease) Increase</td><td>Approved Revenue Requirement (Decrease) Increase</td><td>Approved ROE</td><td>Approval Date</td><td>Rate Effective Date</td></tr><tr><td>ComEd - Illinois (Electric)(a)</td><td>April 16, 2018</td><td>$ (23)</td><td>$ (24)</td><td>8.69%</td><td>December 4, 2018</td><td>January 1, 2019</td></tr><tr><td>ComEd - Illinois (Electric)(a)</td><td>April 8, 2019</td><td>(6)</td><td>(17)</td><td>8.91%</td><td>December 4, 2019</td><td>January 1, 2020</td></tr><tr><td>PECO - Pennsylvania (Electric)</td><td>March 29, 2018</td><td>82</td><td>25</td><td>N/A</td><td>December 20, 2018</td><td>January 1, 2019</td></tr><tr><td>BGE - Maryland (Natural Gas)</td><td>June 8, 2018 (amended October 12, 2018)</td><td>61</td><td>43</td><td>9.8%</td><td>January 4, 2019</td><td>January 4, 2019</td></tr><tr><td>BGE - Maryland (Electric)</td><td>May 24, 2019 (amended December 17, 2019)</td><td>74</td><td>18</td><td>9.7%</td><td>December 17, 2019</td><td>December 17, 2019</td></tr><tr><td>BGE - Maryland (Natural Gas)</td><td>May 24, 2019 (amended December 17, 2019)</td><td>59</td><td>45</td><td>9.75%</td><td>December 17, 2019</td><td>December 17, 2019</td></tr><tr><td>ACE - New Jersey (Electric)</td><td>August 21, 2018 (amended November 19, 2018)</td><td>122</td><td>70</td><td>9.6%</td><td>March 13, 2019</td><td>April 1, 2019</td></tr><tr><td>Pepco - Maryland (Electric)</td><td>January 15, 2019 (amended May 16, 2019)</td><td>27</td><td>10</td><td>9.6%</td><td>August 12, 2019</td><td>August 13, 2019</td></tr></table>

(a) Pursuant to ELMA and FEJA, ComEd's electric distribution rates are established through a performance-based formula, which sunsets at the end of 2022. ComEd is required to file an annual update to its electric distribution formula rate on or before May 1 \( ^{st} \) , with resulting rates effective in January of the following year. ComEd's annual electric distribution formula rate update is based on prior year actual costs and current year projected capital additions (initial year revenue requirement). The update also reconciles any differences between the revenue requirement in effect for the prior year and actual costs incurred from the year (annual reconciliation).

ComEd's 2018 approved revenue requirement above reflects a decrease of $58 million for the initial year revenue requirement for 2018 and an increase of $34 million related to the annual reconciliation for 2017. The revenue requirement for 2018 and the annual reconciliation for 2017 provides for a weighted average debt and equity return on distribution rate base of 6.52%



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 3 — Regulatory Matters

inclusive of an allowed ROE of 8.69%, reflecting the average rate on 30-year treasury notes plus 580 basis points. ComEd's 2019 approved revenue requirement above reflects an increase of $51 million for the initial year revenue requirement for 2019 and a decrease of $68 million related to the annual reconciliation for 2018. The revenue requirement for 2019 and the annual reconciliation for 2018 provides for a weighted average debt and equity return on distribution rate base of 6.51% inclusive of an allowed ROE of 8.91%, reflecting the average rate on 30-year treasury notes plus 580 basis points. See table below for ComEd's regulatory assets associated with its electric distribution formula rate.

During the first quarter of 2018, ComEd revised its electric distribution formula rate to implement revenue decoupling provisions provided for under FEJA. As a result of this revision, ComEd's electric distribution formula rate revenues are not impacted by abnormal weather, usage per customer or numbers of customers. ComEd began reflecting the impacts of this change in its Operating revenues and electric distribution formula rate regulatory asset in the first quarter of 2017.

(b) The PECO rate case proceeding was resolved through a settlement agreement, which did not specify an approved ROE.

(c) Requested and approved increases are before New Jersey sales and use tax.

(d) ROEs in approved settlement are for the purpose of calculating AFUDC and carrying charges.

## Pending Distribution Base Rate Case Proceedings

<table><tr><td>Registration/Unregistration</td><td>Filing Date</td><td>Requested Revenue Requirement Increase</td><td>Requested ROE</td><td>Expected Approval Timing</td></tr><tr><td>Pepco - District of Columbia (Electric) \( ^{(a)} \)</td><td>May 30, 2019 (amended September 16, 2019)</td><td>$ 160</td><td>10.3%</td><td>Fourth quarter of 2020</td></tr><tr><td>DPL - Maryland (Electric)</td><td>December 5, 2019</td><td>19</td><td>10.3%</td><td>Third quarter of 2020</td></tr></table>

(a) Reflects a three-year cumulative multi-year plan and total requested revenue requirement increases of $84 million, $40 million and $36 million for years 2020, 2021, and 2022, respectively, to recover capital investments made in 2018 and 2019 and planned capital investments from 2020 to 2022.

## Transmission Formula Rates

Transmission Formula Rate (Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE). ComEd's, BGE's, Pepco's, DPL's and ACE's transmission rates are each established based on a FERC-approved formula. ComEd, BGE, Pepco, DPL and ACE are required to file an annual update to the FERC-approved formula on or before May 15, with the resulting rates effective on June 1 of the same year. The annual formula rate update is based on prior year actual costs and current year projected capital additions (initial year revenue requirement). The update also reconciles any differences between the revenue requirement in effect beginning June 1 of the prior year and actual costs incurred for that year (annual reconciliation).



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 3 — Regulatory Matters

For 2019, the following total increases/(decreases) were included in ComEd's, BGE's, Pepco's, DPL's and ACE's electric transmission formula rate filings:

<table><tr><td>Registrant</td><td>Initial Revenue Requirement Increase/(Decrease)</td><td>Annual Reconciliation (Decrease)/Increase</td><td>Total Revenue Requirement Increase/(Decrease)</td><td>Allowed Return on Rate Base(c)</td><td>Allowed ROE(d)</td></tr><tr><td>ComEd(a)</td><td>$ 21</td><td>$ (16)</td><td>$ 5</td><td>8.21%</td><td>11.50%</td></tr><tr><td>BGE(a)</td><td>(10)</td><td>(23)</td><td>(19)</td><td>(b)</td><td>7.35%</td></tr><tr><td>Pepco</td><td>15</td><td>11</td><td>26</td><td>7.75%</td><td>10.50%</td></tr><tr><td>DPL</td><td>17</td><td>(1)</td><td>16</td><td>7.14%</td><td>10.50%</td></tr><tr><td>ACE</td><td>11</td><td>(2)</td><td>9</td><td>7.79%</td><td>10.50%</td></tr></table>

(a) The time period for any formal challenges to the annual transmission formula rate update filings expired with no formal challenges submitted

(b) The change in BGE's transmission revenue requirement includes a FERC approved dedicated facilities charge of $14 million to recover the costs of providing transmission service to specifically designated load by BGE.

(c) Represents the weighted average debt and equity return on transmission rate bases.

(d) As part of the FERC-approved settlement of ComEd's 2007 transmission rate case, the rate of return on common equity is 11.50%, inclusive of a 50-basis-point incentive adder for being a member of a RTO, and the common equity component of the ratio used to calculate the weighted average debt and equity return for the transmission formula rate is currently capped at 55%. As part of the FERC-approved settlement of the ROE complaint against BGE, Pepco, DPL and ACE, the rate of return on common equity is 10.50%, inclusive of a 50-basis-point incentive adder for being a member of a RTO.

Transmission Formula Rate (Exelon and PECO). On May 1, 2017, PECO filed a request with FERC seeking approval to update its transmission rates and change the manner in which PECO's transmission rate is determined from a fixed rate to a formula rate. The formula rate will be updated annually to ensure that under this rate customers pay the actual costs of providing transmission services. PECO's initial formula rate filing included a requested increase of $22 million to PECO's annual transmission revenue requirement, which reflected a ROE of 11%, inclusive of a 50 basis point adder for being a member of a RTO. On June 27, 2017, FERC issued an Order accepting the filing and suspending the proposed rates until December 1, 2017, subject to refund, and set the matter for hearing and settlement judge procedures.

On December 5, 2019, FERC issued an Order accepting without modification the settlement agreement filed by PECO and other parties in July 2019. The settlement results in an increase of approximately $14 million with a return on rate base of 7.62% compared to PECO's initial formula rate filing and allows for an ROE of 10.35%, inclusive of a 50 basis point adder for being a member of the RTO. The settlement did not have a material impact on PECO's 2017, 2018, or 2019 annual transmission revenue requirements. PECO will update its rates in 2020 and refund estimated overcollections totaling approximately $28 million related to the amounts billed under the proposed rates in effect since 2017.

Pursuant to the transmission formula rate request discussed above, PECO made its annual formula rate updates in May 2018 and 2019, which included a decrease of $6 million and an increase of $8 million, respectively, to the annual transmission revenue requirement. The updated transmission formula rates were effective on June 1, 2018 and 2019, respectively, subject to refund.

## Other State Regulatory Matters

## Illinois Regulatory Matters

Energy Efficiency Formula Rate (Exelon and ComEd). FEJA allows ComEd to defer energy efficiency costs (except for any voltage optimization costs which are recovered through the electric distribution formula rate) as a separate regulatory asset that is recovered through the energy efficiency formula rate over the weighted average useful life, as approved by the ICC, of the related energy efficiency measures. ComEd earns a return on the energy efficiency regulatory asset at a rate equal to its weighted average cost of capital, which is based on a year-end capital structure and calculated using the same methodology applicable to ComEd's electric distribution formula rate. Beginning January 1, 2018 through December 31, 2030, the return on equity that ComEd earns on its energy efficiency regulatory asset is subject to a maximum downward or upward adjustment of 200 basis points if ComEd's



cumulative persisting annual MWh savings falls short of or exceeds specified percentage benchmarks of its annual incremental savings goal. ComEd is required to file an update to its energy efficiency formula rate on or before June 1 \( ^{st} \)  each year, with resulting rates effective in January of the following year. The annual update is based on projected current year energy efficiency costs, PJM capacity revenues, and the projected year-end regulatory asset balance less any related deferred income taxes (initial year revenue requirement). The update also reconciles any differences between the revenue requirement in effect for the prior year and actual costs incurred from the year (annual reconciliation). The approved energy efficiency formula rate also provides for revenue decoupling provisions similar to those in ComEd's electric distribution formula rate.

During 2019, the ICC approved the following total increases in ComEd's requested energy efficiency revenue requirement:

<table><tr><td>Filing Date</td><td>Requested Revenue Requirement Increase</td><td>Approved Revenue Requirement Increase</td><td>Approved ROE</td><td>Approval Date</td><td>Rate Effective Date</td></tr><tr><td>May 23, 2019</td><td>$ 51</td><td>$ 50 (a)</td><td>8.91%</td><td>November 26, 2019</td><td>January 1, 2020</td></tr></table>

(a) ComEd’s 2020 approved revenue requirement above reflects an increase of $53 million for the initial year revenue requirement for 2020 and a decrease of $3 million related to the annual reconciliation for 2018. The revenue requirement for 2020 provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 6.51% inclusive of an allowed ROE of 8.91%, reflecting the average rate on 30-year treasury notes plus 580 basis points. See table below for ComEd’s regulatory assets associated with its energy efficiency formula rate.

## Maryland Regulatory Matters

Maryland Alternative Rate Plans Rulemaking (Exelon, BGE, PHI, Pepco and DPL). On August 9, 2019, the MDPSC issued an order in which the MDPSC determined that it is now appropriate to move forward to implement alternative rate plans in Maryland. The MDPSC found that a multi-year rate plan, based on a historic test year and allowing up to three future test years, can produce just and reasonable rates. A working group was convened and submitted a detailed implementation report related to multi-year rate plans to the MDPSC on December 20, 2019. In response to the working group report, the MDPSC issued an order on February 4, 2020 establishing a multi-year rate plan pilot and an associated framework for a Maryland utility to use in the pilot multi-year rate plan filing. The working group was required to continue and discuss how best to integrate performance-based measures into a multi-year rate plan. The working group is currently discussing performance-based measures which could be combined with future multi-year rate plans and will submit its report to the MDPSC by April 1, 2020. BGE, Pepco and DPL cannot predict the outcome or the potential financial impact, if any, on BGE, Pepco or DPL.

The Maryland Strategic Infrastructure Development and Enhancement Program (Exelon and BGE). On December 1, 2017 (as amended on January 22, 2018), BGE filed an application with the MDPSC seeking approval for a new gas infrastructure replacement plan and associated surcharge, effective for the five-year period from 2019 through 2023. On May 30, 2018, the MDPSC approved with modifications a new infrastructure plan and associated surcharge, subject to BGE's acceptance of the Order. On June 1, 2018, BGE accepted the MDPSC Order and the associated surcharge became effective January 2019. The five-year plan calls for capital expenditures over the 2019-2023 timeframe of $732 million with an associated revenue requirement of $200 million.

Cash Working Capital Order (Exelon and BGE). On November 17, 2016, the MDPSC rendered a decision in the proceeding to review BGE's request to recover its cash working capital (CWC) requirement for its Provider of Last Resort service, also known as Standard Offer Service (SOS), as well as other components that make up the Administrative Charge, the mechanism that enables BGE to recover its SOS-related costs. The Administrative Charge is comprised of five components: CWC, uncollectibles, incremental costs, return, and an administrative adjustment, which acts as a proxy for retail suppliers' costs. The MDPSC accepted BGE's positions on recovery of CWC and pass-through recovery of BGE's actual uncollectibles and incremental costs. The order also grants BGE a return on the SOS. Subsequently, the MDPSC Staff and residential consumer advocate sought clarification and appealed the amount of return awarded to BGE on the SOS. The appeal currently resides with the Maryland Court of Special Appeals. Also, in BGE's 2019 electric and gas distribution base rate proceeding, the MDPSC established a normalized administrative adjustment. However, a group of electric suppliers appealed the MDPSC's decision to the Circuit Court for Baltimore City. BGE cannot predict the outcome of these appeals.



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

New Jersey Regulatory Matters

ACE Infrastructure Investment Program Filing (Exelon, PHI and ACE). On February 28, 2018, ACE filed with the NJBPU the company's Infrastructure Investment Program (IIP) proposing to seek recovery of a series of investments through a new rider mechanism, totaling $338 million, between 2019-2022 to provide safe and reliable service for its customers. The IIP will allow for more timely recovery of investments made to modernize and enhance ACE's electric system. On April 15, 2019, ACE entered into a settlement agreement with other parties, which allows for a recovery totaling $96 million of reliability related capital investments from July 1, 2019 through June 30, 2023. On April 18, 2019, the NJBPU approved the settlement agreement.

New Jersey Clean Energy Legislation (Exelon, PHI and ACE). On May 23, 2018, New Jersey enacted legislation that established and modified New Jersey's clean energy and energy efficiency programs and solar and renewable energy portfolio standards. On the same day, New Jersey enacted legislation that established a ZEC program that provides compensation for nuclear plants that demonstrate to the NJBPU that they meet certain requirements, including that they make a significant contribution to air quality in the state and that their revenues are insufficient to cover their costs and risks. Electric distribution utilities in New Jersey, including ACE, began collecting from retail distribution customers, through a non-bypassable charge, all costs associated with the utility's procurement of the ZECs effective April 18, 2019. See Generation Regulatory Matters below for additional information.

## Other Federal Regulatory Matters

Transmission-Related Income Tax Regulatory Assets (Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE). On December 13, 2016 (and as amended on March 13, 2017), BGE filed with FERC to begin recovering certain existing and future transmission-related income tax regulatory assets through its transmission formula rate. BGE's existing regulatory assets included (1) amounts that, if BGE's transmission formula rate provided for recovery, would have been previously amortized and (2) amounts that would be amortized and recovered prospectively. ComEd, Pepco, DPL and ACE had similar transmission-related income tax regulatory liabilities and assets also requiring FERC approval. On November 16, 2017, FERC issued an order rejecting BGE's proposed revisions to its transmission formula rate to recover these transmission-related income tax regulatory assets. As a result of the FERC's order, ComEd, BGE, Pepco, DPL and ACE took a charge to Income tax expense within their Consolidated Statements of Operations and Comprehensive Income in the fourth quarter of 2017, reducing their associated transmission-related income tax regulatory assets for the portion of the total transmission-related income tax regulatory assets that would have been previously amortized and recovered through rates. Similar regulatory assets and liabilities at PECO are not subject to the same FERC transmission rate recovery formula. See above for additional information regarding PECO's transmission formula rate filing.

On December 18, 2017, BGE filed for clarification and rehearing of FERC's November 16, 2017 order and on February 23, 2018 (as amended on July 9, 2018), ComEd, Pepco, DPL, and ACE each filed with FERC to revise their transmission formula rate mechanisms to permit recovery of transmission-related income tax regulatory assets, including those amounts that would have been previously amortized and recovered through rates had the transmission formula rate provided for such recovery.

On September 7, 2018, FERC issued orders rejecting BGE's December 18, 2017 request for rehearing and clarification and ComEd's, Pepco's, DPL's and ACE's February 23, 2018 (as amended on July 9, 2018) filings, citing the lack of timeliness of the requests to recover amounts that would have been previously amortized, but indicating that ongoing recovery of certain transmission-related income tax regulatory assets would provide for a more accurate revenue requirement, consistent with its November 16, 2017 order.

On October 1, 2018, ComEd, BGE, Pepco, DPL, and ACE submitted filings to recover ongoing non-TCJA amortization amounts and refund TCJA transmission-related income tax regulatory liabilities for the prospective period starting on October 1, 2018. In addition, on October 9, 2018, ComEd, Pepco, DPL, and ACE sought rehearing of FERC's September 7, 2018 order. On November 2, 2018, BGE filed an appeal of FERC's September 7, 2018 order to the Court of Appeals for the D.C. Circuit. On April 26, 2019 FERC issued an order accepting ComEd's, BGE's, Pepco's, DPL's, and ACE's October 1, 2018 filings, effective October 1, 2018, subject to refund and established hearing and settlement judge procedures. ComEd, BGE, Pepco, DPL, and ACE cannot predict the outcome of these proceedings.

If FERC ultimately rules that the future, ongoing non-TCJA amortization amounts are not recoverable, Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE would record additional charges to Income tax expense, which could be



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

up to approximately $79 million, $51 million, $17 million, $11 million, $4 million, $5 million and $2 million, respectively, as of December 31, 2019.

PJM Transmission Rate Design (All Registrants). On June 15, 2016, several parties, including the Utility Registrants, filed a proposed settlement with FERC to resolve outstanding issues related to cost responsibility for charges to transmission customers for certain transmission facilities that operate at or above 500 kV. The settlement included provisions for monthly credits or charges related to the periods prior to January 1, 2016 that are expected to be refunded or recovered through PJM wholesale transmission rates through December 2025. On May 31, 2018, FERC issued an order approving the settlement. Pursuant to the order, similar charges for the period January 1, 2016 through June 30, 2018 would also be refunded or recovered through PJM wholesale transmission rates over the subsequent 12-month period. PJM commenced billing the refunds and charges associated with this settlement in August 2018.

The Utility Registrants recorded the following payables to/receivables from PJM and related regulatory assets/liabilities in 2018 and have been refunding or recovering these amounts through electric distribution customer rates. Generation recorded a $41 million net payable to PJM and a pre-tax charge within Purchased power and fuel expense in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.

<table><tr><td></td><td colspan="2">PJM Receivable</td><td colspan="2">PJM Payable</td><td colspan="2">Regulatory Asset</td><td colspan="2">Regulatory Liability</td></tr><tr><td>Exelon</td><td>$</td><td>220</td><td>$</td><td>176</td><td>$</td><td>136</td><td>$</td><td>221</td></tr><tr><td>Generation(a)</td><td></td><td>—</td><td></td><td>41</td><td></td><td>—</td><td></td><td>—</td></tr><tr><td>ComEd</td><td></td><td>122</td><td></td><td>—</td><td></td><td>—</td><td></td><td>122</td></tr><tr><td>PECO</td><td></td><td>85</td><td></td><td>—</td><td></td><td>—</td><td></td><td>85</td></tr><tr><td>BGE</td><td></td><td>—</td><td></td><td>51</td><td></td><td>51</td><td></td><td>—</td></tr><tr><td>PHI</td><td></td><td>13</td><td></td><td>84</td><td></td><td>85</td><td></td><td>14</td></tr><tr><td>Pepco</td><td></td><td>—</td><td></td><td>84</td><td></td><td>84</td><td></td><td>—</td></tr><tr><td>DPL</td><td></td><td>10</td><td></td><td>—</td><td></td><td>—</td><td></td><td>10</td></tr><tr><td>ACE</td><td></td><td>3</td><td></td><td>—</td><td></td><td>1</td><td></td><td>4</td></tr></table>

(a) Does not include an offsetting receivable from New Jersey Utilities of $16 million as of December 31, 2018.

## Regulatory Assets and Liabilities

Regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent the excess recovery of costs or accrued credits that have been deferred because it is probable such amounts will be returned to customers through future regulated rates or represent billings in advance of expenditures for approved regulatory programs.



## Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 3 — Regulatory Matters

The following tables provide information about the regulatory assets and liabilities of Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE as of December 31, 2019 and December 31, 2018:

<table><tr><td>December 31, 2019</td><td>Exelon</td><td>ComEd</td><td>PECO</td><td>BGE</td><td>PHI</td><td>Pepco</td><td>DPL</td><td>ACE</td></tr><tr><td>Regulatory assets</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Pension and other postretirement benefits</td><td>$ 2,784</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$</td></tr><tr><td>Pension and other postretirement benefits - Merger related</td><td>1,138</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Deferred income taxes</td><td>528</td><td>—</td><td>518</td><td>—</td><td>10</td><td>10</td><td>—</td><td>—</td></tr><tr><td>AMI programs - Deployment costs</td><td>207</td><td>—</td><td>—</td><td>129</td><td>78</td><td>43</td><td>35</td><td>—</td></tr><tr><td>AMI programs - Legacy Meters</td><td>276</td><td>113</td><td>12</td><td>45</td><td>106</td><td>79</td><td>27</td><td>—</td></tr><tr><td>Electric distribution formula rate annual reconciliations</td><td>34</td><td>34</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Electric distribution formula rate significant one-time events</td><td>66</td><td>66</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Energy efficiency costs</td><td>746</td><td>746</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><tr><td>Fair value of long-term debt</td><td>650</td><td>—</td><td>—</td><td>—</td><td>523</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Fair value of PHI&#x27;s unamortized energy contracts</td><td>443</td><td>—</td><td>—</td><td>—</td><td>443</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Asset retirement obligations</td><td>127</td><td>85</td><td>23</td><td>16</td><td>3</td><td>2</td><td>—</td><td>1</td></tr><tr><td>MGP remediation costs</td><td>302</td><td>287</td><td>11</td><td>4</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Renewable energy</td><td>301</td><td>301</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Electric Energy and Natural Gas Costs</td><td>110</td><td>—</td><td>6</td><td>36</td><td>68</td><td>43</td><td>5</td><td>20</td></tr><tr><td>Transmission formula rate annual reconciliations</td><td>11</td><td>—</td><td>—</td><td>1</td><td>10</td><td>1</td><td>2</td><td>7</td></tr><tr><td>Energy efficiency and demand response programs</td><td>572</td><td>—</td><td>—</td><td>303</td><td>269</td><td>196</td><td>73</td><td>—</td></tr><tr><td>Merger integration costs</td><td>32</td><td>—</td><td>—</td><td>2</td><td>30</td><td>15</td><td>8</td><td>7</td></tr><tr><td>Under-recovered revenue decoupling</td><td>37</td><td>—</td><td>—</td><td>8</td><td>29</td><td>29</td><td>—</td><td>—</td></tr><tr><td>Securitized stranded costs</td><td>37</td><td>—</td><td>—</td><td>—</td><td>37</td><td>—</td><td>—</td><td>37</td></tr><tr><td>Removal costs</td><td>641</td><td>—</td><td>—</td><td>67</td><td>574</td><td>152</td><td>100</td><td>324</td></tr><tr><td>DC PLUG charge</td><td>126</td><td>—</td><td>—</td><td>—</td><td>126</td><td>126</td><td>—</td><td>—</td></tr><tr><td>Other</td><td>337</td><td>129</td><td>25</td><td>26</td><td>167</td><td>76</td><td>24</td><td>29</td></tr><tr><td>Total regulatory assets</td><td>9,505</td><td>1,761</td><td>595</td><td>637</td><td>2,473</td><td>772</td><td>274</td><td>425</td></tr><tr><td>Less: current portion</td><td>1,170</td><td>281</td><td>41</td><td>183</td><td>412</td><td>188</td><td>52</td><td>57</td></tr><tr><td>Total noncurrent regulatory assets</td><td>$ 8,335</td><td>$ 1,480</td><td>$ 554</td><td>$ 454</td><td>$ 2,061</td><td>$ 584</td><td>$ 222</td><td>$ 368</td></tr></tr></table>



## Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 3 — Regulatory Matters

<table><tr><td>December 31, 2019</td><td>Exelon</td><td>ComEd</td><td>PECO</td><td>BGE</td><td>PHI</td><td>Pepco</td><td>DPL</td><td>ACE</td></tr><tr><td>Regulatory liabilities</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Deferred income taxes</td><td>$ 4,944</td><td>$ 2,297</td><td>$ —</td><td>$ 1,089</td><td>$ 1,558</td><td>$ 725</td><td>$ 477</td><td>$ 356</td></tr><tr><td>Nuclear decommissioning</td><td>3,102</td><td>2,622</td><td>480</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Removal costs</td><td>1,621</td><td>1,435</td><td>—</td><td>58</td><td>128</td><td>20</td><td>108</td><td>—</td></tr><tr><td>Electric Energy and Natural Gas Costs</td><td>109</td><td>45</td><td>56</td><td>—</td><td>8</td><td>—</td><td>8</td><td>—</td></tr><tr><td>Transmission formula rate annual reconciliations</td><td>34</td><td>6</td><td>28</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Other</td><td>582</td><td>337</td><td>37</td><td>81</td><td>83</td><td>9</td><td>18</td><td>26</td></tr><tr><td>Total regulatory liabilities</td><td>10,392</td><td>6,742</td><td>601</td><td>1,228</td><td>1,777</td><td>754</td><td>611</td><td>382</td></tr><tr><td>Less: current portion</td><td>406</td><td>200</td><td>91</td><td>33</td><td>70</td><td>8</td><td>37</td><td>25</td></tr><tr><td>Total noncurrent regulatory liabilities</td><td>$ 9,986</td><td>$ 6,542</td><td>$ 510</td><td>$ 1,195</td><td>$ 1,707</td><td>$ 746</td><td>$ 574</td><td>$ 357</td></tr></table>



## Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 3 — Regulatory Matters

<table><tr><td>December 31, 2018</td><td>Exelon</td><td>ComEd</td><td>PECO</td><td>BGE</td><td>PHI</td><td>Pepco</td><td>DPL</td><td>ACE</td></tr><tr><td>Regulatory assets</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Pension and other postretirement benefits</td><td>$ 2,553</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$</td></tr><tr><td>Pension and other postretirement benefits</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>- Merger related</td><td>1,266</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Deferred income taxes</td><td>414</td><td>—</td><td>404</td><td>—</td><td>10</td><td>10</td><td>—</td><td>—</td></tr><tr><td>AMI programs - Deployment costs</td><td>234</td><td>—</td><td>—</td><td>145</td><td>89</td><td>50</td><td>39</td><td>—</td></tr><tr><td>AMI programs - Legacy Meters</td><td>328</td><td>136</td><td>24</td><td>48</td><td>120</td><td>90</td><td>30</td><td>—</td></tr><tr><td>Electric distribution formula rate annual reconciliations</td><td>158</td><td>158</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Electric distribution formula rate significant one-time events</td><td>81</td><td>81</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Energy efficiency costs</td><td>472</td><td>472</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><tr><td>Fair value of long-term debt</td><td>702</td><td>—</td><td>—</td><td>—</td><td>569</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Fair value of PHI&#x27;s unamortized energy contracts</td><td>561</td><td>—</td><td>—</td><td>—</td><td>561</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Asset retirement obligations</td><td>118</td><td>79</td><td>22</td><td>16</td><td>1</td><td>1</td><td>—</td><td>—</td></tr><tr><td>MGP remediation costs</td><td>326</td><td>309</td><td>17</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Renewable energy</td><td>249</td><td>249</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Electric Energy and Natural Gas Costs</td><td>193</td><td>—</td><td>49</td><td>51</td><td>93</td><td>84</td><td>—</td><td>9</td></tr><tr><td>Transmission formula rate annual reconciliations</td><td>41</td><td>6</td><td>—</td><td>4</td><td>31</td><td>10</td><td>14</td><td>7</td></tr><tr><td>Energy efficiency and demand response programs</td><td>545</td><td>—</td><td>1</td><td>289</td><td>255</td><td>188</td><td>67</td><td>—</td></tr><tr><td>Merger integration costs</td><td>42</td><td>—</td><td>—</td><td>3</td><td>39</td><td>18</td><td>11</td><td>10</td></tr><tr><td>Under-recovered revenue decoupling</td><td>27</td><td>—</td><td>—</td><td>2</td><td>25</td><td>25</td><td>—</td><td>—</td></tr><tr><td>Securitized stranded costs</td><td>50</td><td>—</td><td>—</td><td>—</td><td>50</td><td>—</td><td>—</td><td>50</td></tr><tr><td>Removal costs</td><td>564</td><td>—</td><td>—</td><td>—</td><td>564</td><td>158</td><td>97</td><td>309</td></tr><tr><td>DC PLUG charge</td><td>159</td><td>—</td><td>—</td><td>—</td><td>159</td><td>159</td><td>—</td><td>—</td></tr><tr><td>Deferred storm costs</td><td>41</td><td>—</td><td>—</td><td>—</td><td>41</td><td>9</td><td>4</td><td>28</td></tr><tr><td>Other</td><td>303</td><td>110</td><td>24</td><td>17</td><td>162</td><td>79</td><td>28</td><td>13</td></tr><tr><td>Total regulatory assets</td><td>9,427</td><td>1,600</td><td>541</td><td>575</td><td>2,769</td><td>881</td><td>290</td><td>426</td></tr><tr><td>Less: current portion</td><td>1,190</td><td>293</td><td>81</td><td>177</td><td>457</td><td>238</td><td>59</td><td>40</td></tr><tr><td>Total noncurrent regulatory assets</td><td>$ 8,237</td><td>$ 1,307</td><td>$ 460</td><td>$ 398</td><td>$ 2,312</td><td>$ 643</td><td>$ 231</td><td>$ 386</td></tr></tr></table>



## Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 3 — Regulatory Matters

<table><tr><td>December 31, 2018</td><td>Exelon</td><td>ComEd</td><td>PECO</td><td>BGE</td><td>PHI</td><td>Pepco</td><td>DPL</td><td>ACE</td></tr><tr><td>Regulatory liabilities</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Deferred income taxes</td><td>$ 5,228</td><td>$ 2,394</td><td>$ —</td><td>$ 1,132</td><td>$ 1,702</td><td>$ 798</td><td>$ 510</td><td>$ 394</td></tr><tr><td>Nuclear decommissioning</td><td>2,606</td><td>2,217</td><td>389</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Removal costs</td><td>1,547</td><td>1,368</td><td>—</td><td>52</td><td>127</td><td>20</td><td>107</td><td>—</td></tr><tr><td>Electric Energy and Natural Gas Costs</td><td>294</td><td>137</td><td>132</td><td>6</td><td>19</td><td>—</td><td>18</td><td>1</td></tr><tr><td>Other</td><td>528</td><td>227</td><td>75</td><td>79</td><td>100</td><td>11</td><td>30</td><td>25</td></tr><tr><td>Total regulatory liabilities</td><td>10,203</td><td>6,343</td><td>596</td><td>1,269</td><td>1,948</td><td>829</td><td>665</td><td>420</td></tr><tr><td>Less: current portion</td><td>644</td><td>293</td><td>175</td><td>77</td><td>84</td><td>7</td><td>59</td><td>18</td></tr><tr><td>Total noncurrent regulatory liabilities</td><td>$ 9,559</td><td>$ 6,050</td><td>$ 421</td><td>$ 1,192</td><td>$ 1,864</td><td>$ 822</td><td>$ 606</td><td>$ 402</td></tr></table>

Descriptions of the regulatory assets and liabilities included in the tables above are summarized below, including their recovery and amortization periods.

<table><tr><td>Line Item</td><td>Description</td><td>End Date of Remaining Recovery/Refund Period</td><td>Return</td></tr><tr><td>Pension and Other Postretirement Benefits</td><td>Primarily reflects the Utility Registrants&#x27; portion of deferred costs, including unamortized actuarial losses (gains) and prior service costs (credits), associated with Exelon&#x27;s pension and other postretirement benefit plans, which are recovered through customer rates once amortized through net periodic benefit cost. Also, includes the Utility Registrants&#x27; non-service cost components capitalized in Property, plant and equipment, net on their Consolidated Balance Sheets.</td><td>The deferred costs are amortized over the plan participants&#x27; average remaining service periods subject to applicable pension and other postretirement cost recognition policies. See Note 14 - Retirement Benefits for additional information. The capitalized non-service cost components are amortized over the lives of the underlying assets.</td><td>No</td></tr><tr><td>Pension and Other Postretirement Benefits - Merger Related</td><td>The deferred costs are amortized over the plan participants&#x27; average remaining service periods subject to applicable pension and other postretirement cost recognition policies. See Note 14 - Retirement Benefits for additional information. The capitalized non-service cost components are amortized over the lives of the underlying assets.</td><td>Legacy Constellation - 2038</td><td>No</td></tr><tr><td></td><td></td><td>Legacy PHI - 2032</td><td></td></tr></table>



## Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 3 — Regulatory Matters

<table><tr><td>Line Item</td><td>Description</td><td>End Date of Remaining Recovery/Refund Period</td><td>Return</td></tr><tr><td>Deferred Income Taxes</td><td>Deferred income taxes that are recoverable or refundable through customer rates, primarily associated with accelerated depreciation, the equity component of AFUDC, and the effects of income tax rate changes, including those resulting from the TCJA. These amounts include transmission-related regulatory liabilities that require FERC approval separate from the transmission formula rate. See Transmission-Related Income Tax Regulatory Assets section above for additional information.</td><td>Over the period in which the related deferred income taxes reverse, which is generally based on the expected life of the underlying assets. For TCJA, generally refunded over the remaining depreciable life of the underlying assets, except in certain jurisdictions where the commissions have approved a shorter refund period for certain assets not subject to IRS normalization rules.</td><td>No</td></tr><tr><td>AMI Programs - Deployment Costs</td><td>Installation costs of new smart meters, including implementation costs at Pepco and DPL of dynamic pricing for energy usage resulting from smart meters.</td><td>BGE - 2026Pepco - 2027DPL - 2030</td><td>Yes</td></tr><tr><td>AMI Programs - Legacy Meters</td><td>Early retirement costs of legacy meters.</td><td>ComEd - 2028PECO - 2020</td><td>ComEd, Pepco (District of Columbia), DPL (Delaware) - Yes</td></tr><tr><td>Electric distribution formula rate annual reconciliations</td><td>Under-recoveries related to electric distribution service costs recoverable through ComEd&#x27;s performance-based formula rate, which is updated annually with rates effective on January 1st.</td><td>BGE - 2026Pepco - 2027DPL - 2030</td><td>PECO, BGE, Pepco (Maryland), DPL (Maryland) - No</td></tr><tr><td>Electric distribution formula rate significant one-time events</td><td>Under-recoveries of electric distribution service costs related to ComEd&#x27;s significant one-time events (e.g., storm costs), which are recovered over 5 years from date of the event.</td><td>2021</td><td>Yes</td></tr><tr><td>Energy Efficiency Costs</td><td>ComEd&#x27;s costs recovered through the energy efficiency formula rate tariff and the reconciliation of the difference of the revenue requirement in effect for the prior year and the revenue requirement based on actual prior year costs. Deferred energy efficiency costs are recovered over the weighted average useful life of the related energy measure.</td><td>2023</td><td>Yes</td></tr></table>



## Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 3 — Regulatory Matters

<table><tr><td>Line Item</td><td>Description</td><td>End Date of Remaining Recovery/Refund Period</td><td>Return</td></tr><tr><td>Fair Value of Long-Term Debt</td><td>Represents the difference between the carrying value and fair value of long-term debt of PHI and BGE of $523 million and $127 million, respectively, as of December 30, 2019 and $569 million and $133 million, respectively, as of December 30, 2018, as of the PHI and Constellation merger dates.</td><td>BGE - 2043 PHI - 2045</td><td>No</td></tr><tr><td>Fair Value of PHI&#x27;s Unamortized Energy Contracts</td><td>Represents the regulatory assets recorded at Exelon and PHI offsetting the fair value adjustment related to Pepco&#x27;s, DPL&#x27;s and ACE&#x27;s electricity and natural gas energy supply contracts recorded at PHI as of the PHI merger date.</td><td>2036</td><td>No</td></tr><tr><td>Asset Retirement Obligations</td><td>Future legally required removal costs associated with existing asset retirement obligations.</td><td>Over the life of the related assets.</td><td>Yes, once the removal activities have been performed.</td></tr><tr><td>MGP Remediation Costs</td><td>Environmental remediation costs for MGP sites.</td><td>Over the expected remediation period. See Note 18 - Commitments and Contingencies for additional information.</td><td>ComEd, PECO - No</td></tr><tr><td>Renewable Energy</td><td>Represents the change in fair value of ComEd&#x27;s 20-year floating-to-fixed long-term renewable energy swap contracts.</td><td>2032</td><td>No</td></tr><tr><td>Electric Energy and Natural Gas Costs</td><td>Under (over) recoveries related to energy and gas supply related costs recoverable (refundable) under approved rate riders.</td><td>2025</td><td>DPL (Delaware), ACE - Yes ComEd, PECO, BGE, Pepco, DPL (Maryland) - No</td></tr><tr><td>Transmission formula rate annual reconciliations</td><td>Under (over)-recoveries related to transmission service costs recoverable through the Utility Registrants&#x27; FERC formula rates, which are updated annually with rates effective each June 1st.</td><td>2021</td><td>Yes</td></tr><tr><td>Energy efficiency and demand response programs</td><td>Includes under (over)-recoveries of costs incurred related to energy efficiency programs and demand response programs and recoverable costs associated with customer direct load control and energy efficiency and conservation programs that are being recovered from customers.</td><td>PECO - 2021 BGE - 2024 Pepco, DPL - 2034</td><td>BGE, Pepco, DPL - Yes PECO - Yes on capital investment recovered through this mechanism</td></tr></table>



## Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 3 — Regulatory Matters

<table><tr><td>Line Item</td><td>Description</td><td>End Date of Remaining Recovery/Refund Period</td><td>Return</td></tr><tr><td>Merger Integration Costs</td><td>Integration costs to achieve distribution synergies related to the Constellation merger and PHI acquisition. Costs for Pepco (Maryland) and Pepco (District of Columbia) were $6 million and $9 million, respectively as of December 31, 2019 and $9 million each as of December 31, 2018.</td><td>BGE - 2021Pepco - 2021DPL - 2023ACE - 2022</td><td>BGE, Pepco (Maryland), DPL - YesPepco (District of Columbia), ACE - No</td></tr><tr><td>Under (Over)-Recovered Revenue Decoupling</td><td>Electric and / or gas distribution costs recoverable from or (refundable) to customers under decoupling mechanisms.</td><td>BGE, Pepco and DPL - 2020</td><td>BGE, Pepco, DPL - No</td></tr><tr><td>Securitized Stranded Costs</td><td>Represents certain stranded costs associated with ACE&#x27;s former electricity generation business.</td><td>2022</td><td>Yes</td></tr><tr><td>Removal Costs</td><td>For BGE, PHI, Pepco, DPL and ACE, the regulatory asset represents costs incurred to remove property, plant and equipment in excess of amounts received from customers through depreciation rates. For ComEd, BGE, PHI, Pepco and DPL, the regulatory liability represents amounts received from customers through depreciation rates to cover the future non-legally required cost to remove property, plant and equipment, which reduces rate base for ratemaking purposes.</td><td>BGE, PHI, Pepco, DPL and ACE - Asset is generally recovered over the life of the underlining assets.ComEd, BGE, PHI, Pepco and DPL - The liability is reduced as costs are incurred.</td><td>Yes</td></tr><tr><td>DC PLUG Charge</td><td>Costs associated with the District of Columbia Power Line Underground (DC PLUG), which is a projected six year, $500 million project to place underground some of the District of Columbia&#x27;s most outage-prone power lines with $250 million of the project costs funded by Pepco and $250 million funded by the District of Columbia. Rates for the DC PLUG initiative went into effect on February 7, 2018.</td><td>2020 - $30M$67 million to be determined based on future biennial plans filed with the DCPSC.</td><td>Portion of asset funded by Pepco-Yes</td></tr><tr><td>Deferred Storm Costs</td><td>For Pepco, DPL and ACE amounts represent total incremental storm restoration costs incurred due to major storm events recoverable from customers in the Maryland and New Jersey jurisdictions.</td><td>Pepco - 2024DPL - 2023ACE - 2022</td><td>Pepco, DPL - YesACE - No</td></tr><tr><td>Nuclear Decommissioning</td><td>Estimated future decommissioning costs for the Regulatory Agreement Units that are less than the associated NDT fund assets. See Note 9 - Asset Retirement Obligations for additional information.</td><td>Not currently being refunded.</td><td>No</td></tr></table>



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

## Capitalized Ratemaking Amounts Not Recognized

The following table presents authorized amounts capitalized for ratemaking purposes related to earnings on shareholders' investment that are not recognized for financial reporting purposes in Exelon's and the Utility Registrant's Consolidated Balance Sheets. These amounts will be recognized as revenues in the related Consolidated Statements of Operations and Comprehensive Income in the periods they are billable to our customers.

<table><tr><td></td><td colspan="2">Exelon</td><td colspan="2">ComEd(a)</td><td colspan="2">PECO</td><td colspan="2">BGE(b)</td><td colspan="2">PHI</td><td colspan="2">Pepco(c)</td><td colspan="2">DPL(c)</td><td colspan="2">ACE</td></tr><tr><td>December 31, 2019</td><td>$</td><td>63</td><td>$</td><td>3</td><td>$</td><td>—</td><td>$</td><td>53</td><td>$</td><td>7</td><td>$</td><td>4</td><td>$</td><td>3</td><td>$</td><td>—</td></tr><tr><td>December 31, 2018</td><td>$</td><td>65</td><td>$</td><td>8</td><td>$</td><td>—</td><td>$</td><td>49</td><td>$</td><td>8</td><td>$</td><td>5</td><td>$</td><td>3</td><td>$</td><td>—</td></tr></table>

(a) Reflects ComEd's unrecognized equity returns earned for ratemaking purposes on its electric distribution formula rate regulatory assets.

(b) BGE's authorized amounts capitalized for ratemaking purposes primarily relate to earnings on shareholders' investment on its AMI programs.

(c) Pepco's and DPL's authorized amounts capitalized for ratemaking purposes relate to earnings on shareholders' investment on their respective AMI Programs and Energy Efficiency and Demand Response Programs. The earnings on energy efficiency are on Pepco DC and DPL DE programs only.

## Generation Regulatory Matters (Exelon and Generation)

## Illinois Regulatory Matters

Zero Emission Standard. Pursuant to FEJA, on January 25, 2018, the ICC announced that Generation’s Clinton Unit 1, Quad Cities Unit 1 and Quad Cities Unit 2 nuclear plants were selected as the winning bidders through the IPA’s ZEC procurement event.

Generation executed the ZEC procurement contracts with Illinois utilities, including ComEd, effective January 26, 2018 and began recognizing revenue with compensation for the sale of ZECs retroactive to the June 1, 2017 effective date of FEJA. The ZEC price was initially established at $16.50 per MWh of production, subject to annual future adjustments determined by the IPA for specified escalation and pricing adjustment mechanisms designed to lower the ZEC price based on increases in underlying energy and capacity prices. Illinois utilities are required to purchase all ZECs delivered by the zero-emissions nuclear-powered generating facilities, subject to annual cost caps. For the initial delivery year, June 1, 2017 to May 31, 2018, and subsequent delivery year, June 1, 2018 to May 31, 2019, the ZEC annual cost cap was set at $235 million (ComEd's share is approximately $170 million). For subsequent delivery years, the IPA-approved targeted ZEC procurement amounts will change based on forward energy and capacity prices. 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. During the first quarter of 2018, Generation recognized $150 million of revenue related to ZECs generated from June 1, 2017 through December 31, 2017.

On February 14, 2017, two lawsuits were filed in the Northern District of Illinois against the IPA alleging that the state’s ZEC program violates certain provisions of the U.S. Constitution. Both lawsuits argued that the Illinois ZEC program would distort PJM’s FERC-approved energy and capacity market auction system of setting wholesale prices and sought a permanent injunction preventing the implementation of the program. The lawsuits were dismissed by the district court on July 14, 2017. On September 13, 2018, the U.S. Circuit Court of Appeals for the Seventh Circuit affirmed the lower court’s dismissal of both lawsuits. On January 7, 2019, plaintiffs filed a petition seeking U.S. Supreme Court review of the case, which was denied on April 15, 2019.

## New Jersey Regulatory Matters

New Jersey Clean Energy Legislation. On May 23, 2018, New Jersey enacted legislation that established a ZEC program that will provide compensation for nuclear plants that demonstrate to the NJBPU that they meet certain requirements, including that they make a significant contribution to air quality in the state and that their revenues are insufficient to cover their costs and risks. Under the legislation, the NJBPU will issue ZECs to qualifying nuclear power plants and the electric distribution utilities in New Jersey, including ACE, will be required to purchase those ZECs. Selected nuclear plants will receive annual ZEC payments for each energy year (12-month period from June 1 through May 31) within 90 days after the completion of such energy year. The quantity of ZECs issued will be



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 3 — Regulatory Matters

determined based on the greater of 40% of the total number of MWh of electricity distributed by the public electric distribution utilities in New Jersey in the prior year, or the total number of MWh of electricity generated in the prior year by the selected nuclear power plants. The ZEC price is approximately $10 per MWh during the first 3-year eligibility period. For eligibility periods following the first 3-year eligibility period, the NJBPU has discretion to reduce the ZEC price.

On November 19, 2018, NJBPU issued an order providing for the method and application process for determining the eligibility of nuclear power plants, a draft method and process for ranking and selecting eligible nuclear power plants, and the establishment of a mechanism for each regulated utility to purchase ZECs from selected nuclear power plants. On December 19, 2018, PSEG filed complete applications seeking NJBPU approval for Salem 1 and Salem 2, of which Generation owns a 42.59% ownership interest, to participate in the ZEC program. On April 18, 2019, the NJBPU approved the award of ZECs to Salem 1 and Salem 2. Upon approval, Generation began recognizing revenue for the sale of New Jersey ZECs in the month they are generated and has recognized $53 million for the year ended December 31, 2019. On May 15, 2019, New Jersey Rate Counsel appealed the NJBPU's decision to the New Jersey Superior Court. The appeal does not prevent implementation of the ZEC program. Exelon and Generation cannot predict the outcome of the appeal. See Note 6 - Early Plant Retirements for additional information related to Salem.

## New York Regulatory Matters

New York Clean Energy Standard. On August 1, 2016, the NYPSC issued an order establishing the New York CES, a component of which is a Tier 3 ZEC program targeted at preserving the environmental attributes of zero-emissions nuclear-powered generating facilities that meet the criteria demonstrating public necessity as determined by the NYPSC to be Generation's FitzPatrick, Ginnia and Nine Mile Pilot nuclear facilities. The New York State Energy Research and Development Authority (NYSERDA) centrally procures the ZECs through a 12-year contract extending from April 1, 2017 through March 31, 2029, administered in six two-year tranches. ZEC payments are made based upon the number of MWh produced by each facility, subject to specified caps and minimum performance requirements. The ZEC price for the first tranche was set at $17.48 per MWh of production and is administratively determined using a formula based on the social cost of carbon as determined in 2016 by the federal government, subject to pricing adjustments designed to lower the ZEC price based on increases in underlying energy and capacity prices. Following the first tranche, the price will be updated bi-annually. Each Load Serving Entity (LSE) is required to purchase an amount of ZECs from NYSERDA equivalent to its load ratio share of the total electric energy in the New York Control Area. Cost recovery from ratepayers is incorporated into the commodity charges on customer bills.

On October 19, 2016, a coalition of fossil-generation companies filed a complaint in federal district court against the NYPSC alleging that the ZEC program violates certain provisions of the U.S. Constitution; specifically, that the ZEC program interferes with FERC's jurisdiction over wholesale rates and that it discriminates against out of state competitors, which was dismissed by the district court on July 25, 2017. On September 27, 2018, the U.S. Court of Appeals for the Second Circuit affirmed the lower court's dismissal of the complaint against the ZEC program. On January 7, 2019, the fossil-generation companies filed a petition seeking U.S. Supreme Court review of the case which was denied on April 15, 2019.

In addition, on November 30, 2016 (as amended on January 13, 2017), a group of parties filed a Petition in New York State court seeking to invalidate the ZEC program, which argued that the NYPSC did not have authority to establish the program, that it violated state environmental law and that it violated certain technical provisions of the State Administrative Procedures Act when adopting the ZEC program. Subsequently, Generation, CENG and the NYPSC filed motions to dismiss the state court action, which were later opposed by the plaintiffs. On January 22, 2018, the court dismissed the environmental claims and the majority of the plaintiffs from the case but denied the motions to dismiss with respect to the remaining five plaintiffs and claims, without commenting on the merits of the case. On October 8, 2019, the court dismissed all remaining claims. The petitioners filed a notice of appeal on November 4, 2019 and have until May 4, 2020 to file their brief.

See Note 6 — Early Plant Retirements for additional information related to Ginnia and Nine Mile Point, and Note 2 — Mergers, Acquisitions and Dispositions for additional information on Generation's acquisition of FitzPatrick.

Ginna Nuclear Power Plant Reliability Support Services Agreement. In November 2014, in response to a petition filed by Ginna regarding the possible retirement of Ginna, the NYPSC directed Ginna and Rochester Gas



& Electric Company (RG&E) to negotiate a RSSA to support the continued operation of Ginna to maintain the reliability of the RG&E transmission grid for a specified period of time.

On April 8, 2016, FERC accepted Ginna's compliance filing and on April 20, 2016, the NYPSC accepted the revised RSSA with a term expiring on March 31, 2017. In April 2016, Generation began recognizing revenue based on the final approved pricing contained in the RSSA and also recognized a one-time revenue adjustment of $101 million representing the net cumulative previously unrecognized amount of revenue retroactive from the April 1, 2015 effective date through March 31, 2016. A 49.99% portion of the one-time adjustment was removed from Generation's results of operations as a result of the noncontrolling interests in CENG.

The RSSA required Ginna to continue operating through the RSSA term. On September 30, 2016, Ginna filed the required notice with the NYPSC of its intent to continue operating beyond the March 31, 2017 expiry of the RSSA, conditioned upon successful execution of an agreement between Ginna and NYSERDA for the sale of ZECs under the New York CES. Subject to prevailing over any administrative or legal challenges, it is expected the New York CES will allow Ginna to continue to operate through the end of its current operating license in 2029. See Note 6 — Early Plant Retirements for additional information regarding the impacts of a decision to early retire a nuclear plant.

## Federal Regulatory Matters

PJM and NYISO MOPR Proceedings. PJM and NYISO capacity markets include a Minimum Offer Price Rule (MOPR). If a resource is subjected to a MOPR, its offer is adjusted to effectively remove the revenues it receives through a government-provided financial support program - resulting in a higher offer that may not clear the capacity market. Prior to December 19, 2019, the MOPR in PJM applied only to certain new gas-fired resources. Currently, the MOPR in NYISO continues to apply to certain new gas-fired resources.

In January 2017 and May 2018, EPSA filed pleadings at FERC that generally allege that the NYISO and PJM MOPRs should be expanded to apply to existing resources including those receiving ZEC compensation under the New Jersey ZEC (Salem), New York CES (FitzPatrick, Ginna and Nine Mile Point) and Illinois ZES (Quad Cities) programs. For Generation's facilities in PJM and NYISO that are currently receiving ZEC compensation, an expanded MOPR would require exclusion of ZEC compensation when bidding into future capacity auctions, resulting in an increased risk of these facilities not receiving capacity revenues in future auctions. Exelon filed protests at FERC in response to each filing, arguing generally that ZEC payments provide compensation for an environmental attribute and are no different than other renewable support programs that have generally not been subject to a MOPR.

On December 19, 2019, FERC issued an order in the PJM MOPR proceeding that broadly applies the MOPR to all new and existing resources including nuclear, renewables, demand response, energy efficiency, storage and all resources owned by vertically-integrated utilities, greatly expanding the breadth and scope of PJM's MOPR, effective as of PJM's next capacity auction, the timing of which cannot be predicted at this time. FERC directed PJM to make a compliance filing within 90 days. FERC has no deadline for acting on PJM's compliance filing. While FERC included some limited exemptions (generally available to existing renewable, energy efficiency, demand response, storage and existing vertically-integrated utility resources) in its order, no exemptions were available to state-supported nuclear resources. In addition, FERC provided no new mechanism for accommodating state-supported resources other than the existing FRR mechanism under which an entire utility zone would be removed from PJM's capacity auction along with sufficient resources to support the load in such zone. Unless Illinois and New Jersey can implement an FRR program in their PJM zones, the MOPR will apply to Generation's owned or jointly owned nuclear plants in those states receiving a benefit under the Illinois ZES or the New Jersey ZEC program, as applicable, resulting in higher offers for those units that may not clear the capacity market.

On January 21, 2020, Exelon, PJM and a number of other entities submitted individual requests for rehearing of FERC's December 19, 2019 order on the PJM MOPR. FERC routinely extends the deadline by which it must address requests for rehearing. FERC has not yet acted, and has no deadline by which it must act, in the NYISO proceeding.

Exelon is currently working with PJM and other stakeholders to pursue the FRR option prior to the next capacity auction in PJM. If Illinois implements the FRR option, Generation's Illinois nuclear plants could be removed from PJM's capacity auction and instead supply capacity and be compensated under the FRR program, which has the potential to mitigate the current economic distress being experienced by Generation's nuclear plants in Illinois, as discussed in Note 6 — Early Plant Retirements. Implementing the FRR program in Illinois will require both legislative



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 3 — Regulatory Matters

and regulatory changes. Legislation may be introduced in New Jersey as well. Exelon cannot predict whether such legislative and regulatory changes can be implemented prior to the next capacity auction in PJM.

If Generation’s state-supported nuclear plants in PJM or NYISO are subjected to the MOPR without compensation under an FRR or similar program, it could have a material adverse impact on Exelon’s and Generation’s financial statements.

## Operating License Renewals

Conowingo Hydroelectric Project. On August 29, 2012, Generation submitted a hydroelectric license application to FERC for a new license for the Conowingo Hydroelectric Project (Conowingo). In connection with Generation’s efforts to obtain a water quality certification pursuant to Section 401 of the Clean Water Act (401 Certification) from MDE for Conowingo, Generation has been working with MDE and other stakeholders to resolve water quality licensing issues, including: (1) water quality, (2) fish habitat, and (3) sediment.

On April 21, 2016, Generation and the U.S. Fish and Wildlife Service of the U.S. Department of the Interior executed a settlement agreement (DOI Settlement) resolving all fish passage issues between the parties.

On April 27, 2018, MDE issued its 401 Certification for Conowingo. As issued, the 401 Certification contains numerous conditions, including those relating to reduction of nutrients from upstream sources, removal of all visible trash and debris from upstream sources, and implementation of measures relating to fish passage, which could have a material, unfavorable impact on Exelon's and Generation's financial statements through an increase in capital expenditures and operating costs if implemented. On May 25, 2018, Generation filed complaints in federal and state court, along with a petition for reconsideration with MDE, alleging that the conditions are unfair and onerous and in violation of MDE regulations and state, federal, and constitutional law. Generation also requested that FERC defer the issuance of the federal license while these significant state and federal law issues are pending. On February 28, 2019, Generation filed a Petition for Declaratory Order with FERC requesting that FERC issue an order declaring that MDE waived its right to issue a 401 Certification for Conowingo because it failed to timely act on Conowingo's 401 Certification application and requesting that FERC decline to include the conditions required by MDE in April 2018.

On October 29, 2019, Generation and MDE filed with FERC a Joint Offer of Settlement (Offer of Settlement) that would resolve all outstanding issues relating to the 401 Certification. Pursuant to the Offer of Settlement, the parties submitted Proposed License Articles to FERC to be incorporated by FERC into the new license in accordance with FERC's discretionary authority under the Federal Power Act. Among the Proposed License Articles are modifications to river flows to improve aquatic habitat, eel passage improvements and initiatives to support rare, threatened and endangered wildlife. If FERC approves the Offer of Settlement and incorporates the Proposed License Articles into the new license without modification, then MDE would waive its rights to issue a 401 Certification and Generation would agree, pursuant to a separate agreement with MDE (MDE Settlement), to implement additional environmental protection, mitigation and enhancement measures over the anticipated 50-year term of the new license. These measures address mussel restoration and other ecological and water quality matters, among other commitments. Exelon's commitments under the various provisions of the Offer of Settlement and MDE Settlement are not effective unless and until FERC approves the Offer of Settlement and issues the new license with the Proposed License Articles.

The financial impact of the DOI and MDE Settlements and other anticipated license commitments are estimated to be $11 million to $14 million per year, on average, recognized over the new license term, including capital and operating costs. The actual timing and amount of the majority of these costs are not currently fixed and will vary from year to year throughout the life of the new license. Generation cannot currently predict when FERC will issue the new license. As of December 31, 2019, $42 million of direct costs associated with Conowingo licensing efforts have been capitalized. Generation's current depreciation provision for Conowingo assumes renewal of the FERC license.

Peach Bottom Units 2 and 3. On July 10, 2018, Generation submitted a second 20-year license renewal application with the NRC for Peach Bottom Units 2 and 3. Generation anticipates the second license renewal in the first half of 2020. Peach Bottom Units 2 and 3 are currently licensed to operate through 2033 and 2034, respectively. See Note 7 – Property, Plant and Equipment for additional information regarding the estimated useful life and depreciation provisions for Peach Bottom.

PJM Transmission Rate Design. Refer to Other Federal Regulatory Matters above for additional information.



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 4 — Revenue from Contracts with Customers

## 4. Revenue from Contracts with Customers (All Registrants)

The Registrants recognize revenue from contracts with customers to depict the transfer of goods or services to customers at an amount that the entities expect to be entitled to in exchange for those goods or services. Generation's primary sources of revenue include competitive sales of power, natural gas, and other energy-related products and services. The Utility Registrants' primary sources of revenue include regulated electric and gas tariff sales, distribution and transmission services. The performance obligations, revenue recognition and payment terms associated with these sources of revenue are further discussed in the table below. There are no significant financing components for these sources of revenue and no variable consideration for regulated electric and gas tariff sales and regulated transmission services unless noted below.

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



## Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 4 — Revenue from Contracts with Customers

<table><tr><td>Revenue Source</td><td>Description</td><td>Performance Obligation</td><td>Timing of Revenue Recognition</td><td>Payment Terms</td></tr><tr><td>Competitive Power Sales (Exelon and Generation)</td><td>Sales of power and other energy-related commodities to wholesale and retail customers across multiple geographic regions through its customer-facing business, Constellation.</td><td>Various including the delivery of power (generally delivered over time) and other energy-related commodities such as capacity (generally delivered over time), ZECs, RECs or other ancillary services (generally delivered at a point in time).</td><td>Concurrently as power is generated for bundled power sale contracts. (a)</td><td>Within the month following delivery to the customer.</td></tr><tr><td>Competitive Natural Gas Sales (Exelon and Generation)</td><td>Sales of natural gas on a full requirement basis or for an agreed upon volume to commercial and residential customers.</td><td>Delivery of natural gas to the customer.</td><td>Over time as the natural gas is delivered and consumed by the customer.</td><td>Within the month following delivery to the customer.</td></tr><tr><td>Other Competitive Products and Services (Exelon and Generation)</td><td>Sales of other energy-related products and services such as long-term construction and installation of energy efficiency assets and new power generating facilities, primarily to commercial and industrial customers.</td><td>Construction and/or installation of the asset for the customer.</td><td>Revenues, and associated costs, are recognized throughout the contract term using an input method to measure progress towards completion. (b)</td><td>Within 30 or 45 days from the invoice date.</td></tr><tr><td>Regulated Electric and Gas Tariff Sales (Exelon and the Utility Registrants)</td><td>Sales of electricity and electricity distribution services (the Utility Registrants) and natural gas and gas distribution services (PECO, BGE and DPL) to residential, commercial, industrial and governmental customers through regulated tariff rates approved by state regulatory commissions.</td><td>Delivery of electricity and/or natural gas.</td><td>Over time (each day) as the electricity and/or natural gas is delivered to customers. Tariff sales are generally considered daily contracts as customers can discontinue service at any time. (c)</td><td>Within the month following delivery of the electricity or natural gas to the customer.</td></tr><tr><td>Regulated Transmission Services (Exelon and the Utility Registrants)</td><td>The Utility Registrants provide open access to their transmission facilities to PJM, which directs and controls the operation of these transmission facilities and accordingly compensates the Utility Registrants pursuant to filed tariffs at cost-based rates approved by FERC.</td><td>Various including (i) Network Integration Transmission Services (NITS), (ii) scheduling, system control and dispatch services, and (iii) access to the wholesale grid.</td><td>Over time utilizing output methods to measure progress towards completion. (d)</td><td>Paid weekly by PJM.</td></tr></table>

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

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

(c) Electric and natural gas utility customers have the choice to purchase electricity or natural gas from competitive electric generation and natural gas suppliers. While the Utility Registrants are required under state legislation to bill their customers



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 4 — Revenue from Contracts with Customers

for the supply and distribution of electricity and/or natural gas, they recognize revenue related only to the distribution services when customers purchase their electricity or natural gas from competitive suppliers.

(d) Passage of time is used for NITS and access to the wholesale grid and MWHs of energy transported over the wholesale grid is used for scheduling, system control and dispatch services.

Generation incurs incremental costs in order to execute certain retail power and gas sales contracts. These costs, which primarily relate to retail broker fees and sales commissions, are capitalized when incurred as contract acquisition costs and were immaterial as of December 31, 2019 and 2018. The Utility Registrants do not incur any material costs to obtain or fulfill contracts with customers.

## Contract Balances (All Registrants)

## Contract Assets and Liabilities

Generation records contract assets for the revenue recognized on the construction and installation of energy efficiency assets and new power generating facilities before Generation has 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. Generation records contract assets and contract receivables within Other current assets and Accounts receivable, net - Customer, respectively, within Exelon's and Generation's Consolidated Balance Sheets.

Generation records contract liabilities when consideration is received or due prior to the satisfaction of the performance obligations. These contract liabilities primarily relate to upfront consideration received or due for equipment service plans, solar panel leases and the Illinois ZEC program that introduces a cap on the total consideration to be received by Generation. The Generation contract liability related to the Illinois ZEC program includes certain amounts with ComEd that are eliminated in consolidation in Exelon's Consolidated Statements of Operations and Consolidated Balance Sheets. Generation records contract liabilities within Other current liabilities and Other noncurrent liabilities within Exelon's and Generation's Consolidated Balance Sheets.

The following table provides a rollforward of the contract assets and liabilities reflected in Exelon's and Generation's Consolidated Balance Sheets from January 1, 2018 to December 31, 2019:

<table><tr><td rowspan="2"></td><td colspan="3">Contract Assets</td><td colspan="3">Contract Liabilities</td></tr><tr><td>Exelon</td><td colspan="2">Generation</td><td>Exelon</td><td colspan="2">Generation</td></tr><tr><td>Balance as of January 1, 2018</td><td>$     283</td><td>$     283</td><td>$     35</td><td>$     35</td><td>$     35</td><td>$     35</td></tr><tr><td>Consideration received or due</td><td>(146)</td><td></td><td>(146)</td><td>179</td><td></td><td>465</td></tr><tr><td>Revenues recognized</td><td>50</td><td></td><td>50</td><td>(187)</td><td></td><td>(458)</td></tr><tr><td>Balance at December 31, 2018</td><td>187</td><td></td><td>187</td><td>27</td><td></td><td>42</td></tr><tr><td>Consideration received or due</td><td>(143)</td><td></td><td>(143)</td><td>94</td><td></td><td>287</td></tr><tr><td>Revenues recognized</td><td>130</td><td></td><td>130</td><td>(88)</td><td></td><td>(258)</td></tr><tr><td>Balance at December 31, 2019</td><td>$     174</td><td>$     174</td><td>$     33</td><td>$     33</td><td></td><td>71</td></tr></table>

The Utility Registrants do not have any contract assets. The Utility Registrants also record contract liabilities when consideration is received prior to the satisfaction of the performance obligations. As of December 31, 2019 and December 31, 2018, the Utility Registrants' contract liabilities were immaterial.

## Transaction Price Allocated to Remaining Performance Obligations (All Registrants)

The following table shows the amounts of future revenues expected to be recorded in each year for performance obligations that are unsatisfied or partially unsatisfied as of December 31, 2019. 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 Generation’s power and gas sales contracts as they contain variable volumes and/or variable pricing. This disclosure also excludes the Utility Registrants’ gas and electric tariff sales contracts and transmission revenue contracts as they generally have an original expected duration of one year or less and, therefore, do not contain any future, unsatisfied performance obligations to be included in this disclosure.



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 4 — Revenue from Contracts with Customers

<table><tr><td></td><td>2020</td><td>2021</td><td>2022</td><td>2023</td><td>2024 and thereafter</td><td>Total</td></tr><tr><td>Exelon</td><td>$ 400</td><td>$ 141</td><td>$ 65</td><td>$ 45</td><td>$ 199</td><td>$ 850</td></tr><tr><td>Generation</td><td>501</td><td>196</td><td>80</td><td>45</td><td>199</td><td>1,021</td></tr></table>

## Revenue Disaggregation (All Registrants)

The Registrants disaggregate 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 Note 5 — Segment Information for the presentation of the Registrant's revenue disaggregation.

## 5. Segment Information (All Registrants)

Operating segments for each of the Registrants are determined based on information used by the CODM in deciding how to evaluate performance and allocate resources at each of the Registrants.

Exelon has eleven reportable segments, which include Generation's five reportable segments consisting of the Mid-Atlantic, Midwest, New York, ERCOT and all other power regions referred to collectively as "Other Power Regions" and ComEd, PECO, BGE, and PHI's three reportable segments consisting of Pepco, DPL, and ACE. ComEd, PECO, BGE, Pepco, DPL and ACE each represent a single reportable segment, and as such, no separate segment information is provided for these Registrants. Exelon, ComEd, PECO, BGE, Pepco, DPL and ACE's CODMs evaluate the performance of and allocate resources to ComEd, PECO, BGE, Pepco, DPL and ACE based on net income.

The basis for Generation's reportable segments is the integrated management of its 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). Generation's hedging strategies and risk metrics are also aligned to these same geographic regions. Descriptions of each of Generation's five reportable segments are as follows:

- Mid-Atlantic represents operations in the eastern half of PJM, which includes New Jersey, Maryland, Virginia, West Virginia, Delaware, the District of Columbia and parts of Pennsylvania and North Carolina.

• Midwest represents operations in the western half of PJM and the United States footprint of MISO, excluding MISO's Southern Region.

• New York represents operations within NYISO.

• ERCOT represents operations within Electric Reliability Council of Texas.

• Other Power Regions:

• New England represents operations within ISO-NE.

• South represents operations in the FRCC, MISO's Southern Region, the remaining portions of the SERC not included within MISO or PJM.

• West represents operations in the WECC, including California ISO.

• Canada represents operations across the entire country of Canada and includes AESO, OIESO and the Canadian portion of MISO.

The CODMs for Exelon and Generation evaluate the performance of Generation's electric business activities and allocate resources based on RNF. Generation believes that RNF is a useful measurement of operational performance. RNF 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. Generation's operating revenues include all sales to third parties and affiliated sales to the Utility Registrants. 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 Generation's owned generation and fuel costs associated with tolling agreements. The results of Generation's 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 natural gas, as well as other miscellaneous business activities that are not significant to Generation's overall operating revenues or results of operations. Further, Generation's unrealized mark-to-market gains and losses on economic hedging activities and its 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. Exelon and Generation do not use a measure of total assets in making decisions regarding allocating resources to or assessing the performance of these reportable segments.

During the first quarter of 2019, due to a change in economics in our New England region, Generation changed the way that information is reviewed by the CODM. The New England region is no longer regularly reviewed as a separate region by the CODM nor is it presented separately in any external information presented to third parties. Information for the New England region is reviewed by the CODM as part of Other Power Regions. Exelon and Generation retrospectively applied this change.

An analysis and reconciliation of the Registrants' reportable segment information to the respective information in the consolidated financial statements for the years ended December 31, 2019, 2018, and 2017 is as follows:

<table><tr><td></td><td>Generation (a)</td><td>ComEd</td><td>PECO</td><td>BGE</td><td>PHI</td><td>Other (b)</td><td>Intersegment Eliminations</td><td>Exelon</td></tr><tr><td>Operating revenues(c):</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>2019</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Competitive businesses electric revenues</td><td>$ 16,285</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>(1,165)</td></tr><tr><td>Competitive businesses natural gas revenues</td><td>2,148</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(1)</td></tr><tr><td>Competitive businesses other revenues</td><td>491</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(4)</td></tr><tr><td>Rate-regulated electric revenues</td><td>—</td><td>5,747</td><td>2,490</td><td>2,379</td><td>4,626</td><td>—</td><td>—</td><td>(47)</td></tr><tr><td>Rate-regulated natural gas revenues</td><td>—</td><td>—</td><td>610</td><td>727</td><td>167</td><td>—</td><td>—</td><td>(15)</td></tr><tr><td>Shared service and other revenues</td><td>—</td><td>—</td><td>—</td><td>—</td><td>13</td><td>1,921</td><td>—</td><td>(1,934)</td></tr><tr><td>Total operating revenues</td><td>$ 18,924</td><td>$ 5,747</td><td>$ 3,100</td><td>$ 3,106</td><td>$ 4,806</td><td>$ 1,921</td><td>$ (3,166)</td><td>$ 34,438</td></tr></table>



## Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 5 — Segment Information

<table><tr><td></td><td>Generation (a)</td><td>ComEd</td><td>PECO</td><td>BGE</td><td>PHI</td><td>Other (b)</td><td>Intersegment Eliminations</td><td>Exelon</td></tr><tr><td>2018</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Competitive businesses electric revenues</td><td>$ 17,411</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>(1,256)</td></tr><tr><td>Competitive businesses natural gas revenues</td><td>2,718</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(8)</td></tr><tr><td>Competitive businesses other revenues</td><td>308</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(5)</td></tr><tr><td>Rate-regulated electric revenues</td><td>—</td><td>5,882</td><td>2,470</td><td>2,428</td><td>4,602</td><td>—</td><td>—</td><td>(45)</td></tr><tr><td>Rate-regulated natural gas revenues</td><td>—</td><td>—</td><td>568</td><td>741</td><td>181</td><td>—</td><td>—</td><td>(20)</td></tr><tr><td>Shared service and other revenues</td><td>—</td><td>—</td><td>—</td><td>—</td><td>15</td><td>1,948</td><td>—</td><td>(1,960)</td></tr><tr><td>Total operating revenues</td><td>$ 20,437</td><td>$ 5,882</td><td>$ 3,038</td><td>$ 3,169</td><td>$ 4,798</td><td>$ 1,948</td><td>$ (3,294)</td><td>$ 35,978</td></tr><tr><td>2017</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Competitive businesses electric revenues</td><td>$ 15,332</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>(1,105)</td></tr><tr><td>Competitive businesses natural gas revenues</td><td>2,575</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Competitive businesses other revenues</td><td>593</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(1)</td></tr><tr><td>Rate-regulated electric revenues</td><td>—</td><td>5,536</td><td>2,375</td><td>2,489</td><td>4,462</td><td>—</td><td>—</td><td>(29)</td></tr><tr><td>Rate-regulated natural gas revenues</td><td>—</td><td>—</td><td>495</td><td>687</td><td>161</td><td>—</td><td>—</td><td>(10)</td></tr><tr><td>Shared service and other revenues</td><td>—</td><td>—</td><td>—</td><td>—</td><td>49</td><td>1,831</td><td>—</td><td>(1,880)</td></tr><tr><td>Total operating revenues</td><td>$ 18,500</td><td>$ 5,536</td><td>$ 2,870</td><td>$ 3,176</td><td>$ 4,672</td><td>$ 1,831</td><td>$ (3,025)</td><td>$ 33,560</td></tr></table>

<table><tr><td colspan="12">Intersegment revenues(d):</td></tr><tr><td>2019</td><td>$</td><td>1,172</td><td>$</td><td>30</td><td>$</td><td>6</td><td>$</td><td>26</td><td>$</td><td>14</td><td>$</td><td>1,913</td></tr><tr><td>2018</td><td></td><td>1,269</td><td></td><td>27</td><td></td><td>8</td><td></td><td>29</td><td></td><td>15</td><td></td><td>1,942</td></tr><tr><td>2017</td><td></td><td>1,110</td><td></td><td>15</td><td></td><td>7</td><td></td><td>16</td><td></td><td>50</td><td></td><td>1,824</td></tr><tr><td colspan="12">Depreciation and amortization:</td></tr><tr><td>2019</td><td>$</td><td>1,535</td><td>$</td><td>1,033</td><td>$</td><td>333</td><td>$</td><td>502</td><td>$</td><td>754</td><td>$</td><td>95</td></tr><tr><td>2018</td><td></td><td>1,797</td><td></td><td>940</td><td></td><td>301</td><td></td><td>483</td><td></td><td>740</td><td></td><td>92</td></tr><tr><td>2017</td><td></td><td>1,457</td><td></td><td>850</td><td></td><td>286</td><td></td><td>473</td><td></td><td>675</td><td></td><td>87</td></tr><tr><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr></table>



## Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 5 — Segment Information

<table><tr><td></td><td>Generation (a)</td><td>ComEd</td><td>PECO</td><td>BGE</td><td>PHI</td><td>Other (b)</td><td>Intersegment Eliminations</td><td>Exelon</td></tr><tr><td>Operating expenses (c):</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>2019</td><td>$ 17,628</td><td>$ 4,580</td><td>$ 2,388</td><td>$ 2,574</td><td>$ 4,084</td><td>$ 1,996</td><td>$ (3,154)</td><td>$ 30,096</td></tr><tr><td>2018</td><td>19,510</td><td>4,741</td><td>2,452</td><td>2,696</td><td>4,156</td><td>1,929</td><td>(3,341)</td><td>32,143</td></tr><tr><td>2017</td><td>18,001</td><td>4,214</td><td>2,215</td><td>2,562</td><td>3,911</td><td>1,742</td><td>(3,026)</td><td>29,619</td></tr><tr><td>Interest expense, net:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>2019</td><td>$ 429</td><td>$ 359</td><td>$ 136</td><td>$ 121</td><td>$ 263</td><td>$ 308</td><td>$ —</td><td>$ 1,616</td></tr><tr><td>2018</td><td>432</td><td>347</td><td>129</td><td>106</td><td>261</td><td>279</td><td>—</td><td>1,554</td></tr><tr><td>2017</td><td>440</td><td>361</td><td>126</td><td>105</td><td>245</td><td>283</td><td>—</td><td>1,560</td></tr><tr><td>Income (loss) before income taxes:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>2019</td><td>$ 1,917</td><td>$ 851</td><td>$ 593</td><td>$ 439</td><td>$ 514</td><td>$ (327)</td><td>$ (2)</td><td>$ 3,985</td></tr><tr><td>2018</td><td>365</td><td>832</td><td>466</td><td>387</td><td>425</td><td>(249)</td><td>(1)</td><td>2,225</td></tr><tr><td>2017</td><td>1,455</td><td>984</td><td>538</td><td>525</td><td>571</td><td>(296)</td><td>(2)</td><td>3,775</td></tr><tr><td>Income taxes:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>2019</td><td>$ 516</td><td>$ 163</td><td>$ 65</td><td>$ 79</td><td>$ 38</td><td>$ (87)</td><td>$ —</td><td>$ 774</td></tr><tr><td>2018</td><td>(108)</td><td>168</td><td>6</td><td>74</td><td>33</td><td>(55)</td><td>—</td><td>118</td></tr><tr><td>2017</td><td>(1,376)</td><td>417</td><td>104</td><td>218</td><td>217</td><td>294</td><td>—</td><td>(126)</td></tr><tr><td>Net income (loss):</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>2019</td><td>$ 1,217</td><td>$ 688</td><td>$ 528</td><td>$ 360</td><td>$ 477</td><td>$ (240)</td><td>$ (2)</td><td>$ 3,028</td></tr><tr><td>2018</td><td>443</td><td>664</td><td>460</td><td>313</td><td>393</td><td>(193)</td><td>(1)</td><td>2,079</td></tr><tr><td>2017</td><td>2,798</td><td>567</td><td>434</td><td>307</td><td>355</td><td>(590)</td><td>(2)</td><td>3,869</td></tr><tr><td>Capital expenditures:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>2019</td><td>$ 1,845</td><td>$ 1,915</td><td>$ 939</td><td>$ 1,145</td><td>$ 1,355</td><td>$ 49</td><td>$ —</td><td>$ 7,248</td></tr><tr><td>2018</td><td>2,242</td><td>2,126</td><td>849</td><td>959</td><td>1,375</td><td>43</td><td>—</td><td>7,594</td></tr><tr><td>2017</td><td>2,259</td><td>2,250</td><td>732</td><td>882</td><td>1,396</td><td>65</td><td>—</td><td>7,584</td></tr><tr><td>Total assets:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>2019</td><td>$ 48,995</td><td>$ 32,765</td><td>$ 11,469</td><td>$ 10,634</td><td>$ 22,719</td><td>$ 8,484</td><td>$ (10,089)</td><td>$ 124,977</td></tr><tr><td>2018</td><td>47,556</td><td>31,213</td><td>10,642</td><td>9,716</td><td>21,952</td><td>8,355</td><td>(9,800)</td><td>119,634</td></tr></table>

(a) See Note 24 — Related Party Transactions for additional information on intersegment revenues.

(b) Other primarily includes Exelon's corporate operations, shared service entities and other financing and investment activities.

(c) Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants' Consolidated Statements of Operations and Comprehensive Income. See Note 23 — Supplemental Financial Information for additional information on total utility taxes.

(d) Intersegment revenues exclude sales to unconsolidated affiliates. The intersegment profit associated with Generation’s sale of certain products and services by and between Exelon’s segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory authoritative guidance. For Exelon, these amounts are included in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income.



## Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 5 — Segment Information

PHI:

<table><tr><td></td><td>Pepco</td><td>DPL</td><td>ACE</td><td>Other(b)</td><td>Intersegment Eliminations</td><td>PHI</td></tr><tr><td>Operating revenues(a):</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>2019</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Rate-regulated electric revenues</td><td>$ 2,260</td><td>$ 1,139</td><td>$ 1,240</td><td>$ —</td><td>$ (13)</td><td>$ 4,626</td></tr><tr><td>Rate-regulated natural gas revenues</td><td>—</td><td>167</td><td>—</td><td>—</td><td>—</td><td>167</td></tr><tr><td>Shared service and other revenues</td><td>—</td><td>—</td><td>—</td><td>396</td><td>(383)</td><td>13</td></tr><tr><td>Total operating revenues</td><td>$ 2,260</td><td>$ 1,306</td><td>$ 1,240</td><td>$ 396</td><td>$ (396)</td><td>$ 4,806</td></tr><tr><td>2018</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Rate-regulated electric revenues</td><td>$ 2,232</td><td>$ 1,151</td><td>$ 1,236</td><td>$ —</td><td>$ (17)</td><td>$ 4,602</td></tr><tr><td>Rate-regulated natural gas revenues</td><td>—</td><td>181</td><td>—</td><td>—</td><td>—</td><td>181</td></tr><tr><td>Shared service and other revenues</td><td>—</td><td>—</td><td>—</td><td>435</td><td>(420)</td><td>15</td></tr><tr><td>Total operating revenues</td><td>$ 2,232</td><td>$ 1,332</td><td>$ 1,236</td><td>$ 435</td><td>$ (437)</td><td>$ 4,798</td></tr><tr><td>2017</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Rate-regulated electric revenues</td><td>$ 2,151</td><td>$ 1,139</td><td>$ 1,186</td><td>$ —</td><td>$ (14)</td><td>$ 4,462</td></tr><tr><td>Rate-regulated natural gas revenues</td><td>—</td><td>161</td><td>—</td><td>—</td><td>—</td><td>161</td></tr><tr><td>Shared service and other revenues</td><td>—</td><td>—</td><td>—</td><td>52</td><td>(3)</td><td>49</td></tr><tr><td>Total operating revenues</td><td>$ 2,151</td><td>$ 1,300</td><td>$ 1,186</td><td>$ 52</td><td>$ (17)</td><td>$ 4,672</td></tr><tr><td>Intersegment revenues:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>2019</td><td>$ 5</td><td>$ 7</td><td>$ 3</td><td>$ 396</td><td>$ (397)</td><td>$ 14</td></tr><tr><td>2018</td><td>6</td><td>8</td><td>3</td><td>435</td><td>(437)</td><td>15</td></tr><tr><td>2017</td><td>6</td><td>8</td><td>2</td><td>53</td><td>(19)</td><td>50</td></tr><tr><td>Depreciation and amortization:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>2019</td><td>$ 374</td><td>$ 184</td><td>$ 157</td><td>$ 39</td><td>$ —</td><td>$ 754</td></tr><tr><td>2018</td><td>385</td><td>182</td><td>136</td><td>37</td><td>—</td><td>$ 740</td></tr><tr><td>2017</td><td>321</td><td>167</td><td>146</td><td>42</td><td>(1)</td><td>$ 675</td></tr><tr><td>Operating expenses:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>2019</td><td>$ 1,899</td><td>$ 1,089</td><td>$ 1,089</td><td>$ 403</td><td>$ (396)</td><td>$ 4,084</td></tr><tr><td>2018</td><td>1,919</td><td>1,143</td><td>1,087</td><td>442</td><td>(435)</td><td>$ 4,156</td></tr><tr><td>2017</td><td>1,760</td><td>1,071</td><td>1,029</td><td>68</td><td>(17)</td><td>$ 3,911</td></tr><tr><td>Interest expense, net:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>2019</td><td>$ 133</td><td>$ 61</td><td>$ 58</td><td>$ 10</td><td>$ 1</td><td>$ 263</td></tr><tr><td>2018</td><td>128</td><td>58</td><td>64</td><td>11</td><td>—</td><td>$ 261</td></tr><tr><td>2017</td><td>121</td><td>51</td><td>61</td><td>13</td><td>(1)</td><td>$ 245</td></tr><tr><td>Income (loss) before income taxes:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>2019</td><td>$ 259</td><td>$ 169</td><td>$ 99</td><td>$ 476</td><td>$ (489)</td><td>$ 514</td></tr><tr><td>2018</td><td>216</td><td>142</td><td>87</td><td>388</td><td>(408)</td><td>$ 425</td></tr><tr><td>2017</td><td>303</td><td>192</td><td>103</td><td>377</td><td>(404)</td><td>$ 571</td></tr><tr><td>Income taxes:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>2019</td><td>$ 16</td><td>$ 22</td><td>$ —</td><td>$ (1)</td><td>$ 1</td><td>$ 38</td></tr><tr><td>2018</td><td>11</td><td>22</td><td>12</td><td>(10)</td><td>(2)</td><td>$ 33</td></tr><tr><td>2017</td><td>105</td><td>71</td><td>26</td><td>15</td><td>—</td><td>$ 217</td></tr></table>



## Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 5 — Segment Information

<table><tr><td></td><td>Pepco</td><td>DPL</td><td>ACE</td><td>Other(b)</td><td>Intersegment Eliminations</td><td>PHI</td></tr><tr><td>Net income (loss):</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>2019</td><td>$ 243</td><td>$ 147</td><td>$ 99</td><td>$ (26)</td><td>$ 14</td><td>$ 477</td></tr><tr><td>2018</td><td>205</td><td>120</td><td>75</td><td>(22)</td><td>15</td><td>$ 393</td></tr><tr><td>2017</td><td>198</td><td>121</td><td>77</td><td>(91)</td><td>50</td><td>$ 355</td></tr><tr><td>Capital expenditures:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>2019</td><td>$ 626</td><td>$ 348</td><td>$ 375</td><td>$ 6</td><td>$ —</td><td>$ 1,355</td></tr><tr><td>2018</td><td>656</td><td>364</td><td>335</td><td>20</td><td>—</td><td>$ 1,375</td></tr><tr><td>2017</td><td>628</td><td>428</td><td>312</td><td>28</td><td>—</td><td>$ 1,396</td></tr><tr><td>Total assets:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>2019</td><td>$ 8,661</td><td>$ 4,830</td><td>$ 3,933</td><td>$ 11,105</td><td>$ (5,810)</td><td>$ 22,719</td></tr><tr><td>2018</td><td>8,267</td><td>4,588</td><td>3,699</td><td>10,819</td><td>(5,421)</td><td>21,952</td></tr></table>

(a) Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants' Consolidated Statements of Operations and Comprehensive Income. See Note 23 — Supplemental Financial Information for additional information on total utility taxes.

(b) Other primarily includes PHI's corporate operations, shared service entities and other financing and investment activities.



The following tables disaggregate the Registrants' 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. For Generation, the disaggregation of revenues reflects Generation's two primary products of power sales and natural gas sales, with further disaggregation of power sales provided by geographic region. For the Utility Registrants, the disaggregation of revenues reflects the two primary utility services of rate-regulated electric sales and rate-regulated natural gas sales (where applicable), with further disaggregation of these tariff sales provided by major customer groups. Exelon's disaggregated revenues are consistent with Generation and the Utility Registrants but exclude any intercompany revenues.

## Competitive Business Revenues (Generation):

<table><tr><td rowspan="3"></td><td colspan="6">2019</td></tr><tr><td colspan="4">Revenues from external customers(a)</td><td rowspan="2">Intersegment Revenues</td><td rowspan="2">Total Revenues</td></tr><tr><td>Contracts with customers</td><td>Other(b)</td><td>Total</td><td></td></tr><tr><td>Mid-Atlantic</td><td>$ 5,053</td><td>$ 17</td><td>$ 5,070</td><td>$ 4</td><td>$ 5,074</td><td></td></tr><tr><td>Midwest</td><td>4,095</td><td>232</td><td>4,327</td><td>(34)</td><td>4,293</td><td></td></tr><tr><td>New York</td><td>1,571</td><td>25</td><td>1,596</td><td>—</td><td>1,596</td><td></td></tr><tr><td>ERCOT</td><td>768</td><td>229</td><td>997</td><td>16</td><td>1,013</td><td></td></tr><tr><td>Other Power Regions</td><td>3,687</td><td>608</td><td>4,295</td><td>(49)</td><td>4,246</td><td></td></tr><tr><td>Total Competitive Businesses Electric Revenues</td><td>15,174</td><td>1,111</td><td>16,285</td><td>(63)</td><td>16,222</td><td></td></tr><tr><td>Competitive Businesses Natural Gas Revenues</td><td>1,446</td><td>702</td><td>2,148</td><td>62</td><td>2,210</td><td></td></tr><tr><td>Competitive Businesses Other Revenues(c)</td><td>440</td><td>51</td><td>491</td><td>1</td><td>492</td><td></td></tr><tr><td>Total Generation Consolidated Operating Revenues</td><td>17,060</td><td>1,864</td><td>$ 18,924</td><td>$ —</td><td>$ 18,924</td><td></td></tr></table>

<table><tr><td rowspan="3"></td><td colspan="6">2018</td></tr><tr><td colspan="4">Revenues from external customers(a)</td><td rowspan="2">Intersegment Revenues</td><td rowspan="2">Total Revenues</td></tr><tr><td>Contracts with customers</td><td>Other(b)</td><td>Total</td><td></td></tr><tr><td>Mid-Atlantic</td><td>$ 5,241</td><td>$ 233</td><td>$ 5,474</td><td>$ 13</td><td>$ 5,487</td><td></td></tr><tr><td>Midwest</td><td>4,527</td><td>190</td><td>4,717</td><td>(11)</td><td>4,706</td><td></td></tr><tr><td>New York</td><td>1,723</td><td>(36)</td><td>1,687</td><td>—</td><td>1,687</td><td></td></tr><tr><td>ERCOT</td><td>572</td><td>560</td><td>1,132</td><td>1</td><td>1,133</td><td></td></tr><tr><td>Other Power Regions</td><td>3,530</td><td>871</td><td>4,401</td><td>(66)</td><td>4,335</td><td></td></tr><tr><td>Total Competitive Businesses Electric Revenues</td><td>15,593</td><td>1,818</td><td>17,411</td><td>(63)</td><td>17,348</td><td></td></tr><tr><td>Competitive Businesses Natural Gas Revenues</td><td>1,524</td><td>1,194</td><td>2,718</td><td>62</td><td>2,780</td><td></td></tr><tr><td>Competitive Businesses Other Revenues(c)</td><td>510</td><td>(202)</td><td>308</td><td>1</td><td>309</td><td></td></tr><tr><td>Total Generation Consolidated Operating Revenues</td><td>$ 17,627</td><td>$ 2,810</td><td>$ 20,437</td><td>$ —</td><td>$ 20,437</td><td></td></tr></table>



## Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 5 — Segment Information

<table><tr><td rowspan="2"></td><td colspan="6">2017</td></tr><tr><td colspan="5">Revenues from external customers(a)</td><td rowspan="2">Intersegment Revenues</td><td rowspan="2">Total Revenues</td></tr><tr><td></td><td colspan="2">Contracts with customers</td><td>Other(b)</td><td>Total</td></tr><tr><td>Mid-Atlantic</td><td>$     5,523</td><td>$      (8)</td><td>$     5,515</td><td>$     25</td><td>$     5,540</td><td></td></tr><tr><td>Midwest</td><td>3,923</td><td>283</td><td>4,206</td><td>(25)</td><td>4,181</td><td></td></tr><tr><td>New York</td><td>1,605</td><td>(38)</td><td>1,567</td><td>(17)</td><td>1,550</td><td></td></tr><tr><td>ERCOT</td><td>641</td><td>317</td><td>958</td><td>4</td><td>962</td><td></td></tr><tr><td>Other Power Regions</td><td>2,658</td><td>428</td><td>3,086</td><td>(35)</td><td>3,051</td><td></td></tr><tr><td>Total Competitive Businesses Electric Revenues</td><td>14,350</td><td>982</td><td>15,332</td><td>(48)</td><td>15,284</td><td></td></tr><tr><td>Competitive Businesses Natural Gas Revenues</td><td>1,658</td><td>917</td><td>2,575</td><td>53</td><td>2,628</td><td></td></tr><tr><td>Competitive Businesses Other Revenues(c)</td><td>744</td><td>(151)</td><td>593</td><td>(5)</td><td>588</td><td></td></tr><tr><td>Total Generation Consolidated Operating Revenues</td><td>$     16,752</td><td>$     1,748</td><td>$     18,500</td><td>$      —</td><td>$     18,500</td><td></td></tr></table>

(a) Includes all wholesale and retail electric sales to third parties and affiliated sales to the Utility Registrants.

(b) Includes revenues from derivatives and leases.

(c) Other represents activities not allocated to a region. See text above for a description of included activities. Includes a $38 million decrease to revenues for the amortization of intangible assets and liabilities related to commodity contracts recorded at fair value in 2017, unrealized mark-to-market losses of $4 million, $262 million, and $131 million in 2019, 2018, and 2017, respectively, and elimination of intersegment revenues.

Revenues net of purchased power and fuel expense (Generation):

<table><tr><td rowspan="2"></td><td colspan="4">2019</td><td colspan="4">2018</td><td colspan="4">2017</td></tr><tr><td>RNF from external customers(a)</td><td>Intersegment RNF</td><td>Total RNF</td><td>RNF from external customers(a)</td><td>Intersegment RNF</td><td>Total R NF</td><td>RNF from external customers(a)</td><td>Intersegment RNF</td><td>Total</td><td>RNF from external customers(a)</td><td>Intersegment RNF</td><td>Total</td></tr><tr><td>Mid-Atlantic</td><td>$ 2,637</td><td>$ 18</td><td>$ 2,655</td><td>$ 3,022</td><td>$ 51</td><td>$ 3,073</td><td>$ 3,105</td><td>$ 109</td><td>$ 3,214</td><td></td><td></td><td></td></tr><tr><td>Midwest</td><td>2,994</td><td>(32)</td><td>2,962</td><td>3,112</td><td>23</td><td>3,135</td><td>2,810</td><td>10</td><td>2,820</td><td></td><td></td><td></td></tr><tr><td>New York</td><td>1,081</td><td>13</td><td>1,094</td><td>1,112</td><td>10</td><td>1,122</td><td>1,007</td><td>1</td><td>1,008</td><td></td><td></td><td></td></tr><tr><td>ERCOT</td><td>338</td><td>(30)</td><td>308</td><td>501</td><td>(243)</td><td>258</td><td>575</td><td>(243)</td><td>332</td><td></td><td></td><td></td></tr><tr><td>Other Power Regions</td><td>694</td><td>(74)</td><td>620</td><td>883</td><td>(154)</td><td>729</td><td>1,014</td><td>(195)</td><td>819</td><td></td><td></td><td></td></tr><tr><td>Total Revenues net of purchased power and fuel for Reportable Segments</td><td>$ 7,744</td><td>$ (105)</td><td>$ 7,639</td><td>$ 8,630</td><td>$ (313)</td><td>$ 8,317</td><td>$ 8,511</td><td>$ (318)</td><td>$ 8,193</td><td></td><td></td><td></td></tr><tr><td>Other (b)</td><td>324</td><td>105</td><td>429</td><td>114</td><td>313</td><td>427</td><td>299</td><td>318</td><td>617</td><td></td><td></td><td></td></tr><tr><td>Total Generation Revenues net of purchased power and fuel expense</td><td>$ 8,068</td><td>$ —</td><td>$ 8,068</td><td>$ 8,744</td><td>$ —</td><td>$ 8,744</td><td>$ 8,810</td><td>$ —</td><td>$ 8,810</td><td></td><td></td><td></td></tr></table>

(a) Includes purchases and sales from/to third parties and affiliated sales to the Utility Registrants.

(b) Other represents activities not allocated to a region. See text above for a description of included activities. Includes a $54 million decrease in RNF for the amortization of intangible assets and liabilities related to commodity contracts in 2017, unrealized mark-to-market losses of $215 million, $319 million, and $175 million in 2019, 2018, and 2017, respectively, accelerated nuclear fuel amortization associated with the announced early plant retirements as discussed in Note 6 - Early Plant Retirements of $13 million, $57 million and $12 million in 2019, 2018, and 2017, respectively, and the elimination of intersegment RNF.



## Electric and Gas Revenue by Customer Class (Utility Registrants):

<table><tr><td rowspan="2">Revenues from contracts with customers</td><td colspan="9">2019</td></tr><tr><td>ComEd</td><td>PECO</td><td>BGE</td><td>PHI</td><td>Pepco</td><td>DPL</td><td>ACE</td><td></td><td></td></tr><tr><td>Rate-regulated electric revenues</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Residential</td><td>$ 2,916</td><td>$ 1,596</td><td>$ 1,326</td><td>$ 2,316</td><td>$ 1,012</td><td>$ 645</td><td>$ 659</td><td></td><td></td></tr><tr><td>Small commercial &amp; industrial</td><td>1,463</td><td>404</td><td>254</td><td>505</td><td>149</td><td>186</td><td>170</td><td></td><td></td></tr><tr><td>Large commercial &amp; industrial</td><td>540</td><td>219</td><td>436</td><td>1,112</td><td>833</td><td>99</td><td>180</td><td></td><td></td></tr><tr><td>Public authorities &amp; electric railroads</td><td>47</td><td>29</td><td>27</td><td>61</td><td>34</td><td>14</td><td>13</td><td></td><td></td></tr><tr><td>Other(a)</td><td>888</td><td>249</td><td>321</td><td>650</td><td>227</td><td>204</td><td>218</td><td></td><td></td></tr><tr><td>Total rate-regulated electric revenues(b)</td><td>5,854</td><td>2,497</td><td>2,364</td><td>4,644</td><td>2,255</td><td>1,148</td><td>1,240</td><td></td><td></td></tr><tr><td>Rate-regulated natural gas revenues</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Residential</td><td>—</td><td>409</td><td>474</td><td>96</td><td>—</td><td>96</td><td>—</td><td></td><td></td></tr><tr><td>Small commercial &amp; industrial</td><td>—</td><td>169</td><td>77</td><td>44</td><td>—</td><td>45</td><td>—</td><td></td><td></td></tr><tr><td>Large commercial &amp; industrial</td><td>—</td><td>1</td><td>132</td><td>5</td><td>—</td><td>5</td><td>—</td><td></td><td></td></tr><tr><td>Transportation</td><td>—</td><td>25</td><td>—</td><td>14</td><td>—</td><td>14</td><td>—</td><td></td><td></td></tr><tr><td>Other(c)</td><td>—</td><td>6</td><td>31</td><td>7</td><td>—</td><td>7</td><td>—</td><td></td><td></td></tr><tr><td>Total rate-regulated natural gas revenues(d)</td><td>—</td><td>610</td><td>714</td><td>166</td><td>—</td><td>167</td><td>—</td><td></td><td></td></tr><tr><td>Total rate-regulated revenues from contracts with customers</td><td>5,854</td><td>3,107</td><td>3,078</td><td>4,810</td><td>2,255</td><td>1,315</td><td>1,240</td><td></td><td></td></tr><tr><td>Other revenues</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Revenues from alternative revenue programs</td><td>(133)</td><td>(21)</td><td>12</td><td>(14)</td><td>(3)</td><td>(11)</td><td>—</td><td></td><td></td></tr><tr><td>Other rate-regulated electric revenues(e)</td><td>26</td><td>13</td><td>12</td><td>10</td><td>8</td><td>2</td><td>—</td><td></td><td></td></tr><tr><td>Other rate-regulated natural gas revenues(f)</td><td>—</td><td>1</td><td>4</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Total other revenues</td><td>(107)</td><td>(7)</td><td>28</td><td>(4)</td><td>5</td><td>(9)</td><td>—</td><td></td><td></td></tr><tr><td>Total rate-regulated revenues for reportable segments</td><td>$ 5,747</td><td>$ 3,100</td><td>$ 3,106</td><td>$ 4,806</td><td>$ 2,260</td><td>$ 1,306</td><td>$ 1,240</td><td></td><td></td></tr></table>



## Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 5 — Segment Information

<table><tr><td></td><td colspan="8">2018</td></tr><tr><td>Revenues from contracts with customers</td><td>ComEd</td><td>PECO</td><td>BGE</td><td>PHI</td><td>Pepco</td><td>DPL</td><td>ACE</td><td></td></tr><tr><td>Rate-regulated electric revenues</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Residential</td><td>$ 2,942</td><td>$ 1,566</td><td>$ 1,382</td><td>$ 2,351</td><td>$ 1,021</td><td>$ 669</td><td>$ 661</td><td></td></tr><tr><td>Small commercial &amp; industrial</td><td>1,487</td><td>404</td><td>257</td><td>488</td><td>140</td><td>186</td><td>162</td><td></td></tr><tr><td>Large commercial &amp; industrial</td><td>538</td><td>223</td><td>429</td><td>1,124</td><td>846</td><td>100</td><td>178</td><td></td></tr><tr><td>Public authorities &amp; electric railroads</td><td>47</td><td>28</td><td>28</td><td>58</td><td>32</td><td>14</td><td>12</td><td></td></tr><tr><td>Other(a)</td><td>867</td><td>243</td><td>327</td><td>593</td><td>193</td><td>175</td><td>227</td><td></td></tr><tr><td>Total rate-regulated electric revenues(b)</td><td>5,881</td><td>2,464</td><td>2,423</td><td>4,614</td><td>2,232</td><td>1,144</td><td>1,240</td><td></td></tr><tr><td>Rate-regulated natural gas revenues</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Residential</td><td>—</td><td>395</td><td>491</td><td>99</td><td>—</td><td>99</td><td>—</td><td></td></tr><tr><td>Small commercial &amp; industrial</td><td>—</td><td>143</td><td>77</td><td>44</td><td>—</td><td>44</td><td>—</td><td></td></tr><tr><td>Large commercial &amp; industrial</td><td>—</td><td>1</td><td>124</td><td>8</td><td>—</td><td>8</td><td>—</td><td></td></tr><tr><td>Transportation</td><td>—</td><td>23</td><td>—</td><td>16</td><td>—</td><td>16</td><td>—</td><td></td></tr><tr><td>Other(c)</td><td>—</td><td>6</td><td>63</td><td>13</td><td>—</td><td>13</td><td>—</td><td></td></tr><tr><td>Total rate-regulated natural gas revenues(d)</td><td>—</td><td>568</td><td>755</td><td>180</td><td>—</td><td>180</td><td>—</td><td></td></tr><tr><td>Total rate-regulated revenues from contracts with customers</td><td>5,881</td><td>3,032</td><td>3,178</td><td>4,794</td><td>2,232</td><td>1,324</td><td>1,240</td><td></td></tr><tr><td>Other revenues</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Revenues from alternative revenue programs</td><td>(29)</td><td>(7)</td><td>(26)</td><td>(7)</td><td>(7)</td><td>4</td><td>(4)</td><td></td></tr><tr><td>Other rate-regulated electric revenues(e)</td><td>30</td><td>12</td><td>13</td><td>10</td><td>7</td><td>3</td><td>—</td><td></td></tr><tr><td>Other rate-regulated natural gas revenues(e)</td><td>—</td><td>1</td><td>4</td><td>1</td><td>—</td><td>1</td><td>—</td><td></td></tr><tr><td>Total other revenues</td><td>1</td><td>6</td><td>(9)</td><td>4</td><td>—</td><td>8</td><td>(4)</td><td></td></tr><tr><td>Total rate-regulated revenues for reportable segments</td><td>$ 5,882</td><td>$ 3,038</td><td>$ 3,169</td><td>$ 4,798</td><td>$ 2,232</td><td>$ 1,332</td><td>$ 1,236</td><td></td></tr></table>



## Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 5 — Segment Information

<table><tr><td rowspan="2">Revenues from contracts with customers</td><td colspan="9">2017</td></tr><tr><td>ComEd</td><td>PECO</td><td>BGE</td><td>PHI</td><td>Pepco</td><td>DPL</td><td>ACE</td><td></td><td></td></tr><tr><td>Rate-regulated electric revenues</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Residential</td><td>$ 2,715</td><td>$ 1,505</td><td>$ 1,365</td><td>$ 2,246</td><td>$ 964</td><td>$ 663</td><td>$ 619</td><td></td><td></td></tr><tr><td>Small commercial &amp; industrial</td><td>1,363</td><td>401</td><td>254</td><td>490</td><td>137</td><td>187</td><td>166</td><td></td><td></td></tr><tr><td>Large commercial &amp; industrial</td><td>455</td><td>223</td><td>427</td><td>1,086</td><td>794</td><td>103</td><td>189</td><td></td><td></td></tr><tr><td>Public authorities &amp; electric railroads</td><td>44</td><td>30</td><td>31</td><td>60</td><td>33</td><td>14</td><td>13</td><td></td><td></td></tr><tr><td>Other(a)</td><td>886</td><td>204</td><td>299</td><td>541</td><td>199</td><td>163</td><td>191</td><td></td><td></td></tr><tr><td>Total rate-regulated electric revenues(b)</td><td>5,463</td><td>2,363</td><td>2,376</td><td>4,423</td><td>2,127</td><td>1,130</td><td>1,178</td><td></td><td></td></tr><tr><td>Rate-regulated natural gas revenues</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Residential</td><td>—</td><td>331</td><td>437</td><td>90</td><td>—</td><td>90</td><td>—</td><td></td><td></td></tr><tr><td>Small commercial &amp; industrial</td><td>—</td><td>131</td><td>75</td><td>38</td><td>—</td><td>38</td><td>—</td><td></td><td></td></tr><tr><td>Large commercial &amp; industrial</td><td>—</td><td>1</td><td>119</td><td>8</td><td>—</td><td>8</td><td>—</td><td></td><td></td></tr><tr><td>Transportation</td><td>—</td><td>23</td><td>—</td><td>15</td><td>—</td><td>15</td><td>—</td><td></td><td></td></tr><tr><td>Other(c)</td><td>—</td><td>8</td><td>28</td><td>9</td><td>—</td><td>9</td><td>—</td><td></td><td></td></tr><tr><td>Total rate-regulated natural gas revenues(d)</td><td>—</td><td>494</td><td>659</td><td>160</td><td>—</td><td>160</td><td>—</td><td></td><td></td></tr><tr><td>Total rate-regulated revenues from contracts with customers</td><td>5,463</td><td>2,857</td><td>3,035</td><td>4,583</td><td>2,127</td><td>1,290</td><td>1,178</td><td></td><td></td></tr><tr><td>Other revenues</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Revenues from alternative revenue programs</td><td>43</td><td>—</td><td>124</td><td>33</td><td>19</td><td>6</td><td>8</td><td></td><td></td></tr><tr><td>Other rate-regulated electric revenues(e)</td><td>30</td><td>12</td><td>13</td><td>8</td><td>5</td><td>3</td><td>—</td><td></td><td></td></tr><tr><td>Other rate-regulated natural gas revenues(f)</td><td>—</td><td>1</td><td>4</td><td>1</td><td>—</td><td>1</td><td>—</td><td></td><td></td></tr><tr><td>Other revenues(f)</td><td>—</td><td>—</td><td>—</td><td>47</td><td>—</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Total other revenues</td><td>73</td><td>13</td><td>141</td><td>89</td><td>24</td><td>10</td><td>8</td><td></td><td></td></tr><tr><td>Total rate-regulated revenues for reportable segments</td><td>$ 5,536</td><td>$ 2,870</td><td>$ 3,176</td><td>$ 4,672</td><td>$ 2,151</td><td>$ 1,300</td><td>$ 1,186</td><td></td><td></td></tr></table>

(a) Includes revenues from transmission revenue from PJM, wholesale electric revenue and mutual assistance revenue.

(b) Includes operating revenues from affiliates of $30 million, $5 million, $8 million, $14 million, $5 million, $7 million and $3 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2019, $27 million, $7 million, $8 million, $15 million, $6 million, $8 million and $3 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, in 2018, and $15 million, $6 million, $5 million, $3 million, $6 million, $8 million and $2 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2017.

(c) Includes revenues from off-system natural gas sales.

(d) Includes operating revenues from affiliates of $1 million and $18 million at PECO and BGE, respectively, in 2019, $1 million and $21 million at PECO and BGE, respectively, in 2018, and $1 million and $11 million at PECO and BGE, respectively, in 2017.

(e) Includes late payment charge revenues.

(f) Includes operating revenues from affiliates of $47 million at PHI in 2017.

## 6. Early Plant Retirements (Exelon and Generation)

Exelon and Generation continuously evaluate factors that affect the current and expected economic value of Generation’s plants, including, but not limited to: market power prices, results of capacity auctions, potential legislative and regulatory solutions to ensure plants are fairly compensated for benefits they provide through their carbon-free emissions, reliability, or fuel security, and the impact of potential rules from the EPA requiring reduction of carbon and other emissions and the efforts of states to implement those final rules. The precise timing of an early retirement date for any plant, and the resulting financial statement impacts, may be affected by many factors,



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 6 — Early Plant Retirements

including the status of potential regulatory or legislative solutions, results of any transmission system reliability study assessments, the nature of any co-owner requirements and stipulations, and NDT fund requirements for nuclear plants, among other factors. However, the earliest retirement date for any plant would usually be the first year in which the unit does not have capacity or other obligations, and where applicable, just prior to its next scheduled nuclear refueling outage.

## Nuclear Generation

In 2015 and 2016, Generation identified the Clinton and Quad Cities nuclear plants in Illinois, Ginn and Nine Mile Point nuclear plants in New York and Three Mile Island nuclear plant in Pennsylvania as having the greatest risk of early retirement based on economic valuation and other factors. In 2017, PSEG made public similar financial challenges facing its New Jersey nuclear plants, including Salem, of which Generation owns a 42.59% ownership interest. PSEG is the operator of Salem and also has the decision-making authority to retire Salem.

Assuming the continued effectiveness of the Illinois ZES, New Jersey ZEC program and the New York CES, Generation and CENG, through its ownership of Ginn and Nine Mile Point, no longer consider Clinton, Quad Cities, Salem, Ginn or Nine Mile Point to be at heightened risk for early retirement. However, to the extent the Illinois ZES, New Jersey ZEC program or the New York CES do not operate as expected over their full terms, each of these plants could again be at heightened risk for early retirement, which could have a material impact on Exelon's and Generation's future financial statements. In addition, FERC's December 19, 2019 order on the MOPR in PJM may undermine the continued effectiveness of the Illinois ZES and the New Jersey ZEC program unless Illinois and New Jersey implement an FRR mechanism under which the Generation plants in these states would be removed from PJM's capacity auction. See Note 3 — Regulatory Matters for additional information on the Illinois ZES, New Jersey ZEC program, New York CES and FERC's December 19, 2019 order.

In Pennsylvania, the TMI nuclear plant did not clear in the May 2017 PJM capacity auction for the 2020-2021 planning year, the third consecutive year that TMI failed to clear the PJM base residual capacity auction and on May 30, 2017, based on these capacity auction results, prolonged periods of low wholesale power prices, and the absence of federal or state policies that place a value on nuclear energy for its ability to produce electricity without air pollution, Generation announced that it would permanently cease generation operations at TMI. On September 20, 2019, Generation permanently ceased generation operations at TMI.

On February 2, 2018, Generation announced that it would permanently cease generation operations at the Oyster Creek nuclear plant at the end of its current operating cycle and permanently ceased generation operations on September 17, 2018.



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 6 — Early Plant Retirements

As a result of these early nuclear plant retirement decisions, Exelon and Generation recognized incremental non-cash charges to earnings stemming from shortening the expected economic useful lives primarily related to accelerated depreciation of plant assets (including any ARC) and accelerated amortization of nuclear fuel, as well as operating and maintenance expenses. The total annual impact of these charges by year are summarized in the table below.

<table><tr><td>Income statement expense (pre-tax)</td><td>2019(a)</td><td>2018(b)</td><td>2017(c)</td></tr><tr><td>Depreciation and Amortization</td><td></td><td></td><td></td></tr><tr><td>Accelerated depreciation</td><td>$ 216</td><td>$ 539</td><td>$ 250</td></tr><tr><td>Accelerated nuclear fuel amortization</td><td>13</td><td>57</td><td>12</td></tr><tr><td>Operating and Maintenance(d)</td><td>(53)</td><td>32</td><td>77</td></tr><tr><td>Total</td><td>$ 176</td><td>$ 628</td><td>$ 339</td></tr></table>

(a) Reflects incremental charges for TMI from January 1, 2019 through September 20, 2019.

(b) Reflects incremental charges for TMI in 2018 and Oyster Creek from February 2, 2018 through September 17, 2018.

(c) Reflects incremental charges for TMI from May 30, 2017 through December 31, 2017.

(d) In 2019, primarily reflects the net impacts associated with the remeasurements of the TMI ARO in the first and third quarters. In 2018 and 2017, primarily reflects materials and supplies inventory reserve adjustments, employee related costs and CWIP impairments associated with the early retirement decisions for TMI and Oyster Creek. Excludes the charges in the third quarter of 2018 and second quarter of 2019 for the ARO remeasurement due to the sale of Oyster Creek. See Note 2 — Mergers, Acquisitions and Dispositions and Note 9 — Asset Retirement Obligations for additional information.

Generation’s Dresden, Byron, and Braidwood nuclear plants in Illinois are also showing increased signs of economic distress, which could lead to an early retirement, in a market that does not currently compensate them for their unique contribution to grid resiliency and their ability to produce large amounts of energy without carbon and air pollution. The May 2018 PJM capacity auction for the 2021-2022 planning year resulted in the largest volume of nuclear capacity ever not selected in the auction, including all of Dresden, and portions of Byron and Braidwood. Exelon continues to work with stakeholders on state policy solutions, while also advocating for broader market reforms at the regional and federal level.

## Other Generation

On March 29, 2018, Generation notified grid operator ISO-NE of its plans to early retire Mystic Units 8 and 9 absent regulatory reforms on June 1, 2022, at the end of the then-current capacity commitment for Mystic Units 7 and 8. Mystic Unit 9 was then committed through May 2021.

On May 16, 2018, Generation made a filing with FERC to establish cost-of-service compensation and terms and conditions of service for Mystic Units 8 and 9 for the period between June 1, 2022 - May 31, 2024. On December 20, 2018, FERC issued an order accepting the cost of service compensation, reflecting a number of adjustments to the annual fixed revenue requirement and allowing for recovery of a substantial portion of the costs associated with the Everett Marine Terminal. Those adjustments were reflected in a compliance filing filed on March 1, 2019. In the December 20, 2018 order, FERC also directed a paper hearing on ROE using a new methodology. On January 22, 2019, Exelon and several other parties filed requests for rehearing of certain findings in the order.

On March 25, 2019, ISO-NE filed the Inventoried Energy Program, which is intended to provide an interim fuel security program pending conclusion of the stakeholder process to develop a long-term, market-based solution to address fuel security. The Inventoried Energy Program went into effect on August 5, 2019. On October 7, 2019, requests for rehearing were denied and several parties have appealed to the D.C. Circuit Court. FERC ordered ISO-NE to file long-term, market-based fuel security rules by October 15, 2019; FERC has granted an extension to April 15, 2020.

The following table provides the balance sheet amounts as of December 31, 2019 for Exelon's and Generation's significant assets and liabilities associated with the Mystic Units 8 and 9 and Everett Marine Terminal assets that would potentially be impacted by the failure to adopt long-term solutions for reliability and fuel security.



## Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 6 — Early Plant Retirements

<table><tr><td>Asset Balances</td><td>December 31, 2019</td></tr><tr><td>Materials and supplies inventory</td><td>$ 31</td></tr><tr><td>Fuel inventory</td><td>11</td></tr><tr><td>Property, plant and equipment, net</td><td>902</td></tr><tr><td>Liability Balances</td><td></td></tr><tr><td>Asset retirement obligation</td><td>(3)</td></tr></table>

To ensure the continued reliable supply of fuel to Mystic Units 8 and 9 while they remain operating, on October 1, 2018, Generation acquired the Everett Marine Terminal in Massachusetts for a purchase price of $81 million, with the majority of the fair value allocated to Property, plant and equipment and no goodwill recorded. Generation also settled its existing long-term gas supply agreement, resulting in a pre-tax gain of $75 million, which is included within Purchased power and fuel expense in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.

See Note 11 — Asset Impairments for impairment assessment considerations on the New England Asset Group.



## 7. Property, Plant and Equipment (All Registrants)

The following tables present a summary of property, plant and equipment by asset category as of December 31, 2019 and 2018:

<table><tr><td>Asset Category</td><td>Exelon</td><td>Generation</td><td>ComEd</td><td>PECO</td><td>BGE</td><td>PHI</td><td>Pepco</td><td>DPL</td><td>ACE</td></tr><tr><td>December 31, 2019</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Electric—transmission and distribution</td><td>$ 56,809</td><td>$ —</td><td>$ 27,566</td><td>$ 8,957</td><td>$ 8,326</td><td>$ 13,809</td><td>$ 9,734</td><td>$ 4,464</td><td>$ 4,207</td></tr><tr><td>Electric—generation</td><td>29,839</td><td>29,839</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Gas—transportation and distribution</td><td>6,147</td><td>—</td><td>—</td><td>2,899</td><td>2,999</td><td>525</td><td>—</td><td>690</td><td>—</td></tr><tr><td>Common—electric and gas</td><td>1,907</td><td>—</td><td>—</td><td>877</td><td>991</td><td>146</td><td>—</td><td>160</td><td>—</td></tr><tr><td>Nuclear fuel(a)</td><td>5,656</td><td>5,656</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Construction work in progress</td><td>3,055</td><td>702</td><td>662</td><td>250</td><td>483</td><td>921</td><td>628</td><td>125</td><td>166</td></tr><tr><td>Other property, plant and equipment(b)</td><td>799</td><td>13</td><td>47</td><td>27</td><td>25</td><td>108</td><td>64</td><td>21</td><td>27</td></tr><tr><td>Total property, plant and equipment</td><td>104,212</td><td>36,210</td><td>28,275</td><td>13,010</td><td>12,824</td><td>15,509</td><td>10,426</td><td>5,460</td><td>4,400</td></tr><tr><td>Less: accumulated depreciation(c)</td><td>23,979</td><td>12,017</td><td>5,168</td><td>3,718</td><td>3,834</td><td>1,213</td><td>3,517</td><td>1,425</td><td>1,210</td></tr><tr><td>Property, plant and equipment, net</td><td>$ 80,233</td><td>$ 24,193</td><td>$ 23,107</td><td>$ 9,292</td><td>$ 8,990</td><td>$ 14,296</td><td>$ 6,909</td><td>$ 4,035</td><td>$ 3,190</td></tr><tr><td>December 31, 2018</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Electric—transmission and distribution</td><td>$ 53,090</td><td>$ —</td><td>$ 25,991</td><td>$ 8,359</td><td>$ 7,951</td><td>$ 12,664</td><td>$ 9,217</td><td>$ 4,195</td><td>$ 3,866</td></tr><tr><td>Electric—generation</td><td>29,170</td><td>29,170</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Gas—transportation and distribution</td><td>5,530</td><td>—</td><td>—</td><td>2,694</td><td>2,630</td><td>486</td><td>—</td><td>651</td><td>—</td></tr><tr><td>Common—electric and gas</td><td>1,627</td><td>—</td><td>—</td><td>756</td><td>860</td><td>126</td><td>—</td><td>136</td><td>—</td></tr><tr><td>Nuclear fuel(a)</td><td>5,957</td><td>5,957</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Construction work in progress</td><td>3,377</td><td>997</td><td>705</td><td>343</td><td>410</td><td>912</td><td>536</td><td>151</td><td>209</td></tr><tr><td>Other property, plant and equipment(b)</td><td>858</td><td>63</td><td>46</td><td>19</td><td>25</td><td>99</td><td>61</td><td>17</td><td>28</td></tr><tr><td>Total property, plant and equipment</td><td>99,609</td><td>36,187</td><td>26,742</td><td>12,171</td><td>11,876</td><td>14,287</td><td>9,814</td><td>5,150</td><td>4,103</td></tr><tr><td>Less: accumulated depreciation(c)</td><td>22,902</td><td>12,206</td><td>4,684</td><td>3,561</td><td>3,633</td><td>841</td><td>3,354</td><td>1,329</td><td>1,137</td></tr><tr><td>Property, plant and equipment, net</td><td>$ 76,707</td><td>$ 23,981</td><td>$ 22,058</td><td>$ 8,610</td><td>$ 8,243</td><td>$ 13,446</td><td>$ 6,460</td><td>$ 3,821</td><td>$ 2,966</td></tr></table>

(a) Includes nuclear fuel that is in the fabrication and installation phase of $1,025 million and $1,004 million at December 31, 2019 and 2018, respectively.

(b) Primarily composed of land and non-utility property.

(c) Includes accumulated amortization of nuclear fuel in the reactor core at Generation of $2,867 million and $2,969 million as of December 31, 2019 and 2018, respectively.



## Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 7 — Property, Plant and Equipment

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

<table><tr><td rowspan="2">Asset Category</td><td colspan="9">Average Service Life (years)</td></tr><tr><td>Exelon</td><td>Generation</td><td>ComEd</td><td>PECO</td><td>BGE</td><td>PHI</td><td>Pepco</td><td>DPL</td><td>ACE</td></tr><tr><td>Electric - transmission and distribution</td><td>5-80</td><td>N/A</td><td>5-80</td><td>5-65</td><td>5-75</td><td>5-75</td><td>5-75</td><td>5-70</td><td>5-65</td></tr><tr><td>Electric - generation</td><td>1-56</td><td>1-56</td><td>N/A</td><td>N/A</td><td>N/A</td><td>N/A</td><td>N/A</td><td>N/ A</td><td>N/A</td></tr><tr><td>Gas - transportation and distribution</td><td>5-80</td><td>N/A</td><td>N/A</td><td>5-70</td><td>5-80</td><td>5-75</td><td>N/A</td><td>5-75</td><td>N/A</td></tr><tr><td>Common - electric and gas</td><td>4-75</td><td>N/A</td><td>N/A</td><td>5-50</td><td>4-50</td><td>5-75</td><td>N/A</td><td>5-75</td><td>N/A</td></tr><tr><td>Nuclear fuel</td><td>1-8</td><td>1-8</td><td>N/A</td><td>N/A</td><td>N/A</td><td>N/A</td><td>N/A</td><td>N/ A</td><td>N/A</td></tr><tr><td>Other property, plant and equipment</td><td>1-50</td><td>1-10</td><td>34-50</td><td>50</td><td>20-50</td><td>3-50</td><td>33-50</td><td>8-50</td><td>13-15</td></tr></table>

Depreciation provisions are based on the estimated useful lives of the stations, which reflect the first renewal of the operating licenses for all of Generation's operating nuclear generating stations except for Clinton and Peach Bottom. Clinton depreciation provisions are based on an estimated useful life through 2027, which is the last year of the Illinois ZES. Peach Bottom depreciation provisions are based on estimated useful life of 2053 and 2054 for Unit 2 and Unit 3, respectively, which reflects the anticipated second renewal of its operating licenses. Beginning in 2017, TMI and Oyster Creek depreciation provisions were based on their 2019 expected shutdown dates. Beginning February 2018, Oyster Creek depreciation provisions were based on its announced shutdown date of September 2018. See Note 3 — Regulatory Matters for additional information regarding license renewals and the Illinois ZECs and Note 6 — Early Plant Retirements for additional information on the impacts of early plant retirements.

The following table presents the annual depreciation rates for each asset category. Nuclear fuel amortization is charged to fuel expense using the unit-of-production method and not included in the below table.

<table><tr><td rowspan="2"></td><td colspan="10">Annual Depreciation Rates</td></tr><tr><td>Exelon</td><td>Generation</td><td>ComEd</td><td>PECO</td><td>BGE</td><td>PHI</td><td>Pepco</td><td>DPL</td><td>ACE</td><td></td></tr><tr><td>December 31, 2019</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Electric—transmission and distribution</td><td>2.80%</td><td>N/A</td><td>2.99%</td><td>2.36%</td><td>2.60%</td><td>2.77%</td><td>2.47%</td><td>2.86%</td><td>2.94%</td><td></td></tr><tr><td>Electric—generation</td><td>4.35%</td><td>4.35%</td><td>N/A</td><td>N/A</td><td>N/A</td><td>N/A</td><td>N/A</td><td>N/ A</td><td>N/A</td><td></td></tr><tr><td>Gas—transportation and distribution</td><td>2.04%</td><td>N/A</td><td>N/A</td><td>1.89%</td><td>2.30%</td><td>1.55%</td><td>N/A</td><td>1.55%</td><td>N/A</td><td></td></tr><tr><td>Common—electric and gas</td><td>7.37%</td><td>N/A</td><td>N/A</td><td>6.06%</td><td>8.30%</td><td>8.25%</td><td>N/A</td><td>6.24%</td><td>N/A</td><td></td></tr><tr><td>December 31, 2018</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Electric—transmission and distribution</td><td>2.73%</td><td>N/A</td><td>2.95%</td><td>2.35%</td><td>2.61%</td><td>2.61%</td><td>2.40%</td><td>2.77%</td><td>2.45%</td><td></td></tr><tr><td>Electric—generation</td><td>5.37%</td><td>5.37%</td><td>N/A</td><td>N/A</td><td>N/A</td><td>N/A</td><td>N/A</td><td>N/ A</td><td>N/A</td><td></td></tr><tr><td>Gas—transportation and distribution</td><td>2.07%</td><td>N/A</td><td>N/A</td><td>1.90%</td><td>2.36%</td><td>1.59%</td><td>N/A</td><td>1.59%</td><td>N/A</td><td></td></tr><tr><td>Common—electric and gas</td><td>6.98%</td><td>N/A</td><td>N/A</td><td>5.44%</td><td>8.50%</td><td>6.30%</td><td>N/A</td><td>3.70%</td><td>N/A</td><td></td></tr><tr><td>December 31, 2017</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Electric—transmission and distribution</td><td>2.75%</td><td>N/A</td><td>2.99%</td><td>2.37%</td><td>2.58%</td><td>2.63%</td><td>2.35%</td><td>2.75%</td><td>2.46%</td><td></td></tr><tr><td>Electric—generation</td><td>4.36%</td><td>4.36%</td><td>N/A</td><td>N/A</td><td>N/A</td><td>N/A</td><td>N/A</td><td>N/ A</td><td>N/A</td><td></td></tr><tr><td>Gas—transportation and distribution</td><td>2.10%</td><td>N/A</td><td>N/A</td><td>1.89%</td><td>2.33%</td><td>2.07%</td><td>N/A</td><td>2.07%</td><td>N/A</td><td></td></tr><tr><td>Common—electric and gas</td><td>7.05%</td><td>N/A</td><td>N/A</td><td>5.47%</td><td>8.64%</td><td>6.50%</td><td>N/A</td><td>4.14%</td><td>N/A</td><td></td></tr></table>



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 7 — Property, Plant and Equipment

## Capitalized Interest and AFUDC (All Registrants)

The following table summarizes capitalized interest and credits to AFUDC by year:

<table><tr><td></td><td>Exelon</td><td>Generation</td><td>ComEd</td><td>PECO</td><td>BGE</td><td>PHI</td><td>Pepco</td><td>DPL</td><td>ACE</td></tr><tr><td>December 31, 2019</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Capitalized interest</td><td>$ 24</td><td>$ 24</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ \) —</td></tr><tr><td>AFUDC debt and equity</td><td>132</td><td>—</td><td>32</td><td>17</td><td>29</td><td>54</td><td>39</td><td>6</td><td>9</td></tr><tr><td>December 31, 2018</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Capitalized interest</td><td>$ 31</td><td>$ 31</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ \) —</td></tr><tr><td>AFUDC debt and equity</td><td>109</td><td>—</td><td>30</td><td>12</td><td>24</td><td>44</td><td>34</td><td>4</td><td>4</td></tr><tr><td>December 31, 2017</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Capitalized interest</td><td>$ 63</td><td>$ 63</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ \) —</td></tr><tr><td>AFUDC debt and equity</td><td>108</td><td>—</td><td>20</td><td>12</td><td>22</td><td>54</td><td>34</td><td>10</td><td>9</td></tr></table>

See Note 1 — Significant Accounting Policies for additional information regarding property, plant and equipment policies. See Note 16 — Debt and Credit Agreements for additional information regarding Exelon's, ComEd's and PECO's property, plant and equipment subject to mortgage liens.

## 8. Jointly Owned Electric Utility Plant (Exelon, Generation, PECO, DPL and ACE)

Exelon's, Generation's, PECO's, DPL's and ACE's material undivided ownership interests in jointly owned electric plants and transmission facilities at December 31, 2019 and 2018 were as follows:

<table><tr><td rowspan="2"></td><td colspan="6">Nuclear Generation</td><td colspan="2">Transmission</td></tr><tr><td colspan="2">Quad Cities</td><td colspan="2">Peach Bottom</td><td>Salem</td><td colspan="2">Nine Mile Point Unit 2</td><td>NJ/DE(a)</td></tr><tr><td>Operator</td><td colspan="2">Generation</td><td colspan="2">Generation</td><td>PSEG Nuclear</td><td colspan="2">Generation</td><td>PSEG/DPL</td></tr><tr><td>Ownership interest</td><td colspan="2">75.00%</td><td colspan="2">50.00%</td><td colspan="2">42.59%</td><td colspan="2">82.00%</td></tr><tr><td>Exelon&#x27;s share at December 31, 2019:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Plant in service</td><td>$ 1,161</td><td>$ 1,466</td><td>$ 663</td><td>$ 951</td><td>$ 102</td><td></td><td></td><td></td></tr><tr><td>Accumulated depreciation</td><td colspan="2">627</td><td colspan="2">249</td><td colspan="2">156</td><td colspan="2">53</td></tr><tr><td>Construction work in progress</td><td colspan="2">13</td><td colspan="2">53</td><td colspan="2">27</td><td colspan="2">—</td></tr><tr><td>Exelon&#x27;s share at December 31, 2018:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Plant in service</td><td>$ 1,131</td><td>$ 1,451</td><td>$ 648</td><td>$ 910</td><td>$ 103</td><td></td><td></td><td></td></tr><tr><td>Accumulated depreciation</td><td colspan="2">587</td><td colspan="2">227</td><td colspan="2">126</td><td colspan="2">53</td></tr><tr><td>Construction work in progress</td><td colspan="2">13</td><td colspan="2">44</td><td colspan="2">56</td><td colspan="2">—</td></tr></table>

(a) PECO, DPL and ACE own a 42.55%, 1% and 13.9% share, respectively in 151.3 miles of 500kV lines located in New Jersey and of the Salem generating plant substation. PECO, DPL and ACE also own a 42.55%, 7.45% and 7.45% share, respectively, in 2.5 miles of 500kV line located over the Delaware River. ACE also has a 21.78% share in a 500kV New Freedom Switching substation.

Exelon's, Generation's, PECO's, DPL's and ACE's undivided ownership interests are financed with their funds and all operations are accounted for as if such participating interests were wholly owned facilities. Exelon's, Generation's, PECO's, DPL's and ACE's share of direct expenses of the jointly owned plants are included in Purchased power and fuel and Operating and maintenance expenses in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income and in Operating and maintenance expenses in PECO's, PHI's, DPL's and ACE's Consolidated Statements of Operations and Comprehensive Income.



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 9 — Asset Retirement Obligations

## 9. Asset Retirement Obligations (All Registrants)

## Nuclear Decommissioning Asset Retirement Obligations (Exelon and Generation)

Generation has a legal obligation to decommission its nuclear power plants following the expiration of their operating licenses. To estimate its decommissioning obligation related to its nuclear generating stations for financial accounting and reporting purposes, Generation uses a probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models and discount rates. Generation updates its ARO annually unless circumstances warrant more frequent updates, based on its review of updated cost studies and its annual evaluation of cost escalation factors and probabilities assigned to various scenarios. Generation began decommissioning the TMI nuclear plant upon permanently ceasing operations in 2019. See below section for decommissioning of Zion Station.

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

The following table provides a rollforward of the nuclear decommissioning ARO reflected in Exelon's and Generation's Consolidated Balance Sheets, from January 1, 2018 to December 31, 2019:

<table><tr><td>Nuclear decommissioning ARO at January 1, 2018</td><td>$</td><td>9,662</td></tr><tr><td>Accretion expense</td><td></td><td>478</td></tr><tr><td>Net decrease due to changes in, and timing of, estimated future cash flows</td><td></td><td>(77)</td></tr><tr><td>Costs incurred related to decommissioning plants</td><td></td><td>(58)</td></tr><tr><td>Nuclear decommissioning ARO at December 31, 2018 (a) (b)</td><td></td><td>10,005</td></tr><tr><td>Net increase due to changes in, and timing of, estimated future cash flows</td><td></td><td>864</td></tr><tr><td>Sale of Oyster Creek</td><td></td><td>(755)</td></tr><tr><td>Accretion Expense</td><td></td><td>479</td></tr><tr><td>Costs incurred related to decommissioning plants</td><td></td><td>(89)</td></tr><tr><td>Nuclear decommissioning ARO at December 31, 2019 (a)</td><td></td><td>$</td></tr></table>

(a) Includes $112 million and $22 million as the current portion of the ARO at December 31, 2019 and 2018, respectively, which is included in Other current liabilities in Exelon's and Generation's Consolidated Balance Sheets.

(b) Includes $772 million of ARO related to Oyster Creek which is classified as Liabilities held for sale in Exelon's and Generation's Consolidated Balance Sheets at December 31, 2018. See Note 2 — Mergers, Acquisitions and Dispositions for additional information.

The net $864 million increase in the ARO during 2019 for changes in the amounts and timing of estimated decommissioning cash flows was driven by multiple adjustments throughout the year, some with offsetting impacts. These adjustments primarily include:

- An increase of approximately $780 million for changes in the assumed retirement timing probabilities for sites including certain economically challenged nuclear plants and the extension of Peach Bottom's operating life; and

- An increase of approximately $490 million for other impacts that included updated cost escalation rates, primarily for labor, equipment and materials, and current discount rates; partially offset by

- Lower estimated costs to decommission TMI, Nine Mile Point, Ginnia, Braidwood, Byron and LaSalle nuclear units of approximately $410 million resulting from the completion of updated cost studies.



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 9 — Asset Retirement Obligations

The 2019 ARO updates resulted in a decrease of $150 million in Operating and maintenance expense for the year ended December 31, 2019 within Exelon and Generation's Consolidated Statements of Operations and Comprehensive Income. See Note 6—Early Plant Retirements for additional information regarding TMI and economically challenged nuclear plants and Note 3 - Regulatory Matters regarding the Peach Bottom second license renewal.

The net $77 million decrease in the ARO during 2018 for changes in the amounts and timing of estimated decommissioning cash flows was driven by multiple adjustments throughout the year, some with offsetting impacts. These adjustments primarily include:

- A decrease of approximately $205 million primarily due to lower estimated costs for the construction of interim spent fuel storage at TMI and a net decrease in estimated costs to decommission Calvert Cliffs, FitzPatrick, Limerick, and Salem nuclear units resulting from the completion of updated cost studies. There was also a decrease due to changes in decommissioning scenarios and their probabilities. These decreases were partially offset by

- An increase of approximately $115 million for the impact of the early retirement and the announced pending sale of Oyster Creek which closed on July 1, 2019; and

• An increase of approximately $120 million for estimated cost escalation rates, primarily for labor, energy and waste burial costs.

See Note 2 — Mergers, Acquisitions and Dispositions and Note 6—Early Plant Retirements for additional information regarding Oyster Creek.

## NDT Funds

NDT funds have been established for each generation station unit to satisfy Generation's nuclear decommissioning obligations. Generally, NDT funds established for a particular unit may not be used to fund the decommissioning obligations of any other unit.

The NDT funds associated with Generation's nuclear units have been funded with amounts collected from the previous owners and their respective utility customers. PECO is authorized to collect funds, in revenues, for decommissioning the former PECO nuclear plants through regulated rates, and these collections are scheduled through the operating lives of the former PECO plants. The amounts collected from PECO customers are remitted to Generation and deposited into the NDT funds for the unit for which funds are collected. Every five years, PECO files a rate adjustment with the PAPUC that reflects PECO's calculations of the estimated amount needed to decommission each of the former PECO units based on updated fund balances and estimated decommissioning costs. The rate adjustment is used to determine the amount collectible from PECO customers. On March 31, 2017, PECO filed its Nuclear Decommissioning Cost Adjustment with the PAPUC proposing an annual recovery from customers of approximately $4 million. This amount reflects a decrease from the previously approved annual collection of approximately $24 million primarily due to the removal of the collections for Limerick Units 1 and 2 as a result of the NRC approving the extension of the operating licenses for an additional 20 years. On August 8, 2017, the PAPUC approved the filing and the new rates became effective January 1, 2018.

Any shortfall of funds necessary for decommissioning, determined for each generating station unit, is ultimately required to be funded by Generation, with the exception of a shortfall for the current decommissioning activities at Zion Station, where certain decommissioning activities have been transferred to a third-party (see Zion Station Decommissioning below) and the CENG units, where any shortfall is required to be funded by both Generation and EDF. Generation, through PECO, has recourse to collect additional amounts from PECO customers related to a shortfall of NDT funds for the former PECO units, subject to certain limitations and thresholds, as prescribed by an order from the PAPUC. Generally, PECO, and likewise Generation will not be allowed to collect amounts associated with the first $50 million of any shortfall of trust funds compared to decommissioning costs, as well as 5% of any additional shortfalls, on an aggregate basis for all former PECO units. The initial $50 million and up to 5% of any additional shortfalls would be borne by Generation. No recourse exists to collect additional amounts from utility customers for any of Generation's other nuclear units. With respect to the former ComEd and PECO units, any funds remaining in the NDTs after all decommissioning has been completed are required to be refunded to ComEd's or PECO's customers, subject to certain limitations that allow sharing of excess funds with Generation related to the former PECO units. With respect to Generation's other nuclear units, Generation retains any funds remaining after decommissioning. However, in connection with CENG's acquisition of the Nine Mile Point and Ginna plants



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 9 — Asset Retirement Obligations

and settlements with certain regulatory agencies, CENG is subject to certain conditions pertaining to NDT funds that, if met, could possibly result in obligations to make payments to certain third parties (clawbacks). For Nine Mile Point and Ginna, the clawback provisions are triggered only in the event that the required decommissioning activities are discontinued or not started or completed in a timely manner. In the event that the clawback provisions are triggered for Nine Mile Point, then, depending upon the triggering event, an amount equal to 50% of the total amount withdrawn from the funds for non-decommissioning activities or 50% of any excess funds in the trust funds above the amounts required for decommissioning (including spent fuel management and decommissioning) is to be paid to the Nine Mile Point sellers. In the event that the clawback provisions are triggered for Ginna, then an amount equal to any estimated cost savings realized by not completing any of the required decommissioning activities is to be paid to the Ginna sellers. Generation expects to comply with applicable regulations and timely commence and complete all required decommissioning activities.

At December 31, 2019 and 2018, Exelon and Generation had NDT funds totaling $13,353 million and $12,695 million, respectively. The NDT funds included $890 million at December 31, 2018, related to Oyster Creek NDT funds which were classified as Assets held for sale in Exelon's and Generation's Consolidated Balance Sheets. See Note 2 — Mergers, Acquisitions and Dispositions for additional information. The NDT funds include $163 million and $144 million for the current portion of the NDT at December 31, 2019 and 2018, respectively, which are included in Other current assets in Exelon's and Generation's Consolidated Balance Sheets. See Note 23 — Supplemental Financial Information for additional information on activities of the NDT funds.

## Accounting Implications of the Regulatory Agreements with ComEd and PECO

Based on the regulatory agreements with the ICC and PAPUC that dictate Generation's obligations related to the shortfall or excess of NDT funds necessary for decommissioning the former ComEd units on a unit-by-unit basis and the former PECO units in total, decommissioning-related activities net of applicable taxes, including realized and unrealized gains and losses on the NDT funds and accretion of the decommissioning obligation, are generally offset within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. For the former ComEd units, decommissioning-related activities are generally offset within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income as long as the NDT funds are expected to exceed the total estimated decommissioning obligation. For the former PECO units, decommissioning-related activities are generally offset within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income regardless of whether the NDT funds are expected to exceed or fall short of the total estimated decommissioning obligation. The offset of decommissioning-related activities within the Consolidated Statement of Operations and Comprehensive Income results in an equal adjustment to the noncurrent payables to affiliates at Generation. ComEd and PECO have recorded an equal noncurrent affiliate receivable from Generation and corresponding regulatory liability.

Should the expected value of the NDT fund for any former ComEd unit fall below the amount of the expected decommissioning obligation for that unit, the accounting to offset decommissioning-related activities in the Consolidated Statement of Operations and Comprehensive Income for that unit would be discontinued, the decommissioning-related activities would be recognized in the Consolidated Statements of Operations and Comprehensive Income and the adverse impact to Exelon's and Generation's financial statements could be material. As of December 31, 2019, the NDT funds of each of the former ComEd units, except for Zion (see Zion Station Decommissioning below), are expected to exceed the related decommissioning obligation for each of the units. For the purposes of making this determination, the decommissioning obligation referred to is different, as described below, from the calculation used in the NRC minimum funding obligation filings based on NRC guidelines.

Any changes to the PECO regulatory agreements could impact Exelon's and Generation's ability to offset decommissioning-related activities within the Consolidated Statement of Operations and Comprehensive Income, and the impact to Exelon's and Generation's financial statements could be material.

The decommissioning-related activities related to the Non-Regulatory Agreement Units are reflected in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.

See Note 3 — Regulatory Matters and Note 24 — Related Party Transactions for additional information regarding regulatory liabilities at ComEd and PECO and intercompany balances between Generation, ComEd and PECO reflecting the obligation to refund to customers any decommissioning-related assets in excess of the related decommissioning obligations.



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 9 — Asset Retirement Obligations

## Zion Station Decommissioning

In 2010, Generation completed an Asset Sale Agreement (ASA) under which ZionSolutions assumed responsibility for decommissioning Zion Station and Generation transferred to ZionSolutions substantially all the Zion Station's assets, including the related NDT funds. To reduce the risk of default by ZionSolutions, EnergySolutions has provided a $25 million letter of credit to be used to fund decommissioning costs in the event the NDT assets are insufficient. EnergySolutions and its parent company have also provided a performance guarantee.

Following ZionSolutions' completion of its contractual obligations and transfer of the NRC license to Generation, Generation will store the SNF at Zion Station until it is transferred to the DOE for ultimate disposal, and will complete all remaining decommissioning activities associated with the SNF dry storage facility.

Generation had retained its obligation for the SNF as well as certain NDT assets to fund its obligation to maintain the SNF at Zion Station until transfer to the DOE and to complete all remaining decommissioning activities for the SNF storage facility. Any shortage of funds necessary to maintain the SNF and decommission the SNF storage facility is ultimately required to be funded by Generation. Any Zion Station NDT funds remaining after the completion of all decommissioning activities will be returned to ComEd customers in accordance with the applicable orders.

## NRC Minimum Funding Requirements

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

Key assumptions used in the minimum funding calculation using the NRC methodology at December 31, 2019 include: (1) consideration of costs only for the removal of radiological contamination at each unit; (2) the option on a unit-by-unit basis to use generic, non-site specific cost estimates; (3) consideration of only one decommissioning scenario for each unit; (4) the plants cease operation at the end of their current license lives (with no assumed license renewals for those units that have not already received renewals); (5) the assumption of current nominal dollar cost estimates that are neither escalated through the anticipated period of decommissioning, nor discounted using the CARFR; and (6) assumed annual after-tax returns on the NDT funds of 2% (3% for the former PECO units, as specified by the PAPUC).

In contrast, the key criteria and assumptions used by Generation to determine the ARO and to forecast the target growth in the NDT funds at December 31, 2019 include: (1) the use of site specific cost estimates that are updated at least once every five years; (2) the inclusion in the ARO estimate of all legally unavoidable costs required to decommission the unit (e.g., radiological decommissioning and full site restoration for certain units, on-site spent fuel maintenance and storage subsequent to ceasing operations and until DOE acceptance, and disposal of certain low-level radioactive waste); (3) the consideration of multiple scenarios where decommissioning and site restoration activities, as applicable, are completed under possible scenarios ranging from 10 to 70 years after the cessation of plant operations; (4) the consideration of multiple end of life scenarios; (5) the measurement of the obligation at the present value of the future estimated costs and an annual average accretion of the ARO of approximately 5% through a period of approximately 30 years after the end of the extended lives of the units; and (6) an estimated targeted annual pre-tax return on the NDT funds of 5.4% to 6.5% (as compared to a historical 5-year annual average pre-tax return of approximately 6.7%).

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



Generation filed its biennial decommissioning funding status report with the NRC on April 1, 2019 for all units except for Zion Station which is included in a separate report to the NRC submitted by ZionSolutions, LLC. The status report demonstrated adequate decommissioning funding assurance as of December 31, 2018 for all units except for Clinton and Peach Bottom Unit 1. As of February 28, 2019, Clinton demonstrated adequate minimum funding assurance due to market recovery and no further action is required. This demonstration was also included in the April 1, 2019 submittal. As a former PECO plant, financial assurance for decommissioning Peach Bottom Unit 1 is provided by the NDT fund, collections from PECO ratepayers and the ability to adjust those collections in accordance with the approved PAPUC tariff. No additional actions are required aside from the PAPUC filing in accordance with the tariff. See NDT Funds section above for additional information.

Generation will file its next annual decommissioning funding status report with the NRC by March 31, 2020 for shutdown reactors, reactors within five years of shutdown except for Zion Station which is included in a separate report to the NRC submitted by EnergySolutions (see Zion Station Decommissioning above). This report will reflect the status of decommissioning funding assurance as of December 31, 2019 and will include an update for the retirement of TMI in 2019. A shortfall at any unit could necessitate that Exelon post a parental guarantee for Generation's share of the funding assurance. However, the amount of any required guarantee will ultimately depend on the decommissioning approach adopted, the associated level of costs, and the decommissioning trust fund investment performance going forward.

As the future values of trust funds change due to market conditions, the NRC minimum funding status of Generation’s units will change. In addition, if changes occur to the regulatory agreement with the PAPUC that currently allows amounts to be collected from PECO customers for decommissioning the former PECO units, the NRC minimum funding status of those plants could change at subsequent NRC filing dates.

## Non-Nuclear Asset Retirement Obligations (All Registrants)

Generation has AROs for plant closure costs associated with its fossil and renewable generating facilities, including asbestos abatement, removal of certain storage tanks, restoring leased land to the condition it was in prior to construction of renewable generating stations and other decommissioning-related activities. The Utility Registrants have AROs primarily associated with the abatement and disposal of equipment and buildings contaminated with asbestos and PCBs. See Note 1 — Significant Accounting Policies for additional information on the Registrants' accounting policy for AROs.

The following table provides a rollforward of the non-nuclear AROs reflected in the Registrants' Consolidated Balance Sheets from January 1, 2018 to December 31, 2019:

<table><tr><td></td><td>Exelon</td><td>Generation</td><td>ComEd</td><td>PECO</td><td>BGE</td><td>PHI</td><td>Pepco</td><td>DPL</td><td>ACE</td></tr><tr><td>Non-nuclear AROs at January 1, 2018</td><td>$ 384</td><td>$ 197</td><td>$ 113</td><td>$ 27</td><td>$ 24</td><td>$ 16</td><td>$ 3</td><td>$ 10</td><td>$ 3</td></tr><tr><td>Net increase due to changes in, and timing of, estimated future cash flows(a)</td><td>80</td><td>35</td><td>7</td><td>—</td><td>2</td><td>36</td><td>34</td><td>1</td><td>1</td></tr><tr><td>Accretion expense(b)</td><td>16</td><td>10</td><td>4</td><td>1</td><td>1</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Asset divestitures</td><td>(3)</td><td>(3)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Payments</td><td>(6)</td><td>(1)</td><td>(3)</td><td>—</td><td>(2)</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Non-nuclear AROs at December 31, 2018</td><td>471</td><td>238</td><td>121</td><td>28</td><td>25</td><td>52</td><td>37</td><td>11</td><td>4</td></tr><tr><td>Net (decrease) increase due to changes in, and timing of, estimated future cash flows</td><td>17</td><td>7</td><td>8</td><td>—</td><td>(2)</td><td>4</td><td>3</td><td>1</td><td>—</td></tr><tr><td>Development projects</td><td>2</td><td>2</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Accretion expense(b)</td><td>16</td><td>12</td><td>1</td><td>1</td><td>1</td><td>1</td><td>1</td><td>—</td><td>—</td></tr><tr><td>Asset divestitures</td><td>(42)</td><td>(42)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Payments</td><td>(4)</td><td>(1)</td><td>(1)</td><td>(1)</td><td>(1)</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Non-nuclear AROs at December 31, 2019</td><td>$ 460</td><td>$ 216</td><td>$ 129</td><td>$ 28</td><td>$ 23</td><td>$ 57</td><td>$ 41</td><td>$ 12</td><td>$ 4</td></tr></table>



(a) In 2018, Pepco recorded an increase of $22 million in Operating and maintenance expense primarily related to asbestos identified at its Buzzard Point property as part of an annual ARO study. Buzzard Point is a waterfront property in the District of Columbia occupied by an active substation and former Pepco operated steam plant building, which Pepco retired and closed in 1981.

(b) For ComEd and PECO, the majority of the accretion is recorded as an increase to a regulatory asset due to the associated regulatory treatment.

## 10. Leases (All Registrants)

## Lessee

The Registrants have operating leases for which they are the lessees. The following tables outline the significant types of operating lease at each registrant and other terms and conditions of the lease agreements. The Registrants do not have material finance leases.

<table><tr><td></td><td>Exelon</td><td>Generation</td><td>ComEd</td><td>PECO</td><td>BGE</td><td>PHI</td><td>Pepco</td><td>DPL</td><td>ACE</td></tr><tr><td>Contracted generation</td><td>●</td><td>●</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Real estate</td><td>●</td><td>●</td><td>●</td><td>●</td><td>●</td><td>●</td><td>●</td><td>•</td><td>●</td></tr><tr><td>Vehicles and equipment</td><td>●</td><td>●</td><td>●</td><td>●</td><td>●</td><td>●</td><td>●</td><td>•</td><td>●</td></tr><tr><td>(in years)</td><td>Exelon</td><td>Generation</td><td>ComEd</td><td>PECO</td><td>BGE</td><td>PHI</td><td>Pepco</td><td>DPL</td><td>ACE</td></tr><tr><td>Remaining lease terms</td><td>1-86</td><td>1-36</td><td>1-5</td><td>1-14</td><td>1-86</td><td>1-12</td><td>1-12</td><td>1-12</td><td>1-6</td></tr><tr><td>Options to extend the term</td><td>3-30</td><td>3-30</td><td>5</td><td>N/A</td><td>N/A</td><td>3-30</td><td>5</td><td>3-30</td><td>N/A</td></tr><tr><td>Options to terminate within</td><td>1-13</td><td>1</td><td>3</td><td>N/A</td><td>2</td><td>N/A</td><td>N/A</td><td>N/A</td><td>N/A</td></tr></table>

The components of lease costs for the year ended December 31, 2019 were as follows:

<table><tr><td></td><td>Exelon</td><td>Generation</td><td>ComEd</td><td>PECO</td><td>BGE</td><td>PHI</td><td>Pepco</td><td>DPL</td><td>ACE</td></tr><tr><td>Operating lease costs</td><td>$ 320</td><td>$ 222</td><td>$ 3</td><td>$ 1</td><td>$ 33</td><td>$ 48</td><td>$ 12</td><td>$ 14</td><td>$ 7</td></tr><tr><td>Variable lease costs</td><td>300</td><td>282</td><td>2</td><td>—</td><td>2</td><td>6</td><td>2</td><td>2</td><td>1</td></tr><tr><td>Short-term lease costs</td><td>19</td><td>19</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Total lease costs (a)</td><td>$ 639</td><td>$ 523</td><td>$ 5</td><td>$ 1</td><td>$ 35</td><td>$ 54</td><td>$ 14</td><td>$ 16</td><td>$ 8</td></tr></table>

(a) Excludes $51 million, $44 million, $7 million and $7 million of sublease income recorded at Exelon, Generation, PHI and DPL.

The following table presents the Registrants' rental expense under the prior lease accounting guidance for the years ended December 31, 2018 and 2017:

<table><tr><td></td><td>Exelon</td><td>Generation(a)</td><td>ComEd</td><td>PECO</td><td>BGE</td><td>PHI</td><td>Pepco</td><td>DPL</td><td>ACE</td></tr><tr><td>2018</td><td>$ 670</td><td>$ 558</td><td>$ 7</td><td>$ 10</td><td>$ 35</td><td>$ 48</td><td>$ 10</td><td>$ 13</td><td>$ 8</td></tr><tr><td>2017</td><td>709</td><td>578</td><td>9</td><td>9</td><td>32</td><td>63</td><td>11</td><td>16</td><td>14</td></tr></table>

(a) Includes contingent operating lease payments associated with contracted generation agreements that are not included in the minimum future operating lease payments above. Payments made under Generation's contracted generation lease agreements totaled $493 million and $508 million during 2018 and 2017, respectively.



## Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 10 — Leases

The following table provides additional information regarding the presentation of operating ROU assets and lease liabilities within the Registrants' Consolidated Balance Sheets as of December 31, 2019:

<table><tr><td></td><td>Exelon(a)</td><td>Generation(a)</td><td>ComEd</td><td>PECO</td><td>BGE</td><td>PHI</td><td>Pepco</td><td>DPL</td><td>ACE</td></tr><tr><td>Operating lease ROU assets</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Other deferred debits and other assets</td><td>$ 1,305</td><td>$ 895</td><td>$ 9</td><td>$ 2</td><td>$ 77</td><td>$ 273</td><td>$ 56</td><td>$ 63</td><td>$ 18</td></tr><tr><td>Operating lease liabilities</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Other current liabilities</td><td>225</td><td></td><td>157</td><td>3</td><td>—</td><td>32</td><td>31</td><td>6</td><td>9</td></tr><tr><td>Other deferred credits and other liabilities</td><td>1,307</td><td></td><td>925</td><td>8</td><td>1</td><td>50</td><td>254</td><td>51</td><td>65</td></tr><tr><td>Total operating lease liabilities</td><td>$ 1,532</td><td>$ 1,082</td><td>$ 11</td><td>$ 1</td><td>$ 82</td><td>$ 285</td><td>$ 57</td><td>$ 74</td><td>$ 18</td></tr></table>

(a) Exelon's and Generation's operating ROU assets and lease liabilities include $515 million and $664 million, respectively, related to contracted generation.

The weighted average remaining lease terms, in years, and discount rates for operating leases as of December 31, 2019 were as follows:

<table><tr><td></td><td>Exelon</td><td>Generation</td><td>ComEd</td><td>PECO</td><td>BGE</td><td>PHI</td><td>Pepco</td><td>DPL</td><td>ACE</td></tr><tr><td>Remaining lease term</td><td>10.1</td><td>10.6</td><td>4.6</td><td>4.4</td><td>5.4</td><td>9.0</td><td>9.8</td><td>9.7</td><td>4.7</td></tr><tr><td>Discount rate</td><td>4.6%</td><td>4.8%</td><td>3.0%</td><td>3.2%</td><td>3.6%</td><td>4.2%</td><td>4.0%</td><td>4.0%</td><td>3.6%</td></tr></table>

Future minimum lease payments for operating leases as of December 31, 2019 were as follows:

<table><tr><td>Year</td><td>Exelon</td><td>Generation</td><td>ComEd</td><td>PECO</td><td>BGE</td><td>PHI</td><td>Pepco</td><td>DPL</td><td>ACE</td></tr><tr><td>2020</td><td>$ 287</td><td>$ 203</td><td>$ 3</td><td>$ —</td><td>$ 34</td><td>$ 42</td><td>$ 8</td><td>$ 11</td><td>$ 5</td></tr><tr><td>2021</td><td>243</td><td>162</td><td>4</td><td>1</td><td>31</td><td>41</td><td>8</td><td>11</td><td>4</td></tr><tr><td>2022</td><td>177</td><td>113</td><td>2</td><td>—</td><td>16</td><td>38</td><td>8</td><td>10</td><td>4</td></tr><tr><td>2023</td><td>145</td><td>100</td><td>1</td><td>—</td><td>1</td><td>37</td><td>7</td><td>9</td><td>3</td></tr><tr><td>2024</td><td>140</td><td>97</td><td>1</td><td>—</td><td>—</td><td>35</td><td>5</td><td>9</td><td>2</td></tr><tr><td>Remaining years</td><td>976</td><td>741</td><td>1</td><td>—</td><td>18</td><td>153</td><td>34</td><td>41</td><td>2</td></tr><tr><td>Total</td><td>1,968</td><td>1,416</td><td>12</td><td>1</td><td>100</td><td>346</td><td>70</td><td>91</td><td>20</td></tr><tr><td>Interest</td><td>436</td><td>334</td><td>1</td><td>—</td><td>18</td><td>61</td><td>13</td><td>17</td><td>2</td></tr><tr><td>Total operating lease liabilities</td><td>$ 1,532</td><td>$ 1,082</td><td>$ 11</td><td>$ 1</td><td>$ 82</td><td>$ 285</td><td>$ 57</td><td>$ 74</td><td>$ 18</td></tr></table>



# Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 10 — Leases

Future minimum lease payments for operating leases under the prior lease accounting guidance as of December 31, 2018 were as follows:

<table><tr><td></td><td>Exelon(a)(b)</td><td>Generation(a)(b)</td><td>ComEd(a)(c)</td><td>PECO(d)(c)</td><td>BGE(a)(c)(d)(e)</td><td>PHI(a)</td><td>Pepco(a)</td><td>DPL(a)(c)</td><td>ACE(a)</td></tr><tr><td>2019</td><td>$ 140</td><td>$ 33</td><td>$ 7</td><td>$ 5</td><td>$ 35</td><td>$ 48</td><td>$ 11</td><td>$ 14</td><td>$ 7</td></tr><tr><td>2020</td><td>149</td><td>46</td><td>5</td><td>5</td><td>35</td><td>46</td><td>10</td><td>13</td><td>6</td></tr><tr><td>2021</td><td>143</td><td>46</td><td>4</td><td>5</td><td>33</td><td>43</td><td>9</td><td>12</td><td>5</td></tr><tr><td>2022</td><td>126</td><td>47</td><td>4</td><td>5</td><td>18</td><td>42</td><td>8</td><td>12</td><td>5</td></tr><tr><td>2023</td><td>97</td><td>46</td><td>3</td><td>5</td><td>3</td><td>39</td><td>8</td><td>10</td><td>4</td></tr><tr><td>Remaining years</td><td>723</td><td>545</td><td>—</td><td>—</td><td>19</td><td>159</td><td>40</td><td>35</td><td>5</td></tr><tr><td>Total minimum future lease payments</td><td>$ 1,378</td><td>$ 763</td><td>$ 23</td><td>$ 25</td><td>$ 143</td><td>$ 377</td><td>$ 86</td><td>$ 96</td><td>$ 32</td></tr></table>

(a) Includes amounts related to shared use land arrangements.

(b) Excludes Generation’s contingent operating lease payments associated with contracted generation.

(c) Amounts related to certain real estate leases and railroad licenses effectively have indefinite payment periods. As a result, ComEd, PECO, BGE and DPL have excluded these payments from the remaining years as such amounts would not be meaningful. ComEd's, PECO's, BGE's and DPL's average annual obligation for these arrangements, included in each of the years 2019 - 2023, was $3 million, $5 million, $1 million and $1 million respectively. Also includes amounts related to shared use land arrangements.

(d) Includes all future lease payments on a 99-year real estate lease that expires in 2106.

(e) The BGE column above includes minimum future lease payments associated with a 6-year lease for the Baltimore City conduit system that became effective during the fourth quarter of 2016. BGE's total commitments under the lease agreement are $26 million, $28 million, $28 million and $14 million related to years 2019 - 2022, respectively.

Cash paid for amounts included in the measurement of lease liabilities for the year ended December 31, 2019 were as follows:

<table><tr><td></td><td>Exelon</td><td>Generation</td><td>ComEd</td><td>PECO</td><td>BGE</td><td>PHI</td><td>Pepco</td><td>DPL</td><td>ACE</td></tr><tr><td>Operating cash flows from operating leases</td><td>$ 287</td><td>$ 206</td><td>$ 3</td><td>$ —</td><td>$ 33</td><td>$ 37</td><td>$ 9</td><td>$ 6</td><td>$ 5</td></tr></table>

ROU assets obtained in exchange for lease obligations for the year ended December 31, 2019 were as follows:

<table><tr><td></td><td>Exelon</td><td>Generation</td><td>ComEd</td><td>PECO</td><td>BGE</td><td>PHI</td><td>Pepco</td><td>DPL</td><td>ACE</td></tr><tr><td>Operating leases</td><td>$ 52</td><td>$ 14</td><td>$ 6</td><td>$ —</td><td>$ 2</td><td>$ (3)</td><td>$ (1)</td><td>$ (2)</td><td>$ (1)</td></tr></table>

## Lessor

The Registrants have operating leases for which they are the lessors. The following tables outline the significant types of leases at each registrant and other terms and conditions of their lease agreements.

<table><tr><td></td><td>Exelon</td><td>Generation</td><td>ComEd</td><td>PECO</td><td>BGE</td><td>PHI</td><td>Pepco</td><td>DPL</td><td>ACE</td></tr><tr><td>Contracted generation</td><td>●</td><td>●</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Real estate</td><td>●</td><td>●</td><td>●</td><td>●</td><td>●</td><td>●</td><td>●</td><td></td><td>●</td></tr><tr><td>(in years)</td><td>Exelon</td><td>Generation</td><td>ComEd</td><td>PECO</td><td>BGE</td><td>PHI</td><td>Pepco</td><td>DPL</td><td>ACE</td></tr><tr><td>Remaining lease terms</td><td>1-83</td><td>1-32</td><td>1-17</td><td>1-83</td><td>23</td><td>1-13</td><td>1-6</td><td>12-13</td><td>1-2</td></tr><tr><td>Options to extend the term</td><td>1-79</td><td>1-5</td><td>5-79</td><td>5-50</td><td>N/A</td><td>5</td><td>N/A</td><td>N/A</td><td>N/A</td></tr></table>



The components of lease income for the year ended December 31, 2019 were as follows:

<table><tr><td></td><td>Exelon</td><td>Generation</td><td>ComEd</td><td>PECO</td><td>BGE</td><td>PHI</td><td>Pepco</td><td>DPL</td><td>ACE</td></tr><tr><td>Operating lease income</td><td>$ 54</td><td>$ 47</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ 5</td><td>$ —</td><td>$ 4</td><td>$ —</td></tr><tr><td>Variable lease income</td><td>$ 261</td><td>$ 258</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ 3</td><td>$ —</td><td>$ 3</td><td>$ —</td></tr></table>

Future minimum lease payments to be recovered under operating leases as of December 31, 2019 were as follows:

<table><tr><td>Year</td><td>Exelon</td><td>Generation</td><td>ComEd</td><td>PECO</td><td>BGE</td><td>PHI</td><td>Pepco</td><td>DPL</td><td>ACE</td></tr><tr><td>2020</td><td>$ 51</td><td>$ 46</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ 4</td><td>$ —</td><td>$ 3</td><td>$ —</td></tr><tr><td>2021</td><td>51</td><td>45</td><td>—</td><td>—</td><td>—</td><td>4</td><td>1</td><td>3</td><td>—</td></tr><tr><td>2022</td><td>50</td><td>45</td><td>—</td><td>—</td><td>—</td><td>4</td><td>—</td><td>3</td><td>—</td></tr><tr><td>2023</td><td>49</td><td>44</td><td>—</td><td>—</td><td>—</td><td>5</td><td>—</td><td>4</td><td>—</td></tr><tr><td>2024</td><td>48</td><td>44</td><td>—</td><td>—</td><td>—</td><td>4</td><td>—</td><td>4</td><td>—</td></tr><tr><td>Remaining years</td><td>265</td><td>226</td><td>1</td><td>3</td><td>1</td><td>34</td><td>—</td><td>34</td><td>—</td></tr><tr><td>Total</td><td>$ 514</td><td>$ 450</td><td>$ 1</td><td>$ 3</td><td>$ 1</td><td>$ 55</td><td>$ 1</td><td>$ 51</td><td>$ —</td></tr></table>

## 11. Asset Impairments (Exelon, Generation and PHI)

The Registrants evaluate the carrying value of long-lived assets or asset groups for recoverability whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators of impairment may include a deteriorating business climate, including, but not limited to, declines in energy prices, condition of the asset, specific regulatory disallowance, or plans to dispose of a long-lived asset significantly before the end of its useful life. The Registrants determine if long-lived assets or asset groups are impaired by comparing the undiscounted expected future cash flows to the carrying value. When the undiscounted cash flow analysis indicates a long-lived asset or asset group is not recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. The fair value analysis is primarily based on the income approach using significant unobservable inputs (Level 3) including revenue and generation forecasts, projected capital and maintenance expenditures and discount rates. A variation in the assumptions used could lead to a different conclusion regarding the recoverability of an asset or asset group and, thus, could potentially result in material future impairments of the Registrant's long-lived assets.

## Equity Method Investments in Certain Distributed Energy Companies (Exelon and Generation)

In the third quarter of 2019, Generation’s equity method investments in certain distributed energy companies were fully impaired due to an other-than-temporary decline in market conditions and underperforming projects. Exelon and Generation recorded a pre-tax impairment charge of $164 million in Equity in losses of unconsolidated affiliates and an offsetting pre-tax $96 million in Net income attributable to noncontrolling interests in their Consolidated Statements of Operations and Comprehensive Income. As a result, Generation accelerated the amortization of investment tax credits associated with these companies and Exelon and Generation recorded a benefit of $46 million in Income taxes. The impairment charge and the accelerated amortization of investment tax credits resulted in a net $15 million decrease to Exelon’s and Generation’s earnings. See Note 22 — Variable Interest Entities for additional information.

## Antelope Valley Solar Facility (Exelon and Generation)

Generation’s Antelope Valley, a 242 MW solar facility in Lancaster, CA, sells all of its output to PG&E through a PPA. As of December 31, 2019, Generation had approximately $725 million of net long-lived assets related to Antelope Valley. As a result of the PG&E bankruptcy filing in the first quarter of 2019, Generation completed a comprehensive review of Antelope Valley’s estimated undiscounted future cash flows and no impairment charge was recorded. Significant changes in assumptions such as the likelihood of the PPA being rejected as part of the bankruptcy proceedings could potentially result in future impairments of Antelope Valley’s net long-lived assets, which could be material.

Antelope Valley is a wholly owned indirect subsidiary of EGR IV, which had approximately $1,893 million of additional net long-lived assets as of December 31, 2019. EGR IV is a wholly owned indirect subsidiary of Exelon and Generation and includes Generation's interest in EGRP and other projects with non-controlling interests. To date, there have been no indicators to suggest that the carrying amount of other net long-lived assets of EGR IV may not be recoverable.

Generation will continue to monitor the bankruptcy proceedings for any changes in circumstances that may indicate the carrying amount of the net long-lived assets of Antelope Valley or other long-lived assets of EGR IV may not be recoverable.

See Note 16 — Debt and Credit Agreements for additional information on the PG&E bankruptcy.



During the first quarter of 2018, Mystic Unit 9 did not clear in the ISO-NE capacity auction for the 2021 - 2022 planning year. On March 29, 2018, Generation notified ISO-NE of the early retirement of its Mystic Generating Station's Units 7, 8, 9 and the Mystic Jet Unit (Mystic Generating Station assets) absent regulatory reforms. These events suggested that the carrying value of its New England asset group may be impaired. Generation completed a comprehensive review of the estimated undiscounted future cash flows of the New England asset group and no impairment charge was required. Further developments such as the failure of ISO-NE to adopt long-term solutions for reliability and fuel security could potentially result in material future impairments of the New England asset group. See Note 6 — Early Plant Retirements for additional information.

## District of Columbia Sponsorship (Exelon and PHI)

In the third quarter of 2015, PHI entered into a sponsorship agreement with the District of Columbia for future sponsorship rights associated with public property within the District of Columbia, which Exelon and PHI had recorded as a finite-lived intangible asset as of December 31, 2016. The specific sponsorship rights were to be determined through future negotiations. In the fourth quarter of 2017, based upon the lack of available sponsorship opportunities at that time, the asset was written off and a pre-tax impairment charge of $25 million was recorded within Operating and maintenance expense in Exelon's and PHI's Consolidated Statements of Operations and Comprehensive Income.

## ExGen Texas Power (Exelon and Generation)

On May 2, 2017, EGTP entered into a consent agreement with its lenders to initiate the sale of the assets of its wholly owned subsidiaries. As a result, Exelon and Generation classified certain of EGTP's assets and liabilities as held for sale at their respective fair values less costs to sell and recorded a pre-tax impairment charge in 2017 of $460 million within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income. On November 7, 2017, EGTP and its wholly owned subsidiaries filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Code in the United States Bankruptcy Court for the District of Delaware and, as a result, Exelon and Generation deconsolidated EGTP's assets and liabilities from their consolidated financial statements. See Note 2 — Mergers, Acquisitions and Dispositions for additional information.

## 12. Intangible Assets (Exelon, Generation, ComEd, PHI, Pepco, DPL and ACE)

## Goodwill

The following table presents the gross amount of goodwill, accumulated impairment loss and carrying amount of goodwill of Exelon, ComEd and PHI as of December 31, 2019 and 2018. There were no additions, impairments or measurement period adjustments during the years ended December 31, 2019 and 2018.

<table><tr><td></td><td>Gross amount</td><td>Accumulated impairment loss</td><td>Carrying amount</td></tr><tr><td>Exelon</td><td>$     8,660</td><td>$     1,983</td><td>$     6,677</td></tr><tr><td>ComEd \( ^{(a)} \)</td><td>4,608</td><td>1,983</td><td>2,625</td></tr><tr><td>PHI \( ^{(b)} \)</td><td>4,005</td><td>—</td><td>4,005</td></tr></table>

(a) Reflects goodwill recorded in 2000 from the PECO/Unicom merger (predecessor parent company of ComEd).

(b) Reflects goodwill recorded in 2016 from the PHI merger.

Goodwill is not amortized, but is subject to an assessment for impairment at least annually, or more frequently if events occur or circumstances change that would more likely than not reduce the fair value of ComEd's and PHI's reporting units below their carrying amounts. A reporting unit is an operating segment or one level below an operating segment (known as a component) and is the level at which goodwill is tested for impairment. A component of an operating segment is a reporting unit if the component constitutes a business for which discrete financial information is available and its operating results are regularly reviewed by segment management. ComEd has a single operating segment. PHI's operating segments are Pepco, DPL and ACE. See Note 5 — Segment Information for additional information. There is no level below these operating segments for which operating results are regularly reviewed by segment management. Therefore, the ComEd, Pepco, DPL and ACE operating segments are also considered reporting units for goodwill impairment testing purposes. Exelon's and ComEd's $2.6 billion of goodwill has been assigned entirely to the ComEd reporting unit, while Exelon's and PHI's $4.0 billion of goodwill has been assigned to the Pepco, DPL and ACE reporting units in the amounts of $2.1 billion, $1.4 billion and $0.5 billion, respectively.

Entities assessing goodwill for impairment have the option of first performing a qualitative assessment to determine whether a quantitative assessment is necessary. As part of the qualitative assessments, Exelon, ComEd and PHI evaluate, among other things, management's best estimate of projected operating and capital cash flows for their businesses, outcomes of recent regulatory proceedings, changes in certain market conditions, including the discount rate and regulated utility peer EBITDA multiples, and the passing margin from their last quantitative assessments



performed. If an entity bypasses the qualitative assessment, a quantitative two-step, fair value-based test is performed. The first step compares the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, the second step is performed. The second step requires an allocation of fair value to the individual assets and liabilities using purchase price allocation authoritative guidance in order to determine the implied fair value of goodwill.

Application of the goodwill impairment test requires management judgment, including the identification of reporting units and determining the fair value of the reporting unit, which management estimates using a weighted combination of a discounted cash flow analysis and a market multiples analysis. Significant assumptions used in these fair value analyses include discount and growth rates, utility sector market performance and transactions, projected operating and capital cash flows for ComEd's, Pepco's, DPL's and ACE's businesses and the fair value of debt. In applying the second step, if needed, management must estimate the fair value of specific assets and liabilities of the reporting unit.

2019 and 2018 Goodwill Impairment Assessment. ComEd and PHI qualitatively determined that it was more likely than not that the fair values of their reporting units exceeded their carrying values and, therefore, did not perform quantitative assessments as of November 1, 2019 and 2018 for ComEd and as of November 1, 2019 for PHI. The last quantitative assessments performed were as of November 1, 2016 for ComEd and November 1, 2018 for PHI.

PHI performed a quantitative test for its 2018 annual goodwill impairment assessment as of November 1, 2018. The first step of the test comparing the estimated fair values of the Pepco, DPL and ACE reporting units to their carrying values, including goodwill, indicated no impairments of goodwill; therefore, no second step was required.

While the annual assessments indicated no impairments, certain assumptions used to estimate reporting unit fair values are highly sensitive to changes. Adverse regulatory actions or changes in significant assumptions could potentially result in future impairments of Exelon's, ComEd's and PHI's goodwill, which could be material. Based on the results of the last quantitative goodwill test performed, the estimated fair values of the ComEd, Pepco, DPL and ACE reporting units would have needed to decrease by more than 30%, 30%, 20% and 30%, respectively, for ComEd and PHI to fail the first step of their respective impairment tests.

## Other Intangible Assets and Liabilities

Exelon's, Generation's, ComEd's and PHI's other intangible assets and liabilities, included in Unamortized energy contract assets and liabilities and Other deferred debits and other assets in their Consolidated Balance Sheets, consisted of the following as of December 31, 2019 and 2018. The intangible assets and liabilities shown below are amortized on a straight line basis, except for unamortized energy contracts which are amortized in relation to the expected realization of the underlying cash flows:

<table><tr><td rowspan="2"></td><td colspan="3">December 31, 2019</td><td colspan="3">December 31, 2018</td></tr><tr><td>Gross</td><td>Accumulated Amortization</td><td>Net</td><td>Gross</td><td>Accumulated Amortization</td><td>Net</td></tr><tr><td>Generation</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Unamortized Energy Contracts</td><td>1,967</td><td>(1,612)</td><td>355</td><td>1,957</td><td>(1,588)</td><td>369</td></tr><tr><td>Customer Relationships</td><td>343</td><td>(190)</td><td>153</td><td>325</td><td>(162)</td><td>163</td></tr><tr><td>Trade Name</td><td>243</td><td>(193)</td><td>50</td><td>243</td><td>(171)</td><td>72</td></tr><tr><td>ComEd</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Chicago Settlement Agreements</td><td>162</td><td>(155)</td><td>7</td><td>162</td><td>(148)</td><td>14</td></tr><tr><td>PHI</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Unamortized Energy Contracts</td><td>(1,515)</td><td>1,073</td><td>(442)</td><td>(1,515)</td><td>954</td><td>(561)</td></tr><tr><td>Exelon Corporate</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Software License</td><td>95</td><td>(44)</td><td>51</td><td>95</td><td>(34)</td><td>61</td></tr><tr><td>Exelon</td><td>$ 1,295</td><td>$ (1,121)</td><td>$ 174</td><td>$ 1,267</td><td>$ (1,149)</td><td>$ 118</td></tr></table>



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 12 — Intangible Assets

The following table summarizes the amortization expense related to intangible assets and liabilities for each of the years ended December 31, 2019, 2018 and 2017:

<table><tr><td>For the Years Ended December 31,</td><td>Exelon (a)(b)</td><td>Generation (a)</td><td>ComEd</td><td>PHI(b)</td></tr><tr><td></td><td>2019 \(</td><td>(28)</td><td>$ 74</td><td>$ 7</td></tr><tr><td></td><td>2018</td><td>(109)</td><td>63</td><td>7</td></tr><tr><td></td><td>2017</td><td>(237)</td><td>83</td><td>7</td></tr></table>

(a) At Exelon and Generation, amortization of unamortized energy contracts totaling $21 million, $14 million and $35 million for the years ended December 31, 2019, 2018 and 2017, respectively, was recorded in Operating revenues or Purchased power and fuel expense in their Consolidated Statements of Operations and Comprehensive Income.

(b) At Exelon and PHI, amortization of the unamortized energy contract fair value adjustment amounts and the corresponding offsetting regulatory asset and liability amounts are amortized through Purchased power and fuel expense in their Consolidated Statements of Operations and Comprehensive Income.

The following table summarizes the estimated future amortization expense related to intangible assets and liabilities as of December 31, 2019:

<table><tr><td>For the Years Ending December 31,</td><td>Exelon</td><td>Generation</td><td>ComEd</td><td>PHI</td></tr><tr><td>2020</td><td>$ (13)</td><td>$ 85</td><td>$ 7</td><td>$ (115)</td></tr><tr><td>2021</td><td>2</td><td>84</td><td>—</td><td>(92)</td></tr><tr><td>2022</td><td>(21)</td><td>58</td><td>—</td><td>(89)</td></tr><tr><td>2023</td><td>(18)</td><td>53</td><td>—</td><td>(81)</td></tr><tr><td>2024</td><td>22</td><td>50</td><td>—</td><td>(38)</td></tr></table>

## Renewable Energy Credits (Exelon and Generation)

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

The following table presents the current and noncurrent Renewable Energy Credits as of December 31, 2019 and 2018:

<table><tr><td rowspan="2"></td><td colspan="2">As of December 31, 2019</td><td colspan="2">As of December 31, 2018</td></tr><tr><td>Exelon</td><td>Generation</td><td>Exelon</td><td>Generation</td></tr><tr><td>Current REC&#x27;s</td><td>345</td><td>336</td><td>279</td><td>270</td></tr><tr><td>Noncurrent REC&#x27;s</td><td>86</td><td>86</td><td>52</td><td>52</td></tr></table>



## Rate Reconciliation

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

For the Year Ended December 31, 2019

<table><tr><td></td><td>Exelon</td><td>Generation</td><td>ComEd</td><td>PECO</td><td>BGE</td><td>PHI</td><td>Pepco</td><td>DPL</td><td>ACE</td></tr><tr><td>U.S. Federal statutory rate</td><td>21.0%</td><td>21.0%</td><td>21.0%</td><td>21.0%</td><td>2.0%</td><td>21.0%</td><td>21.0%</td><td>21.1%</td><td>21.0%</td></tr><tr><td>Increase (decrease) due to:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>State income taxes, net of Federal income tax benefit</td><td>5.4</td><td>3.8</td><td>8.5</td><td>—</td><td>6.4</td><td>4.7</td><td>2.0</td><td>6.8</td><td>7.0</td></tr><tr><td>Qualified NDT fund income</td><td>5.9</td><td>12.3</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Amortization of investment tax credit, including deferred taxes on basis difference</td><td>(1.5)</td><td>(3.0)</td><td>(0.2)</td><td>—</td><td>(0.1)</td><td>(0.2)</td><td>(0.1)</td><td>(0.2)</td><td>(0.3)</td></tr><tr><td>Plant basis differences</td><td>(1.4)</td><td>—</td><td>—</td><td>(7.2)</td><td>(1.2)</td><td>(1.2)</td><td>(1.8)</td><td>(0.4)</td><td>(0.7)</td></tr><tr><td>Production tax credits and other credits</td><td>(3.1)</td><td>(4.8)</td><td>(1.2)</td><td>—</td><td>(1.3)</td><td>(0.2)</td><td>(0.1)</td><td>—</td><td>(0.1)</td></tr><tr><td>Noncontrolling interests</td><td>(0.6)</td><td>(1.2)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Excess deferred tax amortization</td><td>(5.5)</td><td>—</td><td>(9.7)</td><td>(2.8)</td><td>(6.8)</td><td>(17.5)</td><td>(15.1)</td><td>(14.2)</td><td>(27.0)</td></tr><tr><td>Other</td><td>(0.8)</td><td>(1.2)</td><td>0.8</td><td>—</td><td>—</td><td>0.8</td><td>0.3</td><td>—</td><td>0.1</td></tr><tr><td>Effective income tax rate</td><td>19.4%</td><td>26.9%</td><td>19.2%</td><td>11.0%</td><td>18.0%</td><td>7.4%</td><td>6.2%</td><td>13.0%</td><td>—%</td></tr></table>

For the Year Ended December 31, 2018

<table><tr><td></td><td>Exelon</td><td>Generation</td><td>ComEd</td><td>PECO</td><td>BGE</td><td>PHI</td><td>Pepco</td><td>DPL</td><td>ACE</td></tr><tr><td>U.S. Federal statutory rate</td><td>21.0%</td><td>21.0%</td><td>21.0%</td><td>21.0%</td><td>2.0%</td><td>21.0%</td><td>21.0%</td><td>21.1%</td><td>21.0%</td></tr><tr><td>Increase (decrease) due to:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>State income taxes, net of Federal income tax benefit</td><td>0.5</td><td>(16.6)</td><td>8.3</td><td>(2.6)</td><td>6.6</td><td>2.9</td><td>2.0</td><td>6.7</td><td>7.4</td></tr><tr><td>Qualified NDT fund income</td><td>(1.9)</td><td>(11.8)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Amortization of investment tax credit, including deferred taxes on basis difference</td><td>(1.2)</td><td>(6.5)</td><td>(0.2)</td><td>(0.1)</td><td>(0.1)</td><td>(0.2)</td><td>(0.1)</td><td>(0,3)</td><td>(0.4)</td></tr><tr><td>Plant basis differences</td><td>(3.5)</td><td>—</td><td>(0.2)</td><td>(14.1)</td><td>(1.3)</td><td>(1.6)</td><td>(2.8)</td><td>(0.3)</td><td>(0.5)</td></tr><tr><td>Production tax credits and other credits</td><td>(2.2)</td><td>(13.5)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Noncontrolling interests</td><td>(1.0)</td><td>(6.1)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Excess deferred tax amortization</td><td>(8.3)</td><td>—</td><td>(9.1)</td><td>(3.2)</td><td>(8.0)</td><td>(14.8)</td><td>(15.3)</td><td>(12.0)</td><td>(14.9)</td></tr><tr><td>Tax Cuts and Jobs Act of 2017</td><td>0.9</td><td>2.7</td><td>(0.1)</td><td>—</td><td>—</td><td>0.1</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Other</td><td>1.0</td><td>1.3</td><td>0.5</td><td>0.3</td><td>0.9</td><td>0.4</td><td>0.3</td><td>0.4</td><td>1.2</td></tr><tr><td>Effective income tax rate</td><td>5.3%</td><td>(29.5)%</td><td>20.2%</td><td>1.3%</td><td>19.1%</td><td>7.8%</td><td>5.1%</td><td>15.5%</td><td>13.8%</td></tr></table>



## Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 13 — Income Taxes

<table><tr><td rowspan="2"></td><td colspan="9">For the Year Ended December 31, 2017</td></tr><tr><td>Exelon</td><td>Generation</td><td>ComEd</td><td>PECO</td><td>BGE</td><td>PHI</td><td>Pepco</td><td>DPL</td><td>ACE</td></tr><tr><td>U.S. Federal statutory rate</td><td>35.0 %</td><td>35.0 %</td><td>35.0 %</td><td>35.0 %</td><td></td><td>35.0 %</td><td>35.0 %</td><td>35.0 %</td><td></td></tr><tr><td>Increase (decrease) due to:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>State income taxes, net of Federal income tax benefit</td><td>2.2</td><td>2.9</td><td>5.7</td><td>0.6</td><td>5.4</td><td>4.8</td><td>3.1</td><td>5.4</td><td>5.6</td></tr><tr><td>Qualified NDT fund income</td><td>3.8</td><td>9.9</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Amortization of investment tax credit, including deferred taxes on basis difference</td><td>(0.9)</td><td>(2.1)</td><td>(0.2)</td><td>(0.1)</td><td>(0.1)</td><td>(0.2)</td><td>(0.1)</td><td></td><td>(0.4)</td></tr><tr><td>Plant basis differences(a)</td><td>(1.7)</td><td>—</td><td>0.3</td><td>(13.8)</td><td>0.1</td><td>1.1</td><td>(0.4)</td><td>2.0</td><td>3.6</td></tr><tr><td>Production tax credits and other credits</td><td>(1.8)</td><td>(4.7)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Like-kind exchange</td><td>(1.2)</td><td>—</td><td>1.3</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Merger expenses</td><td>(3.6)</td><td>(1.2)</td><td>—</td><td>—</td><td>—</td><td>(9.6)</td><td>(6.4)</td><td>(7.8)</td><td>(19.8)</td></tr><tr><td>FitzPatrick bargain purchase gain</td><td>(2.2)</td><td>(5.6)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Tax Cuts and Jobs Act of 2017(b)</td><td>(33.1)</td><td>(128.3)</td><td>0.1</td><td>(2.3)</td><td>0.9</td><td>6.4</td><td>2.8</td><td>2.5</td><td>1.6</td></tr><tr><td>Other</td><td>0.2</td><td>(0.5)</td><td>0.2</td><td>(0.1)</td><td>0.2</td><td>0.5</td><td>0.7</td><td>0.1</td><td>(0.4)</td></tr><tr><td>Effective income tax rate</td><td>(3.3)%</td><td>(94.6)%</td><td>42.4 %</td><td>19.3 %</td><td>41.5 %</td><td>38.0 %</td><td>34.7 %</td><td>37.0 %</td><td>25.2 %</td></tr></table>

(a) Includes the charges related to the transmission-related income tax regulatory asset for Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE of $35 million, $3 million, $5 million, $27 million, $14 million, $6 million and $7 million, respectively. See Note 3 - Regulatory Matters for additional information.

(b) As a result of TCAJ, Generation recorded a net decrease to income tax expense, while the Utility Registrants recorded corresponding regulatory liabilities or assets to the extent such amounts are probable of settlement or recovery through customer rates and an adjustment to income tax expense for all other amounts.



## Tax Differences and Carryforwards

The tax effects of temporary differences and carryforwards, which give rise to significant portions of the deferred tax assets (liabilities), as of December 31, 2019 and 2018 are presented below:

<table><tr><td rowspan="2"></td><td colspan="11">As of December 31, 2019</td></tr><tr><td>Exelon</td><td>Generation</td><td>ComEd</td><td>PECO</td><td>BGE</td><td>PHI</td><td>Pepco</td><td>DPL</td><td>ACE</td><td></td><td></td></tr><tr><td>Plant basis differences</td><td>$ (13,413)</td><td>$ (2,814)</td><td>$ (4,197)</td><td>$ (1,978)</td><td>$ (1,578)</td><td>$ (2,681)</td><td>$ (1,204)</td><td>$ (753)</td><td>$ (687)</td><td></td><td></td></tr><tr><td>Accrual based contracts</td><td>61</td><td>(43)</td><td>—</td><td>—</td><td>—</td><td>104</td><td>—</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Derivatives and other financial instruments</td><td>165</td><td>88</td><td>84</td><td>—</td><td>—</td><td>2</td><td>—</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Deferred pension and postretirement obligation</td><td>1,504</td><td>(220)</td><td>(270)</td><td>(28)</td><td>(28)</td><td>(89)</td><td>(75)</td><td>(42)</td><td>(10)</td><td></td><td></td></tr><tr><td>Nuclear decommissioning activities</td><td>(503)</td><td>(503)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Deferred debt refinancing costs</td><td>183</td><td>20</td><td>(7)</td><td>—</td><td>(3)</td><td>142</td><td>(3)</td><td>(2)</td><td>(1)</td><td></td><td></td></tr><tr><td>Regulatory assets and liabilities</td><td>(884)</td><td>—</td><td>183</td><td>(169)</td><td>157</td><td>(10)</td><td>55</td><td>88</td><td>77</td><td></td><td></td></tr><tr><td>Tax loss carryforward</td><td>240</td><td>55</td><td>—</td><td>25</td><td>49</td><td>93</td><td>13</td><td>44</td><td>31</td><td></td><td></td></tr><tr><td>Tax credit carryforward</td><td>892</td><td>897</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Investment in partnerships</td><td>(830)</td><td>(808)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Other, net</td><td>926</td><td>236</td><td>196</td><td>70</td><td>10</td><td>181</td><td>85</td><td>12</td><td>16</td><td></td><td></td></tr><tr><td>Deferred income tax liabilities (net)</td><td>$ (11,659)</td><td>$ (3,092)</td><td>$ (4,011)</td><td>$ (2,080)</td><td>$ (1,393)</td><td>$ (2,258)</td><td>$ (1,129)</td><td>$ (653)</td><td>$ (574)</td><td></td><td></td></tr><tr><td>Unamortized investment tax credits</td><td>(668)</td><td>(648)</td><td>(10)</td><td>(1)</td><td>(3)</td><td>(7)</td><td>(2)</td><td>(2)</td><td>(3)</td><td></td><td></td></tr><tr><td>Total deferred income tax liabilities (net) and unamortized investment tax credits</td><td>$ (12,327)</td><td>$ (3,740)</td><td>$ (4,021)</td><td>$ (2,081)</td><td>$ (1,396)</td><td>$ (2,265)</td><td>$ (1,131)</td><td>$ (655)</td><td>$ (577)</td><td></td><td></td></tr></table>



## Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 13 — Income Taxes

<table><tr><td rowspan="2"></td><td colspan="11">As of December 31, 2018</td></tr><tr><td>Exelon</td><td>Generation</td><td>ComEd</td><td>PECO</td><td>BGE</td><td>PHI</td><td>Pepco</td><td>DPL</td><td>ACE</td><td></td><td></td></tr><tr><td>Plant basis differences</td><td>$ (12,533)</td><td>$ (2,495)</td><td>$ (4,059)</td><td>$ (1,862)</td><td>$ (1,399)</td><td>$ (2,577)</td><td>$ (1,148)</td><td>$ (743)</td><td>$ (645)</td><td></td><td></td></tr><tr><td>Accrual based contracts</td><td>117</td><td>(44)</td><td>—</td><td>—</td><td>—</td><td>161</td><td>—</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Derivatives and other financial instruments</td><td>89</td><td>35</td><td>69</td><td>—</td><td>—</td><td>3</td><td>—</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Deferred pension and postretirement obligation</td><td>1,435</td><td>(188)</td><td>(255)</td><td>(26)</td><td>(26)</td><td>(102)</td><td>(78)</td><td>(46)</td><td>(14)</td><td></td><td></td></tr><tr><td>Nuclear decommissioning activities</td><td>(351)</td><td>(351)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Deferred debt refinancing costs</td><td>234</td><td>23</td><td>(7)</td><td>—</td><td>(3)</td><td>187</td><td>(4)</td><td>(2)</td><td>(1)</td><td></td><td></td></tr><tr><td>Regulatory assets and liabilities</td><td>(740)</td><td>—</td><td>300</td><td>(129)</td><td>172</td><td>(81)</td><td>67</td><td>96</td><td>83</td><td></td><td></td></tr><tr><td>Tax loss carryforward</td><td>237</td><td>78</td><td>—</td><td>18</td><td>25</td><td>96</td><td>12</td><td>52</td><td>26</td><td></td><td></td></tr><tr><td>Tax credit carryforward</td><td>811</td><td>816</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Investment in partnerships</td><td>(797)</td><td>(775)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Other, net</td><td>934</td><td>239</td><td>151</td><td>67</td><td>12</td><td>196</td><td>98</td><td>17</td><td>19</td><td></td><td></td></tr><tr><td>Deferred income tax liabilities (net)</td><td>$ (10,564)</td><td>$ (2,662)</td><td>$ (3,801)</td><td>$ (1,932)</td><td>$ (1,219)</td><td>$ (2,117)</td><td>$ (1,053)</td><td>$ (626)</td><td>$ (532)</td><td></td><td></td></tr><tr><td>Unamortized investment tax credits</td><td>(724)</td><td>(700)</td><td>(12)</td><td>(1)</td><td>(3)</td><td>(8)</td><td>(2)</td><td>(2)</td><td>(3)</td><td></td><td></td></tr><tr><td>Total deferred income tax liabilities (net) and unamortized investment tax credits</td><td>$ (11,288)</td><td>$ (3,362)</td><td>$ (3,813)</td><td>$ (1,933)</td><td>$ (1,222)</td><td>$ (2,125)</td><td>$ (1,055)</td><td>$ (628)</td><td>$ (535)</td><td></td><td></td></tr></table>

The following table provides Exelon's, Generation's, PECO's, BGE's, PHI's, Pepco's, DPL's and ACE's carryforwards, which are presented on a post-apportioned basis, and any corresponding valuation allowances as of December 31, 2019. ComEd does not have net operating losses or credit carryforwards for the year ended December 31, 2019.

<table><tr><td></td><td>Exelon</td><td>Generation</td><td>PECO</td><td>BGE</td><td>PHI</td><td>Pepco</td><td>DPL</td><td>ACE</td></tr><tr><td>Federal</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Federal general business credits carryforwards \( ^{(a)} \)</td><td>$ 891</td><td>$ 897</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td></tr><tr><td>State</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>State net operating losses</td><td>3,986</td><td>1,142</td><td>312</td><td>762</td><td>1,360</td><td>202</td><td>654</td><td>438</td></tr><tr><td>Deferred taxes on state tax attributes (net)</td><td>264</td><td>78</td><td>25</td><td>50</td><td>93</td><td>13</td><td>44</td><td>31</td></tr><tr><td>Valuation allowance on state tax attributes</td><td>26</td><td>24</td><td>—</td><td>1</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Year in which net operating loss or credit carryforwards will begin to expire</td><td>2025</td><td>2029</td><td>2031</td><td>2026</td><td>2028</td><td>2028</td><td>2030</td><td>2031</td></tr></table>

(a) Exelon’s and Generation’s federal general business credit carryforwards will begin expiring in 2034.

Tabular Reconciliation of Unrecognized Tax Benefits

The following table presents changes in unrecognized tax benefits, by Registrant.



## Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 13 — Income Taxes

<table><tr><td></td><td>Exelon</td><td>Generation</td><td>ComEd</td><td>PECO</td><td>BGE</td><td>PHI</td><td>Pepco</td><td>DPL</td><td>ACE</td></tr><tr><td>Balance at January 1, 2017</td><td>$ 916</td><td>$ 490</td><td>$ (12)</td><td>$ —</td><td>$ 120</td><td>$ 172</td><td>$ 80</td><td>$ 37</td><td>$ 22</td></tr><tr><td>Increases based on tax positions prior to 2017</td><td>28</td><td>—</td><td>14</td><td>—</td><td>—</td><td>14</td><td>—</td><td>—</td><td>14</td></tr><tr><td>Decreases based on tax positions prior to 2017(a)</td><td>(196)</td><td>(17)</td><td>—</td><td>—</td><td>—</td><td>(61)</td><td>(21)</td><td>(16)</td><td>(22)</td></tr><tr><td>Decrease from settlements with taxing authorities</td><td>(5)</td><td>(5)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Balance at December 31, 2017</td><td>743</td><td>468</td><td>2</td><td>—</td><td>120</td><td>125</td><td>59</td><td>21</td><td>14</td></tr><tr><td>Change to positions that only affect timing</td><td>15</td><td>15</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Increases based on tax positions prior to 2018</td><td>30</td><td>21</td><td>—</td><td>—</td><td>—</td><td>8</td><td>7</td><td>1</td><td>—</td></tr><tr><td>Decreases based on tax positions prior to 2018(b)</td><td>(251)</td><td>(36)</td><td>—</td><td>—</td><td>(120)</td><td>(88)</td><td>(66)</td><td>(22)</td><td>—</td></tr><tr><td>Decrease from settlements with taxing authorities</td><td>(53)</td><td>(53)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Decreases from expiration of statute of limitations</td><td>(7)</td><td>(7)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Balance at December 31, 2018</td><td>477</td><td>408</td><td>2</td><td>—</td><td>—</td><td>45</td><td>—</td><td>—</td><td>14</td></tr><tr><td>Change to positions that only affect timing</td><td>26</td><td>12</td><td>3</td><td>1</td><td>4</td><td>3</td><td>2</td><td>1</td><td>—</td></tr><tr><td>Increases based on tax positions related to 2019</td><td>2</td><td>1</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Increases based on tax positions prior to 2019</td><td>34</td><td>19</td><td>3</td><td>2</td><td>3</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Decreases based on tax positions prior to 2019</td><td>(3)</td><td>(3)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Decrease from settlements with taxing authorities</td><td>(29)</td><td>4</td><td>(2)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Balance at December 31, 2019</td><td>$ 507</td><td>$ 441</td><td>$ 6</td><td>$ 3</td><td>$ 7</td><td>$ 48</td><td>$ 2</td><td>$ 1</td><td>$ 14</td></tr></table>

(a) Exelon established a liability for an uncertain tax position associated with the tax deductibility of certain merger commitments incurred by Exelon in connection with the acquisitions of Constellation and PHI. In 2017, as a part of its examination of Exelon's return, the IRS National Office issued guidance concurring with Exelon's position that the merger commitments were deductible. As a result, Exelon, Generation, PHI, Pepco, DPL, and ACE decreased their liability for unrecognized tax benefits by $146 million, $19 million, $59 million, $21 million, $16 million and $22 million, respectively, resulting in a benefit to Income taxes on Exelon's, Generation's, PHI's, Pepco's, DPL's, and ACE's Consolidated Statements of Operations and Comprehensive Income and corresponding decreases in their effective tax rates.

(b) Exelon, Generation, BGE, PHI, Pepco, and DPL decreased their unrecognized state tax benefits primarily due to the receipt of favorable guidance with respect to the deductibility of certain depreciable fixed assets. The recognition of the tax benefits related to BGE, PHI, Pepco, and DPL was offset by corresponding regulatory liabilities and that portion had no immediate impact to their effective tax rate.

## Like-Kind Exchange

In 2016, the Tax Court held that Exelon was not entitled to defer a gain on its 1999 like-kind exchange transaction. In addition to the tax and interest related to the gain deferral, the Tax Court also ruled that Exelon was liable for penalties and interest on the penalties. Exelon had fully paid the amounts assessed resulting from the Tax Court decision in 2017. In September 2017, Exelon appealed the Tax Court decision to the U.S. Court of Appeals for the Seventh Circuit. In October 2018, the U.S. Court of Appeals for the Seventh Circuit affirmed the Tax Court's decision. Exelon filed a petition seeking rehearing of the Seventh Circuit's decision, but the Seventh Circuit denied that petition in December 2018. In the first quarter of 2019, Exelon elected not to seek a further review by the U.S. Supreme Court.



# Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 13 — Income Taxes

Court. As a result, Exelon's and ComEd's unrecognized tax benefits decreased by approximately $33 million and $2 million, respectively, in the first quarter of 2019.

## Recognition of unrecognized tax benefits

The following table presents Exelon's, Generation's and PHI's unrecognized tax benefits that, if recognized, would decrease the effective tax rate. ComEd's, PECO's, BGE's, Pepco's, DPL's and ACE's amounts are not material.

<table><tr><td></td><td>Exelon</td><td>Generation</td><td>PHI(a)</td></tr><tr><td>December 31, 2019</td><td>$ 462</td><td>$ 429</td><td>$ 32</td></tr><tr><td>December 31, 2018</td><td>463</td><td>408</td><td>31</td></tr><tr><td>December 31, 2017</td><td>523</td><td>461</td><td>32</td></tr></table>

(a) PHI has $21 million of unrecognized state tax benefits that, if recognized, $14 million would be in the form of a net operating loss carryforward, which is expected to require a full valuation allowance based on present circumstances.

The following table presents Exelon's, BGE's, PHI's, Pepco's, DPL's and ACE's unrecognized tax benefits that, if recognized, may be included in future base rates and that portion would have no impact to the effective tax rate. ComEd's and PECO's amounts are not material.

<table><tr><td></td><td>Exelon</td><td>BGE</td><td>PHI</td><td>Pepco</td><td>DPL</td><td>ACE</td></tr><tr><td>December 31, 2019</td><td>$ 19</td><td>$ 1</td><td>$ 14</td><td>$ —</td><td>$ —</td><td>$ 14</td></tr><tr><td>December 31, 2018</td><td>14</td><td>—</td><td>14</td><td>—</td><td>—</td><td>14</td></tr><tr><td>December 31, 2017</td><td>214</td><td>120</td><td>94</td><td>59</td><td>21</td><td>14</td></tr></table>

Reasonably possible the total amount of unrecognized tax benefits could significantly increase or decrease within 12 months after the reporting date

## Settlement of Income Tax Audits, Refund Claims, and Litigation

The following table represents Exelon's, Generation's and ACE's unrecognized federal and state tax benefits that could significantly decrease within the 12 months after the reporting date as a result of completing audits, potential settlements, refund claims, and the outcomes of pending court cases as of December 31, 2019. ComEd's, PECO's, BGE's, PHI's, Pepco's and DPL's amounts are not material.

<table><tr><td>Exelon(a)</td><td>Generation(a)</td><td>ACE(b)</td></tr><tr><td>$ 425</td><td>$ 411</td><td>$ 14</td></tr></table>

(a) Exelon and Generation have $411 million that, if recognized, would decrease the effective tax rate.

(b) The unrecognized tax benefit related to ACE, if recognized, may be included in future base rates and that portion would have no impact to the effective tax rate.

## Total amounts of interest and penalties recognized

The following table represents the net interest and penalties receivable (payable) related to tax positions reflected in Exelon's Consolidated Balance Sheets. Generation's and the Utility Registrants' amounts are not material.

<table><tr><td>Net interest and penalties receivable as of</td><td>Exelon</td></tr><tr><td>December 31, 2019</td><td>$ 318</td></tr><tr><td>December 31, 2018</td><td>219</td></tr></table>



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

## Description of tax years open to assessment by major jurisdiction

<table><tr><td>Major Jurisdiction</td><td>Open Years</td><td>Registrants Impacted</td></tr><tr><td>Federal consolidated income tax returns</td><td>2002-2018</td><td>All Registrants</td></tr><tr><td>PHI Holdings and subsidiaries consolidated federal income tax returns</td><td>2016</td><td>Exelon, Generation, PHI, Pepco, DPL, ACE</td></tr><tr><td>Delaware separate corporate income tax returns</td><td>Same as federal</td><td>DPL</td></tr><tr><td>District of Columbia combined corporate income tax returns</td><td>2016-2018</td><td>Exelon, PHI, Pepco</td></tr><tr><td>Illinois unitary corporate income tax returns</td><td>2010-2018</td><td>Exelon, Generation, ComEd</td></tr><tr><td>Maryland separate company corporate net income tax returns</td><td>Same as federal</td><td>BGE, Pepco, DPL</td></tr><tr><td>New Jersey separate corporate income tax returns</td><td>2013-2018</td><td>Exelon, Generation</td></tr><tr><td>New Jersey separate corporate income tax returns</td><td>2014-2018</td><td>ACE</td></tr><tr><td>New York combined corporate income tax returns</td><td>2010-March 2012</td><td>Exelon, Generation</td></tr><tr><td>New York combined corporate income tax returns</td><td>2011-2018</td><td>Exelon, Generation</td></tr><tr><td>Pennsylvania separate corporate income tax returns</td><td>2011-2018</td><td>Exelon, Generation</td></tr></table>

## Other Tax Matters

## Federal Income Tax Law Changes

On December 22, 2017, President Trump signed the TCJA into law. Pursuant to the enactment of the TCJA, the Registrants remeasured their existing deferred income tax balances as of December 31, 2017 to reflect the decrease in the corporate income tax rate from 35% to 21%, which resulted in a material decrease to their net deferred income tax liability balances as shown in the table below. Generation recorded a corresponding net decrease to income tax expense, while the Utility Registrants recorded corresponding regulatory liabilities or assets to the extent such amounts are probable of settlement or recovery through customer rates and an adjustment to income tax expense for all other amounts.

The one-time impacts recorded by the Registrants to remeasure their deferred income tax balances at the 21% corporate federal income tax rate as of December 31, 2017 are presented below:

<table><tr><td></td><td>Exelon(b)</td><td>Generation</td><td>ComEd</td><td>PECO(e)</td><td>BGE</td><td>PHI</td><td>Pepco</td><td>DPL</td><td>ACE</td></tr><tr><td>Net Decrease to Deferred Income Tax Liability Balances</td><td>$8,624</td><td>$1,895</td><td>$2,819</td><td>$1,407</td><td>$1,120</td><td>$1,944</td><td>$968</td><td>$540</td><td>$456</td></tr><tr><td>Net Increase to Regulatory Liabilities Recorded(a)</td><td>7,315</td><td>N/A</td><td>2,818</td><td>1,394</td><td>1,124</td><td>1,979</td><td>976</td><td>545</td><td>458</td></tr><tr><td>Net Deferred Income Tax Benefit/(Expense) Recorded</td><td>$1,309</td><td>$1,895</td><td>$1</td><td>$13</td><td>$(4)</td><td>$35</td><td>$(8)</td><td>$5</td><td>$2</td></tr></table>

(a) Reflects the net regulatory liabilities recorded on a pre-tax basis before taking into consideration the income tax benefits associated with the ultimate settlement with customers.

(b) Amounts do not sum across due to deferred tax adjustments recorded at the Exelon Corporation parent company, primarily related to certain employee compensation plans.

(c) Given the regulatory treatment of income tax benefits related to electric and gas distribution repairs, PECO remained in an overall net regulatory asset position as of December 31, 2017 after recording the impacts related to the TCJA.



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

## State Income Tax Law Changes

Illinois - On June 5, 2019, the Governor of Illinois signed a tax bill which would increase the Illinois corporate income tax rate from 9.50% to 10.49% effective for tax years beginning on or after January 1, 2021. The tax rate is contingent upon ratification of state constitutional amendments in November 2020. The effect of the rate change will be recognized in the period in which the new legislation is enacted. Exelon, Generation and ComEd do not expect a material impact to their financial statements as a result of the rate change.

In 2017, Exelon reviewed and updated its marginal state income tax rates based on 2016 state apportionment rates. In addition, Exelon, Generation and ComEd recorded the impacts of Illinois' statutory rate change, which increased the total corporate income tax rate from 7.75% to 9.50% effective July 1, 2017. The following table provides the one-time impact of the rate changes in 2017 for Exelon, Generation and ComEd:

<table><tr><td></td><td colspan="2">Exelon</td><td colspan="2">Generation</td><td colspan="2">ComEd</td></tr><tr><td>Increase to Deferred Income Taxes</td><td>$     250</td><td>$     20</td><td>$     270</td><td></td><td></td><td></td></tr><tr><td>Increase in Regulatory Assets</td><td>270</td><td></td><td>—</td><td></td><td>270</td><td></td></tr><tr><td>(Decrease)/Increase to Income Tax Expense</td><td>(20)</td><td></td><td>20</td><td></td><td>—</td><td></td></tr></table>

## Long-Term Marginal State Income Tax Rate (All Registrants)

Quarterly, Exelon reviews and updates its marginal state income tax rates for changes in state apportionment. The Registrants remeasure their existing deferred income tax balances to reflect the changes in marginal rates, which results in either an increase or decrease to their net deferred income tax liability balances. Utility Registrants record corresponding regulatory liabilities or assets to the extent such amounts are probable of settlement or recovery through customer rates and an adjustment to income tax expense for all other amounts.

<table><tr><td>December 31, 2019</td><td>Exelon</td><td>Generation</td><td>PHI</td><td>DPL</td></tr><tr><td>Increase to Deferred Income Tax Liability</td><td>$     23</td><td>$     9</td><td>$      —</td><td>$      —</td></tr><tr><td>Increase to Income Tax Expense, Net of Federal Taxes</td><td>23</td><td>9</td><td>—</td><td>—</td></tr><tr><td>December 31, 2018</td><td></td><td></td><td></td><td></td></tr><tr><td>Decrease to Deferred Income Tax Liability</td><td>$     50</td><td>$     53</td><td>$     4</td><td>$     2</td></tr><tr><td>Decrease to Income Tax Expense, Net of Federal Taxes</td><td>50</td><td>53</td><td>3</td><td>—</td></tr></table>

There were no material adjustments to income tax expense in 2017 as a result of changes in state apportionment.

## Allocation of Tax Benefits (All Registrants)

Generation and the Utility Registrants are all party to an agreement with Exelon and other subsidiaries of Exelon that provides for the allocation of consolidated tax liabilities and benefits (Tax Sharing Agreement). The Tax Sharing Agreement provides that each party is allocated an amount of tax similar to that which would be owed had the party been separately subject to tax. In addition, any net benefit attributable to Exelon is reallocated to the other Registrants. That allocation is treated as a contribution to the capital of the party receiving the benefit.

The following table presents the allocation of federal tax benefits from Exelon under the Tax Sharing Agreement.

<table><tr><td></td><td>Generation</td><td>ComEd</td><td>PECO</td><td>BGE</td><td>PHI</td><td>Pepco</td><td>DPL</td></tr><tr><td>December 31, 2019(a)</td><td>$     41</td><td>$      —</td><td>$     14</td><td>$     3</td><td>$     7</td><td>$     6</td><td>$     1</td></tr><tr><td>December 31, 2018(b)</td><td>155</td><td>1</td><td>48</td><td>26</td><td>2</td><td>—</td><td>—</td></tr><tr><td>December 31, 2017(c)</td><td>102</td><td>—</td><td>16</td><td>10</td><td>7</td><td>—</td><td>—</td></tr></table>

(a) ACE did not record an allocation of federal tax benefits from Exelon under the Tax Sharing Agreement as a result of a tax net operating loss.

(b) Pepco, DPL and ACE did not record an allocation of federal tax benefits from Exelon under the Tax Sharing Agreement as a result of a tax net operating loss.



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 13 — Income Taxes

(c) ComEd, Pepco, DPL and ACE did not record an allocation of federal tax benefits from Exelon under the Tax Sharing Agreement as a result of a tax net operating loss.

## Research and Development Activities

In the fourth quarter 2019, Exelon and Generation recognized additional tax benefits related to certain research and development activities that qualify for federal and state tax incentives for the 2010 through 2018 tax years, which resulted in an increase to Exelon's and Generation's net income of $108 million and $75 million, respectively, for the year ended December 31, 2019, reflecting a decrease to Exelon's and Generation's Income tax expense of $97 million and $66 million, respectively.

## 14. Retirement Benefits (All Registrants)

Exelon sponsors defined benefit pension plans and OPEB plans for essentially all current employees. Substantially all non-union employees and electing union employees hired on or after January 1, 2001 participate in cash balance pension plans. Effective January 1, 2009, substantially all newly-hired union-represented employees participate in cash balance pension plans. Effective February 1, 2018, most newly-hired Generation and BSC non-represented, non-craft, employees are not eligible for pension benefits, and will instead be eligible to receive an enhanced non-discretionary employer contribution in an Exelon defined contribution savings plan. Effective January 1, 2018, most newly-hired non-represented, non-craft, employees are not eligible for OPEB benefits and employees represented by Local 614 are not eligible for retiree health care benefits.

Effective January 1, 2019, Exelon merged the Exelon Corporation Cash Balance Pension Plan (CBPP) into the Exelon Corporation Retirement Program (ECRP). The merging of the plans did not change the benefits offered to the plan participants and, thus, had no impact on Exelon's pension obligation. However, beginning in 2019, actuarial losses and gains related to the CBPP and ECRP are amortized over participants' average remaining service period of the merged ECRP rather than each individual plan.



## Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 14 — Retirement Benefits

The table below shows the pension and OPEB plans in which employees of each operating company participated at December 31, 2019:

<table><tr><td rowspan="2">Name of Plan:</td><td colspan="8">Operating Company(e)</td></tr><tr><td>Generation</td><td>ComEd</td><td>PECO</td><td>BGE</td><td>PHI</td><td>Pepco</td><td>DPL</td><td>ACE</td></tr><tr><td>Qualified Pension Plans:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Exelon Corporation Retirement Program(a)</td><td>X</td><td>X</td><td>X</td><td>X</td><td>X</td><td>X</td><td>X</td><td></td></tr><tr><td>Exelon Corporation Pension Plan for Bargaining Unit Employees(a)</td><td>X</td><td>X</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Exelon New England Union Employees Pension Plan(a)</td><td>X</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Exelon Employee Pension Plan for Clinton, TMI and Oyster Creek(a)</td><td>X</td><td>X</td><td>X</td><td></td><td>X</td><td></td><td></td><td>X</td></tr><tr><td>Pension Plan of Constellation Energy Group, Inc.(b)</td><td>X</td><td>X</td><td>X</td><td>X</td><td>X</td><td>X</td><td>X</td><td></td></tr><tr><td>Pension Plan of Constellation Energy Nuclear Group, LLC(c)</td><td>X</td><td>X</td><td></td><td>X</td><td>X</td><td></td><td></td><td></td></tr><tr><td>Nine Mile Point Pension Plan(c)</td><td>X</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Constellation Mystic Power, LLC Union Employees Pension Plan Including Plan A and Plan B(b)</td><td>X</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Pepco Holdings LLC Retirement Plan(d)</td><td>X</td><td>X</td><td>X</td><td>X</td><td>X</td><td>X</td><td>X</td><td></td></tr><tr><td>Non-Qualified Pension Plans:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Exelon Corporation Supplemental Pension Benefit Plan and 2000 Excess Benefit Plan(a)</td><td>X</td><td>X</td><td>X</td><td></td><td>X</td><td></td><td></td><td></td></tr><tr><td>Exelon Corporation Supplemental Management Retirement Plan(a)</td><td>X</td><td>X</td><td>X</td><td>X</td><td>X</td><td>X</td><td>X</td><td></td></tr><tr><td>Constellation Energy Group, Inc. Senior Executive Supplemental Plan(b)</td><td>X</td><td></td><td></td><td>X</td><td></td><td></td><td></td><td></td></tr><tr><td>Constellation Energy Group, Inc. Supplemental Pension Plan(b)</td><td>X</td><td></td><td></td><td>X</td><td></td><td></td><td></td><td></td></tr><tr><td>Constellation Energy Group, Inc. Benefits Restoration Plan(b)</td><td>X</td><td>X</td><td></td><td>X</td><td>X</td><td></td><td></td><td></td></tr><tr><td>Constellation Energy Nuclear Plan, LLC Executive Retirement Plan(c)</td><td>X</td><td></td><td></td><td></td><td>X</td><td></td><td></td><td></td></tr><tr><td>Constellation Energy Nuclear Plan, LLC Benefits Restoration Plan(c)</td><td>X</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Baltimore Gas &amp; Electric Company Executive Benefit Plan(b)</td><td>X</td><td></td><td></td><td>X</td><td></td><td></td><td></td><td></td></tr><tr><td>Baltimore Gas &amp; Electric Company Manager Benefit Plan(b)</td><td>X</td><td>X</td><td>X</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Pepco Holdings LLC 2011 Supplemental Executive Retirement Plan(d)</td><td></td><td></td><td></td><td></td><td>X</td><td>X</td><td>X</td><td>X</td></tr><tr><td>Conectiv Supplemental Executive Retirement Plan (d)</td><td>X</td><td></td><td></td><td></td><td>X</td><td></td><td>X</td><td>X</td></tr><tr><td>Pepco Holdings LLC Combined Executive Retirement Plan (d)</td><td></td><td></td><td></td><td></td><td>X</td><td>X</td><td></td><td></td></tr><tr><td>Atlantic City Electric Director Retirement Plan (d)</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td>X</td></tr></table>



## Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 14 — Retirement Benefits

<table><tr><td rowspan="2">Name of Plan:</td><td colspan="8">Operating Company(e)</td></tr><tr><td>Generation</td><td>ComEd</td><td>PECO</td><td>BGE</td><td>PHI</td><td>Pepco</td><td>DPL</td><td>ACE</td></tr><tr><td>OPEB Plans:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>PECO Energy Company Retiree Medical Plan(a)</td><td>X</td><td>X</td><td>X</td><td>X</td><td>X</td><td>X</td><td>X</td><td></td></tr><tr><td>Exelon Corporation Health Care Program(a)</td><td>X</td><td>X</td><td>X</td><td>X</td><td>X</td><td>X</td><td></td><td>X</td></tr><tr><td>Exelon Corporation Employees&#x27; Life Insurance Plan(a)</td><td>X</td><td>X</td><td>X</td><td>X</td><td></td><td></td><td></td><td></td></tr><tr><td>Exelon Corporation Health Reimbursement Arrangement Plan(a)</td><td>X</td><td>X</td><td>X</td><td>X</td><td></td><td></td><td></td><td></td></tr><tr><td>Constellation Energy Group, Inc. Retiree Medical Plan(b)</td><td>X</td><td>X</td><td>X</td><td>X</td><td>X</td><td>X</td><td></td><td></td></tr><tr><td>Constellation Energy Group, Inc. Retiree Dental Plan(b)</td><td>X</td><td></td><td></td><td>X</td><td></td><td></td><td></td><td></td></tr><tr><td>Constellation Energy Group, Inc. Employee Life Insurance Plan and Family Life Insurance Plan(b)</td><td>X</td><td>X</td><td>X</td><td>X</td><td>X</td><td>X</td><td></td><td></td></tr><tr><td>Constellation Mystic Power, LLC</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Post-Employment Medical Account Savings Plan(b)</td><td>X</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Exelon New England Union Post-Employment Medical Savings Account Plan(a)</td><td>X</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Retiree Medical Plan of Constellation Energy Nuclear Group LLC(c)</td><td>X</td><td></td><td></td><td>X</td><td></td><td>X</td><td></td><td></td></tr><tr><td>Retiree Dental Plan of Constellation Energy Nuclear Group LLC(c)</td><td>X</td><td></td><td></td><td>X</td><td></td><td>X</td><td></td><td></td></tr><tr><td>Nine Mile Point Nuclear Station, LLC Medical Care and Prescription Drug Plan for Retired Employees(c)</td><td>X</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Pepco Holdings LLC Welfare Plan for Retirees(d)</td><td>X</td><td>X</td><td>X</td><td>X</td><td>X</td><td>X</td><td>X</td><td></td></tr></table>

(a) These plans are collectively referred to as the legacy Exelon plans.

(b) These plans are collectively referred to as the legacy Constellation Energy Group (CEG) Plans.

(c) These plans are collectively referred to as the legacy CENG plans.

(d) These plans are collectively referred to as the legacy PHI plans.

(e) Employees generally remain in their legacy benefit plans when transferring between operating companies.

Exelon’s traditional and cash balance pension plans are intended to be tax-qualified defined benefit plans. Exelon has elected that the trusts underlying these plans be treated as qualified trusts under the IRC. If certain conditions are met, Exelon can deduct payments made to the qualified trusts, subject to certain IRC limitations.

## Benefit Obligations, Plan Assets and Funded Status

During the first quarter of 2019, Exelon received an updated valuation of its pension and OPEB to reflect actual census data as of January 1, 2019. This valuation resulted in an increase to the pension and OPEB obligations of $75 million and $36 million, respectively. Additionally, accumulated other comprehensive loss increased by $39 million (after-tax) and regulatory assets and liabilities increased by $53 million and decreased by $5 million, respectively.



## Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 14 — Retirement Benefits

The following tables provide a rollforward of the changes in the benefit obligations and plan assets of Exelon for the most recent two years for all plans combined:

<table><tr><td rowspan="2"></td><td colspan="3">Pension Benefits</td><td colspan="3">OPEB</td></tr><tr><td>2019</td><td>2018</td><td>2019</td><td>2018</td><td></td><td></td></tr><tr><td>Change in benefit obligation:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Net benefit obligation at beginning of year</td><td>$ 20,692</td><td>$ 22,337</td><td>$ 4,369</td><td>$ 4,856</td><td></td><td></td></tr><tr><td>Service cost</td><td>357</td><td>405</td><td>93</td><td>112</td><td></td><td></td></tr><tr><td>Interest cost</td><td>883</td><td>802</td><td>188</td><td>175</td><td></td><td></td></tr><tr><td>Plan participants&#x27; contributions</td><td>—</td><td>—</td><td>44</td><td>45</td><td></td><td></td></tr><tr><td>Actuarial (gain) loss \( ^{(a)} \)</td><td>2,322</td><td>(1,561)</td><td>250</td><td>(540)</td><td></td><td></td></tr><tr><td>Plan amendments</td><td>68</td><td>(4)</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Curtailments</td><td>(3)</td><td>—</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Settlements</td><td>(35)</td><td>(48)</td><td>(4)</td><td>(4)</td><td></td><td></td></tr><tr><td>Contractual termination benefits</td><td>1</td><td>—</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Gross benefits paid</td><td>(1,417)</td><td>(1,239)</td><td>(282)</td><td>(275)</td><td></td><td></td></tr><tr><td>Net benefit obligation at end of year</td><td>$ 22,868</td><td>$ 20,692</td><td>$ 4,658</td><td>$ 4,369</td><td></td><td></td></tr><tr><td></td><td colspan="3">Pension Benefits</td><td colspan="3">OPEB</td></tr><tr><td></td><td>2019</td><td>2018</td><td>2019</td><td>2018</td><td></td><td></td></tr><tr><td>Change in plan assets:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Fair value of net plan assets at beginning of year</td><td>$ 16,678</td><td>$ 18,573</td><td>$ 2,408</td><td>$ 2,732</td><td></td><td></td></tr><tr><td>Actual return on plan assets</td><td>3,008</td><td>(945)</td><td>324</td><td>(136)</td><td></td><td></td></tr><tr><td>Employer contributions</td><td>356</td><td>337</td><td>51</td><td>46</td><td></td><td></td></tr><tr><td>Plan participants&#x27; contributions</td><td>—</td><td>—</td><td>44</td><td>45</td><td></td><td></td></tr><tr><td>Gross benefits paid</td><td>(1,417)</td><td>(1,239)</td><td>(282)</td><td>(275)</td><td></td><td></td></tr><tr><td>Settlements</td><td>(35)</td><td>(48)</td><td>(4)</td><td>(4)</td><td></td><td></td></tr><tr><td>Fair value of net plan assets at end of year</td><td>$ 18,590</td><td>$ 16,678</td><td>$ 2,541</td><td>$ 2,408</td><td></td><td></td></tr></table>

(a) The pension actuarial loss in 2019 primarily reflects a decrease in the discount rate. The OPEB actuarial loss in 2019 primarily reflects a decrease in the discount rate. The pension actuarial gain in 2018 primarily reflects an increase in the discount rate. The OPEB actuarial gain in 2018 primarily reflects an increase in the discount rate and favorable health care claims experience.

Exelon presents its benefit obligations and plan assets net on its balance sheet within the following line items:

<table><tr><td rowspan="2"></td><td colspan="3">Pension Benefits</td><td colspan="3">OPEB</td></tr><tr><td>2019</td><td>2018</td><td>2019</td><td>2018</td><td></td><td></td></tr><tr><td>Other current liabilities</td><td>$ 31</td><td>$ 26</td><td>$ 41</td><td>$ 33</td><td></td><td></td></tr><tr><td>Pension obligations</td><td>4,247</td><td>3,988</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Non-pension postretirement benefit obligations</td><td>—</td><td>—</td><td>2,076</td><td>1,928</td><td></td><td></td></tr><tr><td>Unfunded status (net benefit obligation less plan assets)</td><td>$ 4,278</td><td>$ 4,014</td><td>$ 2,117</td><td>$ 1,961</td><td></td><td></td></tr></table>



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 14 — Retirement Benefits

The following table provides the accumulated benefit obligation (ABO) and fair value of plan assets for all pension plans with an ABO in excess of plan assets. Information for pension and OPEB plans with projected benefit obligations (PBO) and accumulated postretirement benefit obligation (APBO), respectively, in excess of plan assets has been disclosed in the Obligations and Plan Assets table above as all pension and OPEB plans are underfunded.

<table><tr><td rowspan="2">ABO in excess of plan assets</td><td colspan="2">Exelon</td></tr><tr><td>2019</td><td>2018</td></tr><tr><td>Accumulated benefit obligation</td><td>21,727</td><td>19,656</td></tr><tr><td>Fair value of net plan assets</td><td>18,590</td><td>16,678</td></tr></table>

## Components of Net Periodic Benefit Costs

The majority of the 2019 pension benefit cost for the Exelon-sponsored plans is calculated using an expected long-term rate of return on plan assets of 7.00% and a discount rate of 4.31%. The majority of the 2019 OPEB cost is calculated using an expected long-term rate of return on plan assets of 6.67% for funded plans and a discount rate of 4.30%.

A portion of the net periodic benefit cost for all plans is capitalized within the Consolidated Balance Sheets. The following tables present the components of Exelon's net periodic benefit costs, prior to capitalization, for the years ended December 31, 2019, 2018 and 2017.

<table><tr><td rowspan="2"></td><td colspan="4">Pension Benefits</td><td colspan="4">OPEB</td></tr><tr><td>2019</td><td>2018</td><td>2017(a)</td><td>2019</td><td>2018</td><td>2017(a)</td><td></td><td></td></tr><tr><td>Components of net periodic benefit cost:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Service cost</td><td>$ 357</td><td>$ 405</td><td>$ 387</td><td>$ 93</td><td>$ 112</td><td>$ 106</td><td></td><td></td></tr><tr><td>Interest cost</td><td>883</td><td>802</td><td>842</td><td>188</td><td>175</td><td>182</td><td></td><td></td></tr><tr><td>Expected return on assets</td><td>(1,225)</td><td>(1,252)</td><td>(1,196)</td><td>(153)</td><td>(173)</td><td>(162)</td><td></td><td></td></tr><tr><td>Amortization of:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Prior service cost (credit)</td><td>—</td><td>2</td><td>1</td><td>(179)</td><td>(186)</td><td>(188)</td><td></td><td></td></tr><tr><td>Actuarial loss</td><td>414</td><td>629</td><td>607</td><td>45</td><td>66</td><td>61</td><td></td><td></td></tr><tr><td>Settlement and other charges</td><td>17</td><td>3</td><td>3</td><td>1</td><td>1</td><td>—</td><td></td><td></td></tr><tr><td>Contractual termination benefits</td><td>1</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Net periodic benefit cost</td><td>$ 447</td><td>$ 589</td><td>$ 644</td><td>$ (5)</td><td>$ (5)</td><td>$ (1)</td><td></td><td></td></tr></table>

(a) FitzPatrick net benefit costs are included for the period after acquisition.

## Cost Allocation to Exelon Subsidiaries

All Registrants account for their participation in Exelon’s pension and OPEB plans by applying multi-employer accounting. Exelon allocates costs related to its pension and OPEB plans to its subsidiaries based on both active and retired employee participation in each plan.

The amounts below represent the Registrants' allocated pension and OPEB costs. As a result of new pension guidance effective on January 1, 2018, certain balances have been reclassified on Exelon's Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2017. For Exelon, the service cost component is included in Operating and maintenance expense and Property, plant and equipment, net, while the non-service cost components are included in Other, net and Regulatory assets for the years ended December 31, 2019 and December 31, 2018 and in Other, net and Property, plant and equipment, net, for the year ended December 31, 2017. For Generation and the Utility Registrants, the service cost and non-service cost components are included



## Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 14 — Retirement Benefits

in Operating and maintenance expense and Property, plant and equipment, net on their consolidated financial statements.

<table><tr><td>For the Years Ended December 31,</td><td>Exelon</td><td>Generation(a)</td><td>ComEd</td><td>PECO</td><td>BGE</td><td>PHI</td><td>Pepco</td><td>DPL</td><td>ACE</td></tr><tr><td>2019</td><td>$ 442</td><td>$ 135</td><td>$ 96</td><td>$ 12</td><td>$ 61</td><td>$ 95</td><td>$ 25</td><td>$ 15</td><td>$ 16</td></tr><tr><td>2018</td><td>583</td><td>204</td><td>177</td><td>18</td><td>60</td><td>67</td><td>15</td><td>6</td><td>12</td></tr><tr><td>2017</td><td>643</td><td>227</td><td>176</td><td>29</td><td>64</td><td>94</td><td>25</td><td>13</td><td>13</td></tr></table>

(a) FitzPatrick net benefit costs are included for the period after acquisition.

## Components of AOCI and Regulatory Assets

Exelon recognizes the overfunded or underfunded status of defined benefit pension and OPEB plans as an asset or liability on its balance sheet, with offsetting entries to AOCI and regulatory assets (liabilities). A portion of current year actuarial gains and losses and prior service costs (credits) is capitalized within Exelon's Consolidated Balance Sheets to reflect the expected regulatory recovery of these amounts, which would otherwise be recorded to AOCI. The following tables provide the components of AOCI and regulatory assets (liabilities) for Exelon for the years ended December 31, 2019, 2018 and 2017 for all plans combined.

<table><tr><td rowspan="2"></td><td colspan="4">Pension Benefits</td><td colspan="4">OPEB</td></tr><tr><td>2019</td><td>2018</td><td>2017</td><td>2019</td><td>2018</td><td>2017</td><td></td><td></td></tr><tr><td>Changes in plan assets and benefit obligations recognized in AOCI and regulatory assets (liabilities):</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Current year actuarial (gain) loss</td><td>$ 538</td><td>$ 635</td><td>$ (222)</td><td>$ 80</td><td>$ (232)</td><td>$ 166</td><td></td><td></td></tr><tr><td>Amortization of actuarial loss</td><td>(414)</td><td>(629)</td><td>(607)</td><td>(45)</td><td>(66)</td><td>(61)</td><td></td><td></td></tr><tr><td>Current year prior service cost (credit)</td><td>68</td><td>(4)</td><td>9</td><td>—</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Amortization of prior service (cost) credit</td><td>—</td><td>(2)</td><td>(1)</td><td>179</td><td>186</td><td>188</td><td></td><td></td></tr><tr><td>Curtailments</td><td>(3)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Settlements</td><td>(17)</td><td>(3)</td><td>(3)</td><td>(1)</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Total recognized in AOCI and regulatory assets (liabilities)</td><td>$ 172</td><td>$ (3)</td><td>$ (824)</td><td>$ 213</td><td>$ (112)</td><td>$ 293</td><td></td><td></td></tr><tr><td>Total recognized in AOCI</td><td>$ 169</td><td>$ 3</td><td>$ (401)</td><td>$ 107</td><td>$ (55)</td><td>$ 168</td><td></td><td></td></tr><tr><td>Total recognized in regulatory assets (liabilities)</td><td>$ 3</td><td>$ (6)</td><td>$ (423)</td><td>$ 106</td><td>$ (57)</td><td>$ 125</td><td></td><td></td></tr></table>



## Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 14 — Retirement Benefits

The following table provides the components of gross accumulated other comprehensive loss and regulatory assets (liabilities) for Exelon that have not been recognized as components of periodic benefit cost at December 31, 2019 and 2018, respectively, for all plans combined:

<table><tr><td rowspan="2"></td><td colspan="3">Pension Benefits</td><td colspan="3">OPEB</td></tr><tr><td colspan="2">2019</td><td colspan="2">2018</td><td>2019</td><td>2018</td></tr><tr><td>Prior service (credit) cost</td><td>$     39</td><td>$      (29)</td><td>$      (158)</td><td>$      (337)</td><td></td><td></td></tr><tr><td>Actuarial loss</td><td colspan="2">7,662</td><td colspan="2">7,558</td><td>565</td><td>531</td></tr><tr><td>Total</td><td>$     7,701</td><td>$     7,529</td><td>$     407</td><td>$     194</td><td></td><td></td></tr><tr><td>Total included in AOCI</td><td>$     4,068</td><td>$     3,899</td><td>$     177</td><td>$     70</td><td></td><td></td></tr><tr><td>Total included in regulatory assets (liabilities)</td><td>$     3,633</td><td>$     3,630</td><td>$     230</td><td>$     124</td><td></td><td></td></tr></table>

## Average Remaining Service Period

For pension benefits, Exelon amortizes its unrecognized prior service costs and certain actuarial gains and losses, as applicable, based on participants' average remaining service periods.

For OPEB, Exelon amortizes its unrecognized prior service costs over participants' average remaining service period to benefit eligibility age and amortizes certain actuarial gains and losses over participants' average remaining service period to expected retirement. The resulting average remaining service periods for pension and OPEB were as follows:

<table><tr><td></td><td>2019</td><td>2018</td><td>2017</td></tr><tr><td>Pension plans</td><td>11.7</td><td>12.0</td><td>11.8</td></tr><tr><td>OPEB plans:</td><td></td><td></td><td></td></tr><tr><td>Benefit Eligibility Age</td><td>8.7</td><td>8.8</td><td>8.8</td></tr><tr><td>Expected Retirement</td><td>9.3</td><td>9.5</td><td>9.6</td></tr></table>

## Assumptions

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

Expected Rate of Return. In selecting the EROA, Exelon considers historical economic indicators (including inflation and GDP growth) that impact asset returns, as well as expectations regarding future long-term capital market performance, weighted by Exelon’s target asset class allocations.

Mortality. The mortality assumption is composed of a base table that represents the current expectation of life expectancy of the population adjusted by an improvement scale that attempts to anticipate future improvements in life expectancy. For the year ended December 31, 2018, Exelon's mortality assumption was supported by an actuarial experience study of Exelon's plan participants and utilized the IRS's RP-2000 base table projected to 2012 with improvement scale AA and projected thereafter with generational improvement scale BB two-dimensional adjusted to a 0.75% long-term rate reached in 2027. For the year ended December 31, 2019, Exelon's mortality assumption utilizes the Society of Actuaries' 2019 base table (Pri-2012) and MP-2019 improvement scale adjusted to a 0.75% long-term rate reached in 2035.

For Exelon, the following assumptions were used to determine the benefit obligations for the plans at December 31, 2019 and 2018. Assumptions used to determine year-end benefit obligations are the assumptions used to estimate the subsequent year's net periodic benefit costs.



## Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 14 — Retirement Benefits

<table><tr><td rowspan="2"></td><td colspan="3">Pension Benefits</td><td colspan="3">OPEB</td></tr><tr><td colspan="2">2019</td><td colspan="2">2018</td><td>2019</td><td>2018</td></tr><tr><td>Discount rate</td><td>3.34%</td><td>(a)</td><td>4.31%</td><td>(a)</td><td>3.31%</td><td>(a)</td></tr><tr><td>Investment Crediting Rate</td><td>3.82%</td><td>(b)</td><td>4.46%</td><td>(b)</td><td>N/A</td><td>N/A</td></tr><tr><td>Rate of compensation increase</td><td></td><td>(c)</td><td></td><td>(c)</td><td></td><td>(c)</td></tr><tr><td></td><td></td><td></td><td>RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)</td><td></td><td></td><td>RP-2000 table projected to 2012 with improvement scale AAA, with Scale BB-2D improvements (adjusted)</td></tr><tr><td>Mortality table</td><td></td><td>Pri-2012 table with MP-2019 improvement scale (adjusted)</td><td></td><td></td><td>Pri-2012 table with MP-2019 improvement scale (adjusted)</td><td></td></tr><tr><td>Health care cost trend on covered charges</td><td>N/A</td><td></td><td>N/A</td><td></td><td>5.00% with ultimate trend of 5.00% in 2017</td><td>5.00% with ultimate trend of 5.00% in 2017</td></tr></table>

(a) The discount rates above represent the blended rates used to determine the majority of Exelon's pension and OPEB obligations. Certain benefit plans used individual rates, which range from 3.02% - 3.44% and 3.27% - 3.4% for pension and OPEB plans, respectively, as of December 31, 2019 and 4.13% - 4.36% and 4.27% - 4.38% for pension and OPEB plans, respectively, as of December 31, 2018.

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

(c) 3.25% through 2019 and 3.75% thereafter.

The following assumptions were used to determine the net periodic benefit cost for Exelon for the years ended December 31, 2019, 2018 and 2017:

<table><tr><td rowspan="2">Exelon</td><td colspan="4">Pension Benefits</td><td colspan="4">Other Postretirement Benefits</td></tr><tr><td colspan="2">2019</td><td colspan="2">2018</td><td>2017</td><td colspan="2">2019</td><td>2018</td></tr><tr><td>Discount rate</td><td>4.31%</td><td>(a)</td><td>3.62%</td><td>(a)</td><td>4.04%</td><td>(a)</td><td>4.30%</td><td>(a)</td></tr><tr><td>Investment Crediting Rate</td><td>4.46%</td><td>(b)</td><td>4.00%</td><td>(b)</td><td>4.46%</td><td>(b)</td><td>N/A</td><td>N/A</td></tr><tr><td>Expected return on plan assets</td><td>7.00%</td><td>(c)</td><td>7.00%</td><td>(c)</td><td>7.00%</td><td>(c</td><td>6.67%</td><td>(c)</td></tr><tr><td>Rate of compensation increase</td><td></td><td>(d)</td><td></td><td>(d)</td><td></td><td>(e)</td><td></td><td>(d)</td></tr><tr><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td>RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)</td><td></td><td>RP-2000 table projected to 2012 with improvement scale AA, with scale BB-2D improvements (adjusted)</td><td></td><td>RP-2000 table projected to2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)</td><td></td><td>RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)</td><td></td></tr><tr><td>Mortality table</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr></table>

(a) The discount rates above represent the blended rates used to establish the majority of Exelon's pension and OPEB costs. Certain benefit plans used individual rates, which range from 4.13%-4.36% and 4.27%-4.38% for pension and OPEB plans, respectively, for the year ended December 31, 2019; 3.49%-3.65% and 3.57%-3.68% for pension and OPEB plans; respectively, for the year ended December 31, 2018; and 3.66%-4.11% and 4.00%-4.17% for pension and OPEB plans, respectively, for the year ended December 31, 2017.

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

(c) Not applicable to pension and other postretirement benefit plans that do not have plan assets.

(d) 3.25% through 2019 and 3.75% thereafter.

(e) The legacy Exelon, CEG and CENG pension and other postretirement plans used a rate of compensation increase of 3.25% through 2019 and 3.75% thereafter, while the legacy PHI pension and OPEB plans used a weighted-average rate of compensation increase of 5% for all periods.



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

## Contributions

Exelon allocates contributions related to its legacy Exelon pension and OPEB plans to its subsidiaries based on accounting cost. For legacy CEG, CENG, FitzPatrick, and PHI plans, pension and OPEB contributions are allocated to the subsidiaries based on employee participation (both active and retired). The following tables provide contributions to the pension and OPEB plans:

<table><tr><td rowspan="2"></td><td colspan="4">Pension Benefits</td><td colspan="4">OPEB</td></tr><tr><td>2019(a)</td><td colspan="2">2018(a)</td><td>2017(a)</td><td colspan="2">2019</td><td>2018</td><td>2017</td></tr><tr><td>Exelon</td><td>$     356</td><td>$     337</td><td>$     341</td><td>$     51</td><td>$     46</td><td>$     64</td><td></td><td></td></tr><tr><td>Generation</td><td>160</td><td>128</td><td>137</td><td>15</td><td>11</td><td>11</td><td></td><td></td></tr><tr><td>ComEd</td><td>72</td><td>38</td><td>36</td><td>5</td><td>4</td><td>5</td><td></td><td></td></tr><tr><td>PECO</td><td>27</td><td>28</td><td>24</td><td>1</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>BGE</td><td>34</td><td>40</td><td>39</td><td>14</td><td>14</td><td>14</td><td></td><td></td></tr><tr><td>PHI</td><td>10</td><td>62</td><td>67</td><td>15</td><td>12</td><td>32</td><td></td><td></td></tr><tr><td>Pepco</td><td>2</td><td>6</td><td>62</td><td>12</td><td>11</td><td>10</td><td></td><td></td></tr><tr><td>DPL</td><td>1</td><td>—</td><td>—</td><td>—</td><td>—</td><td>2</td><td></td><td></td></tr><tr><td>ACE</td><td>—</td><td>6</td><td>—</td><td>1</td><td>—</td><td>20</td><td></td><td></td></tr></table>

(a) Exelon’s and Generation’s pension contributions include $21 million related to the legacy CENG plans that was funded by CENG as provided in an Employee Matters Agreement (EMA) between Exelon and CENG for the year ended December 31, 2017. There were no pension contributions for the years ended December 31, 2019 and 2018.

Management considers 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 of 2006 (the Act), management of the pension obligation and regulatory implications. The Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification). The projected contributions below reflect a funding strategy to make levelized annual contributions with the objective of achieving 100% funded status on an ABO basis over time. This level funding strategy helps minimize volatility of future period required pension contributions. Based on this funding strategy and current market conditions, which are subject to change, Exelon’s estimated annual qualified pension contributions will be approximately $500 million beginning in 2020. Unlike the qualified pension plans, Exelon’s non-qualified pension plans are not funded, given that they are not subject to statutory minimum contribution requirements.

While other postretirement plans are also not subject to statutory minimum contribution requirements, Exelon does fund certain of its plans. For Exelon's funded OPEB plans, contributions generally equal accounting costs, however, Exelon's management has historically considered several factors in determining the level of contributions to its OPEB plans, including liabilities management, levels of benefit claims paid and regulatory implications (amounts deemed prudent to meet regulatory expectations and best assure continued rate recovery). The amounts below include benefit payments related to unfunded plans.



The following table provides all registrants' planned contributions to the qualified pension plans, planned benefit payments to non-qualified pension plans, and planned contributions to other postretirement plans in 2020:

<table><tr><td></td><td colspan="2">Qualified Pension Plans</td><td colspan="2">Non-Qualified Pension Plans</td><td colspan="2">OPEB</td></tr><tr><td>Exelon</td><td>$</td><td>505</td><td>$</td><td>36</td><td>$</td><td>42</td></tr><tr><td>Generation</td><td></td><td>227</td><td></td><td>14</td><td></td><td>16</td></tr><tr><td>ComEd</td><td></td><td>141</td><td></td><td>2</td><td></td><td>3</td></tr><tr><td>PECO</td><td></td><td>17</td><td></td><td>1</td><td></td><td>—</td></tr><tr><td>BGE</td><td></td><td>56</td><td></td><td>2</td><td></td><td>16</td></tr><tr><td>PHI</td><td></td><td>22</td><td></td><td>9</td><td></td><td>7</td></tr><tr><td>Pepco</td><td></td><td>—</td><td></td><td>2</td><td></td><td>7</td></tr><tr><td>DPL</td><td></td><td>—</td><td></td><td>1</td><td></td><td>—</td></tr><tr><td>ACE</td><td></td><td>2</td><td></td><td>—</td><td></td><td>—</td></tr></table>

## Estimated Future Benefit Payments

Estimated future benefit payments to participants in all of the pension plans and postretirement benefit plans at December 31, 2019 were:

<table><tr><td></td><td>Pension Benefits</td><td>OPEB</td></tr><tr><td>2020</td><td>$ 1,227</td><td>$ 258</td></tr><tr><td>2021</td><td></td><td>1,252</td></tr><tr><td>2022</td><td></td><td>1,295</td></tr><tr><td>2023</td><td></td><td>1,310</td></tr><tr><td>2024</td><td></td><td>1,324</td></tr><tr><td>2025 through 2029</td><td></td><td>6,770</td></tr><tr><td>Total estimated future benefit payments through 2029</td><td>$ 13,178</td><td>$ 2,735</td></tr></table>

## Plan Assets

Investment Strategy. On a regular basis, Exelon evaluates its investment strategy to ensure that plan assets will be sufficient to pay plan benefits when due. As part of this ongoing evaluation, Exelon may make changes to its targeted asset allocation and investment strategy.

Exelon has developed and implemented a liability hedging investment strategy for its qualified pension plans that has reduced the volatility of its pension assets relative to its pension liabilities. Exelon is likely to continue to gradually increase the liability hedging portfolio as the funded status of its plans improves. The overall objective is to achieve attractive risk-adjusted returns that will balance the liquidity requirements of the plans' liabilities while striving to minimize the risk of significant losses. Trust assets for Exelon's other postretirement plans are managed in a diversified investment strategy that prioritizes maximizing liquidity and returns while minimizing asset volatility.

Actual asset returns have an impact on the costs reported for the Exelon-sponsored pension and OPEB plans. The actual asset returns across Exelon's pension and OPEB plans for the year ended December 31, 2019 were 18.80% and 14.40%, respectively, compared to an expected long-term return assumption of 7.00% and 6.67%, respectively. Exelon used an EROA of 7.00% and 6.69% to estimate its 2020 pension and OPEB costs, respectively.

Exelon’s pension and OPEB plan target asset allocations at December 31, 2019 and 2018 were as follows:



## Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 14 — Retirement Benefits

<table><tr><td rowspan="2">Asset Category</td><td colspan="2">December 31, 2019</td><td colspan="2">December 31, 2018</td></tr><tr><td>Pension Benefits</td><td>OPEB</td><td>Pension Benefits</td><td>OPEB</td></tr><tr><td>Equity securities</td><td>33%</td><td>46%</td><td>35%</td><td>47%</td></tr><tr><td>Fixed income securities</td><td>44%</td><td>32%</td><td>37%</td><td>28%</td></tr><tr><td>Alternative investments \( ^{(a)} \)</td><td>23%</td><td>22%</td><td>28%</td><td>25%</td></tr><tr><td>Total</td><td>100%</td><td>100%</td><td>100%</td><td>100%</td></tr></table>

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

Concentrations of Credit Risk. Exelon evaluated its pension and OPEB plans' asset portfolios for the existence of significant concentrations of credit risk as of December 31, 2019. Types of concentrations that were evaluated include, but are not limited to, investment concentrations in a single entity, type of industry, foreign country, and individual fund. As of December 31, 2019, there were no significant concentrations (defined as greater than 10% of plan assets) of risk in Exelon's pension and OPEB plan assets.

## Fair Value Measurements

The following tables present pension and OPEB plan assets measured and recorded at fair value in Exelon's Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy at December 31, 2019 and 2018:

<table><tr><td>December 31, 2019(a)</td><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Not subject to leveling</td><td>Total</td></tr><tr><td>Pension plan assets</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Cash equivalents</td><td>$ 258</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ 258</td></tr><tr><td>Equities(b)</td><td>3,616</td><td>—</td><td>5</td><td>2,589</td><td>6,210</td></tr><tr><td>Fixed income:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>U.S. Treasury and agencies</td><td>1,294</td><td>280</td><td>—</td><td>—</td><td>1,574</td></tr><tr><td>State and municipal debt</td><td>—</td><td>56</td><td>—</td><td>—</td><td>56</td></tr><tr><td>Corporate debt</td><td>—</td><td>4,342</td><td>245</td><td>—</td><td>4,587</td></tr><tr><td>Other(b)</td><td>—</td><td>461</td><td>—</td><td>851</td><td>1,312</td></tr><tr><td>Fixed income subtotal</td><td>1,294</td><td>5,139</td><td>245</td><td>851</td><td>7,529</td></tr><tr><td>Private equity</td><td>—</td><td>—</td><td>—</td><td>1,391</td><td>1,391</td></tr><tr><td>Hedge funds</td><td>—</td><td>—</td><td>—</td><td>1,126</td><td>1,126</td></tr><tr><td>Real estate</td><td>—</td><td>—</td><td>—</td><td>1,030</td><td>1,030</td></tr><tr><td>Private credit</td><td>—</td><td>—</td><td>237</td><td>929</td><td>1,166</td></tr><tr><td>Pension plan assets subtotal</td><td>$ 5,168</td><td>$ 5,139</td><td>$ 487</td><td>$ 7,916</td><td>$ 18,710</td></tr></table>



## Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 14 — Retirement Benefits

<table><tr><td>December 31, 2019(a)</td><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Not subject to leveling</td><td>Total</td></tr><tr><td>OPEB plan assets</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Cash equivalents</td><td>$ 39</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ 39</td></tr><tr><td>Equities</td><td>473</td><td>3</td><td>—</td><td>719</td><td>1,195</td></tr><tr><td>Fixed income:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>U.S. Treasury and agencies</td><td>17</td><td>64</td><td>—</td><td>—</td><td>81</td></tr><tr><td>State and municipal debt</td><td>—</td><td>107</td><td>—</td><td>—</td><td>107</td></tr><tr><td>Corporate debt</td><td>—</td><td>49</td><td>—</td><td>—</td><td>49</td></tr><tr><td>Other</td><td>258</td><td>78</td><td>—</td><td>201</td><td>537</td></tr><tr><td>Fixed income subtotal</td><td>275</td><td>298</td><td>—</td><td>201</td><td>774</td></tr><tr><td>Hedge funds</td><td>—</td><td>—</td><td>—</td><td>293</td><td>293</td></tr><tr><td>Real estate</td><td>—</td><td>—</td><td>—</td><td>109</td><td>109</td></tr><tr><td>Private credit</td><td>—</td><td>—</td><td>—</td><td>131</td><td>131</td></tr><tr><td>OPEB plan assets subtotal</td><td>$ 787</td><td>$ 301</td><td>$ —</td><td>$ 1,453</td><td>$ 2,541</td></tr><tr><td>Total pension and OPEB plan assets(c)</td><td>$ 5,955</td><td>$ 5,440</td><td>$ 487</td><td>$ 9,369</td><td>$ 21,251</td></tr><tr><td>December 31, 2018(a)</td><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Not subject to leveling</td><td>Total</td></tr><tr><td>Pension plan assets</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Cash equivalents</td><td>$ 350</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ 350</td></tr><tr><td>Equities(b)</td><td>3,364</td><td>—</td><td>2</td><td>1,980</td><td>5,346</td></tr><tr><td>Fixed income:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>U.S. Treasury and agencies</td><td>996</td><td>173</td><td>—</td><td>—</td><td>1,169</td></tr><tr><td>State and municipal debt</td><td>—</td><td>59</td><td>—</td><td>—</td><td>59</td></tr><tr><td>Corporate debt</td><td>—</td><td>3,716</td><td>216</td><td>—</td><td>3,932</td></tr><tr><td>Other(b)</td><td>—</td><td>329</td><td>—</td><td>613</td><td>942</td></tr><tr><td>Fixed income subtotal</td><td>996</td><td>4,277</td><td>216</td><td>613</td><td>6,102</td></tr><tr><td>Private equity</td><td>—</td><td>—</td><td>—</td><td>1,219</td><td>1,219</td></tr><tr><td>Hedge funds</td><td>—</td><td>—</td><td>—</td><td>1,608</td><td>1,608</td></tr><tr><td>Real estate</td><td>—</td><td>—</td><td>—</td><td>1,029</td><td>1,029</td></tr><tr><td>Private credit</td><td>—</td><td>—</td><td>268</td><td>798</td><td>1,066</td></tr><tr><td>Pension plan assets subtotal</td><td>$ 4,710</td><td>$ 4,277</td><td>$ 486</td><td>$ 7,247</td><td>$ 16,720</td></tr></table>



## Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 14 — Retirement Benefits

<table><tr><td>December 31, 2018(a)</td><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Not subject to leveling</td><td>Total</td></tr><tr><td>OPEB plan assets</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Cash equivalents</td><td>$ 22</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ 22</td></tr><tr><td>Equities</td><td>537</td><td>2</td><td>—</td><td>508</td><td>1,047</td></tr><tr><td>Fixed income:</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>U.S. Treasury and agencies</td><td>11</td><td>56</td><td>—</td><td>—</td><td>67</td></tr><tr><td>State and municipal debt</td><td>—</td><td>126</td><td>—</td><td>—</td><td>126</td></tr><tr><td>Corporate debt</td><td>—</td><td>48</td><td>—</td><td>—</td><td>48</td></tr><tr><td>Other</td><td>183</td><td>72</td><td>—</td><td>170</td><td>425</td></tr><tr><td>Fixed income subtotal</td><td>194</td><td>302</td><td>—</td><td>170</td><td>666</td></tr><tr><td>Hedge funds</td><td>—</td><td>—</td><td>—</td><td>411</td><td>411</td></tr><tr><td>Real estate</td><td>—</td><td>—</td><td>—</td><td>132</td><td>132</td></tr><tr><td>Private credit</td><td>—</td><td>—</td><td>—</td><td>132</td><td>132</td></tr><tr><td>OPEB plan assets subtotal</td><td>$ 753</td><td>$ 304</td><td>$ —</td><td>$ 1,353</td><td>$ 2,410</td></tr><tr><td>Total pension and OPEB plan assets(c)</td><td>$ 5,463</td><td>$ 4,581</td><td>$ 486</td><td>$ 8,600</td><td>$ 19,130</td></tr></table>

(a) See Note 17—Fair Value of Financial Assets and Liabilities for a description of levels within the fair value hierarchy.

(b) Includes derivative instruments of $2 million and less than $1 million, which have a total notional amount of $6,668 million and $5,991 million at December 31, 2019 and 2018, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do not represent the amount of the company's exposure to credit or market loss.

(c) Excludes net liabilities of $120 million and $44 million at December 31, 2019 and 2018, respectively, which are required to reconcile to the fair value of net plan assets. These items consist primarily of receivables or payables related to pending securities sales and purchases, interest and dividends receivable.

The following table presents the reconciliation of Level 3 assets and liabilities for Exelon measured at fair value for pension and OPEB plans for the years ended December 31, 2019 and 2018:

<table><tr><td></td><td>Fixed Income</td><td>Equities</td><td>Private Credit</td><td>Total</td></tr><tr><td>Pension Assets</td><td></td><td></td><td></td><td></td></tr><tr><td>Balance as of January 1, 2019</td><td>$ 216</td><td>$ 2</td><td>$ 268</td><td>$ 486</td></tr><tr><td>Actual return on plan assets:</td><td></td><td></td><td></td><td></td></tr><tr><td>Relating to assets still held at the reporting date</td><td>28</td><td>3</td><td>28</td><td>59</td></tr><tr><td>Relating to assets sold during the period</td><td>(7)</td><td>—</td><td>—</td><td>(7)</td></tr><tr><td>Purchases, sales and settlements:</td><td></td><td></td><td></td><td></td></tr><tr><td>Purchases</td><td>26</td><td>—</td><td>41</td><td>67</td></tr><tr><td>Sales</td><td>(4)</td><td>—</td><td>—</td><td>(4)</td></tr><tr><td>Settlements(a)</td><td>(2)</td><td>—</td><td>(100)</td><td>(102)</td></tr><tr><td>Transfers out of Level 3</td><td>(12)</td><td>—</td><td>—</td><td>(12)</td></tr><tr><td>Balance as of December 31, 2019</td><td>$ 245</td><td>$ 5</td><td>$ 237</td><td>$ 487</td></tr></table>



## Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 14 — Retirement Benefits

<table><tr><td></td><td>Fixed income</td><td>Equities</td><td>Private Credit</td><td>Total</td></tr><tr><td>Pension Assets</td><td></td><td></td><td></td><td></td></tr><tr><td>Balance as of January 1, 2018</td><td>$ 232</td><td>$ 2</td><td>$ 224</td><td>$ 458</td></tr><tr><td>Actual return on plan assets:</td><td></td><td></td><td></td><td></td></tr><tr><td>Relating to assets still held at the reporting date</td><td>(14)</td><td>—</td><td>9</td><td>(5)</td></tr><tr><td>Relating to assets sold during the period</td><td>(1)</td><td>—</td><td>—</td><td>(1)</td></tr><tr><td>Purchases, sales and settlements:</td><td></td><td></td><td></td><td></td></tr><tr><td>Purchases</td><td>19</td><td>—</td><td>35</td><td>54</td></tr><tr><td>Sales</td><td>(8)</td><td>—</td><td>—</td><td>(8)</td></tr><tr><td>Settlements(a)</td><td>(12)</td><td>—</td><td>—</td><td>(12)</td></tr><tr><td>Balance as of December 31, 2018</td><td>$ 216</td><td>$ 2</td><td>$ 268</td><td>$ 486</td></tr></table>

(a) Represents cash settlements only.

There were no significant transfers between Level 1 and Level 2 during the year ended December 31, 2019 for the pension and OPEB plan assets.

## Valuation Techniques Used to Determine Fair Value

The techniques used to fair value the pension and OPEB assets invested in cash equivalents, equities, fixed income, derivatives, private equity, real estate, and private credit investments are the same as the valuation techniques for these types of investments in NDTFs. See Cash Equivalents and NDT Fund Investments in Note 17 - Fair Value of Financial Assets and Liabilities for further information.

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

## Defined Contribution Savings Plan (All Registrants)

The Registrants participate in various 401(k) defined contribution savings plans that are sponsored by Exelon. The plans are qualified under applicable sections of the IRC and allow employees to contribute a portion of their pre-tax and/or after-tax income in accordance with specified guidelines. All Registrants match a percentage of the employee contributions up to certain limits. The following table presents matching contributions to the savings plan for the years ended December 31, 2019, 2018 and 2017:

<table><tr><td>For the Year Ended December 31,</td><td>Exelon</td><td>Generation</td><td>ComEd</td><td>PECO</td><td>BGE</td><td>PHI</td><td>Pepco</td><td>DPL</td><td>ACE</td></tr><tr><td>2019</td><td>$ 161</td><td>$ 73</td><td>$ 35</td><td>$ 11</td><td>$ 12</td><td>13</td><td>$ 3</td><td>$ 3</td><td>$ 2</td></tr><tr><td>2018</td><td>179</td><td>86</td><td>37</td><td>9</td><td>12</td><td>13</td><td>3</td><td>2</td><td>2</td></tr><tr><td>2017</td><td>128</td><td>55</td><td>31</td><td>10</td><td>10</td><td>13</td><td>3</td><td>2</td><td>2</td></tr></table>

## 15. Derivative Financial Instruments (All Registrants)

The Registrants 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



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 15 — Derivative Financial Instruments

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 economic hedges related to commodities, referred to as economic hedges, are recorded at fair value through earnings at Generation and are offset by a corresponding regulatory asset or liability at ComEd. For all NPNS derivative instruments, accounts receivable or accounts payable are recorded when derivative settles and revenue or expense is recognized in earnings as the underlying physical commodity is sold or consumed.

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 referencing 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 that present fair value balances, Generation’s 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.

Generation’s and ComEd’s use of cash collateral is generally unrestricted unless Generation or ComEd are downgraded below investment grade. Cash collateral held by PECO, BGE, Pepco, DPL and ACE must be deposited in an unaffiliated major U.S. commercial bank or foreign bank with a U.S. branch office that meet certain qualifications.

## Commodity Price Risk (All Registrants)

Each of the Registrants employ established policies and procedures to manage their 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 commodity products. The Registrants believe these instruments, which are either determined to be non-derivative or classified as economic hedges, mitigate exposure to fluctuations in commodity prices.

Generation. To the extent the amount of energy Generation produces differs from the amount of energy it has contracted to sell, Exelon and Generation are exposed to market fluctuations in the prices of electricity, fossil fuels and other commodities. Within Exelon, Generation has the most exposure to commodity price risk. As such, Generation uses a variety of derivative and non-derivative instruments to manage the commodity price risk of its 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, Generation 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. Generation is also exposed to differences between the locational settlement prices of certain economic hedges and the hedged generating units. This price difference is actively managed through other instruments which include derivative congestion products, whose changes in fair value are recognized in earnings each period, and auction revenue rights, which are accounted for on an accrual basis.

Additionally, Generation is exposed to certain market risks through its proprietary trading activities. The proprietary trading activities are a complement to Generation’s energy marketing portfolio but represent a small portion of Generation’s overall energy marketing activities and are subject to limits established by Exelon’s RMC.



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 15 — Derivative Financial Instruments

Utility Registrants. The Utility Registrants procure electric and natural gas supply through a competitive procurement process approved by each of the respective state utility commissions. The Utility Registrants' hedging programs are intended to reduce exposure to energy and natural gas price volatility and have no direct earnings impact as the costs are fully recovered from customers through regulatory-approved recovery mechanisms. The following table provides a summary of the Utility Registrants' primary derivative hedging instruments, listed by commodity and accounting treatment.

<table><tr><td>Registrant</td><td>Commodity</td><td>Accounting Treatment</td><td>Hedging instrument</td></tr><tr><td rowspan="2">ComEd</td><td>Electricity</td><td>NPNS</td><td>Fixed price contracts based on all requirements in the IPA procurement plans.</td></tr><tr><td>Electricity</td><td>Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability \( ^{(a)} \)</td><td>20-year floating-to-fixed energy swap contracts beginning June 2012 based on the renewable energy resource procurement requirements in the Illinois Settlement Legislation of approximately 1.3 million MWh&#x27;s per year.</td></tr><tr><td>PECO \( ^{(b)} \)</td><td>Gas</td><td>NPNS</td><td>Fixed price contracts to cover about 20% of planned natural gas purchases in support of projected firm sales.</td></tr><tr><td rowspan="2">Pepco</td><td>Electricity</td><td>NPNS</td><td>Fixed price contracts for all SOS requirements through full requirements contracts.</td></tr><tr><td>Electricity</td><td>NPNS</td><td>Fixed price contracts for between 10-20% of forecasted system supply requirements for flowing (i.e., non-storage) gas for the November through March period.</td></tr><tr><td>BGE</td><td>Gas</td><td>NPNS</td><td>Fixed price contracts for all SOS requirements through full requirements contracts.</td></tr><tr><td rowspan="2">Pepco</td><td>Electricity</td><td>NPNS</td><td>Fixed price contracts for all SOS requirements through full requirements contracts.</td></tr><tr><td>Electricity</td><td>NPNS</td><td>Fixed price contracts through full requirements contracts.</td></tr><tr><td>DPL</td><td>Gas</td><td>Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability \( ^{(c)} \)</td><td>Exchange traded future contracts for 50% of estimated monthly purchase requirements each month, including purchases for storage injections.</td></tr><tr><td>ACE</td><td>Electricity</td><td>NPNS</td><td>Fixed price contracts for all BGS requirements through full requirements contracts.</td></tr></table>

(a) See Note 3 - Regulatory Matters for additional information.

(b) As part of its hedging program, PECO enters into electric supply procurement contracts that do not meet the definition of a derivative instrument.

(c) The fair value of the DPL economic hedge is not material as of December 31, 2019 and 2018 and is not presented in the fair value tables below.



## Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 15 — Derivative Financial Instruments

The following table provides a summary of the derivative fair value balances recorded by Exelon, Generation and ComEd as of December 31, 2019 and 2018:

<table><tr><td rowspan="2">December 31, 2019</td><td colspan="2">Exelon</td><td colspan="6">Generation</td><td colspan="2">ComEd</td></tr><tr><td>Total Derivatives</td><td>Economic Hedges</td><td>Proprietary Trading</td><td>Collateral (a)(b)</td><td>Netting(a)</td><td>Subtotal</td><td>Economic Hedges</td><td></td><td></td><td></td></tr><tr><td>Mark-to-market derivative assets (current assets)</td><td>$     675</td><td>$     3,506</td><td>$     72</td><td>$     287</td><td>$     3,190</td><td>$     675</td><td>$     </td><td>—</td><td></td><td></td></tr><tr><td>Mark-to-market derivative assets (noncurrent assets)</td><td>508</td><td>1,238</td><td>25</td><td>122</td><td>(877)</td><td>508</td><td>—</td><td></td><td></td><td></td></tr><tr><td>Total mark-to-market derivative assets</td><td>1,183</td><td>4,744</td><td>97</td><td>409</td><td>(4,067)</td><td>1,183</td><td>—</td><td></td><td></td><td></td></tr><tr><td>Mark-to-market derivative liabilities (current liabilities)</td><td>(236)</td><td>(3,713)</td><td>(38)</td><td>357</td><td>3,190</td><td>(204)</td><td>(32)</td><td></td><td></td><td></td></tr><tr><td>Mark-to-market derivative liabilities (noncurrent liabilities)</td><td>(380)</td><td>(1,140)</td><td>(11)</td><td>163</td><td>877</td><td>(111)</td><td>(269)</td><td></td><td></td><td></td></tr><tr><td>Total mark-to-market derivative liabilities</td><td>(616)</td><td>(4,853)</td><td>(49)</td><td>520</td><td>4,067</td><td>(315)</td><td>(301)</td><td></td><td></td><td></td></tr><tr><td>Total mark-to-market derivative net assets (liabilities)</td><td>$     567</td><td>$     109</td><td>$     48</td><td>$     929</td><td>$     </td><td>—</td><td>$     868</td><td>$     </td><td>(301)</td><td></td></tr></table>

<table><tr><td>Mark-to-market derivative assets (current assets)</td><td>$     801</td><td>$     3,505</td><td>$     105</td><td>$     121</td><td>$     2,930</td><td>$     801</td><td>$     </td><td>—</td></tr><tr><td>Mark-to-market derivative assets (noncurrent assets)</td><td>445</td><td>1,266</td><td>41</td><td>51</td><td>(913)</td><td>445</td><td>—</td><td></td></tr><tr><td>Total mark-to-market derivative assets</td><td>1,246</td><td>4,771</td><td>146</td><td>172</td><td>(3,843)</td><td>1,246</td><td>—</td><td></td></tr><tr><td>Mark-to-market derivative liabilities (current liabilities)</td><td>(473)</td><td>(3,429)</td><td>(74)</td><td>125</td><td>2,931</td><td>(447)</td><td>(26)</td><td></td></tr><tr><td>Mark-to-market derivative liabilities (noncurrent liabilities)</td><td>(474)</td><td>(1,203)</td><td>(20)</td><td>60</td><td>912</td><td>(251)</td><td>(223)</td><td></td></tr><tr><td>Total mark-to-market derivative liabilities</td><td>(947)</td><td>(4,632)</td><td>(94)</td><td>185</td><td>3,843</td><td>(698)</td><td>(249)</td><td></td></tr><tr><td>Total mark-to-market derivative net assets (liabilities)</td><td>$     299</td><td>$     139</td><td>$     52</td><td>$     357</td><td>$     </td><td>—</td><td>$     548</td><td>$     </td></tr></table>

(a) Exelon and Generation net all available amounts allowed under the derivative authoritative guidance in the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, letters of credit and other forms of non-cash collateral. These amounts are immaterial and not reflected in the table above.

(b) Of the collateral posted/(received), $511 million and $(94) million represents variation margin on the exchanges at December 31, 2019 and 2018, respectively.



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 15 — Derivative Financial Instruments

## Economic Hedges (Commodity Price Risk)

Generation. For the years ended December 31, 2019, 2018 and 2017, Exelon and Generation 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.

<table><tr><td></td><td>2019</td><td colspan="2">2018</td><td colspan="2">2017</td></tr><tr><td>Income Statement Location</td><td></td><td colspan="4">Gain (Loss)</td></tr><tr><td>Operating revenues</td><td>$ —</td><td>$ (270)</td><td>$ (270)</td><td>$ (126)</td><td></td></tr><tr><td>Purchased power and fuel</td><td>(204)</td><td>(47)</td><td>(43)</td><td></td><td></td></tr><tr><td>Total Exelon and Generation</td><td>$ (204)</td><td>$ (317)</td><td>$ (169)</td><td></td><td></td></tr></table>

In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on Generation's owned and contracted generation positions that have not been hedged. Generation hedges commodity price risk on a ratable basis over three-year periods. As of December 31, 2019, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York and ERCOT reportable segments is 91%-94% and 61%-64% for 2020 and 2021, respectively.

## Proprietary Trading (Commodity Price Risk)

Generation also executes commodity derivatives for proprietary trading purposes. 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 Exelon's and Generation's 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 years ended December 31, 2019, 2018 and 2017, net pre-tax commodity mark-to-market gains (losses) for Exelon and Generation were not material. The Utility Registrants do not execute derivatives for proprietary trading purposes.

## Interest Rate and Foreign Exchange Risk (Exelon and Generation)

Exelon and Generation utilize interest rate swaps, which are treated as economic hedges, to manage their interest rate exposure. On July 1, 2018, Exelon designated its fair value hedges related to interest rate risk and Generation de-designated its cash flow hedges related to interest rate risk. The notional amounts were $1,269 million and $1,420 million at December 31, 2019 and 2018, respectively, for Exelon and $569 million and $620 million at December 31, 2019 and 2018, respectively, for Generation.

Generation utilizes foreign currency derivatives to manage foreign exchange rate exposure associated with international commodity purchases in currencies other than U.S. dollars, which are treated as economic hedges. The notional amounts were $231 million and $268 million at December 31, 2019 and 2018, respectively.

The mark-to-market derivative assets and liabilities as of December 31, 2019 and 2018 and the mark-to-market gains (losses) for the years ended December 31, 2019, 2018 and 2017 were not material for Exelon and Generation.

## Credit Risk (All Registrants)

The Registrants 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 at the reporting date.

Generation. For commodity derivatives, Generation enters into enabling agreements that allow for payment netting with its counterparties, which reduces Generation's 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 so, 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 allow for cross product netting. In addition to payment netting language in the enabling agreement, Generation's 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



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 15 — Derivative Financial Instruments

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 risk management capabilities. To the extent that a counterparty's margining thresholds are exceeded, the counterparty is required to post collateral with Generation as specified in each enabling agreement. Generation's 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 Generation’s credit exposure for all derivative instruments, NPNS and payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of December 31, 2019. 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 figures in the tables below exclude credit risk exposure from individual retail counterparties, nuclear fuel procurement contracts and exposure through RTOs, ISOs, NYMEX, ICE, NASDAQ, NGX and Nodal commodity exchanges.

<table><tr><td>Rating as of December 31, 2019</td><td>Total Exposure Before Credit Collateral</td><td>Credit Collateral(a)</td><td>Net Exposure</td><td>Number of Counterparties Greater than 10% of Net Exposure</td><td>Net Exposure of Counterparties Greater than 10% of Net Exposure</td></tr><tr><td>Investment grade</td><td>$ 877</td><td>$ 20</td><td>$ 857</td><td>—</td><td>$ —</td></tr><tr><td>Non-investment grade</td><td>79</td><td>63</td><td>16</td><td></td><td></td></tr><tr><td>No external ratings</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Internally rated — investment grade</td><td>218</td><td>—</td><td>218</td><td></td><td></td></tr><tr><td>Internally rated — non-investment grade</td><td>139</td><td>23</td><td>116</td><td></td><td></td></tr><tr><td>Total</td><td>$ 1,313</td><td>$ 106</td><td>$ 1,207</td><td>—</td><td>$ —</td></tr><tr><td>Net Credit Exposure by Type of Counterparty</td><td></td><td></td><td></td><td>As of December 31, 2019</td><td></td></tr><tr><td>Financial institutions</td><td></td><td></td><td></td><td>$ 9</td><td></td></tr><tr><td>Investor-owned utilities, marketers, power producers</td><td></td><td></td><td></td><td>930</td><td></td></tr><tr><td>Energy cooperatives and municipalities</td><td></td><td></td><td></td><td>235</td><td></td></tr><tr><td>Other</td><td></td><td></td><td></td><td>33</td><td></td></tr><tr><td>Total</td><td></td><td></td><td></td><td>$ 1,207</td><td></td></tr></table>

(a) As of December 31, 2019, credit collateral held from counterparties where Generation had credit exposure included $25 million of cash and $81 million of letters of credit. The credit collateral does not include non-liquid collateral.

Utility Registrants. The Utility Registrants have contracts to procure electric and natural gas supply that provide suppliers with a certain amount of unsecured credit. If the exposure on the supply contract exceeds the amount of unsecured credit, the suppliers may be required to post collateral. The net credit exposure is mitigated primarily by the ability to recover procurement costs through customer rates. As of December 31, 2019, the Utility Registrants' counterparty credit risk with suppliers was immaterial.

## Credit-Risk-Related Contingent Features (All Registrants)

Generation. As part of the normal course of business, Generation routinely enters into physically or financially settled contracts for the purchase and sale of electric capacity, electricity, fuels, emissions allowances and other energy-related products. Certain of Generation's derivative instruments contain provisions that require Generation to post collateral. Generation also enters 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 Generation's credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. These credit-risk related contingent features stipulate that if Generation were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it 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



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 15 — Derivative Financial Instruments

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, Generation believes an amount of several months of future payments (i.e., capacity payments) rather than a calculation of fair value is the best estimate for the contingent collateral obligation, which has been factored into the disclosure below.

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:

<table><tr><td rowspan="2">Credit-Risk Related Contingent Features</td><td colspan="3">As of December 31,</td></tr><tr><td>2019</td><td>2018</td><td></td></tr><tr><td>Gross fair value of derivative contracts containing this feature \( ^{(a)} \)</td><td>$ (956)</td><td>$ (1,723)</td><td></td></tr><tr><td>Offsetting fair value of in-the-money contracts under master netting arrangements \( ^{(b)} \)</td><td>649</td><td>1,105</td><td></td></tr><tr><td>Net fair value of derivative contracts containing this feature \( ^{(c)} \)</td><td>$ (307)</td><td>$ (618)</td><td></td></tr></table>

(a) Amount represents the gross fair value of out-of-the-money derivative contracts containing credit-risk-related contingent features ignoring the effects of master netting agreements.

(b) Amount represents the offsetting fair value of in-the-money derivative contracts under legally enforceable master netting agreements with the same counterparty, which reduces the amount of any liability for which a Registrant could potentially be required to post collateral.

(c) Amount represents the net fair value of out-of-the-money derivative contracts containing credit-risk related contingent features after considering the mitigating effects of offsetting positions under master netting arrangements and reflects the actual net liability upon which any potential contingent collateral obligations would be based.

As of December 31, 2019 and 2018, Exelon and Generation 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.

<table><tr><td rowspan="2"></td><td colspan="3">As of December 31,</td></tr><tr><td>2019</td><td>2018</td><td></td></tr><tr><td>Cash collateral posted</td><td>$ 982</td><td>$ 418</td><td></td></tr><tr><td>Letters of credit posted</td><td>264</td><td>367</td><td></td></tr><tr><td>Cash collateral held</td><td>103</td><td>47</td><td></td></tr><tr><td>Letters of credit held</td><td>112</td><td>44</td><td></td></tr><tr><td>Additional collateral required in the event of a credit downgrade below investment grade</td><td>1,509</td><td>2,104</td><td></td></tr></table>

Generation entered into supply forward contracts with certain utilities, including PECO and BGE, with one-sided collateral postings only from Generation. 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, counterparty suppliers, including Generation, are required to post collateral once certain unsecured credit limits are exceeded.

## Utility Registrants

The Utility Registrants' electric supply procurement contracts do not contain provisions that would require them to post collateral.

PECO's, BGE's, and DPL's natural gas procurement contracts contain provisions that could require PECO, BGE, and DPL to post collateral in the form of cash or credit support, which vary by contract and counterparty, with thresholds contingent upon PECO's, BGE, and DPL's credit rating. As of December 31, 2019, PECO, BGE, and DPL were not required to post collateral for any of these agreements. If PECO, BGE or DPL lost their investment grade credit rating as of December 31, 2019, they could have been required to post incremental collateral to its counterparties of $44 million, $50 million, and $11 million, respectively.



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 16 — Debt and Credit Agreements

## 16. Debt and Credit Agreements (All Registrants)

## Short-Term Borrowings

Exelon Corporate, ComEd and BGE meet their short-term liquidity requirements primarily through the issuance of commercial paper. Generation and PECO meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the Exelon intercompany money pool. Pepco, DPL, and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the PHI intercompany money pool. PHI Corporate meets its short-term liquidity requirements primarily through the issuance of short-term notes and the Exelon intercompany money pool. The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit.

## Commercial Paper

The following table reflects the Registrants' commercial paper programs supported by the revolving credit agreements and bilateral credit agreements at December 31, 2019 and 2018:

<table><tr><td></td><td colspan="2">Maximum Program Size at December 31,</td><td colspan="2">Outstanding Commercial Paper at December 31,</td><td colspan="2">Average Interest Rate on Commercial Paper Borrowings for the Year Ended December 31,</td></tr><tr><td>Commercial Paper Issuer</td><td>2019(a)(b)(c)</td><td>2018(a)(b)(c)</td><td>2019</td><td>2018</td><td>2019</td><td>2018</td></tr><tr><td>Exelon(d)</td><td>$ 9,000</td><td>$ 9,000</td><td>$ 870</td><td>$ 89</td><td>2.25%</td><td>2.15%</td></tr><tr><td>Generation</td><td>5,300</td><td>5,300</td><td>320</td><td>—</td><td>1.84%</td><td>1.96%</td></tr><tr><td>ComEd</td><td>1,000</td><td>1,000</td><td>130</td><td>—</td><td>2.38%</td><td>2.14%</td></tr><tr><td>PECO</td><td>600</td><td>600</td><td>—</td><td>—</td><td>2.39%</td><td>2.24%</td></tr><tr><td>BGE</td><td>600</td><td>600</td><td>76</td><td>35</td><td>2.46%</td><td>2.18%</td></tr><tr><td>PHI</td><td>900</td><td>900</td><td>208</td><td>54</td><td>N/A</td><td>N/A</td></tr><tr><td>Pepco</td><td>300</td><td>300</td><td>82</td><td>40</td><td>2.56%</td><td>2.24%</td></tr><tr><td>DPL</td><td>300</td><td>300</td><td>56</td><td>—</td><td>2.02%</td><td>2.07%</td></tr><tr><td>ACE</td><td>300</td><td>300</td><td>70</td><td>14</td><td>2.43%</td><td>2.21%</td></tr></table>

(a) Excludes $1,400 million and $545 million in bilateral credit facilities at December 31, 2019 and 2018, respectively, and $159 million in credit facilities for project finance at December 31, 2019 and 2018, respectively. These credit facilities do not back Generation's commercial paper program.

(b) At December 31, 2019, excludes $142 million of credit facility agreements arranged at minority and community banks at Generation, ComEd, PECO, BGE, Pepco, DPL and ACE with aggregate commitments of $44 million, $33 million, $33 million, $8 million, $8 million and $8 million, respectively. These facilities expire on October 9, 2020. These facilities are solely utilized to issue letters of credit. At December 31, 2018, excludes $135 million of credit facility agreements arranged at minority and community banks at Generation, ComEd, PECO, BGE, Pepco, DPL and ACE with aggregate commitments of $49 million, $33 million, $34 million, $5 million, $5 million, and $5 million, respectively.

(c) Pepco, DPL and ACE's revolving credit facility has the ability to flex to $500 million, $500 million, and $350 million, respectively. The borrowing capacity may be increased or decreased during the term of the facility, except that (i) the sum of the borrowing capacity must equal the total amount of the facility, and (ii) the aggregate amount of credit used at any given time by each of Pepco, DPL or ACE may not exceed $500 million or the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the borrowing reallocations may not exceed eight per year during the term of the facility.

(d) Includes revolving credit agreement at Exelon Corporate with a maximum program size of $600 million at both December 31, 2019 and 2018, respectively. Exelon Corporate had $136 million of outstanding commercial paper at December 31, 2019 and no outstanding commercial paper at the end of 2018.

In order to maintain their respective commercial paper programs in the amounts indicated above, each Registrant must have credit facilities in place, at least equal to the amount of its commercial paper program. A registrant does not issue commercial paper in an aggregate amount exceeding the then available capacity under its credit facility.



## Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 16 — Debt and Credit Agreements

At December 31, 2019, the Registrants had the following aggregate bank commitments, credit facility borrowings and available capacity under their respective credit facilities:

<table><tr><td rowspan="2">Borrower</td><td rowspan="2">Facility Type</td><td colspan="2">Aggregate Bank</td><td rowspan="2">Facility Draws</td><td rowspan="2">Outstanding Letters of Credit</td><td colspan="3">Available Capacity at December 31, 2019</td></tr><tr><td>Commitment(a)</td><td></td><td>Actual</td><td>To Support Additional Commercial Paper(b)</td><td></td></tr><tr><td>Exelon(b)</td><td>Syndicated Revolver / Bilaterals / Project Finance</td><td>$</td><td>10,559</td><td>$</td><td>—</td><td>1,443</td><td>$ 9,116</td><td>$ 7,353</td></tr><tr><td>Generation</td><td>Syndicated Revolver</td><td></td><td>5,300</td><td>—</td><td></td><td>769</td><td>4,531</td><td>4,211</td></tr><tr><td>Generation</td><td>Bilaterals</td><td></td><td>1,400</td><td>—</td><td></td><td>545</td><td>855</td><td>—</td></tr><tr><td>Generation</td><td>Project Finance</td><td></td><td>159</td><td>—</td><td></td><td>120</td><td>39</td><td>—</td></tr><tr><td>ComEd</td><td>Syndicated Revolver</td><td></td><td>1,000</td><td>—</td><td></td><td>2</td><td>998</td><td>868</td></tr><tr><td>PECO</td><td>Syndicated Revolver</td><td></td><td>600</td><td>—</td><td></td><td>—</td><td>600</td><td>600</td></tr><tr><td>BGE</td><td>Syndicated Revolver</td><td></td><td>600</td><td>—</td><td></td><td>—</td><td>600</td><td>524</td></tr><tr><td>PHI</td><td>Syndicated Revolver</td><td></td><td>900</td><td>—</td><td></td><td>—</td><td>900</td><td>692</td></tr><tr><td>Pepco</td><td>Syndicated Revolver</td><td></td><td>300</td><td>—</td><td></td><td>—</td><td>300</td><td>218</td></tr><tr><td>DPL</td><td>Syndicated Revolver</td><td></td><td>300</td><td>—</td><td></td><td>—</td><td>300</td><td>244</td></tr><tr><td>ACE</td><td>Syndicated Revolver</td><td></td><td>300</td><td>—</td><td></td><td>—
<td>300</td><td>230</td></td></tr></table>

(a) Excludes $142 million of credit facility agreements arranged at minority and community banks at Generation, ComEd, PECO, BGE, Pepco, DPL and ACE with aggregate commitments of $44 million, $33 million, $33 million, $8 million, $8 million, $8 million and $8 million, respectively. These facilities expire on October 9, 2020. These facilities are solely utilized to issue letters of credit. As of December 31, 2019, letters of credit issued under these facilities totaled $5 million, $5 million, $2 million for Generation, ComEd, and BGE, respectively.

(b) Includes $600 million aggregate bank commitment related to Exelon Corporate. Exelon Corporate had $6 million and $9 million outstanding letters of credit at December 31, 2019 and 2018, respectively. Exelon Corporate had $458 million in available capacity to support additional commercial paper at December 31, 2019.



# Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 16 — Debt and Credit Agreements

The following tables present the short-term borrowings activity for Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE during 2019 and 2018.

<table><tr><td>December 31, 2019</td><td colspan="2">Exelon(a)</td><td colspan="2">Generation</td><td colspan="2">ComEd</td><td colspan="2">PECO</td><td colspan="2">BGE</td><td>PHI</td><td>Pepco</td><td>DPL</td><td>ACE</td></tr><tr><td>Average borrowings</td><td>$</td><td>472</td><td>$</td><td>13</td><td>$</td><td>236</td><td>$</td><td>—</td><td>$</td><td>103</td><td>N/A</td><td>45</td><td>21</td><td>$</td></tr><tr><td>Maximum borrowings outstanding</td><td></td><td>890</td><td></td><td>357</td><td></td><td>465</td><td></td><td>21</td><td></td><td>298</td><td>N/A</td><td>144</td><td>125</td><td>180</td></tr><tr><td>Average interest rates, computed on a daily basis</td><td></td><td>2.25%</td><td></td><td>1.84%</td><td></td><td>2.38%</td><td></td><td>2.39%</td><td></td><td>2.46%</td><td>N/A</td><td>2.56%</td><td>2.02%</td><td>2.43%</td></tr><tr><td>Average interest rates, at December 31</td><td></td><td>2.25%</td><td></td><td>1.84%</td><td></td><td>2.38%</td><td></td><td>2.39%</td><td></td><td>2.46%</td><td>N/A</td><td>2.56%</td><td>2.02%</td><td>2.43%</td></tr></table>

<table><tr><td>December 31, 2018</td><td colspan="2">Exelon(a)</td><td colspan="2">Generation</td><td colspan="2">ComEd</td><td colspan="2">PECO</td><td colspan="2">BGE</td><td colspan="2">PHI</td><td colspan="2">Pepco</td><td colspan="2">DPL</td><td colspan="2">ACE</td></tr><tr><td>Average borrowings</td><td>$</td><td>531</td><td>$</td><td>37</td><td>$</td><td>154</td><td>$</td><td>68</td><td>$</td><td>65</td><td>N/A</td><td>$</td><td>22</td><td>$</td><td>87</td><td>$</td><td>95</td></tr><tr><td>Maximum borrowings outstanding</td><td></td><td>1,237</td><td></td><td>583</td><td></td><td>520</td><td></td><td>350</td><td></td><td>239</td><td></td><td>N/A</td><td>90</td><td></td><td>245</td><td></td><td>210</td></tr><tr><td>Average interest rates, computed on a daily basis</td><td></td><td>2.21%</td><td></td><td>1.96%</td><td></td><td>2.14%</td><td></td><td>2.24%</td><td></td><td>2.18%</td><td></td><td>N/A</td><td>2.24%</td><td></td><td>2.07%</td><td></td><td>2.21%</td></tr><tr><td>Average interest rates, at December 31</td><td></td><td>2.15%</td><td></td><td>1.96%</td><td></td><td>2.14%</td><td></td><td>2.24%</td><td></td><td>2.18%</td><td></td><td>N/A</td><td>2.24%</td><td></td><td>2.07%</td><td></td><td>2.21%</td></tr></table>

(a) Includes $3 million and $4 million average borrowings related to Exelon Corporate at December 31, 2019 and 2018, respectively. Exelon Corporate had $144 million and $95 million maximum borrowings outstanding at December 31, 2019 and 2018, with 1.92% and 1.93% average interest rates computed on a daily basis for 2019 and 2018, and 1.92% and 1.93% average interest rates at December 31, 2019 and 2018, respectively.

## Short-Term Loan Agreements

On March 23, 2017, Exelon Corporate entered into a term loan agreement for $500 million, which was renewed on March 22, 2018 with an expiration of March 21, 2019. The loan agreement was renewed on March 20, 2019 and will expire on March 19, 2020. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.95% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Exelon's Consolidated Balance Sheet within Short-Term borrowings.

## Revolving Credit Agreements

On May 26, 2016, Exelon Corporate, Generation, ComEd, PECO and BGE entered into amendments to each of their respective syndicated revolving credit facilities, which extended the maturity of each of the facilities to May 26, 2021. Exelon Corporate also increased the size of its facility from $500 million to $600 million. On May 26, 2016, PHI, Pepco, DPL and ACE entered into an amendment to their Second Amended and Restated Credit Agreement dated as of August 1, 2011, which (i) extended the maturity date of the facility to May 26, 2021, (ii) removed PHI as a borrower under the facility, (iii) decreased the size of the facility from $1.5 billion to $900 million and (iv) aligned its financial covenant from debt to capitalization leverage ratio to interest coverage ratio. On May 26, 2018, each of the Registrants' respective syndicated revolving credit facilities had their maturity dates extended to May 26, 2023.



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 16 — Debt and Credit Agreements

## Bilateral Credit Agreements

The following table reflects the bilateral credit agreements at December 31, 2019:

<table><tr><td>Registrant</td><td>Date Initiated</td><td>Latest Amendment Date</td><td>Maturity Date(a)</td><td>Amount</td></tr><tr><td>Generation(b)</td><td>October 26, 2012</td><td>October 24, 2019</td><td>October 24, 2020</td><td>200</td></tr><tr><td>Generation(c)</td><td>January 11, 2013</td><td>January 4, 2019</td><td>March 1, 2021</td><td>100</td></tr><tr><td>Generation(c)</td><td>January 5, 2016</td><td>January 4, 2019</td><td>April 5, 2021</td><td>150</td></tr><tr><td>Generation(c)</td><td>February 21, 2019</td><td>N/A</td><td>March 31, 2021</td><td>100</td></tr><tr><td>Generation(c)</td><td>October 25, 2019</td><td>N/A</td><td>N/A</td><td>200</td></tr><tr><td>Generation(c)</td><td>October 25, 2019</td><td>N/ A</td><td>N/A</td><td>100</td></tr><tr><td>Generation(c)</td><td>November 20, 2019</td><td>N/A</td><td>N/A</td><td>300</td></tr><tr><td>Generation(c)</td><td>November 21, 2019</td><td>N/A</td><td>November 21, 2020</td><td>150</td></tr><tr><td>Generation(c)</td><td>November 21, 2019</td><td>N/A</td><td>November 21, 2021</td><td>100</td></tr></table>

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

(b) Bilateral credit facility relates to CENG, which is incorporated within Generation, and supports the issuance of letters of credit and funding for working capital and does not back Generation's commercial paper program.

(c) Bilateral credit agreements solely support the issuance of letters of credit and do not back Generation's commercial paper program.

Borrowings under Exelon Corporate’s, Generation’s, ComEd’s, PECO’s, BGE’s, Pepco’s, DPL’s and ACE’s revolving credit agreements bear interest at a rate based upon either the prime rate or a LIBOR-based rate, plus an adder based upon the particular Registrant’s credit rating. The adders for the prime based borrowings and LIBOR-based borrowings are presented in the following table:

<table><tr><td></td><td>Exelon</td><td>Generation</td><td>ComEd</td><td>PECO</td><td>BGE</td><td>Pepco</td><td>DPL</td><td>ACE</td></tr><tr><td>Prime based borrowings</td><td>27.5</td><td>27.5</td><td>7.5</td><td>—</td><td>—</td><td>7.5</td><td>7.5</td><td>7.5</td></tr><tr><td>LIBOR-based borrowings</td><td>127.5</td><td>127.5</td><td>107.5</td><td>90.0</td><td>100.0</td><td>107.5</td><td>107.5</td><td>107.5</td></tr></table>

If any registrant loses its investment grade rating, the maximum adders for prime rate borrowings and LIBOR-based rate borrowings would be 65 basis points and 165 basis points. The credit agreements also require the borrower to pay a facility fee based upon the aggregate commitments. The fee varies depending upon the respective credit ratings of the borrower.

## Variable Rate Demand Bonds

DPL has outstanding obligations in respect of Variable Rate Demand Bonds (VRDB). VRDBs are subject to repayment on the demand of the holders and, for this reason, are accounted for as short-term debt in accordance with GAAP. However, these bonds may be converted to a fixed-rate, fixed-term option to establish a maturity which corresponds to the date of final maturity of the bonds. On this basis, PHI views VRDBs as a source of long-term financing. As of both December 31, 2019 and December 31, 2018, $79 million in variable rate demand bonds issued by DPL were outstanding and are included in the Long-term debt due within one year in Exelon's, PHI's and DPL's Consolidated Balance Sheet.



## Long-Term Debt

The following tables present the outstanding long-term debt at the Registrants as of December 31, 2019 and 2018:

## Exelon

<table><tr><td rowspan="2"></td><td rowspan="2">Rates</td><td rowspan="2">Maturity Date</td><td colspan="2">December 31,</td></tr><tr><td>2019</td><td>2018</td></tr><tr><td>Long-term debt</td><td></td><td></td><td></td><td></td></tr><tr><td>First mortgage bonds(a)</td><td>1.70% -</td><td>7.90%</td><td>2020 - 2049</td><td>$ 17,486</td></tr><tr><td>Senior unsecured notes</td><td>2.45% -</td><td>7.60%</td><td>2020 - 2046</td><td>10,685</td></tr><tr><td>Unsecured notes</td><td>2.40% -</td><td>6.35%</td><td>2021 - 2049</td><td>3,300</td></tr><tr><td>Pollution control notes</td><td>2.50% -</td><td>2.70%</td><td>2025 - 2036</td><td>412</td></tr><tr><td>Nuclear fuel procurement contracts</td><td></td><td>3.15%</td><td>2020</td><td>3</td></tr><tr><td>Notes payable and other</td><td>2.53% -</td><td>7.99%</td><td>2020 - 2053</td><td>154</td></tr><tr><td>Junior subordinated notes</td><td></td><td>3.50%</td><td>2022</td><td>1,150</td></tr><tr><td>Long-term software licensing agreement</td><td></td><td>3.95%</td><td>2024</td><td>55</td></tr><tr><td>Unsecured Tax-Exempt Bonds(b)</td><td>1.63% -</td><td>5.40%</td><td>2022 - 2031</td><td>222</td></tr><tr><td>Medium-Terms Notes (unsecured)</td><td>7.61% -</td><td>7.72%</td><td>2027</td><td>10</td></tr><tr><td>Transition bonds</td><td></td><td>5.55%</td><td>2023</td><td>40</td></tr><tr><td>Loan Agreement</td><td></td><td>2.00%</td><td>2023</td><td>50</td></tr><tr><td>Nonrecourse debt:</td><td></td><td></td><td></td><td></td></tr><tr><td>Fixed rates</td><td>2.29% -</td><td>6.00%</td><td>2031 - 2037</td><td>1,182</td></tr><tr><td>Variable rates</td><td>3.18% -</td><td>4.91%</td><td>2020 - 2024</td><td>811</td></tr><tr><td>Total long-term debt</td><td></td><td></td><td></td><td>35,560</td></tr><tr><td>Unamortized debt discount and premium, net</td><td></td><td></td><td></td><td>(72)</td></tr><tr><td>Unamortized debt issuance costs</td><td></td><td></td><td></td><td>(214)</td></tr><tr><td>Fair value adjustment</td><td></td><td></td><td></td><td>765</td></tr><tr><td>Long-term debt due within one year</td><td></td><td></td><td></td><td>(4,710)</td></tr><tr><td>Long-term debt</td><td></td><td></td><td></td><td>$ 31,329</td></tr><tr><td>Long-term debt to financing trusts(c)</td><td></td><td></td><td></td><td></td></tr><tr><td>Subordinated debentures to ComEd Financing III</td><td></td><td>6.35%</td><td>2033</td><td>$ 206</td></tr><tr><td>Subordinated debentures to PECO Trust III</td><td>6.75% -</td><td>7.38%</td><td>2028</td><td>81</td></tr><tr><td>Subordinated debentures to PECO Trust IV</td><td></td><td>5.75%</td><td>2033</td><td>103</td></tr><tr><td>Total long-term debt to financing trusts</td><td></td><td></td><td></td><td>390</td></tr><tr><td>Unamortized debt issuance costs</td><td></td><td></td><td></td><td>—</td></tr><tr><td>Long-term debt to financing trusts</td><td></td><td></td><td></td><td>$ 390</td></tr></table>

(a) Substantially all of ComEd's assets other than expressly excepted property and substantially all of PECO's, Pepco's, DPL's and ACE's assets are subject to the liens of their respective mortgage indentures.

(b) Bond amount totaling $110 million was previously disclosed within the first mortgage bonds line item, as it was classified as a secured tax-exempt bond. In 2019, the callable bond was reissued as an unsecured tax-exempt bond, and is presented as such within this section.

(c) Amounts owed to these financing trusts are recorded as Long-term debt to financing trusts within Exelon's Consolidated Balance Sheets.



## Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 16 — Debt and Credit Agreements

## Generation

<table><tr><td rowspan="2"></td><td rowspan="2">Rates</td><td rowspan="2">Maturity Date</td><td colspan="2">December 31,</td></tr><tr><td>2019</td><td>2018</td></tr><tr><td>Long-term debt</td><td></td><td></td><td></td><td></td></tr><tr><td>Senior unsecured notes</td><td>2.95% -</td><td>7.60%</td><td>2020 - 2042</td><td>$ 5,420</td></tr><tr><td>Pollution control notes</td><td>2.50% -</td><td>2.70%</td><td>2025 - 2036</td><td>412</td></tr><tr><td>Nuclear fuel procurement contracts</td><td></td><td>3.15%</td><td>2020</td><td>3</td></tr><tr><td>Notes payable and other</td><td>2.53% -</td><td>4.26%</td><td>2020 - 2028</td><td>115</td></tr><tr><td>Nonrecourse debt:</td><td></td><td></td><td></td><td></td></tr><tr><td>Fixed rates</td><td>2.29% -</td><td>6.00%</td><td>2031 - 2037</td><td>1,182</td></tr><tr><td>Variable rates</td><td>3.18% -</td><td>4.91%</td><td>2020 - 2024</td><td>811</td></tr><tr><td>Total long-term debt</td><td></td><td></td><td></td><td>7,943</td></tr><tr><td>Unamortized debt discount and premium, net</td><td></td><td></td><td></td><td>(5)</td></tr><tr><td>Unamortized debt issuance costs</td><td></td><td></td><td></td><td>(42)</td></tr><tr><td>Fair value adjustment</td><td></td><td></td><td></td><td>78</td></tr><tr><td>Long-term debt due within one year</td><td></td><td></td><td></td><td>(3,182)</td></tr><tr><td>Long-term debt</td><td></td><td></td><td></td><td>$ 4,792</td></tr></table>

## ComEd

<table><tr><td rowspan="2"></td><td rowspan="2">Rates</td><td rowspan="2">Maturity Date</td><td colspan="2">December 31,</td></tr><tr><td>2019</td><td>2018</td></tr><tr><td>Long-term debt</td><td></td><td></td><td></td><td></td></tr><tr><td>First mortgage bonds \( ^{(a)} \)</td><td>2.55% -</td><td>6.45%</td><td>2020 - 2049</td><td>$ 8,578</td></tr><tr><td>Notes payable and other</td><td></td><td>7.49%</td><td>2053</td><td>8</td></tr><tr><td>Total long-term debt</td><td></td><td></td><td></td><td>8,586</td></tr><tr><td>Unamortized debt discount and premium, net</td><td></td><td></td><td></td><td>(27)</td></tr><tr><td>Unamortized debt issuance costs</td><td></td><td></td><td></td><td>(68)</td></tr><tr><td>Long-term debt due within one year</td><td></td><td></td><td></td><td>(500)</td></tr><tr><td>Long-term debt</td><td></td><td></td><td></td><td>$ 7,991</td></tr><tr><td>Long-term debt to financing trust \( ^{(b)} \)</td><td></td><td></td><td></td><td></td></tr><tr><td>Subordinated debentures to ComEd Financing III</td><td>6.35%</td><td></td><td>2033</td><td>$ 206</td></tr><tr><td>Total long-term debt to financing trusts</td><td></td><td></td><td></td><td>206</td></tr><tr><td>Unamortized debt issuance costs</td><td></td><td></td><td></td><td>(1)</td></tr><tr><td>Long-term debt to financing trusts</td><td></td><td></td><td></td><td>$ 205</td></tr></table>

(a) Substantially all of ComEd's assets, other than expressly excepted property, are subject to the lien of its mortgage indenture.

(b) Amount owed to this financing trust is recorded as Long-term debt to financing trust within ComEd's Consolidated Balance Sheets.



## Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 16 — Debt and Credit Agreements

## PECO

<table><tr><td rowspan="2"></td><td rowspan="2">Rates</td><td rowspan="2">Maturity Date</td><td colspan="2">December 31,</td></tr><tr><td>2019</td><td>2018</td></tr><tr><td>Long-term debt</td><td></td><td></td><td></td><td></td></tr><tr><td>First mortgage bonds \( ^{(a)} \)</td><td>1.70% -</td><td>5.95%</td><td>2021 - 2049</td><td>$ 3,400</td></tr><tr><td>Loan Agreement</td><td></td><td>2.00%</td><td>2023</td><td>50</td></tr><tr><td>Total long-term debt</td><td></td><td></td><td></td><td>3,450</td></tr><tr><td>Unamortized debt discount and premium, net</td><td></td><td></td><td></td><td>(21)</td></tr><tr><td>Unamortized debt issuance costs</td><td></td><td></td><td></td><td>(24)</td></tr><tr><td>Long-term debt</td><td></td><td></td><td></td><td>$ 3,405</td></tr><tr><td>Long-term debt to financing trusts \( ^{(b)} \)</td><td></td><td></td><td></td><td></td></tr><tr><td>Subordinated debentures to PECO Trust III</td><td>6.75% -</td><td>7.38%</td><td>2028</td><td>$ 81</td></tr><tr><td>Subordinated debentures to PECO Trust IV</td><td></td><td>5.75%</td><td>2033</td><td>103</td></tr><tr><td>Long-term debt to financing trusts</td><td></td><td></td><td></td><td>$ 184</td></tr></table>

(a) Substantially all of PECO's assets are subject to the lien of its mortgage indenture.

(b) Amounts owed to this financing trust are recorded as Long-term debt to financing trusts within PECO's Consolidated Balance Sheets.

## BGE

<table><tr><td rowspan="2"></td><td rowspan="2">Rates</td><td rowspan="2">Maturity Date</td><td colspan="2">December 31,</td></tr><tr><td>2019</td><td>2018</td></tr><tr><td>Long-term debt</td><td></td><td></td><td></td><td></td></tr><tr><td>Unsecured notes</td><td>2.40% -</td><td>6.35%</td><td>2021 - 2049</td><td>$ 3,300</td></tr><tr><td>Total long-term debt</td><td></td><td></td><td></td><td>3,300</td></tr><tr><td>Unamortized debt discount and premium, net</td><td></td><td></td><td></td><td>(9)</td></tr><tr><td>Unamortized debt issuance costs</td><td></td><td></td><td></td><td>(21)</td></tr><tr><td>Long-term debt</td><td></td><td></td><td></td><td>$ 3,270</td></tr></table>



## Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 16 — Debt and Credit Agreements

## PHI

<table><tr><td rowspan="2"></td><td rowspan="2">Rates</td><td rowspan="2">Maturity Date</td><td colspan="2">December 31,</td></tr><tr><td>2019</td><td>2018</td></tr><tr><td>Long-term debt</td><td></td><td></td><td></td><td></td></tr><tr><td>First mortgage bonds \( ^{(a)} \)</td><td>1.76% -</td><td>7.90%</td><td>2021 - 2049</td><td>$ 5,508</td></tr><tr><td>Senior unsecured notes</td><td></td><td>7.45%</td><td>2032</td><td>185</td></tr><tr><td>Unsecured Tax-Exempt Bonds \( ^{(b)} \)</td><td>1.63% -</td><td>5.40%</td><td>2022 - 2031</td><td>222</td></tr><tr><td>Medium-terms notes (unsecured)</td><td>7.61% -</td><td>7.72%</td><td>2027</td><td>10</td></tr><tr><td>Transition bonds \( ^{(c)} \)</td><td></td><td>5.55%</td><td>2023</td><td>40</td></tr><tr><td>Notes payable and other</td><td>3.54% -</td><td>7.99%</td><td>2021 - 2027</td><td>30</td></tr><tr><td>Total long-term debt</td><td></td><td></td><td></td><td>5,995</td></tr><tr><td>Unamortized debt discount and premium, net</td><td></td><td></td><td></td><td>4</td></tr><tr><td>Unamortized debt issuance costs</td><td></td><td></td><td></td><td>(19)</td></tr><tr><td>Fair value adjustment</td><td></td><td></td><td></td><td>583</td></tr><tr><td>Long-term debt due within one year</td><td></td><td></td><td></td><td>(103)</td></tr><tr><td>Long-term debt</td><td></td><td></td><td></td><td>$ 6,460</td></tr></table>

(a) Substantially all of Pepco's, DPL's, and ACE's assets are subject to the lien of its respective mortgage indenture.

(b) Bond amount totaling $110 million was previously disclosed within the first mortgage bonds line item, as it was classified as a secured tax-exempt bond. In 2019, the callable bond was reissued as an unsecured tax-exempt bond, and is presented as such within this section.

(c) Transition bonds are recorded as part of Long-term debt within ACE's Consolidated Balance Sheets.

## Pepco

<table><tr><td rowspan="2"></td><td rowspan="2">Rates</td><td rowspan="2">Maturity Date</td><td colspan="2">December 31,</td></tr><tr><td>2019</td><td>2018</td></tr><tr><td>Long-term debt</td><td></td><td></td><td></td><td></td></tr><tr><td>First mortgage bonds \( ^{(a)} \)</td><td>3.05% -</td><td>7.90%</td><td>2022 - 2048</td><td>$ 2,775</td></tr><tr><td>Unsecured Tax-Exempt Bonds \( ^{(b)} \)</td><td></td><td>1.70%</td><td>2022</td><td>110</td></tr><tr><td>Notes payable and other</td><td>3.54% -</td><td>7.99%</td><td>2021 - 2027</td><td>12</td></tr><tr><td>Total long-term debt</td><td></td><td></td><td></td><td>2,897</td></tr><tr><td>Unamortized debt discount and premium, net</td><td></td><td></td><td></td><td>2</td></tr><tr><td>Unamortized debt issuance costs</td><td></td><td></td><td></td><td>(35)</td></tr><tr><td>Long-term debt due within one year</td><td></td><td></td><td></td><td>(2)</td></tr><tr><td>Long-term debt</td><td></td><td></td><td></td><td>$ 2,862</td></tr></table>

(a) Substantially all of Pepco's assets are subject to the lien of its respective mortgage indenture.

(b) Bond amount totaling $110 million was previously disclosed within the first mortgage bonds line item, as it was classified as a secured tax-exempt bond. In 2019, the callable bond was reissued as an unsecured tax-exempt bond, and is presented as such within this section.



## Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 16 — Debt and Credit Agreements

## DPL

<table><tr><td rowspan="2"></td><td rowspan="2">Rates</td><td rowspan="2">Maturity Date</td><td colspan="3">December 31,</td></tr><tr><td>2019</td><td>2018</td><td></td></tr><tr><td>Long-term debt</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>First mortgage bonds \( ^{(a)} \)</td><td>1.76%</td><td>-</td><td>4.27%</td><td>2023 - 2049</td><td>1,446</td></tr><tr><td>Unsecured Tax-Exempt Bonds</td><td>1.63%</td><td>-</td><td>5.40%</td><td>2024 - 2031</td><td>112</td></tr><tr><td>Medium-terms notes (unsecured)</td><td>7.61%</td><td>-</td><td>7.72%</td><td>2027</td><td>10</td></tr><tr><td>Other</td><td></td><td>3.54%</td><td></td><td>2027</td><td>10</td></tr><tr><td>Total long-term debt</td><td></td><td></td><td></td><td></td><td>1,578</td></tr><tr><td>Unamortized debt discount and premium, net</td><td></td><td></td><td></td><td></td><td>1</td></tr><tr><td>Unamortized debt issuance costs</td><td></td><td></td><td></td><td></td><td>(12)</td></tr><tr><td>Long-term debt due within one year</td><td></td><td></td><td></td><td></td><td>(80)</td></tr><tr><td>Long-term debt</td><td></td><td></td><td></td><td></td><td>1,487</td></tr></table>

(a) Substantially all of DPL's assets are subject to the lien of its respective mortgage indenture.

## ACE

<table><tr><td rowspan="2"></td><td rowspan="2">Rates</td><td rowspan="2">Maturity Date</td><td colspan="2">December 31,</td></tr><tr><td>2019</td><td>2018</td></tr><tr><td>Long-term debt</td><td></td><td></td><td></td><td></td></tr><tr><td>First mortgage bonds \( ^{(a)} \)</td><td>3.38% -</td><td>6.80%</td><td>2021 - 2049</td><td>1,287</td></tr><tr><td>Transition bonds \( ^{(b)} \)</td><td></td><td>5.55%</td><td>2023</td><td>40</td></tr><tr><td>Other</td><td></td><td>3.54%</td><td>2027</td><td>8</td></tr><tr><td>Total long-term debt</td><td></td><td></td><td></td><td>1,335</td></tr><tr><td>Unamortized debt discount and premium, net</td><td></td><td></td><td></td><td>(1)</td></tr><tr><td>Unamortized debt issuance costs</td><td></td><td></td><td></td><td>(7)</td></tr><tr><td>Long-term debt due within one year</td><td></td><td></td><td></td><td>(20)</td></tr><tr><td>Long-term debt</td><td></td><td></td><td></td><td>1,307</td></tr></table>

(a) Substantially all of ACE's assets are subject to the lien of its respective mortgage indenture.

(b) Maturities of ACE's Transition Bonds outstanding at December 31, 2019 are $19 million in 2020 and $21 million in 2021.



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 16 — Debt and Credit Agreements

Long-term debt maturities at Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE in the periods 2020 through 2024 and thereafter are as follows:

<table><tr><td>Year</td><td colspan="2">Exelon</td><td colspan="2">Generation</td><td colspan="2">ComEd</td><td colspan="2">PECO</td><td colspan="2">BGE</td><td colspan="2">PHI</td><td colspan="2">Pepco</td><td colspan="2">DPL</td><td colspan="2">ACE</td></tr><tr><td>2020</td><td>$</td><td>4,710</td><td>$</td><td>3,182</td><td>$</td><td>500</td><td>$</td><td>—</td><td>$</td><td>—</td><td>$</td><td>103</td><td>$</td><td>2</td><td>$</td><td>80</td><td>$</td><td>20</td></tr><tr><td>2021</td><td></td><td>1,517</td><td></td><td>2</td><td></td><td>350</td><td></td><td>300</td><td></td><td>300</td><td></td><td>265</td><td></td><td>2</td><td></td><td>2</td><td></td><td>261</td></tr><tr><td>2022</td><td></td><td>3,088</td><td></td><td>1,024</td><td></td><td>—</td><td></td><td>350</td><td></td><td>250</td><td></td><td>314</td><td></td><td>311</td><td></td><td>2</td><td></td><td>1</td></tr><tr><td>2023</td><td></td><td>855</td><td></td><td>1</td><td></td><td>—</td><td></td><td>50</td><td></td><td>300</td><td></td><td>504</td><td></td><td>1</td><td></td><td>502</td><td></td><td>1</td></tr><tr><td>2024</td><td></td><td>1,596</td><td></td><td>792</td><td></td><td>250</td><td></td><td>—</td><td></td><td>—</td><td></td><td>553</td><td></td><td>401</td><td></td><td>1</td><td></td><td>151</td></tr><tr><td>Thereafter</td><td></td><td>24,184</td><td>(a)</td><td>2,942</td><td></td><td>7,691</td><td>(b)</td><td>2,934</td><td>(c)</td><td>2,450</td><td></td><td>4,256</td><td></td><td>2,180</td><td></td><td>991</td><td></td><td>901</td></tr><tr><td>Total</td><td>$</td><td>35,950</td><td>$</td><td>7,943</td><td>$</td><td>8,791</td><td>$</td><td>3,634</td><td>$</td><td>3,300</td><td>$</td><td>5,995</td><td>$</td><td>2,897</td><td>$</td><td>1,578</td><td>$</td><td>1,335</td></tr></table>

(a) Includes $390 million due to ComEd and PECO financing trusts.

(b) Includes $206 million due to ComEd financing trust.

(c) Includes $184 million due to PECO financing trusts.

## Debt Covenants

As of December 31, 2019, the Registrants are in compliance with debt covenants, except for Antelope Valley's nonrecourse debt event of default as discussed below.

## Nonrecourse Debt

Exelon and Generation have issued nonrecourse debt financing, in which approximately $2.8 billion of generating assets have been pledged as collateral at December 31, 2019. Borrowings under these agreements are secured by the assets and equity of each respective project. The lenders do not have recourse against Exelon or Generation in the event of a default. If a specific project financing entity does not maintain compliance with its specific nonrecourse debt financing covenants, there could be a requirement to accelerate repayment of the associated debt or other borrowings earlier than the stated maturity dates. In these instances, if such repayment was not satisfied, the lenders or security holders would generally have rights to foreclose against the project-specific assets and related collateral. The potential requirement to satisfy its associated debt or other borrowings earlier than otherwise anticipated could lead to impairments due to a higher likelihood of disposing of the respective project-specific assets significantly before the end of their useful lives.

Antelope Valley Solar Ranch One. In December 2011, the DOE Loan Programs Office issued a guarantee for up to $646 million for a nonrecourse loan from the Federal Financing Bank to support the financing of the construction of the Antelope Valley facility. The project became fully operational in 2014. The loan will mature on January 5, 2037. Interest rates on the loan were fixed upon each advance at a spread of 37.5 basis points above U.S. Treasuries of comparable maturity. The advances were completed as of December 31, 2015 and the outstanding loan balance will bear interest at an average blended interest rate of 2.82%. As of December 31, 2019, approximately $485 million was outstanding. In addition, Generation has issued letters of credit to support its equity investment in the project. As of December 31, 2019, Generation had $38 million in letters of credit outstanding related to the project. In 2017, Generation's interests in Antelope Valley were also contributed to and are pledged as collateral for the EGR IV financing structure referenced below.

Antelope Valley sells all of its output to PG&E through a PPA. On January 29, 2019, PG&E filed for protection under Chapter 11 of the U.S. Bankruptcy Code, which created an event of default for Antelope Valley's nonrecourse debt that provides the lender with a right to accelerate amounts outstanding under the loan such that they would become immediately due and payable. As a result of the ongoing event of default and the absence of a waiver from the lender foregoing their acceleration rights, the debt was reclassified as current in Exelon's and Generation's Consolidated Balance Sheets in the first quarter of 2019 and continues to be classified as current as of December 31, 2019. Further, distributions from Antelope Valley to EGR IV are currently suspended.

Continental Wind. In September 2013, Continental Wind, LLC (Continental Wind), an indirect subsidiary of Exelon and Generation, completed the issuance and sale of $613 million senior secured notes. Continental Wind owns



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 16 — Debt and Credit Agreements

and operates a portfolio of wind farms in Idaho, Kansas, Michigan, Oregon, New Mexico and Texas with a total net capacity of 667MW. The net proceeds were distributed to Generation for its general business purposes. The notes are scheduled to mature on February 28, 2033. The notes bear interest at a fixed rate of 6.00% with interest payable semi-annually. As of December 31, 2019, $447 million was outstanding.

In addition, Continental Wind entered into a $131 million letter of credit facility and $10 million working capital revolver facility. Continental Wind has issued letters of credit to satisfy certain of its credit support and security obligations. As of December 31, 2019, the Continental Wind letter of credit facility had $115 million in letters of credit outstanding related to the project.

In 2017, Generation’s interests in Continental Wind were contributed to EGRP. Refer to Note 22 - Variable Interest Entities for additional information on EGRP.

Renewable Power Generation. In March 2016, RPG, an indirect subsidiary of Exelon and Generation, issued $150 million aggregate principal amount of a nonrecourse senior secured notes. The net proceeds were distributed to Generation for paydown of long term debt obligations at Sacramento PV Energy and Constellation Solar Horizons and for general business purposes. The loan is scheduled to mature on March 31, 2035. The term loan bears interest at a fixed rate of 4.11% payable semi-annually. As of December 31, 2019, $106 million was outstanding.

In 2017, Generation’s interests in Renewable Power Generation were contributed to EGRP. Refer to Note 22 - Variable Interest Entities for additional information on EGRP.

SolGen. In September 2016, SolGen, LLC (SolGen), an indirect subsidiary of Exelon and Generation, issued $150 million aggregate principal amount of a nonrecourse senior secured notes. The net proceeds were distributed to Generation for general business purposes. The loan is scheduled to mature on September 30, 2036. The term loan bears interest at a fixed rate of 3.93% payable semi-annually. As of December 31, 2019, $131 million was outstanding. In 2017, Generation’s interests in SolGen were also contributed to and are pledged as collateral for the EGR IV financing structure referenced below.

ExGen Renewables IV. In November 2017, EGR IV, an indirect subsidiary of Exelon and Generation, entered into an $850 million nonrecourse senior secured term loan credit facility agreement. Generation’s interests in EGRP, Antelope Valley, SolGen, and Albany Green Energy were all contributed to and are pledged as collateral for this financing. The net proceeds of $785 million, after the initial funding of $50 million for debt service and liquidity reserves as well as deductions for original discount and estimated costs, fees and expenses incurred in connection with the execution and delivery of the credit facility agreement, were distributed to Generation for general corporate purposes. The $50 million of debt service and liquidity reserves was treated as restricted cash in Exelon’s and Generation’s Consolidated Balance Sheets and Consolidated Statements of Cash Flows. The loan is scheduled to mature on November 28, 2024. The term loan bears interest at a variable rate equal to LIBOR + 3%, subject to a 1% LIBOR floor with interest payable quarterly. As of December 31, 2019, $796 million was outstanding. In addition to the financing, EGR IV entered into interest rate swaps with an initial notional amount of $636 million at an interest rate of 2.32% to manage a portion of the interest rate exposure in connection with the financing.

Although Antelope Valley’s debt is in default, it is nonrecourse to EGR IV. However, if in the future Antelope Valley were to file for bankruptcy protection as a result of events culminating from PG&E’s bankruptcy proceedings this would represent an event of default for EGR IV’s debt that would provide the lender with an opportunity to accelerate EGR IV’s debt. See Note 22 - Variable Interest Entities for additional information on EGRP.

## 17. Fair Value of Financial Assets and Liabilities (All Registrants)

Exelon measure and records 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 the Registrants 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.



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 17 — Fair Value of Financial Assets and Liabilities

- Level 3 — unobservable inputs, such as internally developed pricing models or third-party valuations for the asset or liability due to little or no market activity for the asset or liability.

## Fair Value of Financial Liabilities Recorded at the Carrying Amount

The following tables present the carrying amounts and fair values of the Registrants' short-term liabilities, long-term debt, SNF obligation, and trust preferred securities (long-term debt to financing trusts or junior subordinated debentures) as of December 31, 2019 and 2018. The Registrants have no financial liabilities classified as Level 1.

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

<table><tr><td rowspan="3"></td><td colspan="6">December 31, 2019</td><td colspan="6">December 31, 2018</td></tr><tr><td rowspan="2">Carrying Amount</td><td colspan="3">Fair Value</td><td rowspan="2">Total</td><td rowspan="2">Carrying Amount</td><td colspan="3">Fair Value</td><td colspan="3">Total</td></tr><tr><td>Level 2</td><td>Level 3</td><td></td><td>Level 2</td><td>Level 3</td><td></td><td>Level 2</td><td>Level</td><td>3</td></tr><tr><td colspan="13">Long-Term Debt, including amounts due within one year \( ^{(a)} \)</td></tr><tr><td>Exelon</td><td>$ 36,039</td><td>$ 37,453</td><td>$ 2,580</td><td>$ 40,033</td><td>$ 35,424</td><td>$ 33,711</td><td>$ 2,158</td><td>$ 35,869</td><td></td><td></td><td></td><td></td></tr><tr><td>Generation</td><td>7,974</td><td>7,304</td><td>1,366</td><td>8,670</td><td>8,793</td><td>7,467</td><td>1,443</td><td>8,910</td><td></td><td></td><td></td><td></td></tr><tr><td>ComEd</td><td>8,491</td><td>9,848</td><td>—</td><td>9,848</td><td>8,101</td><td>8,390</td><td>—</td><td>8,390</td><td></td><td></td><td></td><td></td></tr><tr><td>PECO</td><td>3,405</td><td>3,868</td><td>50</td><td>3,918</td><td>3,084</td><td>3,157</td><td>50</td><td>3,207</td><td></td><td></td><td></td><td></td></tr><tr><td>BGE</td><td>3,270</td><td>3,649</td><td>—</td><td>3,649</td><td>2,876</td><td>2,950</td><td>—</td><td>2,950</td><td></td><td></td><td></td><td></td></tr><tr><td>PHI</td><td>6,563</td><td>5,902</td><td>1,164</td><td>7,066</td><td>6,259</td><td>5,436</td><td>665</td><td>6,101</td><td></td><td></td><td></td><td></td></tr><tr><td>Pepco</td><td>2,864</td><td>3,198</td><td>388</td><td>3,586</td><td>2,719</td><td>2,901</td><td>196</td><td>3,097</td><td></td><td></td><td></td><td></td></tr><tr><td>DPL</td><td>1,567</td><td>1,408</td><td>311</td><td>1,719</td><td>1,494</td><td>1,303</td><td>193</td><td>1,496</td><td></td><td></td><td></td><td></td></tr><tr><td>ACE</td><td>1,327</td><td>1,026</td><td>464</td><td>1,490</td><td>1,188</td><td>987</td><td>275</td><td>1,262</td><td></td><td></td><td></td><td></td></tr><tr><td colspan="13">Long-Term Debt to Financing Trusts \( ^{(a)} \)</td></tr><tr><td>Exelon</td><td>$ 390</td><td>$ —</td><td>$ 428</td><td>$ 428</td><td>$ 390</td><td>$ —</td><td>$ 400</td><td>$ 400</td><td></td><td></td><td></td><td></td></tr><tr><td>ComEd</td><td>205</td><td>—</td><td>227</td><td>227</td><td>205</td><td>—</td><td>209</td><td>209</td><td></td><td></td><td></td><td></td></tr><tr><td>PECO</td><td>184</td><td>—</td><td>201</td><td>201</td><td>184</td><td>—</td><td>191</td><td>191</td><td></td><td></td><td></td><td></td></tr><tr><td colspan="13">SNF Obligation</td></tr><tr><td>Exelon</td><td>$ 1,199</td><td>$ 1,055</td><td>$ —</td><td>$ 1,055</td><td>$ 1,171</td><td>$ 949</td><td>$ —</td><td>$ 949</td><td></td><td></td><td></td><td></td></tr><tr><td>Generation</td><td>1,199</td><td>1,055</td><td>—</td><td>1,055</td><td>1,171</td><td>949</td><td>—</td><td>949</td><td></td><td></td><td></td><td></td></tr></table>

(a) Includes unamortized debt issuance costs which are not fair valued. Refer to Note 16 — Debt and Credit Agreements for each Registrant's unamortized debt issuance costs.

Exelon uses the following methods and assumptions to estimate fair value of financial liabilities recorded at carrying cost:



## Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 17 — Fair Value of Financial Assets and Liabilities

<table><tr><td>Type</td><td>Level</td><td>Registrants</td><td>Valuation</td></tr><tr><td colspan="4">Long-term debt, including amounts due within one year</td></tr><tr><td>Taxable Debt Securities</td><td>2</td><td>All</td><td>The fair value is determined by a valuation model that is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. Exelon obtains credit spreads based on trades of existing Exelon debt securities as well as other issuers in the utility sector with similar credit ratings. The yields are then converted into discount rates of various tenors that are used for discounting the respective cash flows of the same tenor for each bond or note.</td></tr><tr><td>Variable Rate Financing Debt</td><td>2</td><td>Exelon, Generation, DPL</td><td>Debt rates are reset on a regular basis and the carrying value approximates fair value.</td></tr><tr><td>Taxable Private Placement Debt Securities</td><td>3</td><td>Exelon, Pepco, DPL, ACE</td><td>Rates are obtained similar to the process for taxable debt securities. Due to low trading volume and qualitative factors such as market conditions, low volume of investors and investor demand, these debt securities are Level 3.</td></tr><tr><td>Government Backed Fixed Rate Project Financing Debt</td><td>3</td><td>Exelon, Generation</td><td>The fair value is similar to the process for taxable debt securities. Due to the lack of market trading data on similar debt, the discount rates are derived based on the original loan interest rate spread to the applicable U.S. Treasury rate as well as a current market curve derived from government-backed securities.</td></tr><tr><td>Non-Government Backed Fixed Rate Nonrecourse Debt</td><td>3</td><td>Exelon, Generation, Pepco</td><td>Fair value is based on market and quoted prices for its own and other nonrecourse debt with similar risk profiles. Given the low trading volume in the nonrecourse debt market, the price quotes used to determine fair value will reflect certain qualitative factors, such as market conditions, investor demand, new developments that might significantly impact the project cash flows or off-taker credit, and other circumstances related to the project</td></tr><tr><td>Long Term Debt to Financing Trusts</td><td>3</td><td>Exelon, ComEd, PECO</td><td>Fair value is based on publicly traded securities issued by the financing trusts. Due to low trading volume of these securities and qualitative factors, such as market conditions, investor demand, and circumstances related to each issue, this debt is classified as Level 3.</td></tr><tr><td>SNF Obligation</td><td>2</td><td>Exelon, Generation</td><td>The carrying amount is derived from a contract with the DOE to provide for disposal of SNF from Generation&#x27;s nuclear generating stations. When determining the fair value of the obligation, the future carrying amount of the SNF obligation is calculated by compounding the current book value of the SNF obligation at the 13-week U.S. Treasury rate. The compounded obligation amount is discounted back to present value using Generation&#x27;s discount rate, which is calculated using the same methodology as described above for the taxable debt securities, and an estimated maturity date of 2030.</td></tr></table>



## Recurring Fair Value Measurements

The following tables present assets and liabilities measured and recorded at fair value in the Registrants' Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2019 and 2018:

<table><tr><td rowspan="2">As of December 31, 2019</td><td colspan="6">Exelon</td><td colspan="6">Generation</td></tr><tr><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Not subject to leveling</td><td>Total</td><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Not subject to leving</td><td>Total</td><td></td><td></td></tr><tr><td>Assets</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Cash equivalents(a)</td><td>$ 639</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ 639</td><td>$ 214</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ 214</td><td></td><td></td></tr><tr><td>NDT fund investments</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Cash equivalents(b)</td><td>365</td><td>87</td><td>—</td><td>—</td><td>452</td><td>365</td><td>87</td><td>—</td><td>—</td><td>452</td><td></td><td></td><td></td></tr><tr><td>Equities</td><td>3,353</td><td>1,753</td><td>—</td><td>1,388</td><td>6,494</td><td>3,353</td><td>1,753</td><td>—</td><td>1,388</td><td></td><td>6,494</td><td></td><td></td></tr><tr><td>Fixed income</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Corporate debt</td><td>—</td><td>1,469</td><td>257</td><td>—</td><td>1,726</td><td>—</td><td>1,469</td><td>257</td><td>—</td><td>1,726</td><td></td><td></td><td></td></tr><tr><td>U.S. Treasury and agencies</td><td>1,808</td><td>131</td><td>—</td><td>—</td><td>1,939</td><td>1,808</td><td>131</td><td>—</td><td>—</td><td>1,939</td><td></td><td></td><td></td></tr><tr><td>Foreign governments</td><td>—</td><td>42</td><td>—</td><td>—</td><td>42</td><td>—</td><td>42</td><td>—</td><td>—</td><td>42</td><td></td><td></td><td></td></tr><tr><td>State and municipal debt</td><td>—</td><td>90</td><td>—</td><td>—</td><td>90</td><td>—</td><td>90</td><td>—</td><td>—</td><td>90</td><td></td><td></td><td></td></tr><tr><td>Other(c)</td><td>—</td><td>33</td><td>—</td><td>953</td><td>986</td><td>—</td><td>33</td><td>—</td><td>953</td><td>986</td><td></td><td></td><td></td></tr><tr><td>Fixed income subtotal</td><td>1,808</td><td>1,765</td><td>257</td><td>953</td><td>4,783</td><td>1,808</td><td>1,765</td><td>257</td><td>953</td><td>4</td><td>783</td><td></td><td></td></tr><tr><td>Private credit</td><td>—</td><td>—</td><td>254</td><td>508</td><td>762</td><td>—</td><td>—</td><td>254</td><td>508</td><td>762</td><td></td><td></td><td></td></tr><tr><td>Private equity</td><td>—</td><td>—</td><td>—</td><td>402</td><td>402</td><td>—</td><td>—</td><td>—</td><td>402</td><td>402</td><td></td><td></td><td></td></tr><tr><td>Real estate</td><td>—</td><td>—</td><td>—</td><td>607</td><td>607</td><td>—</td><td>—</td><td>—</td><td>607</td><td>607</td><td></td><td></td><td></td></tr><tr><td>NDT fund investments subtotal(d)</td><td>5,526</td><td>3,605</td><td>511</td><td>3,858</td><td>13,500</td><td>5,526</td><td>3,605</td><td>511</td><td>3,858</td><td></td><td>13,500</td><td></td><td></td></tr><tr><td>Rabbi trust investments</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Cash equivalents</td><td>50</td><td>—</td><td>—</td><td>—</td><td>50</td><td>4</td><td>—</td><td>—</td><td>—</td><td>4</td><td></td><td></td><td></td></tr><tr><td>Mutual funds</td><td>81</td><td>—</td><td>—</td><td>—</td><td>81</td><td>25</td><td>—</td><td>—</td><td>—</td><td>25</td><td></td><td></td><td></td></tr><tr><td>Fixed income</td><td>—</td><td>12</td><td>—</td><td>—</td><td>12</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td><td></td></tr><tr><td>Life insurance contracts</td><td>—</td><td>78</td><td>41</td><td>—</td><td>119</td><td>—</td><td>25</td><td>—</td><td>—</td><td>25</td><td></td><td></td><td></td></tr><tr><td>Rabbi trust investments subtotal</td><td>131</td><td>90</td><td>41</td><td>—</td><td>262</td><td>29</td><td>25</td><td>—</td><td>—</td><td>54</td><td></td><td></td><td></td></tr><tr><td>Commodity derivative assets</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Economic hedges</td><td>768</td><td>2,491</td><td>1,485</td><td>—</td><td>4,744</td><td>768</td><td>2,491</td><td>1,485</td><td>—</td><td>4</td><td></td><td></td><td></td></tr><tr><td>Proprietary trading</td><td>—</td><td>37</td><td>60</td><td>—</td><td>97</td><td>—</td><td>37</td><td>60</td><td>—</td><td>97</td><td></td><td></td><td></td></tr><tr><td>Effect of netting and allocation of collateral(e)(f)</td><td>(908)</td><td>(2,162)</td><td>(588)</td><td>—</td><td>(3,658)</td><td>(908)</td><td>(2,162)</td><td>(588)</td><td>(3,658)</td><td></td><td></td><td></td><td></td></tr><tr><td>Commodity derivative assets subtotal</td><td>(140)</td><td>366</td><td>957</td><td>—</td><td>1,183</td><td>(140)</td><td>366</td><td>957</td><td>—</td><td>1,183</td><td></td><td></td><td></td></tr><tr><td>Total assets</td><td>6,156</td><td>4,061</td><td>1,509</td><td>3,858</td><td>15,584</td><td>5,629</td><td>3,996</td><td>1,468</td><td>3,858</td><td>14,951</td><td></td><td></td><td></td></tr></table>



## Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 17 — Fair Value of Financial Assets and Liabilities

<table><tr><td rowspan="2">As of December 31, 2019</td><td colspan="5">Exelon</td><td colspan="5">Generation</td></tr><tr><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Not subject to leveling</td><td>Total</td><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Not subject to leveling</td><td>Total</td></tr><tr><td>Liabilities</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Commodity derivative liabilities</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Economic hedges</td><td>(1,071)</td><td>(2,855)</td><td>(1,228)</td><td>—</td><td>(5,154)</td><td>(1,071)</td><td>(2,855)</td><td>(927)</td><td>—</td><td>(4,853)</td><td></td></tr><tr><td>Proprietary trading</td><td>—</td><td>(34)</td><td>(15)</td><td>—</td><td>(49)</td><td>—</td><td>(34)</td><td>(15)</td><td>—</td><td>(4,853)</td><td></td></tr><tr><td>Effect of netting and allocation of collateral(e)(f)</td><td>1,071</td><td>2,714</td><td>802</td><td>—</td><td>4,587</td><td>1,071</td><td>2,714</td><td>802</td><td>—</td><td>4.587</td><td></td></tr><tr><td>Commodity derivative liabilities subtotal</td><td>—</td><td>(175)</td><td>(441)</td><td>—</td><td>(616)</td><td>—</td><td>(175)</td><td>(140)</td><td>—</td><td>(315)</td><td></td></tr><tr><td>Deferred compensation obligation</td><td>—</td><td>(147)</td><td>—</td><td>—</td><td>(147)</td><td>—</td><td>(41)</td><td>—</td><td>—</td><td>(41)</td><td></td></tr><tr><td>Total liabilities</td><td>—</td><td>(322)</td><td>(441)</td><td>—</td><td>(763)</td><td>—</td><td>(216)</td><td>(140)</td><td>—</td><td>(356)</td><td></td></tr><tr><td>Total net assets</td><td>$ 6,156</td><td>$ 3,739</td><td>$ 1,068</td><td>$ 3,858</td><td>$ 14,821</td><td>$ 5,629</td><td>$ 3,780</td><td>$ 1,328</td><td>$ 3,858</td><td>$ 14,595</td><td></td></tr></table>

<table><tr><td rowspan="2">As of December 31, 2018</td><td colspan="5">Exelon</td><td colspan="5">Generation</td></tr><tr><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Not subject to leveling</td><td>Total</td><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Not subject to leveling</td><td>Total</td></tr><tr><td>Assets</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Cash equivalents(a)</td><td>$ 1,243</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ 1,243</td><td>$ 581</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ 581</td></tr><tr><td>NDT fund investments</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Cash equivalents(b)</td><td>252</td><td>86</td><td>—</td><td>—</td><td>338</td><td>252</td><td>86</td><td>—</td><td>—</td><td>338</td></tr><tr><td>Equities</td><td>2,918</td><td>1,591</td><td>—</td><td>1,381</td><td>5,890</td><td>2,918</td><td>1,591</td><td>—</td><td>1,381</td><td>1,890</td></tr><tr><td>Fixed income</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Corporate debt</td><td>—</td><td>1,593</td><td>230</td><td>—</td><td>1,823</td><td>—</td><td>1,593</td><td>230</td><td>—</td><td>1,823</td></tr><tr><td>U.S. Treasury and agencies</td><td>2,081</td><td>99</td><td>—</td><td>—</td><td>2,180</td><td>2,081</td><td>99</td><td>—</td><td>—</td><td>2,180</td></tr><tr><td>Foreign governments</td><td>—</td><td>50</td><td>—</td><td>—</td><td>50</td><td>—</td><td>50</td><td>—</td><td>—</td><td>50</td></tr><tr><td>State and municipal debt</td><td>—</td><td>149</td><td>—</td><td>—</td><td>149</td><td>—</td><td>149</td><td>—</td><td>—</td><td>149</td></tr><tr><td>Other(c)</td><td>—</td><td>30</td><td>—</td><td>846</td><td>876</td><td>—</td><td>30</td><td>—</td><td>846</td><td>876</td></tr><tr><td>Fixed income subtotal</td><td>2,081</td><td>1,921</td><td>230</td><td>846</td><td>5,078</td><td>2,081</td><td>1,921</td><td>230</td><td>846</td><td>5.078</td></tr><tr><td>Private credit</td><td>—</td><td>—</td><td>313</td><td>367</td><td>680</td><td>—</td><td>—</td><td>313</td><td>367</td><td>680</td></tr><tr><td>Private equity</td><td>—</td><td>—</td><td>—</td><td>329</td><td>329</td><td>—</td><td>—</td><td>—</td><td>329</td><td>329</td></tr><tr><td>Real estate</td><td>—</td><td>—</td><td>—</td><td>510</td><td>510</td><td>—</td><td>—</td><td>—</td><td>510</td><td>510</td></tr><tr><td>NDT fund investments subtotal(d)</td><td>5,251</td><td>3,598</td><td>543</td><td>3,433</td><td>12,825</td><td>5,251</td><td>3,598</td><td>543</td><td>3,433</td><td></td></tr></table>



## Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 17 — Fair Value of Financial Assets and Liabilities

<table><tr><td rowspan="2">As of December 31, 2018</td><td colspan="5">Exelon</td><td colspan="5">Generation</td></tr><tr><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Not subject to leveling</td><td>Total</td><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Not subject to leveling</td><td>Total</td></tr><tr><td>Rabbi trust investments</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Cash equivalents</td><td>48</td><td>—</td><td>—</td><td>—</td><td>48</td><td>5</td><td>—</td><td>—</td><td>—</td><td>5</td></tr><tr><td>Mutual funds</td><td>72</td><td>—</td><td>—</td><td>—</td><td>72</td><td>24</td><td>—</td><td>—</td><td>—</td><td>24</td></tr><tr><td>Fixed income</td><td>—</td><td>15</td><td>—</td><td>—</td><td>15</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Life insurance contracts</td><td>—</td><td>70</td><td>38</td><td>—</td><td>108</td><td>—</td><td>22</td><td>—</td><td>—</td><td>22</td></tr><tr><td>Rabbi trust investments subtotal</td><td>120</td><td>85</td><td>38</td><td>—</td><td>243</td><td>29</td><td>22</td><td>—</td><td>—</td><td>51</td></tr><tr><td>Commodity derivative assets</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Economic hedges</td><td>541</td><td>2,760</td><td>1,470</td><td>—</td><td>4,771</td><td>541</td><td>2,760</td><td>1,470</td><td>—</td><td>4.771</td></tr><tr><td>Proprietary trading</td><td>—</td><td>69</td><td>77</td><td>—</td><td>146</td><td>—</td><td>69</td><td>77</td><td>—</td><td>146</td></tr><tr><td>Effect of netting and allocation of collateral(e)(f)</td><td>(582)</td><td>(2,357)</td><td>(732)</td><td>—</td><td>(3,671)</td><td>(582)</td><td>(2,357)</td><td>(732)</td><td>-</td><td>(3,671)</td></tr><tr><td>Commodity derivative assets subtotal</td><td>(41)</td><td>472</td><td>815</td><td>—</td><td>1,246</td><td>(41)</td><td>472</td><td>815</td><td>—</td><td>1,246</td></tr><tr><td>Total assets</td><td>6,573</td><td>4,155</td><td>1,396</td><td>3,433</td><td>15,557</td><td>5,820</td><td>4,092</td><td>1,358</td><td>3,433</td><td>14,703</td></tr><tr><td>Liabilities</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Commodity derivative liabilities</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Economic hedges</td><td>(642)</td><td>(2,963)</td><td>(1,276)</td><td>—</td><td>(4,881)</td><td>(642)</td><td>(2,963)</td><td>(1,027)</td><td>—</td><td>(4,632)</td></tr><tr><td>Proprietary trading</td><td>—</td><td>(73)</td><td>(21)</td><td>—</td><td>(94)</td><td>—</td><td>(73)</td><td>(21)</td><td>—</td><td>(84)</td></tr><tr><td>Effect of netting and allocation of collateral(e)(f)</td><td>639</td><td>2,581</td><td>808</td><td>—</td><td>4,028</td><td>639</td><td>2,581</td><td>808</td><td>—</td><td>4,028</td></tr><tr><td>Commodity derivative liabilities subtotal</td><td>(3)</td><td>(455)</td><td>(489)</td><td>—</td><td>(947)</td><td>(3)</td><td>(455)</td><td>(240)</td><td>—</td><td>(698)</td></tr><tr><td>Deferred compensation obligation</td><td>—</td><td>(137)</td><td>—</td><td>—</td><td>(137)</td><td>—</td><td>(35)</td><td>—</td><td>—</td><td>(35)</td></tr><tr><td>Total liabilities</td><td>(3)</td><td>(592)</td><td>(489)</td><td>—</td><td>(1,084)</td><td>(3)</td><td>(490)</td><td>(240)</td><td>—</td><td>(733)</td></tr><tr><td>Total net assets</td><td>$ 6,570</td><td>$ 3,563</td><td>$ 907</td><td>$ 3,433</td><td>$ 14,473</td><td>$ 5,817</td><td>$ 3,602</td><td>$ 1,118</td><td>$ 3,433</td><td>$ 13,970</td></tr></table>

(a) Exelon excludes cash of $373 million and $458 million at December 31, 2019 and 2018, respectively, and restricted cash of $110 million and $80 million at December 31, 2019 and 2018, respectively, and includes long-term restricted cash of $177 million and $185 million at December 31, 2019 and 2018, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. Generation excludes cash of $177 million and $283 million at December 31, 2019 and 2018, respectively and restricted cash of $58 million and $39 million at December 31, 2019 and 2018, respectively.

(b) Includes $90 million and $50 million of cash received from outstanding repurchase agreements at December 31, 2019 and 2018, respectively, and is offset by an obligation to repay upon settlement of the agreement as discussed in (d) below.

(c) Includes derivative instruments of $2 million and $44 million, which have a total notional amount of $724 million and $1,432 million at December 31, 2019 and 2018, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do not represent the amount of the company's exposure to credit or market loss.

(d) Excludes net liabilities of $147 million and $130 million at December 31, 2019 and 2018, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, repurchase agreement obligations, and payables related to pending securities purchases. The repurchase agreements are generally short-term in nature with durations generally of 30 days or less.

(e) Collateral posted/(received) from counterparties totaled $163 million, $551 million and $214 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2019. Collateral posted/(received) from



counterparties totaled $57 million, $224 million and $76 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2018.

(f) Of the collateral posted/(received), $511 million and $(94) million represents variation margin on the exchanges as of December 31, 2019 and 2018, respectively.

As of December 31, 2019, Generation has outstanding commitments to invest in fixed income, private credit, private equity and real estate investments of approximately $85 million, $166 million, $375 million and $427 million, respectively. These commitments will be funded by Generation's existing NDT funds.

Exelon and Generation hold investments without readily determinable fair values with carrying amounts of $69 million as of December 31, 2019. Changes were immaterial in fair value, cumulative adjustments and impairments for the year ended December 31, 2019.

<table><tr><td rowspan="2">As of December 31, 2019</td><td colspan="6">ComEd</td><td colspan="6">PECO</td><td colspan="6">BGE</td></tr><tr><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Total</td><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Total</td><td></td><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Total</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Assets</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Cash equivalents(a)</td><td>$ 280</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ 280</td><td>$ 15</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ 15</td><td>$ —</td><td>$ —</td><td>$ —</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Rabbi trust investments</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Mutual funds</td><td>—</td><td>—</td><td>—</td><td>—</td><td>8</td><td>—</td><td>—</td><td>8</td><td>8</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Life insurance contracts</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>11</td><td>—</td><td>11</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Rabbi trust investments subtotal</td><td>—</td><td>—</td><td>—</td><td>—</td><td>8</td><td>11</td><td>—</td><td>19</td><td>8</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Total assets</td><td>280</td><td>—</td><td>—</td><td>280</td><td>23</td><td>11</td><td>—</td><td>34</td><td>8</td><td>—</td><td>—</td><td>—</td><td>8</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Liabilities</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Deferred compensation obligation</td><td>—</td><td>(8)</td><td>—</td><td>(8)</td><td>—</td><td>(9)</td><td>—</td><td>(9)</td><td>—</td><td>(5)</td><td>—</td><td>(5)</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Mark-to-market derivative liabilities(b)</td><td>—</td><td>—</td><td>(301)</td><td>(301)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Total liabilities</td><td>—</td><td>(8)</td><td>(301)</td><td>(309)</td><td>—</td><td>(9)</td><td>—</td><td>(9)</td><td>—</td><td>(5)</td><td>—</td><td>(5)</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Total net assets (liabilities)</td><td>$ 280</td><td>$ (8)</td><td>$ (301)</td><td>$ (29)</td><td>$ 23</td><td>$ 2</td><td>$ —</td><td>$ 25</td><td>$ 8</td><td>$ (5)</td><td>$ —</td><td>$ 3</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr></table>



## Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 17 — Fair Value of Financial Assets and Liabilities

<table><tr><td rowspan="2">As of December 31, 2018</td><td colspan="6">ComEd</td><td colspan="6">PECO</td><td colspan="6">BGE</td></tr><tr><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Total</td><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Total</td><td></td><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Total</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Assets</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Cash equivalents(a)</td><td>$ 209</td><td>$ —</td><td>$ —</td><td>$ 209</td><td>$ 111</td><td>$ —</td><td>$ —</td><td>$ 111</td><td>$ 4</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ 4</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Rabbi trust investments</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Mutual funds</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>7</td><td>—</td><td>—</td><td>7</td><td>6</td><td>—</td><td>—</td><td>—</td><td>6</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Life insurance contracts</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>10</td><td>—</td><td>—</td><td>10</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Rabbi trust investments subtotal</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>7</td><td>10</td><td>—</td><td>17</td><td>6</td><td>—</td><td>—</td><td>—</td><td>6</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Total assets</td><td>209</td><td>—</td><td>—</td><td>—</td><td>209</td><td>118</td><td>10</td><td>—</td><td>128</td><td>10</td><td>—</td><td>—</td><td>—</td><td>10</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Liabilities</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Deferred compensation obligation</td><td>—</td><td>(6)</td><td>—</td><td>(6)</td><td>—</td><td>(10)</td><td>—</td><td>(10)</td><td>—</td><td>(5)</td><td>—</td><td>—</td><td>(5)</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Mark-to-market derivative liabilities(b)</td><td>—</td><td>—</td><td>(249)</td><td>(249)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td>—</td><td>—</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Total liabilities</td><td>—</td><td>(6)</td><td>(249)</td><td>(255)</td><td>—</td><td>(10)</td><td>—</td><td>(10)</td><td>—</td><td>(5)</td><td>—</td><td>—</td><td>(5)</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Total net assets (liabilities)</td><td>$ 209</td><td>$ (6)</td><td>$ (249)</td><td>$ (46)</td><td>$ 118</td><td>$ —</td><td>$ —</td><td>$ 118</td><td>$ 10</td><td>$ (5)</td><td>$ —</td><td>$ —</td><td>$ 5</td><td></td><td></td><td></td><td></td><td></td><td></td></tr></table>

(a) ComEd excludes cash of $90 million and $93 million at December 31, 2019 and 2018 and restricted cash of $33 million and $28 million at December 31, 2019 and 2018, respectively, and includes long-term restricted cash of $163 million and $166 million at December 31, 2019 and 2018, respectively which is reported in Other deferred debits in the Consolidated Balance Sheets. PECO excludes cash of $12 million and $24 million at December 31, 2019 and 2018, respectively. BGE excludes cash of $24 million and $7 million at December 31, 2019 and 2018, respectively, and restricted cash of $1 million and $2 million at December 31, 2019 and 2018, respectively.

(b) The Level 3 balance consists of the current and noncurrent liability of $32 million and $269 million, respectively, at December 31, 2019, and $26 million and $223 million, respectively, at December 31, 2018, related to floating-to-fixed energy swap contracts with unaffiliated suppliers.

<table><tr><td rowspan="2">PHI</td><td colspan="6">As of December 31, 2019</td><td colspan="6">As of December 31, 2018</td></tr><tr><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Total</td><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Total</td><td></td><td></td><td></td><td></td></tr><tr><td>Assets</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Cash equivalents(a)</td><td>$ 124</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ 124</td><td>$ 147</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ 147</td><td></td><td></td><td></td></tr><tr><td>Rabbi trust investments</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Cash equivalents</td><td>44</td><td>—</td><td>—</td><td>44</td><td>42</td><td>—</td><td>—</td><td>—</td><td>42</td><td></td><td></td><td></td><td></td></tr><tr><td>Mutual Funds</td><td>14</td><td>—</td><td>—</td><td>14</td><td>13</td><td>—</td><td>—</td><td>—</td><td>13</td><td></td><td></td><td></td><td></td></tr><tr><td>Fixed income</td><td>—</td><td>12</td><td>—</td><td>12</td><td>—</td><td>15</td><td>—</td><td>—</td><td>15</td><td></td><td></td><td></td><td></td></tr><tr><td>Life insurance contracts</td><td>—</td><td>24</td><td>41</td><td>65</td><td>—</td><td>22</td><td>38</td><td>60</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Rabbi trust investments subtotal(b)</td><td>58</td><td>36</td><td>41</td><td>135</td><td>55</td><td>37</td><td>38</td><td>130</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Total assets</td><td>182</td><td>36</td><td>41</td><td>259</td><td>202</td><td>37</td><td>38</td><td>277</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Liabilities</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Deferred compensation obligation</td><td>—</td><td>(19)</td><td>—</td><td>(19)</td><td>—</td><td>(21)</td><td>—</td><td>(21)</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Total liabilities</td><td>—</td><td>(19)</td><td>—</td><td>(19)</td><td>—</td><td>(21)</td><td>—</td><td>(21)</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Total net assets</td><td>$ 182</td><td>$ 17</td><td>$ 41</td><td>$ 240</td><td>$ 202</td><td>$ 16</td><td>$ 38</td><td>$ 256</td><td></td><td></td><td></td><td></td><td></td></tr></table>



## Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 17 — Fair Value of Financial Assets and Liabilities

<table><tr><td rowspan="2"></td><td colspan="6">Pepco</td><td colspan="6">DPL</td><td colspan="6">ACE</td></tr><tr><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Total</td><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Total</td><td></td><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Total</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Assets</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Cash equivalents(a)</td><td>$ 34</td><td>$ —</td><td>$ —</td><td>$ 34</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ 16</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ 16</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Rabbi trust investments</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Cash equivalents</td><td>43</td><td>—</td><td>—</td><td>43</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td></tr><tr><td>Fixed income</td><td>—</td><td>2</td><td>—</td><td>2</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td></tr><tr><td>Life insurance contracts</td><td>—</td><td>24</td><td>41</td><td>65</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td></tr><tr><td>Rabbi trust investments subtotal</td><td>43</td><td>26</td><td>41</td><td>110</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td></tr><tr><td>Total assets</td><td>77</td><td>26</td><td>41</td><td>144</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>16</td><td>—</td><td>—</td><td>—</td><td>16</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Liabilities</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Deferred compensation obligation</td><td>—</td><td>(2)</td><td>—</td><td>(2)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td></tr><tr><td>Total liabilities</td><td>—</td><td>(2)</td><td>—</td><td>(2)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td></tr><tr><td>Total net assets</td><td>$ 77</td><td>$ 24</td><td>$ 41</td><td>$ 142</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ 16</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ 16</td><td></td><td></td><td></td><td></td><td></td></tr></table>

<table><tr><td rowspan="2">As of December 31, 2018</td><td colspan="6">Pepco</td><td colspan="6">DPL</td><td colspan="6">ACE</td></tr><tr><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Total</td><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Total</td><td></td><td>Level 1</td><td>Level 2</td><td>Level 3</td><td>Total</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Assets</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Cash equivalents(a)</td><td>$ 38</td><td>$ —</td><td>$ —</td><td>$ 38</td><td>$ 16</td><td>$ —</td><td>$ —</td><td>$ 16</td><td>$ 23</td><td>$ —</td><td>$ —</td><td>$ 23</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Rabbi trust investments</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Cash equivalents</td><td>41</td><td>—</td><td>—</td><td>41</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td></tr><tr><td>Fixed income</td><td>—</td><td>5</td><td>—</td><td>5</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td></tr><tr><td>Life insurance contracts</td><td>—</td><td>22</td><td>37</td><td>59</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td></tr><tr><td>Rabbi trust investments subtotal</td><td>41</td><td>27</td><td>37</td><td>105</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td></tr><tr><td>Total assets</td><td>79</td><td>27</td><td>37</td><td>143</td><td>16</td><td>—</td><td>—</td><td>16</td><td>23</td><td>—</td><td>—</td><td>—</td><td>23</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Liabilities</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Deferred compensation obligation</td><td>—</td><td>(3)</td><td>—</td><td>(3)</td><td>—</td><td>(1)</td><td>—</td><td>(1)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td><td></td><td></td></tr><tr><td>Total liabilities</td><td>—</td><td>(3)</td><td>—</td><td>(3)</td><td>—</td><td>(1)</td><td>—</td><td>(1)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td><td></td><td></td></tr><tr><td>Total net assets</td><td>$ 79</td><td>$ 24</td><td>$ 37</td><td>$ 140</td><td>$ 16</td><td>$ (1)</td><td>$ —</td><td>$ 15</td><td>$ 23</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ 23</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr></table>

(a) PHI excludes cash of $57 million and $39 million at December 31, 2019 and 2018, respectively, and includes long term restricted cash of $14 million and $19 million at December 31, 2019 and 2018, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. Pepco excludes cash of $29 million and $15 million at December 31, 2019 and 2018, respectively. DPL excludes cash of $13 million and $8 million at December 31, 2019 and 2018, respectively. ACE excludes cash of $12 million and $7 million at December 31, 2019 and 2018, respectively, and includes long-term restricted cash of $14 million and $19 million at December 31, 2019 and 2018, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets.



## Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 17 — Fair Value of Financial Assets and Liabilities

The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 2019 and 2018:

<table><tr><td rowspan="2">For the year ended December 31, 2019</td><td colspan="2">Exelon</td><td colspan="2">Generation</td><td colspan="2">ComEd</td><td colspan="2">PHI and Pepco</td><td rowspan="2">Eliminated in Consolidation</td></tr><tr><td>Total</td><td>NDT Fund Investments</td><td>Mark-to-Market Derivatives</td><td>Total Generation</td><td>Mark-to-Market Derivatives</td><td>Life Insurance Contracts</td><td></td><td></td></tr><tr><td>Balance as of January 1, 2019</td><td>$     907</td><td>$     543</td><td>$     575</td><td>$     1,118</td><td>$      (249)</td><td>$     38</td><td>$     38</td><td>—</td><td></td></tr><tr><td>Total realized / unrealized gains (losses)</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Included in net income</td><td>(23)</td><td>5</td><td>(31) (a)</td><td>(26)</td><td>—</td><td>3</td><td>—</td><td></td><td></td></tr><tr><td>Included in noncurrent payables to affiliates</td><td>—</td><td>34</td><td>—</td><td>34</td><td>—</td><td>—</td><td>—</td><td>(34)</td><td></td></tr><tr><td>Included in regulatory assets/liabilities</td><td>(18)</td><td>—</td><td>—</td><td>—</td><td>(52) (b)</td><td>—</td><td>—</td><td>34</td><td></td></tr><tr><td>Change in collateral</td><td>138</td><td>—</td><td>138</td><td>138</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td></tr><tr><td>Purchases, sales, issuances and settlements</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Purchases</td><td>176</td><td>44</td><td>132</td><td>176</td><td>—</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Sales</td><td>(23)</td><td>(21)</td><td>(2)</td><td>(23)</td><td>—</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Settlements</td><td>(89)</td><td>(94)</td><td>5</td><td>(89)</td><td>—</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Transfers into Level 3</td><td>5</td><td>—</td><td>5 (c)</td><td>5</td><td>—</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Transfers out of Level 3</td><td>(5)</td><td>—</td><td>(5) (c)</td><td>(5)</td><td>—</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Balance as of December 31, 2019</td><td>$     1,068</td><td>$     511</td><td>$     817</td><td>$     1,328</td><td>$      (301)</td><td>$     41</td><td>$     41</td><td>—</td><td></td></tr><tr><td>The amount of total gains (losses) included in income attributed to the change in unrealized (losses) gains related to assets and liabilities held as of December 31, 2019</td><td>$     359</td><td>$     5</td><td>$     351</td><td>$     356</td><td>$     3</td><td>$     3</td><td>$     3</td><td>—</td><td></td></tr></table>



## Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 17 — Fair Value of Financial Assets and Liabilities

<table><tr><td rowspan="2">For the year ended December 31, 2018</td><td colspan="2">Exelon</td><td colspan="2">Generation</td><td colspan="2">ComEd</td><td colspan="2">PHI and Pepco</td><td rowspan="2">Eliminated in Consolidation</td></tr><tr><td>Total</td><td>NDT Fund Investments</td><td>Mark-to-Market Derivatives</td><td>Total Generation</td><td>Mark-to-Market Derivatives</td><td>Life Insurance Contracts</td><td></td><td></td></tr><tr><td>Balance as of January 1, 2018</td><td>$ 966</td><td>$ 648</td><td>$ 552</td><td>$ 1,200</td><td>$ (256)</td><td>$ 22</td><td>$</td><td>—</td><td></td></tr><tr><td>Total realized / unrealized gains (losses)</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Included in net income</td><td>(101)</td><td>—</td><td>(105)</td><td>(105)</td><td>—</td><td></td><td>4</td><td></td><td>—</td></tr><tr><td>Included in noncurrent payables to affiliates</td><td>—</td><td>(1)</td><td>—</td><td>(1)</td><td>—</td><td></td><td>—</td><td></td><td>1</td></tr><tr><td>Included in regulatory assets/liabilities</td><td>6</td><td>—</td><td>—</td><td>—</td><td>7</td><td>(b)</td><td>—</td><td></td><td>(1)</td></tr><tr><td>Change in collateral</td><td>(5)</td><td>—</td><td>(5)</td><td>(5)</td><td>—</td><td></td><td>—</td><td></td><td>—</td></tr><tr><td>Purchases, sales, issuances and settlements</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Purchases</td><td>226</td><td>36</td><td>190</td><td>226</td><td>—</td><td></td><td>—</td><td></td><td>—</td></tr><tr><td>Sales</td><td>(4)</td><td>—</td><td>(4)</td><td>(4)</td><td>—</td><td></td><td>—</td><td></td><td>—</td></tr><tr><td>Settlements</td><td>(123)</td><td>(140)</td><td>5</td><td>(135)</td><td>—</td><td></td><td>12</td><td></td><td>—</td></tr><tr><td>Transfers into Level 3</td><td>(22)</td><td>—</td><td>(22)</td><td>(22)</td><td>—</td><td></td><td>—</td><td></td><td>—</td></tr><tr><td>Transfers out of Level 3</td><td>(36)</td><td>—</td><td>(36)</td><td>(36)</td><td>—</td><td></td><td>—</td><td></td><td>—</td></tr><tr><td>Balance as of December 31, 2018</td><td>$ 907</td><td>$ 543</td><td>$ 575</td><td>$ 1,118</td><td>$ (249)</td><td>$ 38</td><td>$</td><td>—</td><td></td></tr><tr><td>The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held as of December 31, 2018</td><td>$ 160</td><td>$ (5)</td><td>$ 165</td><td>$ 160</td><td>$ —</td><td>$ —</td><td>$ —</td><td></td><td>—</td></tr></table>

(a) Includes a reduction for the reclassification of $377 million and $265 million of realized gains due to the settlement of derivative contracts for the years ended December 31, 2019 and 2018, respectively.

(b) Includes $78 million of decreases in fair value and an increase for realized losses due to settlements of $26 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2019. Includes $24 million of decreases in fair value and an increase for realized losses due to settlements of $17 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2018.

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

The following 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 years ended December 31, 2019 and 2018:

<table><tr><td rowspan="2"></td><td colspan="6">Exelon</td><td colspan="3">Generation</td><td colspan="2">PHI and Pepco</td></tr><tr><td>Operating Revenues</td><td>Purchased Power and Fuel</td><td>Operating and Maintenance</td><td>Other, net</td><td>Operating Revenues</td><td>Purchased Power and Fuel</td><td>Other, net</td><td>Operating and Maintenance</td><td></td><td></td><td></td></tr><tr><td>Total gains (losses) included in net income for the year ended December 31, 2019</td><td>$ 219</td><td>$ (245)</td><td>$ 3</td><td>$ 5</td><td>$ 219</td><td>$ (245)</td><td>$ 5</td><td>$ 3</td><td></td><td></td><td></td></tr><tr><td>Change in the unrealized gains (losses) relating to assets and liabilities held for the year ended December 31, 2019</td><td>546</td><td>(195)</td><td>3</td><td>5</td><td>546</td><td>(195)</td><td>5</td><td></td><td></td><td></td><td></td></tr><tr><td></td><td></td><td></td><td></td><td>332</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr></table>



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 17 — Fair Value of Financial Assets and Liabilities

<table><tr><td rowspan="2"></td><td colspan="6">Exelon</td><td colspan="3">Generation</td><td colspan="2">PHI and Pepco</td></tr><tr><td>Operating Revenues</td><td>Purchased Power and Fuel</td><td>Operating and Maintenance</td><td>Other, net</td><td>Operating Revenues</td><td>Purchased Power and Fuel</td><td>Other, net</td><td>Operating and Maintenance</td><td></td><td></td></tr><tr><td>Total (losses) gains included in net income for the year ended December 31, 2018</td><td>$ (7)</td><td>$ (93)</td><td>$ 4</td><td>$ 3</td><td>$ (7)</td><td>$ (93)</td><td>$ 3</td><td>$ 3</td><td>$ 4</td><td></td></tr><tr><td>Change in the unrealized gains (losses) relating to assets and liabilities held for the year ended December 31, 2018</td><td>144</td><td>21</td><td>—</td><td>(2)</td><td>144</td><td>21</td><td>(2)</td><td>—</td><td></td><td></td></tr></table>

Valuation Techniques Used to Determine Fair Value

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

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

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

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

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



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 17 — Fair Value of Financial Assets and Liabilities

are based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences and are categorized as Level 2.

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

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

Private credit. Private credit investments primarily consist of investments in private debt strategies. These investments are generally less liquid assets with an underlying term of 3 to 5 years and are intended to be held to maturity. The fair value of these investments is determined by the fund manager or administrator and include unobservable inputs such as cost, operating results, and discounted cash flows. Private credit investments held directly by Elevon and Generation are categorized as Level 3 because they are based largely on inputs that are unobservable and utilize complex valuation models. Private credit fund investments with multiple investors are not classified within the fair value hierarchy because their fair value is determined using NAV or its equivalent as a practical expedient.

Private equity. These investments include those in limited partnerships that invest in operating companies that are not publicly traded on a stock exchange such as leveraged buyouts, growth capital, venture capital, distressed investments and investments in natural resources. Private equity valuations are reported by the fund manager and are based on the valuation of the underlying investments, which include unobservable inputs such as cost, operating results, discounted future cash flows and market based comparable data. The fair value of private equity investments is determined using NAV or its equivalent as a practical expedient, and therefore, these investments are not classified within the fair value hierarchy.

Real estate. These investments are funds with a direct investment in pools of real estate properties. These funds are valued by investment managers on a periodic basis using pricing models that use independent appraisals from sources with professional qualifications. These valuation inputs are not highly observable. The fair value of real estate investments is determined using NAV or its equivalent as a practical expedient, and therefore, these investments are not classified within the fair value hierarchy.

Generation evaluated its NDT portfolios for the existence of significant concentrations of credit risk as of December 31, 2019. Types of concentrations that were evaluated include, but are not limited to, investment concentrations in a single entity, type of industry, foreign country, and individual fund. As of December 31, 2019, there were no significant concentrations (generally defined as greater than 10 percent) of risk in Generation's NDT assets.

See Note 9 — Asset Retirement Obligations for additional information on the NDT fund investments. See Note 14 — Retirement Benefits for the valuation techniques used for hedge fund investments.

Rabbi Trust Investments (Exelon, Generation, PECO, BGE, PHI, Pepco, DPL and ACE). The Rabbi trusts were established to hold assets related to deferred compensation plans existing for certain active and retired members of Exelon's executive management and directors. The Rabbi trusts' assets are included in investments in the Registrants' Consolidated Balance Sheets and consist primarily of money market funds, mutual funds, fixed income securities and life insurance policies. Money market funds and mutual funds are publicly quoted and have been categorized as Level 1 given the clear observability of the prices. The fair values of fixed income securities are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities, adjusted for observable differences and are categorized in Level 2. The life insurance policies are valued using the cash surrender value of the policies, net of loans against those policies, which is provided by a third-party. Certain life insurance policies, which consist primarily of mutual funds that are priced based on observable market



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 17 — Fair Value of Financial Assets and Liabilities

data, have been categorized as Level 2 because the life insurance policies can be liquidated at the reporting date for the value of the underlying assets. Life insurance policies that are valued using unobservable inputs have been categorized as Level 3, where the fair value is determined based on the cash surrender value of the policy, which contains unobservable inputs and assumptions. Because Exelon relies on its third-party insurance provider to develop the inputs without adjustment for the valuations of its Level 3 investments, quantitative information about significant unobservable inputs used in valuing these investments is not reasonably available to Exelon. Therefore, Exelon has not disclosed such inputs.

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

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

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

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

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



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 17 — Fair Value of Financial Assets and Liabilities

For commodity derivatives, the primary input to the valuation models is the forward commodity price curve for each instrument. Forward commodity price curves are derived by risk management for liquid locations and by the traders and portfolio managers for illiquid locations. All locations are reviewed and verified by risk management considering published exchange transaction prices, executed bilateral transactions, broker quotes, and other observable or public data sources. The relevant forward commodity curve used to value each of the derivatives depends on a number of factors, including commodity type, delivery location, and delivery period. Price volatility varies by commodity and location. When appropriate, Generation discounts future cash flows using risk free interest rates with adjustments to reflect the credit quality of each counterparty for assets and Generation's own credit quality for liabilities. The level of observability of a forward commodity price varies generally due to the delivery location and delivery period. Certain delivery locations including PJM West Hub (for power) and Henry Hub (for natural gas) are more liquid and prices are observable for up to three years in the future. The observability period of volatility is generally shorter than the underlying power curve used in option valuations. The forward curve for a less liquid location is estimated by using the forward curve from the liquid location and applying a spread to represent the cost to transport the commodity to the delivery location. This spread does not typically represent a majority of the instrument's market price. As a result, the change in fair value is closely tied to liquid market movements and not a change in the applied spread. The change in fair value associated with a change in the spread is generally immaterial. An average spread calculated across all Level 3 power and gas delivery locations is approximately $2.22 and $0.54 for power and natural gas, respectively. Many of the commodity derivatives are short term in nature and thus a majority of the fair value may be based on observable inputs even though the contract as a whole must be classified as Level 3.

On December 17, 2010, ComEd entered into several 20-year floating to fixed energy swap contracts with unaffiliated suppliers for the procurement of long-term renewable energy and associated RECs. See Note 15 — Derivative Financial Instruments for additional information. The fair value of these swaps has been designated as a Level 3 valuation due to the long tenure of the positions and internal modeling assumptions. The modeling assumptions include using natural gas heat rates to project long term forward power curves adjusted by a renewable factor that incorporates time of day and seasonality factors to reflect accurate renewable energy pricing. In addition, marketability reserves are applied to the positions based on the tenor and supplier risk.

See Note 15 — Derivative Financial Instruments for additional information on mark-to-market derivatives.



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 17 — Fair Value of Financial Assets and Liabilities

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

<table><tr><td>Type of trade</td><td colspan="2">Fair Value at December 31, 2019</td><td colspan="2">Fair Value at December 31, 2018</td><td>Valuation Technique</td><td colspan="2">Unobservable Input</td><td colspan="2">2019 Range</td><td colspan="2">2018 Range</td></tr><tr><td>Mark-to-market derivatives—Economic hedges (Exelon and Generation)(a)(b)</td><td>$</td><td>558</td><td>$</td><td>443</td><td>Discounted Cash Flow</td><td>Forward power price</td><td>$9</td><td>-</td><td>$180</td><td>$12</td><td>-</td></tr><tr><td></td><td></td><td></td><td></td><td></td><td></td><td>Forward gas price</td><td>$0.83</td><td>-</td><td>$10.72</td><td>$0.78</td><td>-</td></tr><tr><td></td><td></td><td></td><td></td><td></td><td>Option Model</td><td>Volatility percentage</td><td>8%</td><td>-</td><td>236%</td><td>10%</td><td>-</td></tr><tr><td>Mark-to-market derivatives—Proprietary trading (Exelon and Generation)(a)(b)</td><td>$</td><td>45</td><td>$</td><td>56</td><td>Discounted Cash Flow</td><td>Forward power price</td><td>$25</td><td>-</td><td>$180</td><td>$14</td><td>-</td></tr><tr><td>Mark-to-market derivatives (Exelon and ComEd)</td><td>$</td><td>(301)</td><td>$</td><td>(249)</td><td>Discounted Cash Flow</td><td>Forward heat rate(c)</td><td>9X</td><td>-</td><td>10X</td><td>10X</td><td>-</td></tr><tr><td></td><td></td><td></td><td></td><td></td><td></td><td>Marketability reserve</td><td>3%</td><td>-</td><td>7%</td><td>4%</td><td>-</td></tr><tr><td></td><td></td><td></td><td></td><td></td><td></td><td>Renewable factor</td><td>91%</td><td>-</td><td>123%</td><td>86%</td><td>-</td></tr></table>

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

(b) The fair values do not include cash collateral posted on level three positions of $214 million and $76 million as of December 31, 2019 and December 31, 2018, respectively.

(c) Quoted forward natural gas rates are utilized to project the forward power curve for the delivery of energy at specified future dates. The natural gas curve is extrapolated beyond its observable period to the end of the contract's delivery.

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 Generation's 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 Generation the obligation or option to purchase a commodity), with offsetting impacts to short positions (contracts that give Generation 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 reserves listed above would decrease the fair value of the positions. 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.



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 18 — Commitments and Contingencies

## 18. Commitments and Contingencies (All Registrants)

## Commitments

PHI Merger Commitments (Exelon, PHI, Pepco, DPL and ACE). Approval of the PHI Merger in Delaware, New Jersey, Maryland and the District of Columbia was conditioned upon Exelon and PHI agreeing to certain commitments. The following amounts represent total commitment costs that have been recorded since the acquisition date and the total remaining obligations for Exelon, PHI, Pepco, DPL and ACE as of December 31, 2019:

<table><tr><td>Description</td><td>Exelon</td><td>PHI</td><td>Pepco</td><td>DPL</td><td>ACE</td></tr><tr><td>Total commitments</td><td>$ 513</td><td>$ 320</td><td>$ 120</td><td>$ 89</td><td>$ 111</td></tr><tr><td>Remaining commitments \( ^{(a)} \)</td><td>$ 101</td><td>$ 79</td><td>$ 65</td><td>$ 8</td><td>$ 6</td></tr></table>

(a) Remaining commitments extend through 2026 and include rate credits, energy efficiency programs and delivery system modernization.

In addition, Exelon is committed to develop or to assist in the commercial development of approximately 37 MWs of new solar generation in Maryland, District of Columbia, and Delaware at an estimated cost of approximately $127 million, which will generate future earnings at Exelon and Generation. Investment costs, which are expected to be primarily capital in nature, are recognized as incurred and recorded in Exelon's and Generation's financial statements. As of December 31, 2019, 27 MWs of new generation were developed and Exelon and Generation have incurred costs of $120 million. Exelon has also committed to purchase 100 MWs of wind energy in PJM. DPL has committed to conducting three RFPs to procure up to a total of 120 MWs of wind RECs for the purpose of meeting Delaware's renewable portfolio standards. DPL has conducted two of the three wind REC RFPs. The first 40 MW wind REC tranche was conducted in 2017 and did not result in a purchase agreement. The second 40 MW wind REC tranche was conducted in 2018 and resulted in a proposed REC purchase agreement that was approved by the DPSC in March 2019. The third and final 40 MW wind REC tranche will be conducted in 2022.



Commercial Commitments (All Registrants). The Registrants' commercial commitments as of December 31, 2019, representing commitments potentially triggered by future events, were as follows:

<table><tr><td rowspan="2">Exelon</td><td rowspan="2">Total</td><td colspan="8">Expiration within</td></tr><tr><td>2020</td><td>2021</td><td>2022</td><td>2023</td><td>2024</td><td>2025 and beyond</td><td></td><td></td></tr><tr><td>Letters of credit</td><td>$ 1,455</td><td>$ 1,314</td><td>$ 141</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td></td></tr><tr><td>Surety bonds(a)</td><td>855</td><td>809</td><td>46</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td></tr><tr><td>Financing trust guarantees</td><td>378</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>378</td><td></td></tr><tr><td>Guaranteed lease residual values(b)</td><td>26</td><td>2</td><td>2</td><td>4</td><td>3</td><td>6</td><td>10</td><td></td><td></td></tr><tr><td>Total commercial commitments</td><td>$ 2,714</td><td>$ 2,125</td><td>$ 189</td><td>$ 4</td><td>$ 3</td><td>$ 6</td><td>$ 388</td><td></td><td></td></tr><tr><td colspan="10"></td></tr><tr><td>Generation</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Letters of credit</td><td>$ 1,440</td><td>$ 1,302</td><td>$ 138</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td></td></tr><tr><td>Surety bonds(a)</td><td>670</td><td>662</td><td>8</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td></tr><tr><td>Total commercial commitments</td><td>$ 2,110</td><td>$ 1,964</td><td>$ 146</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td></td></tr><tr><td colspan="10"></td></tr><tr><td>ComEd</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Letters of credit</td><td>$ 7</td><td>$ 7</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td></td></tr><tr><td>Surety bonds(a)</td><td>50</td><td>48</td><td>2</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td></tr><tr><td>Financing trust guarantees</td><td>200</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>200</td><td></td></tr><tr><td>Total commercial commitments</td><td>$ 257</td><td>$ 55</td><td>$ 2</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ 200</td><td></td></tr><tr><td colspan="10"></td></tr><tr><td>PECO</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Surety bonds(a)</td><td>$ 9</td><td>$ 9</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td></td></tr><tr><td>Financing trust guarantees</td><td>178</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>178</td><td></td></tr><tr><td>Total commercial commitments</td><td>$ 187</td><td>$ 9</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ 178</td><td></td></tr><tr><td colspan="10"></td></tr><tr><td>BGE</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Letters of credit</td><td>$ 2</td><td>$ 2</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td></td></tr><tr><td>Surety bonds(a)</td><td>3</td><td>3</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td></tr><tr><td>Total commercial commitments</td><td>$ 5</td><td>$ 5</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td></td></tr><tr><td colspan="10"></td></tr><tr><td>PHI</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Surety bonds(a)</td><td>$ 21</td><td>$ 21</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td></td></tr><tr><td>Guaranteed lease residual values(b)</td><td>26</td><td>2</td><td>2</td><td>4</td><td>3</td><td>6</td><td>10</td><td></td><td></td></tr><tr><td>Total commercial commitments</td><td>$ 47</td><td>$ 23</td><td>$ 2</td><td>$ 4</td><td>$ 3</td><td>$ 6</td><td>$ 10</td><td></td><td></td></tr><tr><td colspan="10"></td></tr><tr><td>Pepco</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Surety bonds(a)</td><td>$ 14</td><td>$ 14</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td></td></tr><tr><td>Guaranteed lease residual values(b)</td><td>9</td><td>—</td><td>—</td><td>1</td><td>1</td><td>2</td><td>5</td><td></td><td></td></tr><tr><td>Total commercial commitments</td><td>$ 23</td><td>$ 14</td><td>$ —</td><td>$ —</td><td>$ 1</td><td>$ 2</td><td>$ 5</td><td></td><td></td></tr><tr><td colspan="10"></td></tr><tr><td>DPL</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Surety bonds(a)</td><td>$ 4</td><td>$ 4</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td></td></tr><tr><td>Guaranteed lease residual values(b)</td><td>11</td><td>1</td><td>1</td><td>2</td><td>1</td><td>3</td><td>3</td><td></td><td></td></tr><tr><td>Total commercial commitments</td><td>$ 15</td><td>$ 5</td><td>$ 1</td><td>$ 2</td><td>$ 1</td><td>$ 3</td><td>$ 3</td><td></td><td></td></tr><tr><td colspan="10"></td></tr><tr><td>ACE</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Surety bonds(a)</td><td>$ 3</td><td>$ 3</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td></td></tr><tr><td>Guaranteed lease residual values(b)</td><td>7</td><td>1</td><td>1</td><td>1</td><td>1</td><td>1</td><td>2</td><td></td><td></td></tr><tr><td>Total commercial commitments</td><td>$ 10</td><td>$ 4</td><td>$ 1</td><td>$ 1</td><td>$ 1</td><td>$ 1</td><td>$ 2</td><td></td><td></td></tr></table>






# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 18 — Commitments and Contingencies

(b) Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The lease term associated with these assets ranges from 1 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $69 million guaranteed by Exelon and PHI, of which $23 million, $29 million and $18 million is guaranteed by Pepco, DPL and ACE, respectively. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.

## Nuclear Insurance (Exelon and Generation)

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

The Price-Anderson Act was enacted to ensure the availability of funds for public liability claims arising from an incident at any of the U.S. licensed nuclear facilities and to limit the liability of nuclear reactor owners for such claims from any single incident. As of December 31, 2019, the current liability limit per incident is $13.9 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors at least once every five years with the last adjustment effective November 1, 2018. In accordance with the Price-Anderson Act, Generation maintains financial protection at levels equal to the amount of liability insurance available from private sources through the purchase of private nuclear energy liability insurance for public liability claims that could arise in the event of an incident. Effective January 1, 2017, the required amount of nuclear energy liability insurance purchased is $450 million for each operating site. Claims exceeding that amount are covered through mandatory participation in a financial protection pool, as required by the Price Anderson Act, which provides the additional $13.5 billion per incident in funds available for public liability claims. Participation in this secondary financial protection pool requires the operator of each reactor to fund its proportionate share of costs for any single incident that exceeds the primary layer of financial protection. Exelon's share of this secondary layer would be approximately $2.9 billion, however any amounts payable under this secondary layer would be capped at $434 million per year.

In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay public liability claims exceeding the $13.9 billion limit for a single incident.

As part of the execution of the NOSA on April 1, 2014, Generation executed an Indemnity Agreement pursuant to which Generation agreed to indemnify EDF and its affiliates against third-party claims that may arise from any future nuclear incident (as defined in the Price-Anderson Act) in connection with the CENG nuclear plants or their operations. Exelon guarantees Generation's obligations under this indemnity. See Note 22 — Variable Interest Entities for additional information on Generation's operations relating to CENG.

Generation is required each year to report to the NRC the current levels and sources of property insurance that demonstrates Generation possesses sufficient financial resources to stabilize and decontaminate a reactor and reactor station site in the event of an accident. The property insurance maintained for each facility is currently provided through insurance policies purchased from NEIL, an industry mutual insurance company of which Generation is a member.

NEIL may declare distributions to its members as a result of favorable operating experience. In recent years, NEIL has made distributions to its members, but Generation cannot predict the level of future distributions or if they will continue at all. Generation's portion of the annual distribution declared by NEIL is estimated to be $136 million for 2019, and was $58 million and $60 million for 2018 and 2017, respectively. In addition, in March 2018, NEIL declared a supplemental distribution. Generation's portion of the supplemental distribution declared by NEIL was $31 million. The distributions were recorded as a reduction to Operating and maintenance expense within Exelon and Generation's Consolidated Statements of Operations and Comprehensive Income.

Premiums paid to NEIL by its members are also subject to a potential assessment for adverse loss experience in the form of a retrospective premium obligation. NEIL has never assessed this retrospective premium since its formation in 1973, and Generation cannot predict the level of future assessments, if any. The current maximum aggregate annual retrospective premium obligation for Generation is approximately $334 million. NEIL requires its members to maintain an investment grade credit rating or to ensure collectability of their annual retrospective premium obligation by providing a financial guarantee, letter of credit, deposit premium, or some other means of assurance.



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 18 — Commitments and Contingencies

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

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

## Spent Nuclear Fuel Obligation (Exelon and Generation)

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

Generation currently assumes the DOE will begin accepting SNF in 2030 and uses that date for purposes of estimating the nuclear decommissioning asset retirement obligations. The SNF acceptance date assumption is based on management's estimates of the amount of time required for DOE to select a site location and develop the necessary infrastructure for long-term SNF storage.

The NWPA and the Standard Contracts required the DOE to begin taking possession of SNF generated by nuclear generating units by no later than January 31, 1998. The DOE, however, failed to meet that deadline and its performance is expected to be delayed significantly. In August 2004, Generation and the DOJ, in close consultation with the DOE, reached a settlement under which the government agreed to reimburse Generation, subject to certain damage limitations based on the extent of the government's breach, for costs associated with storage of SNF at Generation's nuclear stations pending the DOE's fulfillment of its obligations. Generation's settlement agreement does not include FitzPatrick and FitzPatrick does not currently have a settlement agreement in place. Calvert Cliffs, Ginn and Nine Mile Point each have separate settlement agreements in place with the DOE which were extended during 2017 to provide for the reimbursement of SNF storage costs through December 31, 2019. Generation expects the terms for each of the settlement agreements to be extended during 2020 for another three years to cover SNF storage costs through December 31, 2022. Generation submits annual reimbursement requests to the DOE for costs associated with the storage of SNF. In all cases, reimbursement requests are made only after costs are incurred and only for costs resulting from DOE delays in accepting the SNF.

Under the settlement agreements, Generation has received cumulative cash reimbursements for costs incurred as follows:

<table><tr><td></td><td colspan="2">Total</td><td colspan="2">Net(a)</td></tr><tr><td>Cumulative cash reimbursements</td><td>$</td><td>1,288</td><td>$</td><td>1,113</td></tr></table>

(a) Total after considering amounts due to co-owners of certain nuclear stations and to the former owner of Oyster Creek.



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 18 — Commitments and Contingencies

As of December 31, 2019 and 2018, the amount of SNF storage costs for which reimbursement has been or will be requested from the DOE under the DOE settlement agreements is as follows:

<table><tr><td></td><td colspan="2">December 31, 2019</td><td colspan="2">December 31, 2018</td></tr><tr><td>DOE receivable - current \( ^{(a)} \)</td><td>$</td><td>249</td><td>$</td><td>124</td></tr><tr><td>DOE receivable - noncurrent \) ^{(b)}</td><td></td><td>30</td><td></td><td>15</td></tr><tr><td>Amounts owed to co-owners \( ^{(a)(c)} \)</td><td></td><td>(37)</td><td></td><td>(17)</td></tr></table>

(a) Recorded in Accounts receivable, other.

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

(c) Non-CENG amounts owed to co-owners are recorded in Accounts receivable, other. CENG amounts owed to co-owners are recorded in Accounts payable. Represents amounts owed to the co-owners of Peach Bottom, Quad Cities, and Nine Mile Point Unit 2 generating facilities.

The Standard Contracts with the DOE also required the payment to the DOE of a one-time fee applicable to nuclear generation through April 6, 1983. The below table outlines the SNF liability recorded at Exelon and Generation as of December 31, 2019 and 2018:

<table><tr><td></td><td colspan="2">December 31, 2019</td><td colspan="2">December 31, 2018</td></tr><tr><td>Former ComEd units \( ^{(a)} \)</td><td>$</td><td>1,075</td><td>$</td><td>1,052</td></tr><tr><td>Fitzpatrick \( ^{(b)} \)</td><td></td><td>124</td><td></td><td>119</td></tr><tr><td>Total SNF Obligation</td><td>$</td><td>1,199</td><td>$</td><td>1,171</td></tr></table>

(a) ComEd previously elected to defer payment of the one-time fee of $277 million for its units (which are now part of Generation), with interest to the date of payment, until just prior to the first delivery of SNF to the DOE. The unfunded liabilities for SNF disposal costs, including the one-time fee, were transferred to Generation as part of Exelon's 2001 corporate restructuring.

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

Interest for Exelon's and Generation's SNF liabilities accrues at the 13-week Treasury Rate. The 13-week Treasury Rate in effect for calculation of the interest accrual at December 31, 2019 was 1.551% for the deferred amount transferred from ComEd and 1.879% for the deferred FitzPatrick amount.

The following table summarizes sites for which Exelon and Generation do not have an outstanding SNF Obligation:

<table><tr><td>Description</td><td>Sites</td></tr><tr><td>Fees have been paid</td><td>Former PECO units, Clinton and Calvert Cliffs</td></tr><tr><td>Outstanding SNF Obligation remains with former owners</td><td>Nine Mile Point, Ginnia and TMI</td></tr></table>

## Environmental Remediation Matters

General (All Registrants). The Registrants' 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, the Registrants are generally liable for the costs of remediating environmental contamination of property now or formerly owned by them and of property contaminated by hazardous substances generated by them. The Registrants own or lease a number of real estate parcels, including parcels on which their operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. In addition, the Registrants are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future. Unless otherwise disclosed, the Registrants cannot reasonably estimate whether they will incur significant liabilities for additional investigation and remediation costs at these or additional sites identified by the Registrants, environmental agencies



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 18 — Commitments and Contingencies

or others, or whether such costs will be recoverable from third parties, including customers. Additional costs could have a material, unfavorable impact on the Registrants' financial statements.

MGP Sites (Exelon and the Utility Registrants). ComEd, PECO, BGE and DPL have identified sites where former MGP or gas purification activities have or may have resulted in actual site contamination. For almost all of these sites, there are additional PRPs that may share responsibility for the ultimate remediation of each location.

- ComEd has 21 sites that are currently under some degree of active study and/or remediation. ComEd expects the majority of the remediation at these sites to continue through at least 2025.

- PECO has 8 sites that are currently under some degree of active study and/or remediation. PECO expects the majority of the remediation at these sites to continue through at least 2022.

- BGE has 4 sites that currently require some level of remediation and/or ongoing activity. BGE expects the majority of the remediation at these sites to continue through at least 2021.

• DPL has 1 site that is currently under study and the required cost at the site is not expected to be material.

The historical nature of the MGP and gas purification sites and the fact that many of the sites have been buried and built over, impacts the ability to determine a precise estimate of the ultimate costs prior to initial sampling and determination of the exact scope and method of remedial activity. Management determines its best estimate of remediation costs using all available information at the time of each study, including probabilistic and deterministic modeling for ComEd and PECO, and the remediation standards currently required by the applicable state environmental agency. Prior to completion of any significant clean up, each site remediation plan is approved by the appropriate state environmental agency.

ComEd, pursuant to an ICC order, and PECO, pursuant to settlements of natural gas distribution rate cases with the PAPUC, are currently recovering environmental remediation costs of former MGP facility sites through customer rates. While BGE and DPL do not have riders for MGP clean-up costs, they have historically received recovery of actual clean-up costs in distribution rates.

As of December 31, 2019 and 2018, the Registrants had accrued the following undiscounted amounts for environmental liabilities in Other current liabilities and Other deferred credits and other liabilities within their respective Consolidated Balance Sheets:

<table><tr><td rowspan="2"></td><td colspan="3">December 31, 2019</td><td colspan="3">December 31, 2018</td></tr><tr><td>Total environmental investigation and remediation reserve</td><td>Portion of total related to MGP investigation and remediation</td><td>Total environmental investigation and remediation reserve</td><td>Portion of total related to MGP investigation and termination</td><td>Portion of total related to MGP investigation and termination</td><td></td></tr><tr><td>Exelon</td><td>$ 478</td><td>$ 320</td><td>$ 496</td><td>$ 356</td><td></td><td></td></tr><tr><td>Generation</td><td>105</td><td>—</td><td>108</td><td>—</td><td></td><td></td></tr><tr><td>ComEd</td><td>304</td><td>303</td><td>329</td><td>327</td><td></td><td></td></tr><tr><td>PECO</td><td>19</td><td>17</td><td>27</td><td>25</td><td></td><td></td></tr><tr><td>BGE</td><td>2</td><td>—</td><td>5</td><td>4</td><td></td><td></td></tr><tr><td>PHI</td><td>48</td><td>—</td><td>27</td><td>—</td><td></td><td></td></tr><tr><td>Pepco</td><td>46</td><td>—</td><td>25</td><td>—</td><td></td><td></td></tr><tr><td>DPL</td><td>1</td><td>—</td><td>1</td><td>—</td><td></td><td></td></tr><tr><td>ACE</td><td>1</td><td>—</td><td>1</td><td>—</td><td></td><td></td></tr></table>

Cotter Corporation (Exelon and Generation). The EPA has advised Cotter Corporation (Cotter), a former ComEd subsidiary, that it is potentially liable in connection with radiological contamination at a site known as the West Lake Landfill in Missouri. In 2000, ComEd sold Cotter to an unaffiliated third-party. As part of the sale, ComEd agreed to indemnify Cotter for any liability arising in connection with the West Lake Landfill. In connection with Exelon's 2001 corporate restructuring, this responsibility to indemnify Cotter was transferred to Generation. Including Cotter, there are three PRPs participating in the West Lake Landfill remediation proceeding. Investigation by Generation has identified a number of other parties who also may be PRPs and could be liable to contribute to the final remedy. Further investigation is ongoing.



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 18 — Commitments and Contingencies

In September 2018, the EPA issued its Record of Decision (ROD) Amendment for the selection of the final remedy. The ROD modified the EPA’s previously proposed plan for partial excavation of the radiological materials by reducing the depths of the excavation. The ROD also allows for variation in depths of excavation depending on radiological concentrations. The EPA and the PRPs have entered into a Consent Agreement to perform the Remedial Design, which is expected to be completed in the 2020 - 2021 time frame. In March 2019 the PRPs received Special Notice Letters from the EPA to perform the Remedial Action work. On October 8, 2019, Generation provided a non-binding good faith offer to conduct, or finance, a portion of the remedy, subject to certain conditions. The total estimated cost of the remedy, taking into account the current EPA technical requirements and the total costs expected to be incurred collectively by the PRPs in fully executing the remedy, is approximately $280 million, including cost escalation on an undiscounted basis, which would be allocated among the final group of PRPs. Generation has determined that a loss associated with the EPA’s partial excavation and enhanced landfill cover remedy is probable and has recorded a liability included in the table above, that reflects management’s best estimate of Cotter’s allocable share of the ultimate cost. Given the joint and several nature of this liability, the magnitude of Generation’s ultimate liability will depend on the actual costs incurred to implement the required remediation remedy as well as on the nature and terms of any cost-sharing arrangements with the final group of PRPs. Therefore, it is reasonably possible that the ultimate cost and Generation’s associated allocable share could differ significantly once these uncertainties are resolved, which could have a material impact on Exelon’s and Generation’s future financial statements.

One of the other PRPs has indicated it will be making a contribution claim against Cotter for costs that it has incurred to prevent the subsurface fire from spreading to those areas of the West Lake Landfill where radiological materials are believed to have been disposed. At this time, Exelon and Generation do not possess sufficient information to assess this claim and therefore are unable to estimate a range of loss, if any. As such, no liability has been recorded for the potential contribution claim. It is reasonably possible, however, that resolution of this matter could have a material, unfavorable impact on Exelon's and Generation's financial statements.

In January 2018, the PRPs were advised by the EPA that it will begin an additional investigation and evaluation of groundwater conditions at the West Lake Landfill. In September 2018, the PRPs agreed to an Administrative Settlement Agreement and Order on Consent for the performance by the PRPs of the groundwater Remedial Investigation (RI)/Feasibility Study (FS). The purpose of this RI/FS is to define the nature and extent of any groundwater contamination from the West Lake Landfill site and evaluate remedial alternatives. Generation estimates the undiscounted cost for the groundwater RI/FS to be approximately $20 million. Generation determined a loss associated with the RI/FS is probable and has recorded a liability included in the table above that reflects management's best estimate of Cotter's allocable share of the cost among the PRPs. At this time Generation cannot predict the likelihood or the extent to which, if any, remediation activities may be required and therefore cannot estimate a reasonably possible range of loss for response costs beyond those associated with the RI/FS component. It is reasonably possible, however, that resolution of this matter could have a material, unfavorable impact on Exelon's and Generation's future financial statements.

In August 2011, Cotter was notified by the DOJ that Cotter is considered a PRP with respect to the government’s clean-up costs for contamination attributable to low level radioactive residues at a former storage and reprocessing facility named Latty Avenue near St. Louis, Missouri. The Latty Avenue site is included in ComEd’s indemnification responsibilities discussed above as part of the sale of Cotter. The radioactive residues had been generated initially in connection with the processing of uranium ores as part of the U.S. Government’s Manhattan Project. Cotter purchased the residues in 1969 for initial processing at the Latty Avenue facility for the subsequent extraction of uranium and metals. In 1976, the NRC found that the Latty Avenue site had radiation levels exceeding NRC criteria for decontamination of land areas. Latty Avenue was investigated and remediated by the United States Army Corps of Engineers pursuant to funding under FUSRAP. The DOJ has not yet formally advised the PRPs of the amount that it is seeking, but it is believed to be approximately $90 million from all PRPs. Pursuant to a series of annual agreements since 2011, the DOJ and the PRPs have tolled the statute of limitations until February 2020 so that settlement discussions could proceed. Generation has determined that a loss associated with this matter is probable under its indemnification agreement with Cotter and has recorded an estimated liability, which is included in the table above.

Benning Road Site (Exelon, Generation, PHI and Pepco). In September 2010, PHI received a letter from EPA identifying the Benning Road site as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. A portion of the site was formerly the location of a Pepco Energy Services electric generating facility, which was deactivated in June 2012. The remaining portion of the site consists of a Pepco transmission and distribution service center that remains in operation. In December 2011, the U.S. District Court for the District of Columbia approved a Consent Decree entered into by Pepco and Pepco Energy Services with the DOEE, which



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 18 — Commitments and Contingencies

requires Pepco and Pepco Energy Services to conduct a RI/FS for the Benning Road site and an approximately 10 to 15-acre portion of the adjacent Anacostia River.

Since 2013, Pepco and Pepco Energy Services (now Generation, pursuant to Exelon's 2016 acquisition of PHI) have been performing RI work and have submitted multiple draft RI reports to the DOEE. In September 2019, Pepco and Generation issued a draft "final" RI report which DOEE approved and on October 4, 2019 released this document for review and comment by the public. The 45 day comment period ended on November 18, 2019 and a public meeting was held by Pepco on November 2, 2019. Pepco and Generation will proceed to develop a FS to evaluate possible remedial alternatives for submission to DOEE. The Court has established a schedule for completion of the FS, and approval by the DOEE, by September 16, 2021.

DOEE will then prepare a Proposed Plan and issue a Record of Decision identifying any further response actions determined to be necessary, after considering public comment on the Proposed Plan. PHI, Pepco and Generation have determined that a loss associated with this matter is probable and have accrued an estimated liability, which is included in the table above.

Anacostia River Tidal Reach (Exelon, PHI and Pepco). Contemporaneous with the Benning Road site RI/FS being performed by Pepco and Generation, DOEE and the National Park Service have been conducting a separate RI/FS focused on the entire tidal reach of the Anacostia River extending from just north of the Maryland-District of Columbia boundary line to the confluence of the Anacostia and Potomac Rivers. The river-wide RI incorporated the results of the river sampling performed by Pepco and Pepco Energy Services as part of the Benning RI/FS, as well as similar sampling efforts conducted by owners of other sites adjacent to this segment of the river and supplemental river sampling conducted by DOEE's contractor. DOEE asked Pepco, along with parties responsible for other sites along the river, to participate in a "Consultative Working Group" to provide input into the process for future remedial actions and to ensure proper coordination with the other river cleanup efforts currently underway, including cleanup of the river segment adjacent to the Benning Road site resulting from the Benning Road site RI/FS. In addition, the District of Columbia Council directed DOEE to form an official advisory committee made up of members of federal, state and local environmental regulators, community and environmental groups and various academic and technical experts to provide guidance and support to DOEE as the project progressed. This group, called the Anacostia Leadership Council, has met regularly since it was formed. Pepco has participated in the Consultative Working Group. In April 2018, DOEE released a draft RI report for public review and comment. Pepco submitted written comments to the draft RI and participated in a public hearing.

Pepco has determined that it is probable that costs for remediation will be incurred and recorded a liability in the third quarter 2019 for management's best estimate of its share of those costs based on DOEE's stated position following a series of meetings attended by representatives from the Anacostia Leadership Council and the Consultative Working Group. On December 27, 2019, DOEE released a Focused Feasibility Study (FFS) and a Proposed Plan (PP) for review and comment by the public which will be the basis for the Interim ROD, which is expected to be completed in September 2020. The FFS and PP are consistent with the DOEE's stated position to follow an adaptive management approach which will allow several identified "hot spots" in the river to be addressed first while continuing to conduct studies and to monitor the river to evaluate improvements and determine potential future remediation plans. The adaptive management process chosen by DOEE is less intrusive, provides more long term environmental certainty, is less costly, and allows for site specific remediation plans already underway, including the plan for the Benning Road site to proceed to conclusion. The comment period ends on March 2, 2020 and a public meeting will be held on January 23, 2021. Pepco concluded that incremental exposure remains reasonably possible, however management cannot reasonably estimate a range of loss beyond the amounts recorded, which are included in the table above.

In addition to the activities associated with the remedial process outlined above, there is a complementary statutory program that requires an assessment to determine if any natural resources have been damaged as a result of the contamination that is being remediated, and, if so, that a plan be developed by the federal, state and local Natural Resource Damage Trustees, who are defined by CERCLA as the responsible parties for the restoration or compensation for any loss of those resources from the environmental contaminants at the site. If natural resources cannot be restored, then compensation for the injury can be sought from the responsible parties. The assessment of Natural Resource Damages (NRD) typically takes place following cleanup because cleanups sometimes also effectively restore habitat. During the second quarter of 2018, Pepco became aware that the Trustees are in the beginning stages of this process that often takes many years beyond the remedial decision to complete. Pepco has concluded that a loss associated with the eventual NRD assessment is reasonably possible. Due to the very early stage of the assessment process, Pepco cannot reasonably estimate the range of loss.



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 18 — Commitments and Contingencies

## Litigation and Regulatory Matters

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

At December 31, 2019 and 2018, Exelon and Generation had recorded estimated liabilities of approximately $83 million and $79 million, respectively, in total for asbestos-related bodily injury claims. As of December 31, 2019, approximately $26 million of this amount related to 263 open claims presented to Generation, while the remaining $57 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, Generation monitors actual experience against the number of forecasted claims to be received and expected claim payments and evaluates whether adjustments to the estimated liabilities are necessary.

It is reasonably possible that additional exposure to estimated future asbestos-related bodily injury claims in excess of the amount accrued could have a material, unfavorable impact on Exelon’s and Generation’s financial statements.

Fund Transfer Restrictions (All Registrants). Under applicable law, Exelon may borrow or receive an extension of credit from its subsidiaries. Under the terms of Exelon’s intercompany money pool agreement, Exelon can lend to, but not borrow from the money pool.

Under applicable law, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE can pay dividends only from retained, undistributed or current earnings. A significant loss recorded at Generation, ComEd, PECO, BGE, PHI, Pepco, DPL or ACE may limit the dividends that these companies can distribute to Exelon.

ComEd has agreed in connection with financings arranged through ComEd Financing III that it will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debt securities issued to ComEd Financing III; (2) it defaults on its guarantee of the payment of distributions on the preferred trust securities of ComEd Financing III; or (3) an event of default occurs under the Indenture under which the subordinated debt securities are issued. No such event has occurred.

PECO has agreed in connection with financings arranged through PEC L.P. and PECO Trust IV that PECO will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debentures, which were issued to PEC L.P. or PECO Trust IV; (2) it defaults on its guarantee of the payment of distributions on the Series D Preferred Securities of PEC L.P. or the preferred trust securities of PECO Trust IV; or (3) an event of default occurs under the Indenture under which the subordinated debentures are issued. No such event has occurred.

BGE is subject to restrictions established by the MDPSC that prohibit BGE from paying a dividend on its common shares if (a) after the dividend payment, BGE's equity ratio would be below 48% as calculated pursuant to the MDPSC's ratemaking precedents or (b) BGE's senior unsecured credit rating is rated by two of the three major credit rating agencies below investment grade. No such event has occurred.

Pepco is subject to certain dividend restrictions established by settlements approved in Maryland and the District of Columbia. Pepco is prohibited from paying a dividend on its common shares if (a) after the dividend payment, Pepco's equity ratio would be 48% as equity levels are calculated under the ratemaking precedents of the MDPSC or (b) DPL's senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. No such event has occurred.

DPL is subject to certain dividend restrictions established by settlements approved in Delaware and Maryland. DPL is prohibited from paying a dividend on its common shares if (a) after the dividend payment, DPL's equity ratio would be 48% as equity levels are calculated under the ratemaking precedents of the DPSC and MDPSC or (b) DPL's senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. No such event has occurred.

ACE is subject to certain dividend restrictions established by settlements approved in New Jersey. ACE is prohibited from paying a dividend on its common shares if (a) after the dividend payment, ACE's equity ratio would be 48% as equity levels are calculated under the ratemaking precedents of the NJBPU or (b) ACE's senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. ACE is also subject to a



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 18 — Commitments and Contingencies

dividend restriction which requires ACE to obtain the prior approval of the NJBPU before dividends can be paid it its equity as a percent of its total capitalization, excluding securitization debt, falls below 30%. No such events have occurred.

City of Everett Tax Increment Financing Agreement (Exelon and Generation). On April 10, 2017, the City of Everett petitioned the Massachusetts Economic Assistance Coordinating Council (EACC) to revoke the 1999 tax increment financing agreement (TIF Agreement) relating to Mystic Units 8 and 9 on the grounds that the total investment in Mystic Units 8 and 9 materially deviates from the investment set forth in the TIF Agreement. On October 31, 2017, a three-member panel of the EACC conducted an administrative hearing on the City's petition. On November 30, 2017, the hearing panel issued a tentative decision denying the City's petition, finding that there was no material misrepresentation that would justify revocation of the TIF Agreement. On December 13, 2017, the tentative decision was adopted by the full EACC. On January 12, 2018, the City filed a complaint in Massachusetts Superior Court requesting, among other things, that the court set aside the EACC's decision, grant the City's request to decertify the Project and the TIF Agreement, and award the City damages for alleged underpaid taxes over the period of the TIF Agreement. On January 8, 2020, the Massachusetts Superior Court affirmed the decision of the EACC denying the City's petition. The deadline for appeal is March 9, 2020. Generation continues to believe that the City's claim lacks merit. Accordingly, Generation has not recorded a liability for payment resulting from such a revocation, nor can Generation estimate a reasonably possible range of loss, if any, associated with any such revocation. Further, it is reasonably possible that property taxes assessed in future periods, including those following the expiration of the current TIF Agreement in 2020, could be material to Generation's financial statements.

Subpoenas (Exelon and ComEd). Exelon and ComEd received a grand jury subpoena in the second quarter of 2019 from the U.S. Attorney's Office for the Northern District of Illinois requiring production of information concerning their lobbying activities in the State of Illinois. On October 4, 2019, Exelon and ComEd received a second grand jury subpoena from the U.S. Attorney's Office for the Northern District of Illinois requiring production of records of any communications with certain individuals and entities. On October 22, 2019, the SEC notified Exelon and ComEd that it has also opened an investigation into their lobbying activities. Exelon and ComEd have cooperated fully and intend to continue to cooperate fully and expeditiously with the U.S. Attorney's Office and the SEC. Exelon and ComEd cannot predict the outcome of the U.S. Attorney's Office or the SEC investigations. No loss contingency has been reflected in Exelon's and ComEd's consolidated financial statements as this contingency is neither probable nor reasonably estimable at this time. Management is currently unable to estimate a range of reasonably possible loss as these matters are subject to change.

Subsequent to Exelon announcing the receipt of the subpoenas, a putative class action lawsuit has been filed against Exelon and certain officers of Exelon and ComEd alleging misrepresentations or omissions by Exelon purporting to relate to matters that are the subject of the subpoenas and the SEC investigation. Exelon believes that these claims lack merit and intends to defend against them, and though the costs or any loss associated with the lawsuit cannot be reasonably estimated at this time, Exelon does not believe that the lawsuit will have a material adverse impact on Exelon's or ComEd's consolidated financial statements.

General (All Registrants). The Registrants 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. The Registrants 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.



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 19 — Shareholders' Equity

## 19. Shareholders' Equity (Exelon and Utility Registrants)

## ComEd Common Stock Warrants

The following table presents warrants outstanding to purchase ComEd common stock and shares of common stock reserved for the conversion of warrants. The warrants entitle the holders to convert such warrants into common stock of ComEd at a conversion rate of one share of common stock for three warrants.

<table><tr><td rowspan="2"></td><td colspan="2">December 31,</td></tr><tr><td>2019</td><td>2018</td></tr><tr><td>Warrants outstanding</td><td>60,228</td><td>60,285</td></tr><tr><td>Common Stock reserved for conversion</td><td>20,076</td><td>20,095</td></tr></table>

## Equity Securities Offering

In June 2014, Exelon issued $1.15 billion of junior subordinated notes in the form of 23 million equity units. In June 2017, Exelon settled the forward equity purchase contract on these equity units through issuance of 33 million shares of common stock from treasury stock, which triggered full dilution in the EPS calculation. Previously, the equity units were included in the calculation of diluted EPS using the treasury stock method.

## Share Repurchases

There currently is no Exelon Board of Director authority to repurchase shares. Any previous shares repurchased are held as treasury shares, at cost, unless cancelled or reissued at the discretion of Exelon's management.

## Preferred and Preference Securities

The following table presents the Registrants' shares of preferred securities authorized, none of which are outstanding as of December 31, 2019 and 2018:

<table><tr><td></td><td>Preferred Securities Authorized</td></tr><tr><td>Exelon</td><td>100,000,000</td></tr><tr><td>ComEd</td><td>850,000</td></tr><tr><td>PECO</td><td>15,000,000</td></tr><tr><td>BGE</td><td>1,000,000</td></tr><tr><td>Pepco</td><td>6,000,000</td></tr><tr><td>ACE \( ^{(a)} \)</td><td>2,799,979</td></tr></table>

(a) Includes 799,979 shares of cumulative preferred stock and 2,000,000 of no-par preferred stock as of December 31, 2019 and 2018, respectively.

The following table presents ComEd's, BGE's and ACE's preference securities authorized, none of which are outstanding as of December 31, 2019 and 2018:

<table><tr><td></td><td>Preference Securities Authorized</td></tr><tr><td>ComEd - Cumulative preference securities</td><td>6,810,451</td></tr><tr><td>BGE \( ^{(a)} \)</td><td>6,500,000</td></tr><tr><td>ACE</td><td>3,000,000</td></tr></table>

(a) Includes 4,600,000 shares of unclassified preference securities and 1,900,000 shares of previously redeemed preference securities as of December 31, 2019 and 2018, respectively.



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

## 20. Stock-Based Compensation Plans (All Registrants)

## Stock-Based Compensation Plans

Exelon grants stock-based awards through its LTIP, which primarily includes performance share awards, restricted stock units and stock options. At December 31, 2019, there were approximately 12 million shares authorized for issuance under the LTIP. For the years ended December 31, 2019, 2018 and 2017, exercised and distributed stock-based awards were primarily issued from authorized but unissued common stock shares.

The Registrants grant cash awards. The following table does not include expense related to these plans as they are not considered stock-based compensation plans under the applicable authoritative guidance.

The following table presents the stock-based compensation expense included in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. The Utility Registrants' stock-based compensation expense for the years ended December 31, 2019, 2018 and 2017 was not material.

<table><tr><td rowspan="2">Components of Stock-Based Compensation Expense</td><td colspan="4">Year Ended December 31,</td></tr><tr><td>2019</td><td>2018</td><td>2017</td><td></td></tr><tr><td>Total stock-based compensation expense included in operating and maintenance expense</td><td>$     77</td><td>$     208</td><td>$     191</td><td></td></tr><tr><td>Income tax benefit</td><td>(20)</td><td>(54)</td><td>(74)</td><td></td></tr><tr><td>Total after-tax stock-based compensation expense</td><td>$     57</td><td>$     154</td><td>$     117</td><td></td></tr><tr><td>Generation</td><td></td><td></td><td></td><td></td></tr><tr><td>Components of Stock-Based Compensation Expense</td><td></td><td></td><td></td><td></td></tr><tr><td>Total stock-based compensation expense included in operating and maintenance expense</td><td>$     37</td><td>$     77</td><td>$     88</td><td></td></tr><tr><td>Income tax benefit</td><td>(10)</td><td>(20)</td><td>(34)</td><td></td></tr><tr><td>Total after-tax stock-based compensation expense</td><td>$     27</td><td>$     57</td><td>$     54</td><td></td></tr></table>

Exelon receives a tax deduction based on the intrinsic value of the award on the exercise date for stock options and the distribution date for performance share awards and restricted stock units. For each award, throughout the requisite service period, Exelon recognizes the tax benefit related to compensation costs. The following table presents information regarding Exelon’s realized tax benefit when distributed:

<table><tr><td rowspan="2"></td><td colspan="4">Year Ended December 31,</td></tr><tr><td>2019</td><td>2018</td><td>2017</td><td></td></tr><tr><td>Performance share awards</td><td>$     41</td><td>$     16</td><td>$     29</td><td></td></tr><tr><td>Restricted stock units</td><td>24</td><td>28</td><td>35</td><td></td></tr></table>

## Performance Share Awards

Performance share awards are granted under the LTIP. The performance share awards are settled 50% in common stock and 50% in cash at the end of the three-year performance period, except for awards granted to vice presidents and higher officers that are settled 100% in cash if certain ownership requirements are satisfied.

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



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 20 — Stock-Based Compensation Plans

For nonretirement-eligible employees, stock-based compensation costs are recognized over the vesting period of three years using the straight-line method. For performance share awards granted to retirement-eligible employees, the value of the performance shares is recognized ratably over the vesting period, which is the year of grant.

Exelon processes forfeitures as they occur for employees who do not complete the requisite service period.

The following table summarizes Exelon’s nonvested performance share awards activity:

<table><tr><td></td><td>Shares</td><td>Weighted Average Grant Date Fair Value (per share)</td></tr><tr><td>Nonvested at December 31, 2018 \( ^{(a)} \)</td><td>3,403,228</td><td>33.13</td></tr><tr><td>Granted</td><td>1,089,903</td><td>47.37</td></tr><tr><td>Change in performance</td><td>(799,618)</td><td>40.85</td></tr><tr><td>Vested</td><td>(1,610,146)</td><td>28.90</td></tr><tr><td>Forfeited</td><td>(25,249)</td><td>45.03</td></tr><tr><td>Undistributed vested awards \( ^{(b)} \)</td><td>(348,363)</td><td>48.82</td></tr><tr><td>Nonvested at December 31, 2019 \( ^{(a)} \)</td><td>1,709,755</td><td>39.21</td></tr></table>

(a) Excludes 2,017,870 and 3,586,259 of performance share awards issued to retirement-eligible employees as of December 31, 2019 and 2018, respectively, as they are fully vested.

(b) Represents performance share awards that vested but were not distributed to retirement-eligible employees during 2019.

The following table summarizes the weighted average grant date fair value and the total fair value of performance share awards granted and settled.

<table><tr><td rowspan="2"></td><td colspan="4">Year Ended December 31,</td></tr><tr><td colspan="2">2019 (a)</td><td colspan="2">2018</td></tr><tr><td>Weighted average grant date fair value (per share)</td><td>$ 47.37</td><td>$ 38.15</td><td>$ 35.00</td><td></td></tr><tr><td>Total fair value of performance shares settled</td><td>158</td><td>61</td><td>72</td><td></td></tr><tr><td>Total fair value of performance shares settled in cash</td><td>131</td><td>49</td><td>56</td><td></td></tr></table>

(a) As of December 31, 2019, $17 million of total unrecognized compensation costs related to nonvested performance shares are expected to be recognized over the remaining weighted-average period of 1.6 years.

## Restricted Stock Units

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

The value of the restricted stock units is expensed over the requisite service period using the straight-line method. The requisite service period for restricted stock units is generally three to five years. However, certain restricted stock unit awards become fully vested upon the employee reaching retirement-eligibility. The value of the restricted stock units granted to retirement-eligible employees is either recognized immediately upon the date of grant or through the date at which the employee reaches retirement eligibility. Exelon processes forfeitures as they occur for employees who do not complete the requisite service period.



## Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 20 — Stock-Based Compensation Plans

The following table summarizes Exelon's nonvested restricted stock unit activity:

<table><tr><td></td><td>Shares</td><td>Weighted Average Grant Date Fair Value (per share)</td></tr><tr><td>Nonvested at December 31, 2018 \( ^{(a)} \)</td><td>2,293,341</td><td>35.06</td></tr><tr><td>Granted</td><td>902,857</td><td>45.65</td></tr><tr><td>Vested</td><td>(1,232,704)</td><td>32.83</td></tr><tr><td>Forfeited</td><td>(33,603)</td><td>39.01</td></tr><tr><td>Undistributed vested awards  \( ^{(b)} \)</td><td>(431,178)</td><td>44.75</td></tr><tr><td>Nonvested at December 31, 2019 \( ^{(a)} \)</td><td>1,498,713</td><td>40.35</td></tr></table>

(a) Excludes 863,196 and 1,131,487 of restricted stock units issued to retirement-eligible employees as of December 31, 2019 and 2018, respectively, as they are fully vested.

(b) Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2019.

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

<table><tr><td rowspan="2"></td><td colspan="4">Year Ended December 31,</td></tr><tr><td>2019 (a)</td><td>2018</td><td>2017</td><td></td></tr><tr><td>Weighted average grant date fair value (per share)</td><td>$ 45.65</td><td>$ 38.60</td><td>$ 34.98</td><td></td></tr><tr><td>Total fair value of restricted stock units vested</td><td>92</td><td>106</td><td>88</td><td></td></tr></table>

(a) As of December 31, 2019, $28 million of total unrecognized compensation costs related to nonvested restricted stock units are expected to be recognized over the remaining weighted-average period of 2.8 years.

## Stock Options

Non-qualified stock options to purchase shares of Exelon's common stock were granted through 2012 under the LTIP. The exercise price of the stock options is equal to the fair market value of the underlying stock on the date of option grant. Stock options will expire no later than ten years from the date of grant.

At December 31, 2019 all stock options were vested and there were no unrecognized compensation costs.

The following table presents information with respect to stock option activity:

<table><tr><td></td><td>Shares</td><td>Weighted Average Exercise Price (per share)</td><td>Weighted Average Remaining Contractual Life (years)</td><td>Aggregate Intrinsic Value</td></tr><tr><td>Balance of shares outstanding at December 31, 2018</td><td>4,027,652</td><td>43.95</td><td>2.90</td><td>14</td></tr><tr><td>Options exercised</td><td>(1,388,165)</td><td>42.25</td><td></td><td></td></tr><tr><td>Options expired</td><td>(750,442)</td><td>55.96</td><td></td><td></td></tr><tr><td>Balance of shares outstanding at December 31, 2019</td><td>1,889,045</td><td>40.43</td><td>1.56</td><td>10</td></tr><tr><td>Exercisable at December 31, 2019 \( ^{(a)} \)</td><td>1,889,045</td><td>40.43</td><td>1.56</td><td>10</td></tr></table>

(a) Includes stock options issued to retirement eligible employees.



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 20 — Stock-Based Compensation Plans

The following table summarizes additional information regarding stock options exercised:

<table><tr><td rowspan="2"></td><td colspan="4">Year Ended December 31,</td></tr><tr><td>2019</td><td>2018</td><td>2017</td><td></td></tr><tr><td>Intrinsic value \( ^{(a)} \)</td><td>9</td><td>12</td><td>15</td><td></td></tr><tr><td>Cash received for exercise price</td><td>59</td><td>56</td><td>107</td><td></td></tr></table>

(a) The difference between the market value on the date of exercise and the option exercise price.

## 21. Changes in Accumulated Other Comprehensive Income (Exelon)

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

<table><tr><td></td><td>Gains and (Losses) on Cash Flow Hedges</td><td>Unrealized Gains and (Losses) on Marketable Securities</td><td>Pension and Non-Pension Postretirement Items (a)</td><td>Foreign Currency Items</td><td>AOCI of Investments Unconsolidated Affiliates (b)</td><td>Total</td></tr><tr><td>Balance at December 31, 2016</td><td>$ (17)</td><td>$ 4</td><td>$ (2,610)</td><td>$ (30)</td><td>$ (7)</td><td>$ (2,660)</td></tr><tr><td>OCI before reclassifications</td><td>(1)</td><td>6</td><td>11</td><td>7</td><td>6</td><td>29</td></tr><tr><td>Amounts reclassified from AOCI</td><td>4</td><td>—</td><td>140</td><td>—</td><td>—</td><td>144</td></tr><tr><td>Net current-period OCI</td><td>3</td><td>6</td><td>151</td><td>7</td><td>6</td><td>173</td></tr><tr><td>Impact of adoption of Reclassification of Certain Tax Effects from AOCI(c)</td><td>—</td><td>—</td><td>(539)</td><td>—</td><td>—</td><td>(539)</td></tr><tr><td>Balance at December 31, 2017</td><td>$ (14)</td><td>$ 10</td><td>$ (2,998)</td><td>$ (23)</td><td>$ (1)</td><td>$ (3,026)</td></tr><tr><td>OCI before reclassifications</td><td>11</td><td>—</td><td>(143)</td><td>(10)</td><td>1</td><td>(141)</td></tr><tr><td>Amounts reclassified from AOCI</td><td>1</td><td>—</td><td>181</td><td>—</td><td>—</td><td>182</td></tr><tr><td>Net current-period OCI</td><td>12</td><td>—</td><td>38</td><td>(10)</td><td>1</td><td>41</td></tr><tr><td>Impact of adoption of Recognition and Measurement of Financial Assets and Financial Liabilities standard(d)</td><td>—</td><td>(10)</td><td>—</td><td>—</td><td>—</td><td>(10)</td></tr><tr><td>Balance at December 31, 2018</td><td>$ (2)</td><td>$ —</td><td>$ (2,960)</td><td>$ (33)</td><td>$ —</td><td>$ (2,995)</td></tr><tr><td>OCI before reclassifications</td><td>—</td><td>—</td><td>(289)</td><td>6</td><td>(2)</td><td>(285)</td></tr><tr><td>Amounts reclassified from AOCI</td><td>—</td><td>—</td><td>84</td><td>—</td><td>2</td><td>86</td></tr><tr><td>Net current-period OCI</td><td>—</td><td>—</td><td>(205)</td><td>6</td><td>—</td><td>(199)</td></tr><tr><td>Balance at December 31, 2019</td><td>$ (2)</td><td>$ —</td><td>$ (3,165)</td><td>$ (27)</td><td>$ —</td><td>$ (3,194)</td></tr></table>

(a) This AOCI component is included in the computation of net periodic pension and OPEB cost. See Note 14 — Retirement Benefits for additional information. See Exelon's Statements of Operations and Comprehensive Income for individual components of AOCI.

(b) All amounts are net of noncontrolling interests.

(c) Exelon early adopted the new standard Reclassification of Certain Tax Effects from AOCI. The standard was adopted retrospectively as of December 31, 2017, which resulted in an increase to Exelon's Retained earnings and Accumulated other comprehensive loss of $539 million, primarily related to deferred income taxes associated with Exelon's pension and OPEB obligations.

(d) Exelon prospectively adopted the new standard Recognition and Measurement of Financial Assets and Financial Liabilities. The standard was adopted as of January 1, 2018, which resulted in an increase to Retained earnings and Accumulated other comprehensive loss of $10 million for Exelon. The amounts reclassified related to Rabbi Trusts.



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

<table><tr><td rowspan="2"></td><td colspan="4">For the Year Ended December 31,</td></tr><tr><td>2019</td><td>2018</td><td>2017</td><td></td></tr><tr><td>Pension and non-pension postretirement benefit plans:</td><td></td><td></td><td></td><td></td></tr><tr><td>Prior service benefit reclassified to periodic benefit cost</td><td>$     23</td><td>$     24</td><td>$     36</td><td></td></tr><tr><td>Actuarial loss reclassified to periodic benefit cost</td><td>(52)</td><td>(86)</td><td>(128)</td><td></td></tr><tr><td>Pension and non-pension postretirement benefit plans valuation adjustment</td><td>100</td><td>50</td><td>13</td><td></td></tr></table>

## 22. Variable Interest Entities (Exelon, Generation, PHI and ACE)

At December 31, 2019 and 2018, Exelon, Generation, PHI and ACE collectively consolidated several VIEs or VIE groups for which the applicable Registrant was the primary beneficiary (see Consolidated VIEs below) and had significant interests in several other VIEs for which the applicable Registrant does not have the power to direct the entities' activities and, accordingly, was not the primary beneficiary (see Unconsolidated VIEs below). Consolidated and unconsolidated VIEs are aggregated to the extent that the entities have similar risk profiles.

## Consolidated VIEs

The table below shows the carrying amounts and classification of the consolidated VIEs' assets and liabilities included in the consolidated financial statements of Exelon, Generation, PHI and ACE as of December 31, 2019 and 2018. 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 the general credit of Exelon, Generation, PHI and ACE.

<table><tr><td rowspan="2"></td><td colspan="5">December 31, 2019</td><td colspan="4">December 31, 2018</td></tr><tr><td>Exelon(a)</td><td colspan="2">Generation</td><td>PHI(a)</td><td colspan="2">ACE</td><td>Exelon</td><td>Generation</td><td>PHI</td></tr><tr><td>Cash and cash equivalents</td><td>$ 163</td><td>$ 163</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ 414</td><td>$ 414</td><td>$ —</td><td>$ —</td></tr><tr><td>Restricted cash and cash equivalents</td><td>88</td><td>85</td><td>3</td><td>3</td><td>66</td><td>62</td><td>4</td><td>4</td><td></td></tr><tr><td>Accounts receivable, net</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Customer</td><td>151</td><td>151</td><td>—</td><td>—</td><td>146</td><td>146</td><td>—</td><td>—</td><td></td></tr><tr><td>Other</td><td>39</td><td>39</td><td>—</td><td>—</td><td>23</td><td>23</td><td>—</td><td>—</td><td></td></tr><tr><td>Unamortized energy contract asset (b)</td><td>23</td><td>23</td><td>—</td><td>—</td><td>25</td><td>25</td><td>—</td><td>—</td><td></td></tr><tr><td>Inventories, net</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Materials and supplies</td><td>227</td><td>227</td><td>—</td><td>—</td><td>212</td><td>212</td><td>—</td><td>—</td><td></td></tr><tr><td>Other current assets</td><td>32</td><td>31</td><td>1</td><td>—</td><td>52</td><td>49</td><td>3</td><td>—</td><td></td></tr><tr><td>Total current assets</td><td>723</td><td>719</td><td>4</td><td>3</td><td>938</td><td>931</td><td>7</td><td>4</td><td></td></tr><tr><td>Property, plant and equipment, net (c)</td><td>6,022</td><td>6,022</td><td>—</td><td>—</td><td>6,188</td><td>6,188</td><td>—</td><td>—</td><td></td></tr><tr><td>Nuclear decommissioning trust funds</td><td>2,741</td><td>2,741</td><td>—</td><td>—</td><td>2,351</td><td>2,351</td><td>—</td><td>—</td><td></td></tr><tr><td>Unamortized energy contract asset (b)</td><td>250</td><td>250</td><td>—</td><td>—</td><td>274</td><td>274</td><td>—</td><td>—</td><td></td></tr><tr><td>Other noncurrent assets</td><td>89</td><td>73</td><td>16</td><td>14</td><td>258</td><td>232</td><td>26</td><td>19</td><td></td></tr><tr><td>Total noncurrent assets</td><td>9,102</td><td>9,086</td><td>16</td><td>14</td><td>9,071</td><td>9,045</td><td>26</td><td>19</td><td></td></tr><tr><td>Total assets</td><td>$ 9,825</td><td>$ 9,805</td><td>$ 20</td><td>$ 17</td><td>$ 10,009</td><td>$ 9,976</td><td>$ 33</td><td>$ 23</td><td></td></tr><tr><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Long-term debt due within one year</td><td>$ 544</td><td>$ 523</td><td>$ 21</td><td>$ 20</td><td>$ 87</td><td>$ 66</td><td>$ 21</td><td>$ 18</td><td></td></tr><tr><td>Accounts payable</td><td>106</td><td>106</td><td>—</td><td>—</td><td>96</td><td>96</td><td>—</td><td>—</td><td></td></tr><tr><td>Accrued expenses</td><td>70</td><td>70</td><td>—</td><td>—</td><td>73</td><td>72</td><td>1</td><td>1</td><td></td></tr><tr><td>Unamortized energy contract liabilities</td><td>8</td><td>8</td><td>—</td><td>—</td><td>15</td><td>15</td><td>—</td><td>—</td><td></td></tr><tr><td>Other current liabilities</td><td>3</td><td>3</td><td>—</td><td>—</td><td>3</td><td>3</td><td>—</td><td>—</td><td></td></tr><tr><td>Total current liabilities</td><td>731</td><td>710</td><td>21</td><td>20</td><td>274</td><td>252</td><td>22</td><td>19</td><td></td></tr><tr><td>Long-term debt</td><td>527</td><td>504</td><td>23</td><td>21</td><td>1,072</td><td>1,025</td><td>47</td><td>40</td><td></td></tr><tr><td>Asset retirement obligations (d)</td><td>2,128</td><td>2,128</td><td>—</td><td>—</td><td>2,165</td><td>2,165</td><td>—</td><td>—</td><td></td></tr><tr><td>Unamortized energy contract liabilities</td><td>1</td><td>1</td><td>—</td><td>—</td><td>1</td><td>1</td><td>—</td><td>—</td><td></td></tr><tr><td>Other noncurrent liabilities</td><td>89</td><td>89</td><td>—</td><td>—</td><td>42</td><td>42</td><td>—</td><td>—</td><td></td></tr></table>



<table><tr><td>Total noncurrent liabilities</td><td>2,745</td><td>2,722</td><td>23</td><td>21</td><td>3,280</td><td>3,233</td><td>47</td><td>40</td></tr><tr><td>Total liabilities</td><td>$ 3,476</td><td>$ 3,432</td><td>$ 44</td><td>$ 41</td><td>$ 3,554</td><td>$ 3,485</td><td>$ 69</td><td>$ 59</td></tr></table>

(a) Includes certain purchase accounting adjustments not pushed down to the ACE standalone entity.

(b) These are unrestricted assets to Exelon and Generation.

(c) Exelon's and Generation's balances include unrestricted assets of $20 million and $43 million as of December 31, 2019 and 2018, respectively.

(d) Exelon's and Generation's balances include liabilities with recourse of $3 million and $5 million as of December 31, 2019 and 2018, respectively.



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 22 — Variable Interest Entities

As of December 31, 2019 and 2018, Exelon's and Generation's consolidated VIEs consist of:

<table><tr><td>Consolidated VIE or VIE groups:</td><td>Reason entity is a VIE:</td><td>Reason Generation is primary beneficiary:</td></tr><tr><td>CENG - A joint venture between Generation and EDF. Generation has a 50.01% equity ownership in CENG. See additional discussion below.</td><td>Disproportionate relationship between equity interest and operational control as a result of the Nuclear Operating Services Agreement (NOSA) described further below.</td><td>Generation conducts the operational activities.</td></tr><tr><td>EGRP - A collection of wind and solar project entities. Generation has a 51% equity ownership in EGRP. See additional discussion below.</td><td>Similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner.</td><td>Generation conducts the operational activities.</td></tr><tr><td>Blue Stem Wind - A Tax Equity structure which is consolidated by EGRP. Generation is a minority interest holder.</td><td>Similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner.</td><td>Generation conducts the operational activities.</td></tr><tr><td>Antelope Valley - A solar generating facility, which is 100% owned by Generation. Antelope Valley sells all of its output to PG&amp;E through a PPA.</td><td>The PPA contracts absorb variability through a performance guarantee.</td><td>Generation conducts all activities.</td></tr><tr><td>Equity investment in distributed energy company - Generation has a 31% equity ownership. This distributed energy company has an interest in an unconsolidated VIE. (See Unconsolidated VIEs disclosure below).</td><td>Similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner.</td><td>Generation conducts the operational activities.</td></tr><tr><td>Generation fully impaired this investment in the third quarter of 2019. See note 11- Asset Impairments for additional information.</td><td></td><td></td></tr></table>

CENG - On April 1, 2014, Generation, CENG, and subsidiaries of CENG executed the NOSA pursuant to which Generation conducts all activities associated with the operations of the CENG fleet and provides corporate and administrative services to CENG and the CENG fleet for the remaining life of the CENG nuclear plants as if they were a part of the Generation nuclear fleet, subject to the CENG member rights of EDF. See Note 2 — Mergers, Acquisitions and Dispositions for additional information.

Exelon and Generation, where indicated, provide the following support to CENG:

• Generation provided a $400 million loan to CENG. The remaining balance was fully paid by CENG in January 2019.

- Generation executed an Indemnity Agreement pursuant to which Generation agreed to indemnify EDF against third-party claims that may arise from any future nuclear incident (as defined in the Price-Anderson Act) in connection with the CENG nuclear plants or their operations. Exelon guarantees Generation’s obligations under this Indemnity Agreement. (See Note 18 — Commitments and Contingencies for more details),

- Generation and EDF share in the $688 million of contingent payment obligations for the payment of contingent retrospective premium adjustments for the nuclear liability insurance, and

- Exelon has executed an agreement to provide up to $245 million to support the operations of CENG as well as a $165 million guarantee of CENG's cash pooling agreement with its subsidiaries.

EGRP - EGRP is a collection of wind and solar project entities and some of these project entities are VIEs that are consolidated by EGRP. Generation owns a number of limited liability companies that build, own, and operate solar and wind power facilities some of which are owned by EGRP. While Generation or EGRP owns 100% of the solar entities and 100% of the majority of the wind entities, it has been determined that certain of the solar and wind entities are VIEs because the entities require additional subordinated financial support in the form of a parental guarantee of debt, loans from the customers in order to obtain the necessary funds for construction of the solar



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 22 — Variable Interest Entities

facilities, or the customers absorb price variability from the entities through the fixed price power and/or REC purchase agreements. Generation is the primary beneficiary of these solar and wind entities that qualify as VIEs because Generation controls the design, construction, and operation of the facilities. Generation provides operating and capital funding to the solar and wind entities for ongoing construction, operations and maintenance and there is limited recourse related to Generation related to certain solar and wind entities.

In 2017, Generation’s interests in EGRP were contributed to and are pledged for the ExGen Renewables IV non-recourse debt project financing structure. Refer to Note 16 — Debt and Credit Agreements for additional information on ExGen Renewables IV.

As of December 31, 2019 and 2018, Exelon's, PHI's and ACE's consolidated VIE consists of:

<table><tr><td>Consolidated VIEs:</td><td>Reason entity is a VIE:</td><td>Reason ACE is the primary beneficiary:</td></tr><tr><td>ACE Transition Funding - A special purpose entity formed by ACE for the purpose of securitizing authorized portions of ACE&#x27;s recoverable stranded costs through the issuance and sale of transition bonds. Proceeds from the sale of each series of transition bonds by ATF were transferred to ACE in exchange for the transfer by ACE to ATF of the right to collect a non-bypassable Transition Bond Charge from ACE customers pursuant to bondable stranded costs rate orders issued by the NJBPU in an amount sufficient to fund the principal and interest payments on transition bonds and related taxes, expenses and fees.</td><td>ACE&#x27;s equity investment is a variable interest as, by design, it absorbs any initial variability of ACETF. The bondholders also have a variable interest for the investment made to purchase the transition bonds.</td><td>ACE controls the servicing activities.</td></tr></table>

## Unconsolidated VIEs

Exelon’s and Generation’s 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 Exelon’s and Generation’s Consolidated Balance Sheets in Investments. For the energy purchase and sale contracts (commercial agreements), the carrying amount of assets and liabilities in Exelon’s and Generation’s Consolidated Balance Sheets that relate to their involvement with the VIEs are predominantly related to working capital accounts and generally represent the amounts owed by, or owed to, Exelon and Generation for the deliveries associated with the current billing cycles under the commercial agreements.

As of December 31, 2019 and 2018, Exelon and Generation had significant unconsolidated variable interests in several VIEs for which Exelon or Generation, as applicable, was not the primary beneficiary. These interests include certain equity method investments and certain commercial agreements.

The following table presents summary information about Exelon and Generation’s significant unconsolidated VIE entities:

<table><tr><td rowspan="2"></td><td rowspan="2">Commercial Agreement VIEs</td><td colspan="3">December 31, 2019</td><td rowspan="2">Total</td><td rowspan="2">Commercial Agreement VIEs</td><td rowspan="2">December 31, 2018</td><td rowspan="2">Total</td></tr><tr><td>Equity Investment</td><td>VIE</td></tr><tr><td>Total assets \( ^{(a)} \)</td><td>$ 636</td><td>$ 443</td><td>$ 1,079</td><td>$ 597</td><td>$ 472</td><td>$ 1,069</td><td></td></tr><tr><td>Total liabilities \( ^{(a)} \)</td><td>33</td><td>227</td><td>260</td><td>37</td><td>222</td><td>259</td><td></td></tr><tr><td>Exelon&#x27;s ownership interest in VIE \( ^{(a)} \)</td><td>—</td><td>191</td><td>191</td><td>—</td><td>223</td><td>223</td><td></td></tr><tr><td>Other ownership interests in VIE \( ^{(a)} \)</td><td>604</td><td>25</td><td>629</td><td>560</td><td>27</td><td>587</td><td></td></tr><tr><td>Registrants&#x27; maximum exposure to loss:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Carrying amount of equity method investments</td><td>—</td><td>—</td><td>—</td><td>—</td><td>223</td><td>223</td><td></td></tr></table>

(a) These items represent amounts on the unconsolidated VIE balance sheets, not in Exelon's or Generation's Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs.



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 22 — Variable Interest Entities

For each of the unconsolidated VIEs, Exelon and Generation have assessed the risk of a loss equal to their maximum exposure to be remote and, accordingly, Exelon and Generation have not recognized a liability associated with any portion of the maximum exposure to loss.

As of December 31, 2019 and 2018, Exelon's and Generation's unconsolidated VIEs consist of:

<table><tr><td>Unconsolidated VIE groups:</td><td>Reason entity is a VIE:</td><td>Reason Generation is not the primary beneficiary:</td></tr><tr><td>Equity investments in distributed energy companies -</td><td>Similar structures to a limited partnership and the limited partners do not have kick out rights with respect to the general partner.</td><td>Generation does not conduct the operational activities.</td></tr><tr><td>1) Generation has a 90% equity ownership in a distributed energy company. 2) Generation, via a consolidated VIE, has a 90% equity ownership in a distributed energy company (See Consolidated VIEs disclosure above).</td><td></td><td></td></tr><tr><td>Generation fully impaired this investment in the third quarter of 2019. See note 11- Asset Impairments for additional information.</td><td></td><td></td></tr><tr><td>Energy Purchase and Sale agreements - Generation has several energy purchase and sale agreements with generating facilities.</td><td>PPA contracts that absorb variability through fixed pricing.</td><td>Generation does not conduct the operational activities.</td></tr></table>

## 23. Supplemental Financial Information (All Registrants)

## Supplemental Statement of Operations Information

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

Taxes other than income taxes

<table><tr><td></td><td>Exelon</td><td>Generation</td><td>ComEd</td><td>PECO</td><td>BGE</td><td>PHI</td><td>Pepco</td><td>DPL</td><td>ACE</td></tr><tr><td>For the year ended December 31, 2019</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Utility \( ^{(a)} \)</td><td>$ 881</td><td>$ 112</td><td>$ 242</td><td>$ 132</td><td>$ 90</td><td>$ 304</td><td>$ 286</td><td>$ 18</td><td>$ —</td></tr><tr><td>Property</td><td>595</td><td>274</td><td>29</td><td>17</td><td>153</td><td>122</td><td>85</td><td>34</td><td>2</td></tr><tr><td>Payroll</td><td>232</td><td>115</td><td>27</td><td>15</td><td>17</td><td>24</td><td>7</td><td>4</td><td>2</td></tr></table>

<table><tr><td>Utility \( ^{(a)} \)</td><td>$ 919</td><td>$ 114</td><td>$ 243</td><td>$ 131</td><td>$ 94</td><td>$ 337</td><td>$ 316</td><td>$ 21</td><td>$ —</td></tr><tr><td>Property</td><td>557</td><td>273</td><td>30</td><td>15</td><td>143</td><td>94</td><td>58</td><td>32</td><td>3</td></tr><tr><td>Payroll</td><td>247</td><td>130</td><td>27</td><td>16</td><td>17</td><td>24</td><td>5</td><td>3</td><td>2</td></tr></table>

<table><tr><td>Utility \( ^{(a)} \)</td><td>$ 898</td><td>$ 126</td><td>$ 240</td><td>$ 125</td><td>$ 89</td><td>$ 318</td><td>$ 300</td><td>$ 18</td><td>$ —</td></tr><tr><td>Property</td><td>545</td><td>269</td><td>28</td><td>14</td><td>132</td><td>101</td><td>62</td><td>32</td><td>3</td></tr><tr><td>Payroll</td><td>230</td><td>121</td><td>26</td><td>15</td><td>15</td><td>26</td><td>6</td><td>4</td><td>2</td></tr></table>

(a) Generation’s utility tax represents gross receipts tax related to its retail operations and the Utility Registrants’ utility taxes represents municipal and state utility taxes and gross receipts taxes related to their operating revenues.



## Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 23 — Supplemental Financial Information

<table><tr><td rowspan="2"></td><td colspan="12">Other, Net</td></tr><tr><td>Exelon</td><td>Generation</td><td>ComEd</td><td>PECO</td><td>BGE</td><td>PHI</td><td>Pepco</td><td>DPL</td><td>ACE</td><td></td><td></td><td></td></tr><tr><td>For the year ended December 31, 2019</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Decommissioning-related activities:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Net realized income on NDT funds \( ^{(a)} \)</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Regulatory agreement units</td><td>$ 297</td><td>$ 297</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$  —</td><td>$ —</td><td></td><td></td></tr><tr><td>Non-regulatory agreement units</td><td>363</td><td>363</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td><td></td></tr><tr><td>Net unrealized gains on NDT funds</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Regulatory agreement units</td><td>795</td><td>795</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td><td></td></tr><tr><td>Non-regulatory agreement units</td><td>411</td><td>411</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td><td></td></tr><tr><td>Regulatory offset to NDT fund-related activities \( ^{(b)} \)</td><td>(876)</td><td>(876)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td><td></td></tr><tr><td>Decommissioning-related activities</td><td>990</td><td>990</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td><td></td></tr><tr><td>AFUDC—Equity</td><td>85</td><td>—</td><td>—</td><td>17</td><td>13</td><td>21</td><td>34</td><td>25</td><td>4</td><td>5</td><td></td><td></td></tr><tr><td>Non-service net periodic benefit cost</td><td>13</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td><td></td><td></td></tr><tr><td>For the year ended December 31, 2018</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Decommissioning-related activities:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Net realized income on NDT funds \( ^{(a)} \)</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Regulatory agreement units</td><td>$ 506</td><td>$ 506</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$  —</td><td></td><td></td><td></td></tr><tr><td>Non-regulatory agreement units</td><td>302</td><td>302</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td><td></td></tr><tr><td>Net unrealized losses on NDT funds</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Regulatory agreement units</td><td>(715)</td><td>(715)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td><td></td></tr><tr><td>Non-regulatory agreement units</td><td>(483)</td><td>(483)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td><td></td></tr><tr><td>Regulatory offset to NDT fund-related activities \( ^{(b)} \)</td><td>171</td><td>171</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td><td></td></tr><tr><td>Decommissioning-related activities</td><td>(219)</td><td>(219)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td><td></td></tr><tr><td>AFUDC—Equity</td><td>69</td><td>—</td><td>—</td><td>19</td><td>7</td><td>18</td><td>25</td><td>22</td><td>2</td><td>1</td><td></td><td></td></tr><tr><td>Non-service net periodic benefit cost</td><td>(47)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td><td></td><td></td></tr><tr><td>For the year ended December 31, 2017</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Decommissioning-related activities:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Net realized income on NDT funds \( ^{(a)} \)</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Regulatory agreement units</td><td>$ 488</td><td>$ 488</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$  —</td><td></td><td></td><td></td></tr><tr><td>Non-regulatory agreement units</td><td>209</td><td>209</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td><td></td></tr><tr><td>Net unrealized gains on NDT funds</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Regulatory agreement units</td><td>455</td><td>455</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td><td></td></tr><tr><td>Non-regulatory agreement units</td><td>521</td><td>521</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td><td></td></tr><tr><td>Regulatory offset to NDT fund-related activities \( ^{(b)} \)</td><td>(724)</td><td>(724)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td><td></td></tr><tr><td>Decommissioning-related activities</td><td>949</td><td>949</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td><td></td></tr><tr><td>AFUDC—Equity</td><td>73</td><td>—</td><td>12</td><td>9</td><td>16</td><td>36</td><td>23</td><td>7</td><td>6</td><td></td><td></td><td></td></tr><tr><td>Non-service net periodic benefit cost</td><td>(109)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td><td></td><td></td></tr></table>

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

(b) Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units, including the elimination of income taxes related to all NDT fund activity for those units. See Note 9 — Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning.



## Supplemental Cash Flow Information

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

Depreciation, amortization and accretion

<table><tr><td></td><td>Exelon</td><td>Generation</td><td>ComEd</td><td>PECO</td><td>BGE</td><td>PHI</td><td>Pepco</td><td>DPL</td><td>ACE</td></tr><tr><td>For the year ended December 31, 2019</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Property, plant and equipment</td><td>$ 3,665</td><td>$ 1,485</td><td>$ 886</td><td>$ 303</td><td>$ 359</td><td>$ 547</td><td>$ 239</td><td>$ 146</td><td>$ 123</td></tr><tr><td>Amortization of regulatory assets</td><td>528</td><td>—</td><td>147</td><td>30</td><td>143</td><td>207</td><td>135</td><td>38</td><td>34</td></tr><tr><td>Amortization of intangible assets, net</td><td>59</td><td>50</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Amortization of energy contract assets and liabilities(a)</td><td>21</td><td>21</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Nuclear fuel(b)</td><td>1,016</td><td>1,016</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>ARO accretion(c)</td><td>491</td><td>491</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Total depreciation, amortization and accretion</td><td>$ 5,780</td><td>$ 3,063</td><td>$ 1,033</td><td>$ 333</td><td>$ 502</td><td>$ 754</td><td>$ 374</td><td>$ 184</td><td>$ 157</td></tr></table>

<table><tr><td>For the year ended December 31, 2018</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Property, plant and equipment</td><td>$ 3,740</td><td>$ 1,748</td><td>$ 820</td><td>$ 274</td><td>$ 335</td><td>$ 480</td><td>$ 218</td><td>$ 131</td><td>$ 94</td></tr><tr><td>Amortization of regulatory assets</td><td>555</td><td>—</td><td>120</td><td>27</td><td>148</td><td>260</td><td>167</td><td>51</td><td>42</td></tr><tr><td>Amortization of intangible assets, net</td><td>58</td><td>49</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Amortization of energy contract assets and liabilities(a)</td><td>14</td><td>14</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Nuclear fuel(b)</td><td>1,115</td><td>1,115</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>ARO accretion(c)</td><td>489</td><td>489</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Total depreciation, amortization and accretion</td><td>$ 5,971</td><td>$ 3,415</td><td>$ 940</td><td>$ 301</td><td>$ 483</td><td>$ 740</td><td>$ 385</td><td>$ 182</td><td>$ 136</td></tr></table>

<table><tr><td>For the year ended December 31, 2017</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Property, plant and equipment</td><td>$ 3,293</td><td>$ 1,409</td><td>$ 777</td><td>$ 261</td><td>$ 312</td><td>$ 457</td><td>$ 203</td><td>$ 124</td><td>$ 89</td></tr><tr><td>Amortization of regulatory assets</td><td>478</td><td>—</td><td>73</td><td>25</td><td>161</td><td>218</td><td>118</td><td>43</td><td>57</td></tr><tr><td>Amortization of intangible assets, net</td><td>57</td><td>48</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Amortization of energy contract assets and liabilities(a)</td><td>35</td><td>35</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Nuclear fuel(b)</td><td>1,096</td><td>1,096</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>ARO accretion(c)</td><td>468</td><td>468</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>Total depreciation, amortization and accretion</td><td>$ 5,427</td><td>$ 3,056</td><td>$ 850</td><td>$ 286</td><td>$ 473</td><td>$ 675</td><td>$ 321</td><td>$ 167</td><td>$ 146</td></tr></table>

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

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

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



## Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 23 — Supplemental Financial Information

<table><tr><td rowspan="2"></td><td colspan="12">Cash paid (refunded) during the year:</td></tr><tr><td>Exelon</td><td>Generation</td><td>ComEd</td><td>PECO</td><td>BGE</td><td>PHI</td><td>Pepco</td><td>DPL</td><td>ACE</td><td></td><td></td><td></td></tr><tr><td>For the year ended December 31, 2019</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Interest (net of amount capitalized)</td><td>$ 1,470</td><td>$ 373</td><td>$ 343</td><td>$ 129</td><td>$ 106</td><td>$ 255</td><td>$ 130</td><td>$ 59</td><td>$ 55</td><td></td><td></td><td></td></tr><tr><td>Income taxes (net of refunds)</td><td>265</td><td>(44)</td><td>(42)</td><td>82</td><td>17</td><td>29</td><td>7</td><td>19</td><td>(5)</td><td></td><td></td><td></td></tr><tr><td>For the year ended December 31, 2018</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Interest (net of amount capitalized)</td><td>$ 1,421</td><td>$ 369</td><td>$ 332</td><td>$ 125</td><td>$ 94</td><td>$ 250</td><td>$ 123</td><td>$ 56</td><td>$ 61</td><td></td><td></td><td></td></tr><tr><td>Income taxes (net of refunds)</td><td>95</td><td>746</td><td>(153)</td><td>(2)</td><td>14</td><td>(32)</td><td>41</td><td>(6)</td><td>(12)</td><td></td><td></td><td></td></tr><tr><td>For the year ended December 31, 2017</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Interest (net of amount capitalized)</td><td>$ 2,430</td><td>$ 391</td><td>$ 307</td><td>$ 103</td><td>$ 96</td><td>$ 236</td><td>$ 114</td><td>$ 49</td><td>$ 59</td><td></td><td></td><td></td></tr><tr><td>Income taxes (net of refunds)</td><td>540</td><td>337</td><td>83</td><td>47</td><td>(2)</td><td>(144)</td><td>(104)</td><td>(49)</td><td>(2)</td><td></td><td></td><td></td></tr></table>



## Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 23 — Supplemental Financial Information

<table><tr><td rowspan="2">For the year ended December 31, 2019</td><td colspan="11">Other non-cash operating activities:</td></tr><tr><td>Exelon</td><td>Generation</td><td>ComEd</td><td>PECO</td><td>BGE</td><td>PHI</td><td>Pepco</td><td>DPL</td><td>ACE</td><td></td><td></td></tr><tr><td>Pension and non-pension postretirement benefit costs</td><td>$ 438</td><td>$ 135</td><td>$ 96</td><td>$ 12</td><td>$ 61</td><td>$ 95</td><td>$ 25</td><td>$ 15</td><td>$ 16</td><td></td><td></td></tr><tr><td>Provision for uncollectible accounts</td><td>120</td><td>31</td><td>33</td><td>31</td><td>8</td><td>17</td><td>7</td><td>4</td><td>5</td><td></td><td></td></tr><tr><td>Other decommissioning-related activity(a)</td><td>(506)</td><td>(506)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Energy-related options(b)</td><td>22</td><td>22</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Amortization of rate stabilization deferral</td><td>(4)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>(4)</td><td>(4)</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Discrete impacts from EIMA and FEJA(d)</td><td>128</td><td>—</td><td>128</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Long-term incentive plan</td><td>10</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td><td></td></tr><tr><td>Amortization of operating ROU asset</td><td>244</td><td>172</td><td>3</td><td>—</td><td>30</td><td>33</td><td>8</td><td>8</td><td>4</td><td></td><td></td></tr><tr><td>Change in environmental liabilities</td><td>23</td><td>—</td><td>—</td><td>—</td><td>—</td><td>23</td><td>23</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>For the year ended December 31, 2018</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Pension and non-pension postretirement benefit costs</td><td>$ 583</td><td>$ 204</td><td>$ 177</td><td>$ 18</td><td>$ 59</td><td>$ 67</td><td>$ 15</td><td>$ 6</td><td>$ 12</td><td></td><td></td></tr><tr><td>Provision for uncollectible accounts</td><td>159</td><td>48</td><td>40</td><td>33</td><td>10</td><td>28</td><td>11</td><td>6</td><td>11</td><td></td><td></td></tr><tr><td>Other decommissioning-related activity(a)</td><td>(2)</td><td>(2)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Energy-related options(b)</td><td>10</td><td>10</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Amortization of rate stabilization deferral</td><td>21</td><td>—</td><td>—</td><td>—</td><td>—</td><td>21</td><td>21</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Asset retirement costs</td><td>20</td><td>—</td><td>—</td><td>—</td><td>—</td><td>20</td><td>22</td><td>(1)</td><td>(1)</td><td></td><td></td></tr><tr><td>Discrete impacts from EIMA and FEJA(d)</td><td>28</td><td>—</td><td>28</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Long-term incentive plan</td><td>140</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td><td></td></tr><tr><td>For the year ended December 31, 2017</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Pension and non-pension postretirement benefit costs</td><td>$ 643</td><td>$ 227</td><td>$ 176</td><td>$ 29</td><td>$ 62</td><td>$ 94</td><td>$ 25</td><td>$ 13</td><td>$ 13</td><td></td><td></td></tr><tr><td>Provision for uncollectible accounts</td><td>125</td><td>38</td><td>34</td><td>26</td><td>8</td><td>19</td><td>8</td><td>3</td><td>8</td><td></td><td></td></tr><tr><td>Other decommissioning-related activity(a)</td><td>(313)</td><td>(313)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Energy-related options(b)</td><td>7</td><td>7</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Amortization of rate stabilization deferral</td><td>(3)</td><td>—</td><td>—</td><td>—</td><td>7</td><td>(10)</td><td>(10)</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Discrete impacts from EIMA and FEJA(d)</td><td>(52)</td><td>—</td><td>(52)</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Vacation accrual adjustment(e)</td><td>(68)</td><td>(35)</td><td>(12)</td><td>—</td><td>—</td><td>(8)</td><td>(8)</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Long-term incentive plan</td><td>109</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td><td></td></tr><tr><td>Change in environmental liabilities</td><td>44</td><td>44</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td></tr></table>

(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. See Note 9 — Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning.

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

(c) See Note 2 - Mergers, Acquisitions and Dispositions for additional information.



# Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 23 — Supplemental Financial Information

(d) Reflects the change in ComEd's distribution and energy efficiency formula rates. See Note 3 — Regulatory Matters for additional information.

(e) On December 1, 2017, Exelon adopted a single, standard vacation accrual policy for all non-represented, non-craft (represented and craft policies remained unchanged) employees effective January 1, 2018. To reflect the new policy, Exelon recorded a one-time, $68 million pre-tax credit to expense to reverse 2018 vacation cost originally accrued throughout 2017 that was accrued ratably during 2018.

The following tables provide a reconciliation of cash, cash equivalents and restricted cash reported within the Registrants' Consolidated Balance Sheets that sum to the total of the same amounts in their Consolidated Statements of Cash Flows.

<table><tr><td></td><td>Exelon</td><td>Generation</td><td>ComEd</td><td>PECO</td><td>BGE</td><td>PHI</td><td>Pepco</td><td>DPL</td><td>ACE</td></tr><tr><td>December 31, 2019</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Cash and cash equivalents</td><td>$ 587</td><td>$ 303</td><td>$ 90</td><td>$ 21</td><td>$ 24</td><td>$ 131</td><td>$ 30</td><td>$ 13</td><td>$ 12</td></tr><tr><td>Restricted cash</td><td>358</td><td>146</td><td>150</td><td>6</td><td>1</td><td>36</td><td>33</td><td>—</td><td>2</td></tr><tr><td>Restricted cash included in other long-term assets</td><td>177</td><td>—</td><td>163</td><td>—</td><td>—</td><td>14</td><td>—</td><td>—</td><td>14</td></tr><tr><td>Total cash, cash equivalents and restricted cash</td><td>$ 1,122</td><td>$ 449</td><td>$ 403</td><td>$ 27</td><td>$ 25</td><td>$ 181</td><td>$ 63</td><td>$ 13</td><td>$ 28</td></tr><tr><td>December 31, 2018</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Cash and cash equivalents</td><td>$ 1,349</td><td>$ 750</td><td>$ 135</td><td>$ 130</td><td>$ 7</td><td>$ 124</td><td>$ 16</td><td>$ 23</td><td>$ 7</td></tr><tr><td>Restricted cash</td><td>247</td><td>153</td><td>29</td><td>5</td><td>6</td><td>43</td><td>37</td><td>1</td><td>4</td></tr><tr><td>Restricted cash included in other long-term assets</td><td>185</td><td>—</td><td>166</td><td>—</td><td>—</td><td>19</td><td>—</td><td>—</td><td>19</td></tr><tr><td>Total cash, cash equivalents and restricted cash</td><td>$ 1,781</td><td>$ 903</td><td>$ 330</td><td>$ 135</td><td>$ 13</td><td>$ 186</td><td>$ 53</td><td>$ 24</td><td>$ 30</td></tr><tr><td>December 31, 2017</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Cash and cash equivalents</td><td>$ 898</td><td>$ 416</td><td>$ 76</td><td>$ 271</td><td>$ 17</td><td>$ 30</td><td>$ 5</td><td>$ 2</td><td>$ 2</td></tr><tr><td>Restricted cash</td><td>207</td><td>138</td><td>5</td><td>4</td><td>1</td><td>42</td><td>35</td><td>—</td><td>6</td></tr><tr><td>Restricted cash included in other long-term assets</td><td>85</td><td>—</td><td>63</td><td>—</td><td>—</td><td>23</td><td>—</td><td>—</td><td>23</td></tr><tr><td>Total cash, cash equivalents and restricted cash</td><td>$ 1,190</td><td>$ 554</td><td>$ 144</td><td>$ 275</td><td>$ 18</td><td>$ 95</td><td>$ 40</td><td>$ 2</td><td>$ 31</td></tr><tr><td>December 31, 2016</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Cash and cash equivalents</td><td>$ 635</td><td>$ 290</td><td>$ 56</td><td>$ 63</td><td>$ 23</td><td>$ 170</td><td>$ 9</td><td>$ 46</td><td>$ 101</td></tr><tr><td>Restricted cash</td><td>253</td><td>158</td><td>2</td><td>4</td><td>24</td><td>43</td><td>33</td><td>—</td><td>9</td></tr><tr><td>Restricted cash included in other long-term assets</td><td>26</td><td>—</td><td>—</td><td>—</td><td>3</td><td>23</td><td>—</td><td>—</td><td>23</td></tr><tr><td>Total cash, cash equivalents and restricted cash</td><td>$ 914</td><td>$ 448</td><td>$ 58</td><td>$ 67</td><td>$ 50</td><td>$ 236</td><td>$ 42</td><td>$ 46</td><td>$ 133</td></tr></table>



## Supplemental Balance Sheet Information

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

<table><tr><td rowspan="2"></td><td colspan="10">Unbilled customer revenues(a)</td></tr><tr><td>Exelon</td><td>Generation</td><td>ComEd</td><td>PECO</td><td>BGE</td><td>PHI</td><td>Pepco</td><td>DPL</td><td>ACE</td><td></td></tr><tr><td>December 31, 2019</td><td>$ 1,535</td><td>$ 807</td><td>$ 218</td><td>$ 146</td><td>$ 170</td><td>$ 194</td><td>$ 100</td><td>$ 61</td><td>$ 33</td><td></td></tr><tr><td>December 31, 2018</td><td>1,656</td><td>965</td><td>223</td><td>114</td><td>168</td><td>186</td><td>97</td><td>59</td><td>30</td><td></td></tr></table>

(a) Unbilled customer revenues are classified in customer accounts receivables, net in Exelon's and the Utility Registrants' Consolidated Balance Sheets.

<table><tr><td rowspan="2"></td><td colspan="12">Investments</td></tr><tr><td>Exelon</td><td>Generation</td><td>ComEd</td><td>PECO</td><td>BGE</td><td>PHI</td><td>Pepco</td><td>DPL</td><td>ACE</td><td></td><td></td><td></td></tr><tr><td>December 31, 2019</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Equity method investments:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Other equity method investments</td><td>$ 92</td><td>$ 71</td><td>$ 6</td><td>$ 8</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td></td><td></td></tr><tr><td>Other investments:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Employee benefit trusts and investments \( ^{(a)} \)</td><td>262</td><td>54</td><td>—</td><td>19</td><td>7</td><td>135</td><td>110</td><td>—</td><td>—</td><td></td><td></td><td></td></tr><tr><td>Equity investments without readily determinable fair values</td><td>69</td><td>69</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td><td></td></tr><tr><td>Other available for sale debt security investments</td><td>41</td><td>41</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td><td></td></tr><tr><td>Total investments</td><td>$ 464</td><td>$ 235</td><td>$ 6</td><td>$ 27</td><td>$ 7</td><td>$ 135</td><td>$ 110</td><td>$ —</td><td>$ —</td><td></td><td></td><td></td></tr></table>

<table><tr><td colspan="12">December 31, 2018</td></tr><tr><td>Equity method investments:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Distributed energy companies</td><td>$ 180</td><td>$ 180</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$  \) —</td><td>$ —</td><td></td><td></td></tr><tr><td>Other equity method investments</td><td>87</td><td>71</td><td>6</td><td>8</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Total equity method investments</td><td>267</td><td>251</td><td>6</td><td>8</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>Other investments:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Employee benefit trusts and investments \( ^{(a)} \)</td><td>244</td><td>49</td><td>—</td><td>17</td><td>5</td><td>130</td><td>105</td><td>—</td><td>—</td><td></td><td></td><td></td></tr><tr><td>Equity investments without readily determinable fair values</td><td>72</td><td>72</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td><td></td></tr><tr><td>Other available for sale debt security investments</td><td>40</td><td>40</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td><td></td></tr><tr><td>Other</td><td>2</td><td>2</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td></td><td></td></tr><tr><td>Total investments</td><td>$ 625</td><td>$ 414</td><td>$ 6</td><td>$ 25</td><td>$ 5</td><td>$ 130</td><td>$ 105</td><td>$ —</td><td>$ —</td><td></td><td></td><td></td></tr></table>

(a) The Registrants' debt and equity security investments are recorded at fair market value.



## Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)

Note 23 — Supplemental Financial Information

<table><tr><td rowspan="2"></td><td colspan="12">Accrued expenses</td></tr><tr><td>Exelon</td><td>Generation</td><td>ComEd</td><td>PECO</td><td>BGE</td><td>PHI</td><td>Pepco</td><td>DPL</td><td>ACE</td><td></td><td></td><td></td></tr><tr><td>December 31, 2019</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Compensation-related accruals \( ^{(a)} \)</td><td>$ 1,052</td><td>$ 422</td><td>$ 171</td><td>$ 58</td><td>$ 78</td><td>$ 101</td><td>$ 28</td><td>$ 19</td><td>$ 15</td><td></td><td></td><td></td></tr><tr><td>Taxes accrued</td><td>414</td><td>222</td><td>83</td><td>3</td><td>26</td><td>117</td><td>90</td><td>14</td><td>8</td><td></td><td></td><td></td></tr><tr><td>Interest accrued</td><td>337</td><td>65</td><td>110</td><td>37</td><td>46</td><td>49</td><td>23</td><td>8</td><td>12</td><td></td><td></td><td></td></tr><tr><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>December 31, 2018</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Compensation-related accruals \( ^{(a)} \)</td><td>$ 1,191</td><td>$ 479</td><td>$ 187</td><td>$ 49</td><td>$ 68</td><td>$ 99</td><td>$ 29</td><td>$ 19</td><td>$ 12</td><td></td><td></td><td></td></tr><tr><td>Taxes accrued</td><td>412</td><td>226</td><td>71</td><td>28</td><td>46</td><td>74</td><td>58</td><td>4</td><td>5</td><td></td><td></td><td></td></tr><tr><td>Interest accrued</td><td>334</td><td>77</td><td>105</td><td>33</td><td>39</td><td>50</td><td>25</td><td>8</td><td>12</td><td></td><td></td><td></td></tr></table>

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

## 24. Related Party Transactions (All Registrants)

## Operating revenues from affiliates

## Generation

The following table presents Generation’s Operating revenues from affiliates, which are primarily recorded as Purchased power from affiliates and an immaterial amount recorded as Operating and maintenance expense from affiliates at the Utility Registrants:

<table><tr><td rowspan="2"></td><td colspan="4">For the Years Ended December 31,</td></tr><tr><td>2019</td><td>2018</td><td>2017</td><td></td></tr><tr><td>Operating revenues from affiliates:</td><td></td><td></td><td></td><td></td></tr><tr><td>ComEd (a)(b)</td><td>$ 369</td><td>$ 523</td><td>$ 121</td><td></td></tr><tr><td>PECO (c)</td><td>158</td><td>128</td><td>138</td><td></td></tr><tr><td>BGE (d)</td><td>289</td><td>260</td><td>388</td><td></td></tr><tr><td>PHI</td><td>353</td><td>355</td><td>463</td><td></td></tr><tr><td>Pepco (e)</td><td>264</td><td>206</td><td>255</td><td></td></tr><tr><td>DPL (f)</td><td>70</td><td>120</td><td>179</td><td></td></tr><tr><td>ACE (g)</td><td>19</td><td>29</td><td>29</td><td></td></tr><tr><td>Other</td><td>3</td><td>2</td><td>5</td><td></td></tr><tr><td>Total operating revenues from affiliates (Generation)</td><td>$ 1,172</td><td>$ 1,268</td><td>$ 1,115</td><td></td></tr></table>

(a) Generation has an ICC-approved RFP contract with ComEd to provide a portion of ComEd's electricity supply requirements. Generation also sells RECs and ZECs to ComEd.

(b) For 2019, ComEd’s Purchased power from Generation of $376 million is recorded as Operating revenues from ComEd of $369 million and Purchased power and fuel from ComEd of $7 million at Generation. For 2018, ComEd’s Purchased power from Generation of $529 million is recorded as Operating revenues from ComEd of $523 million and Purchased power and fuel from ComEd of $6 million at Generation.

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

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

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

(f) Generation provides a portion of DPL's energy requirements under its MDPSC and DPSC approved market based SOS and gas commodity programs.



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

PHI

PHI's Operating revenues from affiliates are primarily with BSC for services that PHISCO provides to BSC.

## Operating and maintenance expense from affiliates

The Registrants receive a variety of corporate support services from BSC. Pepco, DPL and ACE also receive corporate support services from PHISCO. See Note 1 - Significant Accounting Policies for additional information regarding BSC and PHISCO.

The following table presents the service company costs allocated to the Registrants:

<table><tr><td rowspan="3"></td><td colspan="4">Operating and maintenance from affiliates</td><td colspan="3">Operating and maintenance</td><td colspan="3">Capitalized costs</td></tr><tr><td colspan="4">For the years ended December 31,</td><td colspan="3">For the years ended December 31,</td><td colspan="3">For the years ended November 31,</td></tr><tr><td>2019</td><td>2018</td><td>2017</td><td>2017</td><td>2019</td><td>2018</td><td>2017</td><td>2019</td><td>2018</td><td>2017</td></tr><tr><td>Exelon</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>BSC</td><td></td><td></td><td></td><td></td><td></td><td></td><td>$ 516</td><td>$ 448</td><td>$ 330</td><td></td></tr><tr><td>PHISCO</td><td></td><td></td><td></td><td></td><td></td><td></td><td>72</td><td>79</td><td>—</td><td></td></tr><tr><td>Generation</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>BSC</td><td>$ 570</td><td>$ 652</td><td>$ 689</td><td>$</td><td>—</td><td>66</td><td>67</td><td>98</td><td></td><td></td></tr><tr><td>ComEd</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>BSC</td><td>263</td><td>265</td><td>270</td><td></td><td>—</td><td>148</td><td>135</td><td>118</td><td></td><td></td></tr><tr><td>PECO</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>BSC</td><td>149</td><td>146</td><td>146</td><td></td><td>—</td><td>88</td><td>64</td><td>59</td><td></td><td></td></tr><tr><td>BGE</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>BSC</td><td>157</td><td>157</td><td>152</td><td></td><td>—</td><td>126</td><td>79</td><td>54</td><td></td><td></td></tr><tr><td>PHI</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>BSC</td><td>139</td><td>147</td><td>145</td><td></td><td>—</td><td>88</td><td>102</td><td>—</td><td></td><td></td></tr><tr><td>PHISCO (a)</td><td>—</td><td>—</td><td>—</td><td></td><td>—</td><td>72</td><td>79</td><td>—</td><td></td><td></td></tr><tr><td>Pepco</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>BSC</td><td>85</td><td>89</td><td>53</td><td></td><td>—</td><td>38</td><td>40</td><td>—</td><td></td><td></td></tr><tr><td>PHISCO (a)</td><td>124</td><td>137</td><td>5</td><td></td><td>219</td><td>33</td><td>32</td><td>—</td><td></td><td></td></tr><tr><td>PES (b)</td><td>—</td><td>—</td><td>—</td><td></td><td>29</td><td>—</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>DPL</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>BSC</td><td>52</td><td>51</td><td>31</td><td></td><td>—</td><td>25</td><td>28</td><td>—</td><td></td><td></td></tr><tr><td>PHISCO (a)</td><td>100</td><td>111</td><td>—</td><td></td><td>165</td><td>20</td><td>25</td><td>—</td><td></td><td></td></tr><tr><td>PES (b)</td><td>—</td><td>—</td><td>—</td><td></td><td>9</td><td>—</td><td>—</td><td>—</td><td></td><td></td></tr><tr><td>ACE</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>BSC</td><td>42</td><td>42</td><td>25</td><td></td><td>—</td><td>19</td><td>20</td><td>—</td><td></td><td></td></tr><tr><td>PHISCO (a)</td><td>90</td><td>98</td><td>—</td><td></td><td>135</td><td>19</td><td>21</td><td>—</td><td></td><td></td></tr></table>

(a) Due to the PHI entities' system conversion to Exelon's accounting systems on January 1, 2018, corporate support services received from PHISCO are reported in Operating and maintenance from affiliates and in Capitalized costs beginning in 2018.

(b) PES performed underground transmission, distribution construction and maintenance services, including services that are treated as capital costs, for Pepco and DPL.



## Current Receivables from/Payables to affiliates

The following tables present current receivables from affiliates and current payables to affiliates:

December 31, 2019

<table><tr><td rowspan="2">Payables to affiliates:</td><td colspan="12">Receivables from affiliates:</td></tr><tr><td>Generation</td><td colspan="2">Comed</td><td colspan="2">PECO</td><td colspan="2">BGE</td><td colspan="2">ACE</td><td>BSC</td><td>PHISCO</td><td>Other</td><td>Total</td></tr><tr><td>Generation</td><td></td><td>$ 27</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>67</td><td>$ —</td><td>$ 23</td><td>$ 117</td><td></td><td></td></tr><tr><td>ComEd</td><td>$ 78</td><td>(a)</td><td></td><td>—</td><td></td><td>—</td><td>—</td><td>54</td><td></td><td>—</td><td>8</td><td>140</td><td></td></tr><tr><td>PECO</td><td>27</td><td></td><td>—</td><td></td><td>—</td><td>—</td><td>25</td><td></td><td>—</td><td>3</td><td>55</td><td></td><td></td></tr><tr><td>BGE</td><td>28</td><td></td><td>—</td><td>—</td><td></td><td>—</td><td>34</td><td></td><td>—</td><td>4</td><td>66</td><td></td><td></td></tr><tr><td>PHI</td><td></td><td>—</td><td>—</td><td>—</td><td></td><td>—</td><td>—</td><td>4</td><td></td><td>—</td><td>10</td><td>14</td><td></td></tr><tr><td>Pepco</td><td>34</td><td></td><td>—</td><td>—</td><td></td><td>—</td><td>—</td><td>16</td><td>15</td><td>1</td><td>66</td><td></td><td></td></tr><tr><td>DPL</td><td>7</td><td></td><td>—</td><td>—</td><td></td><td>—</td><td>3</td><td>10</td><td>11</td><td>1</td><td>32</td><td></td><td></td></tr><tr><td>ACE</td><td>7</td><td></td><td>—</td><td>—</td><td></td><td>—</td><td></td><td>7</td><td>10</td><td>1</td><td>25</td><td></td><td></td></tr><tr><td>Other</td><td>9</td><td></td><td>1</td><td>1</td><td>1</td><td>1</td><td>1</td><td>—</td><td></td><td>—</td><td></td><td>13</td><td></td></tr><tr><td>Total</td><td>$ 190</td><td>$ 28</td><td>$ 1</td><td>$ 1</td><td>$ 1</td><td>$ 4</td><td>$ 217</td><td>$ 36</td><td>$ 51</td><td>$ 528</td><td></td><td></td><td></td></tr></table>

December 31, 2018

<table><tr><td rowspan="2">Payables to affiliates:</td><td colspan="12">Receivables from affiliates:</td></tr><tr><td>Generation</td><td colspan="2">Comed</td><td colspan="2">BGE</td><td colspan="2">Pepco</td><td colspan="2">ACE</td><td>BSC</td><td>PHISCO</td><td>Other</td><td>Total</td></tr><tr><td>Generation</td><td></td><td>$ 19</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>$ —</td><td>95</td><td>$ —</td><td>$ 25</td><td>$ 139</td><td></td><td></td></tr><tr><td>ComEd</td><td>$ 69</td><td>(a)</td><td></td><td>—</td><td></td><td>—</td><td>—</td><td>56</td><td></td><td>—</td><td>8</td><td>133</td><td></td></tr><tr><td>PECO</td><td>30</td><td></td><td>—</td><td>—</td><td></td><td>—</td><td>—</td><td>26</td><td></td><td>—</td><td>3</td><td>59</td><td></td></tr><tr><td>BGE</td><td>24</td><td></td><td>—</td><td></td><td>—</td><td>—</td><td>—</td><td>38</td><td></td><td>—</td><td>3</td><td>65</td><td></td></tr><tr><td>PHI</td><td></td><td>—</td><td></td><td>—</td><td></td><td>—</td><td>—</td><td>3</td><td></td><td>—</td><td>9</td><td>12</td><td></td></tr><tr><td>Pepco</td><td>28</td><td></td><td>—</td><td></td><td>—</td><td></td><td>—</td><td>19</td><td></td><td>14</td><td>1</td><td>62</td><td></td></tr><tr><td>DPL</td><td>7</td><td></td><td>—</td><td></td><td>—</td><td>1</td><td>1</td><td>11</td><td></td><td>12</td><td>1</td><td>33</td><td></td></tr><tr><td>ACE</td><td>5</td><td></td><td>—</td><td></td><td>—</td><td></td><td>—</td><td>8</td><td></td><td>13</td><td>2</td><td>28</td><td></td></tr><tr><td>Other</td><td>10</td><td></td><td>1</td><td>1</td><td></td><td>—</td><td>—</td><td>—</td><td></td><td>—</td><td></td><td>12</td><td></td></tr><tr><td>Total</td><td>$ 173</td><td>$ 20</td><td>$ 1</td><td>$ 1</td><td>$ 1</td><td>$ 1</td><td>$ 256</td><td>$ 39</td><td>$ 52</td><td>$ 543</td><td></td><td></td><td></td></tr></table>

(a) At December 31, 2019 and 2018, Generation also had a contract liability with ComEd for $37 million and $14 million, respectively, that was included in Other liabilities on Generation's Consolidated Balance Sheets. At December 31, 2019 and 2018, ComEd had a Current Payable to Generation of $41 million and $55 million, respectively, on its Consolidated Balance Sheets, which consisted of Generation's Current Receivable from ComEd, partially offset by Generation's contract liability with ComEd.



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

Note 24 — Related Party Transactions

## Borrowings from Exelon/PHI intercompany money pool

To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing both Exelon and PHI operate an intercompany money pool. Generation, ComEd, PECO, and PHI Corporate participate in the Exelon money pool. Pepco, DPL and ACE participate in the PHI intercompany money pool.

## Noncurrent Receivables from/Payables to affiliates

Generation has long-term payables to ComEd and PECO as a result of the nuclear decommissioning contractual construct whereby, to the extent NDT funds are greater than the underlying ARO at the end of decommissioning, such amounts are due back to ComEd and PECO, as applicable, for payment to their respective customers. See Note 9 — Asset Retirement Obligations for additional information.

The following table presents noncurrent receivables from affiliates at ComEd and PECO which are recorded as noncurrent payables to affiliates at Generation:

<table><tr><td rowspan="2"></td><td colspan="2">December 31,</td></tr><tr><td>2019</td><td>2018</td></tr><tr><td>ComEd</td><td>$ 2,622</td><td>$ 2,217</td></tr><tr><td>PECO</td><td>480</td><td>389</td></tr><tr><td>Other</td><td>1</td><td>—</td></tr><tr><td>Total:</td><td>$ 3,103</td><td>$ 2,606</td></tr></table>

## Long-term debt to financing trusts

The following table presents Long-term debt to financing trusts:

<table><tr><td rowspan="2"></td><td colspan="6">As of December 31,</td></tr><tr><td colspan="3">2019</td><td colspan="3">2018</td></tr><tr><td></td><td>Exelon</td><td>ComEd</td><td>PECO</td><td>Exelon</td><td>ComEd</td><td>PECO</td></tr><tr><td>ComEd Financing III</td><td>$ 206</td><td>$ 205</td><td>$ —</td><td>$ 206</td><td>$ 205</td><td>$ —</td></tr><tr><td>PECO Trust III</td><td>81</td><td>—</td><td>81</td><td>81</td><td>—</td><td>81</td></tr><tr><td>PECO Trust IV</td><td>103</td><td>—</td><td>103</td><td>103</td><td>—</td><td>103</td></tr><tr><td>Total</td><td>$ 390</td><td>$ 205</td><td>$ 184</td><td>$ 390</td><td>$ 205</td><td>$ 184</td></tr></table>

## Long-term debt to affiliates

In connection with the debt obligations assumed by Exelon as part of the Constellation merger, Exelon and subsidiaries of Generation (former Constellation subsidiaries) assumed intercompany loan agreements that mirror the terms and amounts of the third-party debt obligations of Exelon, resulting in intercompany notes payable included in Long-term debt to affiliates in Generation's Consolidated Balance Sheets and intercompany notes receivable at Exelon Corporate.



## 25. Quarterly Data (Unaudited) (All Registrants)

## Exelon

The data shown below, which may not equal the total for the year due to the effects of rounding and dilution, includes all adjustments that Exelon considers necessary for a fair presentation of such amounts:

<table><tr><td rowspan="2"></td><td colspan="3">Operating Revenues</td><td colspan="3">Operating Income</td><td colspan="2">Net Income Attributable to Common Shareholders</td></tr><tr><td>2019</td><td>2018</td><td>2019</td><td>2018</td><td>2019</td><td>2018</td><td>2019</td><td></td></tr><tr><td>Quarter ended:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>March 31</td><td>$ 9,477</td><td>$ 9,691</td><td>$ 1,218</td><td>$ 1,099</td><td>$ 907</td><td>$ 583</td><td></td><td></td></tr><tr><td>June 30</td><td>7,689</td><td>8,074</td><td>841</td><td>940</td><td>484</td><td>537</td><td></td><td></td></tr><tr><td>September 30</td><td>8,929</td><td>9,401</td><td>1,353</td><td>1,144</td><td>772</td><td>731</td><td></td><td></td></tr><tr><td>December 31 \( ^{(a)} \)</td><td>8,343</td><td>8,812</td><td>962</td><td>706</td><td>773</td><td>152</td><td></td><td></td></tr></table>

<table><tr><td rowspan="2"></td><td colspan="3">Net Income per Basic Share</td><td colspan="3">Net Income per Diluted Share</td></tr><tr><td>2019</td><td>2018</td><td>2019</td><td>2018</td><td></td><td></td></tr><tr><td>Quarter ended:</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>March 31</td><td>$ 0.93</td><td>$ 0.60</td><td>$ 0.93</td><td>$ 0.60</td><td></td><td></td></tr><tr><td>June 30</td><td>0.50</td><td>0.56</td><td>0.50</td><td>0.55</td><td></td><td></td></tr><tr><td>September 30</td><td>0.79</td><td>0.76</td><td>0.79</td><td>0.75</td><td></td><td></td></tr><tr><td>December 31</td><td>0.79</td><td>0.16</td><td>0.79</td><td>0.16</td><td></td><td></td></tr></table>

(a) Operating revenues, Operating income and Net income attributable to common shareholders for the quarter ended December 31, 2019 include a $6 million reduction related to a correction for Pepco's decoupling mechanism for the 2019 interim periods. See Note 1 — Significant Accounting Policies for additional information.

## Generation

The data shown below includes all adjustments that Generation considers necessary for a fair presentation of such amounts:

<table><tr><td rowspan="2"></td><td colspan="3">Operating Revenues</td><td colspan="3">Operating Income</td><td colspan="2">Net Income (Loss) Attributable to Membership Interest</td></tr><tr><td>2019</td><td>2018</td><td>2019</td><td>2018</td><td>2019</td><td>2018</td><td></td><td></td></tr><tr><td>Quarter ended:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>March 31</td><td>$ 5,296</td><td>$ 5,512</td><td>$ 333</td><td>$ 347</td><td>$ 363</td><td>$ 136</td><td></td><td></td></tr><tr><td>June 30</td><td>4,210</td><td>4,579</td><td>147</td><td>282</td><td>108</td><td>178</td><td></td><td></td></tr><tr><td>September 30</td><td>4,774</td><td>5,278</td><td>482</td><td>311</td><td>257</td><td>234</td><td></td><td></td></tr><tr><td>December 31</td><td>4,644</td><td>5,069</td><td>362</td><td>35</td><td>397</td><td>(178)</td><td></td><td></td></tr></table>



## ComEd

The data shown below includes all adjustments that ComEd considers necessary for a fair presentation of such amounts:

<table><tr><td rowspan="2"></td><td colspan="3">Operating Revenues</td><td colspan="3">Operating Income</td><td colspan="3">Net Income</td></tr><tr><td>2019</td><td colspan="2">2018</td><td>2019</td><td colspan="2">2018</td><td>2019</td><td colspan="3">2018</td></tr><tr><td>Quarter ended:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>March 31</td><td>$     1,408</td><td>$     1,512</td><td>$     276</td><td>$     292</td><td>$     157</td><td>$     165</td><td></td><td></td><td></td><td></td></tr><tr><td>June 30</td><td>1,351</td><td>1,398</td><td>311</td><td>288</td><td>186</td><td>164</td><td></td><td></td><td></td><td></td></tr><tr><td>September 30</td><td>1,583</td><td>1,598</td><td>328</td><td>323</td><td>200</td><td>193</td><td></td><td></td><td></td><td></td></tr><tr><td>December 31</td><td>1,405</td><td>1,373</td><td>255</td><td>242</td><td>144</td><td>141</td><td></td><td></td><td></td><td></td></tr></table>

## PECO

The data shown below includes all adjustments that PECO considers necessary for a fair presentation of such amounts:

<table><tr><td rowspan="2"></td><td colspan="3">Operating Revenues</td><td colspan="3">Operating Income</td><td colspan="3">Net Income</td></tr><tr><td>2019</td><td colspan="2">2018</td><td>2019</td><td colspan="2">2018</td><td>2019</td><td colspan="3">2018</td></tr><tr><td>Quarter ended:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>March 31</td><td>$     900</td><td>$     866</td><td>$     222</td><td>$     142</td><td>$     168</td><td>$     113</td><td></td><td></td><td></td><td></td></tr><tr><td>June 30</td><td>655</td><td>653</td><td>145</td><td>127</td><td>102</td><td>96</td><td></td><td></td><td></td><td></td></tr><tr><td>September 30</td><td>778</td><td>757</td><td>183</td><td>154</td><td>140</td><td>126</td><td></td><td></td><td></td><td></td></tr><tr><td>December 31</td><td>766</td><td>765</td><td>162</td><td>165</td><td>118</td><td>124</td><td></td><td></td><td></td><td></td></tr></table>

## BGE

The data shown below includes all adjustments that BGE considers necessary for a fair presentation of such amounts:

<table><tr><td rowspan="2"></td><td colspan="3">Operating Revenues</td><td colspan="3">Operating Income</td><td colspan="3">Net Income</td></tr><tr><td>2019</td><td colspan="2">2018</td><td>2019</td><td colspan="2">2018</td><td>2019</td><td colspan="3">2018</td></tr><tr><td>Quarter ended:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>March 31</td><td>$     976</td><td>$     977</td><td>$     220</td><td>$     177</td><td>$     160</td><td>$     128</td><td></td><td></td><td></td><td></td></tr><tr><td>June 30</td><td>649</td><td>662</td><td>80</td><td>85</td><td>45</td><td>51</td><td></td><td></td><td></td><td></td></tr><tr><td>September 30</td><td>703</td><td>731</td><td>91</td><td>103</td><td>55</td><td>63</td><td></td><td></td><td></td><td></td></tr><tr><td>December 31</td><td>779</td><td>799</td><td>142</td><td>109</td><td>99</td><td>71</td><td></td><td></td><td></td><td></td></tr></table>



## PHI

The data shown below includes all adjustments that PHI considers necessary for a fair presentation of such amounts:

<table><tr><td rowspan="2"></td><td colspan="3">Operating Revenues</td><td colspan="3">Operating Income</td><td colspan="3">Net Income</td></tr><tr><td>2019</td><td>2018</td><td>2019</td><td>2018</td><td>2019</td><td>2018</td><td>2019</td><td>2020</td><td>2021</td></tr><tr><td>Quarter ended:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>March 31</td><td>$ 1,228</td><td>$ 1,249</td><td>$ 175</td><td>$ 124</td><td>$ 117</td><td>$ 63</td><td></td><td></td><td></td></tr><tr><td>June 30</td><td>1,091</td><td>1,074</td><td>165</td><td>151</td><td>106</td><td></td><td>82</td><td></td><td></td></tr><tr><td>September 30</td><td>1,380</td><td>1,359</td><td>256</td><td>243</td><td>189</td><td></td><td>185</td><td></td><td></td></tr><tr><td>December 31(a)</td><td>1,107</td><td>1,115</td><td>128</td><td>124</td><td>65</td><td></td><td>62</td><td></td><td></td></tr></table>

(a) Operating revenues, Operating income and Net income attributable to common shareholders for the quarter ended December 31, 2019 include a $6 million reduction related to a correction for Pepco's decoupling mechanism for the 2019 interim periods. See Note 1 — Significant Accounting Policies for additional information.

## Pepco

The data shown below includes all adjustments that Pepco considers necessary for a fair presentation of such amounts:

<table><tr><td rowspan="2"></td><td colspan="3">Operating Revenues</td><td colspan="3">Operating Income</td><td colspan="3">Net Income</td></tr><tr><td>2019</td><td>2018</td><td>2019</td><td>2018</td><td>2019</td><td>2018</td><td>2019</td><td>2020</td><td>2021</td></tr><tr><td>Quarter ended:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>March 31</td><td>$ 575</td><td>$ 555</td><td>$ 84</td><td>$ 54</td><td>$ 55</td><td>$ 29</td><td></td><td></td><td></td></tr><tr><td>June 30</td><td>531</td><td>521</td><td>93</td><td>83</td><td>64</td><td></td><td>52</td><td></td><td></td></tr><tr><td>September 30</td><td>642</td><td>626</td><td>127</td><td>110</td><td>98</td><td></td><td>87</td><td></td><td></td></tr><tr><td>December 31(a)</td><td>513</td><td>529</td><td>57</td><td>63</td><td>26</td><td></td><td>36</td><td></td><td></td></tr></table>

(a) Operating revenues, Operating income and Net income attributable to common shareholders for the quarter ended December 31, 2019 include a $6 million reduction related to a correction for Pepco's decoupling mechanism for the 2019 interim periods. See Note 1 — Significant Accounting Policies for additional information.

## DPL

The data shown below includes all adjustments that DPL considers necessary for a fair presentation of such amounts:

<table><tr><td rowspan="2"></td><td colspan="3">Operating Revenues</td><td colspan="3">Operating Income</td><td colspan="3">Net Income</td></tr><tr><td>2019</td><td>2018</td><td>2019</td><td>2018</td><td>2019</td><td>2018</td><td>2019</td><td>2020</td><td>2021</td></tr><tr><td>Quarter ended:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>March 31</td><td>$ 380</td><td>$ 384</td><td>$ 72</td><td>$ 49</td><td>$ 53</td><td>$ 31</td><td></td><td></td><td></td></tr><tr><td>June 30</td><td>287</td><td>289</td><td>44</td><td>42</td><td>30</td><td></td><td>26</td><td></td><td></td></tr><tr><td>September 30</td><td>319</td><td>328</td><td>51</td><td>51</td><td>33</td><td></td><td>33</td><td></td><td></td></tr><tr><td>December 31</td><td>319</td><td>331</td><td>50</td><td>48</td><td>31</td><td></td><td>30</td><td></td><td></td></tr></table>



# Combined Notes to Consolidated Financial Statements (Dollars in millions, except per share data unless otherwise noted)

## ACE

The data shown below includes all adjustments that ACE considers necessary for a fair presentation of such amounts:

<table><tr><td rowspan="2"></td><td colspan="3">Operating Revenues</td><td colspan="3">Operating Income</td><td colspan="3">Net Income (Loss)</td></tr><tr><td>2019</td><td>2018</td><td>2019</td><td>2018</td><td>2019</td><td>2018</td><td>2019</td><td></td><td>2018</td></tr><tr><td>Quarter ended:</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>March 31</td><td>$ 273</td><td>$ 310</td><td>$ 21</td><td>$ 23</td><td>$ 10</td><td>$ 7</td><td></td><td></td><td></td></tr><tr><td>June 30</td><td>274</td><td>265</td><td>28</td><td>25</td><td>14</td><td></td><td></td><td>8</td><td></td></tr><tr><td>September 30</td><td>419</td><td>406</td><td>79</td><td>84</td><td>63</td><td></td><td>61</td><td></td><td></td></tr><tr><td>December 31</td><td>274</td><td>254</td><td>23</td><td>14</td><td>12</td><td></td><td>(1)</td><td></td><td></td></tr></table>

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

All Registrants

None.

ITEM 9A. CONTROLS AND PROCEDURES

All Registrants—Disclosure Controls and Procedures

During the fourth quarter of 2019, each registrant's management, including its principal executive officer and principal financial officer, evaluated the effectiveness of that registrant's disclosure controls and procedures related to the recording, processing, summarizing and reporting of information in that registrant's periodic reports that it files with the SEC. These disclosure controls and procedures have been designed by each registrant to ensure that (a) information relating to that registrant, including its consolidated subsidiaries, that is required to be included in filings under the Securities Exchange Act of 1934, is accumulated and made known to that registrant's management, including its principal executive officer and principal financial officer, by other employees of that registrant and its subsidiaries as appropriate to allow timely decisions regarding required disclosure, and (b) this information is recorded, processed, summarized, evaluated 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 December 31, 2019, the principal executive officer and principal financial officer of each registrant concluded that such registrant's disclosure controls and procedures were effective to accomplish their objectives.

All Registrants—Changes in Internal Control Over Financial Reporting

Each registrant continually strives to improve its disclosure controls and procedures to enhance the quality of its financial reporting and to maintain dynamic systems that change as conditions warrant. However, there have been no changes in internal control over financial reporting that occurred during the fourth quarter of 2019 that have materially affected, or are reasonably likely to materially affect, any of the registrant's internal control over financial reporting.

All Registrants—Internal Control Over Financial Reporting

Management is required to assess and report on the effectiveness of its internal control over financial reporting as of December 31, 2019. As a result of that assessment, management determined that there were no material weaknesses as of December 31, 2019 and, therefore, concluded that each registrant's internal control over financial reporting was effective. Management's Report on Internal Control Over Financial Reporting is included in ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

ITEM 9B. OTHER INFORMATION

All Registrants






## PART III

Exelon Generation Company, LLC, PECO Energy Company, Baltimore Gas and Electric Company, Pepco Holdings LLC, Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K for a reduced disclosure format. Accordingly, all items in this section relating to Generation, PECO, BGE, PHI, Pepco, DPL and ACE are not presented.

## ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

## Executive Officers

The information required by ITEM 10. relating to executive officers is set forth above in ITEM 1. BUSINESS—Executive officers of the Registrants at February 11, 2020.

## Directors, Director Nomination Process and Audit Committee

The information required under ITEM 10 concerning directors and nominees for election as directors at the annual meeting of shareholders (Item 401 of Regulation S-K), the director nomination process (Item 407(c)(3)), the audit committee (Item 407(d)(4) and (d)(5)) and the beneficial reporting compliance (Sec. 16(a)) is incorporated herein by reference to information to be contained in Exelon's definitive 2020 proxy statement (2020 Exelon Proxy Statement) and the ComEd information statement (2020 ComEd Information Statement) to be filed with the SEC on or before April 30, 2020 pursuant to Regulation 14A or 14C, as applicable, under the Securities Exchange Act of 1934.

## Code of Ethics

Exelon's Code of Business Conduct is the code of ethics that applies to Exelon's and ComEd's Chief Executive Officer, Chief Financial Officer, Corporate Controller, and other finance organization employees. The Code of Business Conduct is filed as Exhibit 14 to this report and is available on Exelon's website at www.exeloncorp.com. The Code of Business Conduct will be made available, without charge, in print to any shareholder who requests such document from Carter C. Culver, Senior Vice President and Deputy General Counsel, Exelon Corporation, P.O. Box 805398, Chicago, Illinois 60680-5398.

If any substantive amendments to the Code of Business Conduct are made or any waivers are granted, including any implicit waiver, from a provision of the Code of Business Conduct, to its Chief Executive Officer, Chief Financial Officer or Corporate Controller, Exelon will disclose the nature of such amendment or waiver on Exelon's website, www.exeloncorp.com, or in a report on Form 8-K.



## ITEM 11. EXECUTIVE COMPENSATION

The information required by this item will be set forth under Executive Compensation Data and Report of the Compensation Committee in the Exelon Proxy Statement for the 2020 Annual Meeting of Shareholders or the ComEd 2020 Information Statement, which are incorporated herein by reference.



## ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The additional information required by this item will be set forth under Ownership of Exelon Stock in the 2020 Exelon Proxy Statement or the ComEd 2020 Information Statement and incorporated herein by reference.

Securities Authorized for Issuance under Exelon Equity Compensation Plans

<table><tr><td></td><td>[A]</td><td>[B]</td><td>[C]</td></tr><tr><td>Plan Category</td><td>Number of securities to be issued upon exercise of outstanding Options, warrants and rights (Note 1)</td><td>Weighted-average price of outstanding Options, warrants and rights (Note 2)</td><td>Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column [A]) (Note 3)</td></tr><tr><td>Equity compensation plans approved by security holders</td><td>8,738,206</td><td>$ 21.17</td><td>31,091,584</td></tr></table>

(1) Balance includes stock options, unvested performance shares, and unvested restricted shares granted under the Exelon LTIP or predecessor company plans including shares awarded under those plans and deferred into the stock deferral plan, and deferred stock units granted to directors as part of their compensation. Unvested performance shares are subject to performance metrics ranging from 0% to 150% of target award values and to a total shareholder return modifier. For performance shares granted in 2017, 2018 and 2019, the total includes the number of shares that could be issued pursuant to the terms of the Exelon LTIP plan, which provides that final payouts are made 50% in shares of stock and 50% in cash, and if the performance and total shareholder return modifier metrics were both at maximum, representing a best case performance scenario, for a total of 4,005,200 shares. If the performance and total shareholder return modifier metrics were at target, the number of securities to be issued for such awards would be 2,002,600. The deferred stock units granted to directors includes 467,218 shares to be issued upon the conversion of deferred stock units awarded to members of the Exelon Board of Directors. Conversion of the deferred stock units to shares occurs after a director terminates service to the Exelon board or the board of any of its subsidiary companies. See Note 20 — Stock-Based Compensation Plans of the Combined Notes to Consolidated Financial Statements for additional information about the material features of the plans.

(2) The weighted-average price reported in column B does not take the performance shares and shares credited to deferred compensation plans into account.

(3) Includes 17,125,705 shares remaining available for issuance from the employee stock purchase plan.

No ComEd securities are authorized for issuance under equity compensation plans.



## ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

The additional information required by this item will be set forth under Related Persons Transactions and Director Independence in the Exelon Proxy Statement for the 2020 Annual Meeting of Shareholders or the ComEd 2020 Information Statement, which are incorporated herein by reference.



## ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The information required by this item will be set forth under The Ratification of PricewaterhouseCoopers LLP as Exelon's Independent Accountant for 2020 in the Exelon Proxy Statement for the 2020 Annual Meeting of Shareholders and the ComEd 2020 Information Statement, which are incorporated herein by reference.



## PART IV

## ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a) The following documents are filed as a part of this report:

## (1) Exelon

(i) Financial Statements (Item 8):

Report of Independent Registered Public Accounting Firm dated February 11, 2020 of PricewaterhouseCoopers LLP

Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2019, 2018 and 2017

Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 2018 and 2017

Consolidated Balance Sheets at December 31, 2019 and 2018

Consolidated Statements of Changes in Equity for the Years Ended December 31, 2018, 2017 and 2016

Notes to Consolidated Financial Statements

(ii) Financial Statement Schedules:

Schedule I—Condensed Financial Information of Parent (Exelon Corporate) at December 31, 2019 and 2018 and for the Years Ended December 31, 2019, 2018 and 2017

Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2019, 2018 and 2017

Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto.



## Exelon Corporation and Subsidiary Companies
Schedule I – Condensed Financial Information of Parent (Exelon Corporate)
Condensed Statements of Operations and Other Comprehensive Income

<table><tr><td rowspan="2">(In millions)</td><td colspan="4">For the Years Ended December 31,</td></tr><tr><td>2019</td><td>2018</td><td>2017</td><td></td></tr><tr><td>Operating expenses</td><td></td><td></td><td></td><td></td></tr><tr><td>Operating and maintenance</td><td>$     33</td><td>$      (5)</td><td>$     10</td><td></td></tr><tr><td>Operating and maintenance from affiliates</td><td>9</td><td>9</td><td>25</td><td></td></tr><tr><td>Other</td><td>1</td><td>4</td><td>4</td><td></td></tr><tr><td>Total operating expenses</td><td>43</td><td>8</td><td>39</td><td></td></tr><tr><td>Operating loss</td><td>(43)</td><td>(8)</td><td>(39)</td><td></td></tr><tr><td>Other income and (deductions)</td><td></td><td></td><td></td><td></td></tr><tr><td>Interest expense, net</td><td>(321)</td><td>(312)</td><td>(315)</td><td></td></tr><tr><td>Equity in earnings of investments</td><td>3,254</td><td>2,183</td><td>4,407</td><td></td></tr><tr><td>Interest income from affiliates, net</td><td>39</td><td>42</td><td>40</td><td></td></tr><tr><td>Other, net</td><td>14</td><td>3</td><td>1</td><td></td></tr><tr><td>Total other income</td><td>2,986</td><td>1,916</td><td>4,133</td><td></td></tr><tr><td>Income before income taxes</td><td>2,943</td><td>1,908</td><td>4,094</td><td></td></tr><tr><td>Income taxes</td><td>7</td><td>(97)</td><td>315</td><td></td></tr><tr><td>Net income</td><td>$     2,936</td><td>$     2,005</td><td>$     3,779</td><td></td></tr><tr><td>Other comprehensive income (loss)</td><td></td><td></td><td></td><td></td></tr><tr><td>Pension and non-pension postretirement benefit plans:</td><td></td><td></td><td></td><td></td></tr><tr><td>Prior service benefit reclassified to periodic costs</td><td>(64)</td><td>(66)</td><td>(56)</td><td></td></tr><tr><td>Actuarial loss reclassified to periodic cost</td><td>148</td><td>247</td><td>197</td><td></td></tr><tr><td>Pension and non-pension postretirement benefit plan valuation adjustment</td><td>(289)</td><td>(143)</td><td>10</td><td></td></tr><tr><td>Unrealized gain on cash flow hedges</td><td>1</td><td>12</td><td>3</td><td></td></tr><tr><td>Unrealized gain on marketable securities</td><td>—</td><td>—</td><td>6</td><td></td></tr><tr><td>Unrealized gain on equity investments</td><td>—</td><td>1</td><td>6</td><td></td></tr><tr><td>Unrealized (loss) gain on foreign currency translation</td><td>—</td><td>(10)</td><td>7</td><td></td></tr><tr><td>Other comprehensive income (loss)</td><td>(204)</td><td>41</td><td>173</td><td></td></tr><tr><td>Comprehensive income</td><td>$     2,732</td><td>$     2,046</td><td>$     3,952</td><td></td></tr></table>

See the Notes to Financial Statements



## Exelon Corporation and Subsidiary Companies
Schedule I – Condensed Financial Information of Parent (Exelon Corporate)
Condensed Statements of Cash Flows

<table><tr><td rowspan="2">(In millions)</td><td colspan="4">For the Years Ended December 31,</td></tr><tr><td>2019</td><td colspan="2">2018</td><td>2017</td></tr><tr><td>Net cash flows provided by operating activities</td><td>$     1,948</td><td>$     2,576</td><td>$     1,914</td><td></td></tr><tr><td>Cash flows from investing activities</td><td></td><td></td><td></td><td></td></tr><tr><td>Changes in Exelon intercompany money pool</td><td>95</td><td>1</td><td>(129)</td><td></td></tr><tr><td>Investment in affiliates</td><td>(1,071)</td><td>(1,231)</td><td>(1,710)</td><td></td></tr><tr><td>Other investing activities</td><td>—</td><td>—</td><td>(5)</td><td></td></tr><tr><td>Net cash flows used in investing activities</td><td>(976)</td><td>(1,230)</td><td>(1,844)</td><td></td></tr><tr><td>Cash flows from financing activities</td><td></td><td></td><td></td><td></td></tr><tr><td>Changes in short-term borrowings</td><td>136</td><td>—</td><td>—</td><td></td></tr><tr><td>Proceeds from short-term borrowings with maturities greater than 90 days</td><td>—</td><td>—</td><td>500</td><td></td></tr><tr><td>Retirement of long-term debt</td><td>—</td><td>—</td><td>(569)</td><td></td></tr><tr><td>Common stock issued from treasury stock</td><td>—</td><td>—</td><td>1,150</td><td></td></tr><tr><td>Dividends paid on common stock</td><td>(1,408)</td><td>(1,332)</td><td>(1,236)</td><td></td></tr><tr><td>Proceeds from employee stock plans</td><td>112</td><td>105</td><td>150</td><td></td></tr><tr><td>Other financing activities</td><td>—</td><td>(4)</td><td>(9)</td><td></td></tr><tr><td>Net cash flows used in financing activities</td><td>(1,160)</td><td>(1,231)</td><td>(14)</td><td></td></tr><tr><td>(Decrease) Increase in cash, cash equivalents and restricted cash</td><td>(188)</td><td>115</td><td>56</td><td></td></tr><tr><td>Cash, cash equivalents and restricted cash at beginning of period</td><td>189</td><td>74</td><td>18</td><td></td></tr><tr><td>Cash, cash equivalents and restricted cash at end of period</td><td>$     1</td><td>$     189</td><td>$     74</td><td></td></tr></table>

See the Notes to Financial Statements



## Exelon Corporation and Subsidiary Companies
Schedule I – Condensed Financial Information of Parent (Exelon Corporate)
Condensed Balance Sheets

<table><tr><td rowspan="2">(In millions)</td><td colspan="2">December 31,</td></tr><tr><td>2019</td><td>2018</td></tr><tr><td>ASSETS</td><td></td><td></td></tr><tr><td>Current assets</td><td></td><td></td></tr><tr><td>Cash and cash equivalents</td><td>$ 1</td><td>$ 189</td></tr><tr><td>Accounts receivable, net</td><td></td><td></td></tr><tr><td>Other accounts receivable</td><td>168</td><td>48</td></tr><tr><td>Accounts receivable from affiliates</td><td>41</td><td>44</td></tr><tr><td>Mark-to-market derivative assets</td><td></td><td></td></tr><tr><td></td><td>3</td><td>—</td></tr><tr><td>Notes receivable from affiliates</td><td>679</td><td>216</td></tr><tr><td>Regulatory assets</td><td>253</td><td>182</td></tr><tr><td>Other</td><td>4</td><td>4</td></tr><tr><td>Total current assets</td><td>1,149</td><td>683</td></tr><tr><td>Property, plant and equipment, net</td><td>47</td><td>48</td></tr><tr><td>Deferred debits and other assets</td><td></td><td></td></tr><tr><td>Regulatory assets</td><td>3,772</td><td>3,742</td></tr><tr><td>Investments in affiliates</td><td>42,245</td><td>40,425</td></tr><tr><td>Deferred income taxes</td><td>1,524</td><td>1,455</td></tr><tr><td>Notes receivable from affiliates</td><td>329</td><td>898</td></tr><tr><td>Other</td><td>308</td><td>235</td></tr><tr><td>Total deferred debits and other assets</td><td>48,178</td><td>46,755</td></tr><tr><td>Total assets</td><td>$ 49,374</td><td>$ 47,486</td></tr></table>

See the Notes to Financial Statements



## Exelon Corporation and Subsidiary Companies
Schedule I – Condensed Financial Information of Parent (Exelon Corporate)
Condensed Balance Sheets

<table><tr><td rowspan="2">(In millions)</td><td colspan="2">December 31,</td></tr><tr><td>2019</td><td>2018</td></tr><tr><td>LIABILITIES AND SHAREHOLDERS&#x27; EQUITY</td><td></td><td></td></tr><tr><td>Current liabilities</td><td></td><td></td></tr><tr><td>Short-term borrowings</td><td>$     636</td><td>$     500</td></tr><tr><td>Long-term debt due within one year</td><td>1,458</td><td>—</td></tr><tr><td>Accounts payable</td><td>1</td><td>1</td></tr><tr><td>Accrued expenses</td><td>131</td><td>184</td></tr><tr><td>Payables to affiliates</td><td>363</td><td>360</td></tr><tr><td>Regulatory liabilities</td><td>13</td><td>15</td></tr><tr><td>Pension obligations</td><td>77</td><td>63</td></tr><tr><td>Other</td><td>10</td><td>14</td></tr><tr><td>Total current liabilities</td><td>2,689</td><td>1,137</td></tr><tr><td>Long-term debt</td><td>5,717</td><td>7,147</td></tr><tr><td>Deferred credits and other liabilities</td><td></td><td></td></tr><tr><td>Regulatory liabilities</td><td>31</td><td>32</td></tr><tr><td>Pension obligations</td><td>7,960</td><td>7,795</td></tr><tr><td>Non-pension postretirement benefit obligations</td><td>403</td><td>199</td></tr><tr><td>Deferred income taxes</td><td>263</td><td>233</td></tr><tr><td>Other</td><td>87</td><td>202</td></tr><tr><td>Total deferred credits and other liabilities</td><td>8,744</td><td>8,461</td></tr><tr><td>Total liabilities</td><td>17,150</td><td>16,745</td></tr><tr><td>Commitments and contingencies</td><td></td><td></td></tr><tr><td>Shareholders&#x27; equity</td><td></td><td></td></tr><tr><td>Common stock (No par value, 2,000 shares authorized, 973 shares and 968 shares outstanding at December 31, 2019 and 2018, respectively)</td><td>19,274</td><td>19,116</td></tr><tr><td>Treasury stock, at cost (2 shares at December 31, 2019 and 2018)</td><td>(123)</td><td>(123)</td></tr><tr><td>Retained earnings</td><td>16,267</td><td>14,743</td></tr><tr><td>Accumulated other comprehensive loss, net</td><td>(3,194)</td><td>(2,995)</td></tr><tr><td>Total shareholders&#x27; equity</td><td>32,224</td><td>30,741</td></tr><tr><td>Total liabilities and shareholders&#x27; equity</td><td>$     49,374</td><td>$     47,486</td></tr></table>

See the Notes to Financial Statements



# Exelon Corporation and Subsidiary Companies
Schedule I – Condensed Financial Information of Parent (Exelon Corporate)
Notes to Financial Statements

## 1. Basis of Presentation

Exelon Corporate is a holding company that conducts substantially all of its business operations through its subsidiaries. These condensed financial statements and related footnotes have been prepared in accordance with Rule 12-04, Schedule I of Regulation S-X. These statements should be read in conjunction with the consolidated financial statements and notes thereto of Exelon Corporation.

Exelon Corporate owns 100% of all of its significant subsidiaries, either directly or indirectly, except for Commonwealth Edison Company (ComEd), of which Exelon Corporate owns more than 99%, and Baltimore Gas and Electric Company (BGE), of which Exelon owns 100% of the common stock but none of BGE's preferred stock.

## 2. Debt and Credit Agreements

## Short-Term Borrowings

Exelon Corporate meets its short-term liquidity requirements primarily through the issuance of commercial paper. Exelon Corporate had $136 million of outstanding commercial paper borrowings at December 31, 2019 and no outstanding commercial paper borrowings at December 31, 2018.

## Short-Term Loan Agreements

On March 23, 2017, Exelon Corporate entered into a $500 million term loan agreement, which was renewed on March 22, 2018 with an expiration of March 21, 2019. The loan agreement was renewed on March 20, 2019 and will expire on March 19, 2020. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.95% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Exelon's Consolidated Balance Sheet within Short-Term borrowings.

## Revolving Credit Agreements

On May 26, 2016, Exelon Corporate amended its syndicated revolving credit facility with aggregate bank commitments of $600 million through May 26, 2021. On May 26, 2018, Exelon Corporate had its maturity date extended to May 26, 2023. As of December 31, 2019, Exelon Corporation had available capacity under those commitments of $458 million. See Note 16—Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information regarding Exelon Corporation's credit agreement.

## Long-Term Debt

The following tables present the outstanding long-term debt for Exelon Corporate as of December 31, 2019 and December 31, 2018:

<table><tr><td rowspan="2"></td><td rowspan="2">Rates</td><td rowspan="2">Maturity Date</td><td colspan="3">December 31,</td></tr><tr><td>2019</td><td>2018</td><td></td></tr><tr><td>Long-term debt</td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Junior subordinated notes</td><td>3.50%</td><td>2022</td><td>$</td><td>1,150</td><td>$</td></tr><tr><td>Senior unsecured notes(a)</td><td>2.45% -</td><td>7.60%</td><td>2020 - 2046</td><td>5,889</td><td>5,889</td></tr><tr><td>Total long-term debt</td><td></td><td></td><td></td><td>7,039</td><td>7,039</td></tr><tr><td>Unamortized debt discount and premium, net</td><td></td><td></td><td></td><td>(7)</td><td>(7)</td></tr><tr><td>Unamortized debt issuance costs</td><td></td><td></td><td></td><td>(39)</td><td>(47)</td></tr><tr><td>Fair value adjustment</td><td></td><td></td><td></td><td>182</td><td>162</td></tr><tr><td>Long-term debt due within one year</td><td></td><td></td><td></td><td>(1,458)</td><td>—</td></tr><tr><td>Long-term debt</td><td></td><td></td><td></td><td>$</td><td>5,717</td></tr></table>

(a) Senior unsecured notes include mirror debt that is held on both Generation and Exelon Corporation's balance sheets.

The debt maturities for Exelon Corporate for the periods 2020, 2021, 2022, 2023, 2024 and thereafter are as follows:



Exelon Corporation and Subsidiary Companies
Schedule I – Condensed Financial Information of Parent (Exelon Corporate)
Notes to Financial Statements

<table><tr><td>2020</td><td>$</td><td>1,458</td></tr><tr><td>2021</td><td></td><td>300</td></tr><tr><td>2022</td><td></td><td>1,150</td></tr><tr><td>2023</td><td></td><td>—</td></tr><tr><td>2024</td><td></td><td>—</td></tr><tr><td>Remaining years</td><td></td><td>4,131</td></tr><tr><td>Total long-term debt</td><td>$</td><td>7,039</td></tr></table>

## 3. Commitments and Contingencies

See Note 18—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for Exelon Corporate’s commitments and contingencies related to environmental matters and fund transfer restrictions.

## 4. Related Party Transactions

The financial statements of Exelon Corporate include related party transactions as presented in the tables below:

<table><tr><td rowspan="2">(In millions)</td><td colspan="4">For the Years Ended December 31,</td></tr><tr><td>2019</td><td>2018</td><td>2017</td><td></td></tr><tr><td>Operating and maintenance from affiliates:</td><td></td><td></td><td></td><td></td></tr><tr><td>BSC(a)</td><td>$     9</td><td>$     11</td><td>$     23</td><td></td></tr><tr><td>Other</td><td>—</td><td>(2)</td><td>2</td><td></td></tr><tr><td>Total operating and maintenance from affiliates:</td><td>$     9</td><td>$     9</td><td>$     25</td><td></td></tr><tr><td>Interest income from affiliates, net:</td><td></td><td></td><td></td><td></td></tr><tr><td>Generation</td><td>$     36</td><td>$     36</td><td>$     37</td><td></td></tr><tr><td>BSC</td><td>3</td><td>4</td><td>3</td><td></td></tr><tr><td>Exelon Energy Delivery Company, LLC(b)</td><td>—</td><td>2</td><td>—</td><td></td></tr><tr><td>Total interest income from affiliates, net:</td><td>$     39</td><td>$     42</td><td>$     40</td><td></td></tr><tr><td>Equity in earnings (losses) of investments:</td><td></td><td></td><td></td><td></td></tr><tr><td>Exelon Energy Delivery Company, LLC(b)</td><td>$     2,054</td><td>$     1,830</td><td>$     1,663</td><td></td></tr><tr><td>Generation</td><td>1,125</td><td>369</td><td>2,710</td><td></td></tr><tr><td>UII, LLC</td><td>97</td><td>—</td><td>41</td><td></td></tr><tr><td>PCI</td><td>1</td><td>(17)</td><td>1</td><td></td></tr><tr><td>BSC</td><td>—</td><td>—</td><td>1</td><td></td></tr><tr><td>Exelon Enterprises</td><td>(16)</td><td>—</td><td>1</td><td></td></tr><tr><td>Exelon INQB8R</td><td>(8)</td><td>—</td><td>—</td><td></td></tr><tr><td>Exelon Transmission Company, LLC</td><td>(2)</td><td>1</td><td>(10)</td><td></td></tr><tr><td>Other</td><td>3</td><td>—</td><td>—</td><td></td></tr><tr><td>Total equity in earnings of investments:</td><td>$     3,254</td><td>$     2,183</td><td>$     4,407</td><td></td></tr><tr><td>Cash contributions received from affiliates</td><td>$     2,514</td><td>$     2,302</td><td>$     1,879</td><td></td></tr></table>



## Exelon Corporation and Subsidiary Companies
Schedule I – Condensed Financial Information of Parent (Exelon Corporate)
Notes to Financial Statements

<table><tr><td rowspan="2">(in millions)</td><td colspan="3">December 31,</td></tr><tr><td>2019</td><td>2018</td><td></td></tr><tr><td>Accounts receivable from affiliates (current):</td><td></td><td></td><td></td></tr><tr><td>BSC(a)</td><td>$ 11</td><td>$ 13</td><td></td></tr><tr><td>Generation</td><td>13</td><td>17</td><td></td></tr><tr><td>ComEd</td><td>2</td><td>4</td><td></td></tr><tr><td>PECO</td><td>2</td><td>2</td><td></td></tr><tr><td>BGE</td><td>1</td><td>2</td><td></td></tr><tr><td>PHISCO</td><td>7</td><td>6</td><td></td></tr><tr><td>Exelon VTI, LLC</td><td>5</td><td>—</td><td></td></tr><tr><td>Total accounts receivable from affiliates (current):</td><td>$ 41</td><td>$ 44</td><td></td></tr><tr><td>Notes receivable from affiliates (current):</td><td></td><td></td><td></td></tr><tr><td>BSC(a)</td><td>$ 109</td><td>$ 116</td><td></td></tr><tr><td>Generation(c)</td><td>558</td><td>100</td><td></td></tr><tr><td>PHI</td><td>12</td><td>—</td><td></td></tr><tr><td>Total notes receivable from affiliates (current):</td><td>$ 679</td><td>$ 216</td><td></td></tr><tr><td>Investments in affiliates:</td><td></td><td></td><td></td></tr><tr><td>BSC(a)</td><td>$ 197</td><td>$ 197</td><td></td></tr><tr><td>Exelon Energy Delivery Company, LLC(b)</td><td>28,147</td><td>26,679</td><td></td></tr><tr><td>Generation</td><td>13,484</td><td>13,204</td><td></td></tr><tr><td>PCI</td><td>62</td><td>61</td><td></td></tr><tr><td>UII, LLC</td><td>365</td><td>268</td><td></td></tr><tr><td>Exelon Transmission Company, LLC</td><td>—</td><td>1</td><td></td></tr><tr><td>Voluntary Employee Beneficiary Association trust</td><td>(4)</td><td>(1)</td><td></td></tr><tr><td>Exelon Enterprises</td><td>6</td><td>22</td><td></td></tr><tr><td>Exelon INQB8R, LLC</td><td>(8)</td><td>—</td><td></td></tr><tr><td>Other</td><td>(4)</td><td>(6)</td><td></td></tr><tr><td>Total investments in affiliates:</td><td>$ 42,245</td><td>$ 40,425</td><td></td></tr><tr><td>Notes receivable from affiliates (non-current):</td><td></td><td></td><td></td></tr><tr><td>Generation(c)</td><td>$ 329</td><td>$ 898</td><td></td></tr><tr><td>Accounts payable to affiliates (current):</td><td></td><td></td><td></td></tr><tr><td>UII, LLC</td><td>$ 360</td><td>$ 360</td><td></td></tr><tr><td>Exelon Enterprises</td><td>3</td><td>—</td><td></td></tr><tr><td>Total accounts payable to affiliates (current):</td><td>$ 363</td><td>$ 360</td><td></td></tr></table>

(a) Exelon Corporate receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead.

(b) Exelon Energy Delivery Company, LLC consists of ComEd, PECO, BGE, PHI, Pepco, DPL and ACE.

(c) In connection with the debt obligations assumed by Exelon as part of the Constellation merger, Exelon and subsidiaries of Generation (former Constellation subsidiaries) assumed intercompany loan agreements that mirror the terms and amounts of the third-party debt obligations of Exelon, resulting in intercompany notes payable included in Long-Term Debt to affiliates in Generation's Consolidated Balance Sheets and intercompany notes receivable at Exelon Corporate, which are eliminated in consolidation in Exelon's Consolidated Balance Sheets.

## Exelon Corporation and Subsidiary Companies

## Schedule II – Valuation and Qualifying Accounts

<table><tr><td>Column A</td><td>Column B</td><td colspan="3">Column C</td><td>Column D</td><td>Column E</td></tr><tr><td></td><td></td><td colspan="3">Additions and adjustments</td><td></td><td></td></tr><tr><td></td><td></td><td>Balance at Beginning of Period</td><td>Charged to Costs and Expenses</td><td>Charged to Other Accounts</td><td>Deductions</td><td>Balance at End of Period</td></tr><tr><td></td><td></td><td></td><td></td><td>(in millions)</td><td></td><td></td></tr><tr><td>For the year ended December 31, 2019</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Allowance for uncollectible accounts \( ^{(a)} \)</td><td>$ 319</td><td>$ 119</td><td>$ 26</td><td>(c)</td><td>$ 170</td><td>(e) $ 294</td></tr></table>



<table><tr><td>Deferred tax valuation allowance</td><td>35</td><td>—</td><td>(9)</td><td>—</td><td>26</td></tr><tr><td>Reserve for obsolete materials</td><td>156</td><td>6</td><td>— (d)</td><td>7</td><td>155</td></tr><tr><td colspan="6">For the year ended December 31, 2018</td></tr><tr><td>Allowance for uncollectible accounts \( ^{(a)} \)</td><td>322</td><td>159</td><td>35 (c)</td><td>197 (e)</td><td>319</td></tr><tr><td>Deferred tax valuation allowance</td><td>37</td><td>—</td><td>5</td><td>7</td><td>35</td></tr><tr><td>Reserve for obsolete materials</td><td>174</td><td>25</td><td>(31)</td><td>12</td><td>156</td></tr><tr><td colspan="6">For the year ended December 31, 2017</td></tr><tr><td>Allowance for uncollectible accounts \( ^{(a)} \)</td><td>334</td><td>126</td><td>27 (b)(c)</td><td>165 (e)</td><td>322</td></tr><tr><td>Deferred tax valuation allowance</td><td>20</td><td>—</td><td>17 (b)</td><td>—</td><td>37</td></tr><tr><td>Reserve for obsolete materials</td><td>113</td><td>56</td><td>10 (b)</td><td>5</td><td>174</td></tr></table>

(a) Excludes the non-current allowance for uncollectible accounts related to PECO's installment plan receivables of $9 million, $13 million, and $15 million for the years ended December 31, 2019, 2018 and 2017, respectively.

(b) Primarily represents the addition of PHI's results as of March 23, 2016, the date of the merger.

(c) Includes charges for late payments and non-service receivables.

(d) Primarily reflects the reclassification of assets as held for sale.

(e) Write-off of individual accounts receivable.



## Exelon Generation Company, LLC and Subsidiary Companies

## (2) Generation

(i) Financial Statements (Item 8):

Report of Independent Registered Public Accounting Firm dated February 11, 2020 of PricewaterhouseCoopers LLP

Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2019, 2018 and 2017

Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 2018 and 2017

Consolidated Balance Sheets at December 31, 2019 and 2018

Consolidated Statements of Changes in Equity for the Years Ended December 31, 2019, 2018 and 2017

Notes to Consolidated Financial Statements

(ii) Financial Statement Schedule:

Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2019, 2018 and 2017

Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto



## Exelon Generation Company, LLC and Subsidiary Companies

## Schedule II – Valuation and Qualifying Accounts

<table><tr><td>Column A</td><td colspan="2">Column B</td><td colspan="3">Column C</td><td>Column D</td><td>Column E</td></tr><tr><td></td><td></td><td colspan="3">Additions and adjustments</td><td></td><td></td><td></td></tr><tr><td>Description</td><td>Balance at Beginning of Period</td><td>Charged to Costs and Expenses</td><td>Charged to Other Accounts</td><td></td><td></td><td>Deductions</td><td>Balance at End of Period</td></tr><tr><td></td><td></td><td></td><td></td><td>(in millions)</td><td></td><td></td><td></td></tr><tr><td>For the year ended December 31, 2019</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Allowance for uncollectible accounts</td><td>$     104</td><td>$     27</td><td>$      (11)</td><td>$     39</td><td>$     81</td><td></td><td></td></tr><tr><td>Deferred tax valuation allowance</td><td>26</td><td>—</td><td>(2)</td><td>—</td><td>24</td><td></td><td></td></tr><tr><td>Reserve for obsolete materials</td><td>145</td><td>—</td><td>—</td><td>2</td><td>143</td><td></td><td></td></tr><tr><td>For the year ended December 31, 2018</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Allowance for uncollectible accounts</td><td>$     114</td><td>$     44</td><td>$     4</td><td>$     58</td><td>$     104</td><td></td><td></td></tr><tr><td>Deferred tax valuation allowance</td><td>23</td><td>—</td><td>3</td><td>—</td><td>26</td><td></td><td></td></tr><tr><td>Reserve for obsolete materials</td><td>166</td><td>20</td><td>(32)</td><td>(2)</td><td>9</td><td>145</td><td></td></tr><tr><td>For the year ended December 31, 2017</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Allowance for uncollectible accounts</td><td>$     91</td><td>$     34</td><td>$      —</td><td>$     11</td><td>$     114</td><td></td><td></td></tr><tr><td>Deferred tax valuation allowance</td><td>9</td><td>—</td><td>14</td><td>—</td><td>23</td><td></td><td></td></tr><tr><td>Reserve for obsolete materials</td><td>106</td><td>51</td><td>9</td><td>—</td><td>166</td><td></td><td></td></tr></table>

(a) Primarily reflects the reclassification of assets as held for sale.



## Commonwealth Edison Company and Subsidiary Companies

## (3) ComEd

(i) Financial Statements (Item 8):

Report of Independent Registered Public Accounting Firm dated February 11, 2020 of PricewaterhouseCoopers LLP

Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2019, 2018 and 2017

Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 2018 and 2017

Consolidated Balance Sheets at December 31, 2019 and 2018

Consolidated Statements of Changes in Shareholders' Equity for the Years Ended December 31, 2019, 2018 and 2017

Notes to Consolidated Financial Statements

(ii) Financial Statement Schedule:

Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2019, 2018 and 2017

Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto



## Commonwealth Edison Company and Subsidiary Companies

## Schedule II – Valuation and Qualifying Accounts

<table><tr><td>Column A</td><td colspan="2">Column B</td><td colspan="2">Column C</td><td>Column D</td><td>Column E</td></tr><tr><td></td><td></td><td></td><td colspan="2">Additions and adjustments</td><td></td><td></td></tr><tr><td>Description</td><td>Balance at Beginning of Period</td><td></td><td>Charged to Costs and Expenses</td><td>Charged to Other Accounts</td><td>Deductions</td><td>Balance at End of Period</td></tr><tr><td></td><td></td><td></td><td></td><td>(in millions)</td><td></td><td></td></tr><tr><td>For the year ended December 31, 2019</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Allowance for uncollectible accounts</td><td>$     81</td><td>$     35</td><td>$     20</td><td>(a)</td><td>$     57</td><td>(b)</td></tr><tr><td>Reserve for obsolete materials</td><td>6</td><td>6</td><td>—</td><td></td><td>5</td><td></td></tr><tr><td>For the year ended December 31, 2018</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Allowance for uncollectible accounts</td><td>$     73</td><td>$     44</td><td>$     23</td><td>(a)</td><td>$     59</td><td>(b)</td></tr><tr><td>Reserve for obsolete materials</td><td>5</td><td>3</td><td>1</td><td></td><td>3</td><td></td></tr><tr><td>For the year ended December 31, 2017</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Allowance for uncollectible accounts</td><td>$     70</td><td>$     39</td><td>$     20</td><td>(a)</td><td>$     56</td><td>(b)</td></tr><tr><td>Reserve for obsolete materials</td><td>4</td><td>3</td><td>1</td><td></td><td>3</td><td></td></tr></table>

(a) Primarily charges for late payments and non-service receivables.

(b) Write-off of individual accounts receivable.



## PECO Energy Company and Subsidiary Companies

## (4) PECO

(i) Financial Statements (Item 8):

Report of Independent Registered Public Accounting Firm dated February 11, 2020 of PricewaterhouseCoopers LLP

Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2019, 2018 and 2017

Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 2018 and 2017

Consolidated Balance Sheets at December 31, 2019 and 2018

Consolidated Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2019, 2018 and 2017

Notes to Consolidated Financial Statements

(ii) Financial Statement Schedule:

Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2019, 2018 and 2017

Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto



## PECO Energy Company and Subsidiary Companies

## Schedule II – Valuation and Qualifying Accounts

<table><tr><td>Column A</td><td colspan="2">Column B</td><td colspan="3">Column C</td><td>Column D</td><td>Column E</td></tr><tr><td></td><td></td><td></td><td colspan="3">Additions and adjustments</td><td></td><td></td></tr><tr><td>Description</td><td>Balance at Beginning of Period</td><td></td><td>Charged to Costs and Expenses</td><td>Charged to Other Accounts</td><td></td><td>Deductions</td><td>Balance at End of Period</td></tr><tr><td></td><td></td><td></td><td></td><td>(in millions)</td><td></td><td></td><td></td></tr><tr><td>For the year ended December 31, 2019</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Allowance for uncollectible accounts(a)</td><td>$ 61</td><td>$ 31</td><td>$ 3</td><td>(b)</td><td>$ 33</td><td>(c)</td><td>$ 62</td></tr><tr><td>Reserve for obsolete materials</td><td>2</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td>2</td></tr><tr><td>For the year ended December 31, 2018</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Allowance for uncollectible accounts(a)</td><td>$ 56</td><td>$ 33</td><td>$ 3</td><td>(b)</td><td>$ 31</td><td>(c)</td><td>$ 61</td></tr><tr><td>Reserve for obsolete materials</td><td>2</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td>2</td></tr><tr><td>For the year ended December 31, 2017</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Allowance for uncollectible accounts(a)</td><td>$ 61</td><td>$ 26</td><td>$ 4</td><td>(b)</td><td>$ 35</td><td>(c)</td><td>$ 56</td></tr><tr><td>Reserve for obsolete materials</td><td>2</td><td>—</td><td>—</td><td>—</td><td>—</td><td></td><td>2</td></tr></table>

(a) Excludes the non-current allowance for uncollectible accounts related to PECO's installment plan receivables of $9 million, $13 million, and $15 million for the years ended December 31, 2019, 2018, and 2017, respectively.

(b) Primarily charges for late payments.

(c) Write-off of individual accounts receivable.



## Baltimore Gas and Electric Company and Subsidiary Companies

## (5) BGE

(i) Financial Statements (Item 8):

Report of Independent Registered Public Accounting Firm dated February 11, 2020 of PricewaterhouseCoopers LLP

Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2019, 2018 and 2017

Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 2018 and 2017

Consolidated Balance Sheets at December 31, 2019 and 2018

Consolidated Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2019, 2018 and 2017

Notes to Consolidated Financial Statements

(ii) Financial Statement Schedule:

Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2019, 2018 and 2017

Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto



## Baltimore Gas and Electric Company and Subsidiary Companies

## Schedule II – Valuation and Qualifying Accounts

<table><tr><td>Column A</td><td colspan="2">Column B</td><td colspan="2">Column C</td><td>Column D</td><td>Column E</td></tr><tr><td></td><td></td><td colspan="3">Additions and adjustments</td><td></td><td></td></tr><tr><td>Description</td><td>Balance at Beginning of Period</td><td>Charged to Costs and Expenses</td><td>Charged to Other Accounts</td><td>Deductions</td><td>Balance at End of Period</td><td></td></tr><tr><td></td><td></td><td></td><td>(in millions)</td><td></td><td></td><td></td></tr><tr><td>For the year ended December 31, 2019</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Allowance for uncollectible accounts</td><td>$     20</td><td>$     8</td><td>$     7</td><td>$     18</td><td>(a)</td><td>$     17</td></tr><tr><td>Deferred tax valuation allowance</td><td>1</td><td>—</td><td>—</td><td>—</td><td></td><td>1</td></tr><tr><td>Reserve for obsolete materials</td><td>1</td><td>—</td><td>—</td><td>—</td><td></td><td>1</td></tr></table>

(a) Write-off of individual accounts receivable.



## (6) PHI

(i) Financial Statements (Item 8):

Report of Independent Registered Public Accounting Firm dated February 11, 2020 of PricewaterhouseCoopers LLP

Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2019, 2018 and 2017

Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 2018 and 2017

Consolidated Balance Sheets at December 31, 2019 and 2018

Consolidated Statements of Changes in Equity for the Years Ended December 31, 2019, 2018 and 2017

Notes to Consolidated Financial Statements

(ii) Financial Statement Schedule:

Schedule II – Valuation and Qualifying Accounts for the Years Ended December 31, 2019, 2018 and 2017

Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto



## Pepco Holdings LLC and Subsidiary Companies

## Schedule II – Valuation and Qualifying Accounts

<table><tr><td>Column A</td><td colspan="2">Column B</td><td colspan="3">Column C</td><td>Column D</td><td>Column E</td></tr><tr><td></td><td></td><td></td><td colspan="3">Additions and adjustments</td><td></td><td></td></tr><tr><td>Description</td><td>Balance at Beginning of Period</td><td></td><td>Charged to Costs and Expenses</td><td>Charged to Other Accounts</td><td></td><td>Deductions</td><td>Balance at End of Period</td></tr><tr><td></td><td></td><td></td><td></td><td>(in millions)</td><td></td><td></td><td></td></tr><tr><td>For the Year Ended December 31, 2019</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Allowance for uncollectible accounts</td><td>$ 53</td><td>$ 17</td><td>$ 7</td><td>(a)</td><td>$ 24</td><td>(b)</td><td>$ 53</td></tr><tr><td>Deferred tax valuation allowance</td><td>8</td><td>—</td><td></td><td>(8)</td><td></td><td>—</td><td>—</td></tr><tr><td>Reserve for obsolete materials</td><td>2</td><td>1</td><td></td><td>—</td><td></td><td>—</td><td>3</td></tr><tr><td>For the Year Ended December 31, 2018</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Allowance for uncollectible accounts</td><td>$ 55</td><td>$ 28</td><td>$ 7</td><td>(a)</td><td>$ 37</td><td>(b)</td><td>$ 53</td></tr><tr><td>Deferred tax valuation allowance</td><td>13</td><td>—</td><td>2</td><td></td><td>7</td><td></td><td>8</td></tr><tr><td>Reserve for obsolete materials</td><td>2</td><td>—</td><td>—</td><td></td><td>—</td><td></td><td>2</td></tr><tr><td>For the Year Ended December 31, 2017</td><td></td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Allowance for uncollectible accounts</td><td>$ 80</td><td>$ 19</td><td>$ 6</td><td>(a)</td><td>$ 50</td><td>(b)</td><td>$ 55</td></tr><tr><td>Deferred tax valuation allowance</td><td>10</td><td>—</td><td>3</td><td></td><td>—</td><td></td><td>13</td></tr><tr><td>Reserve for obsolete materials</td><td>2</td><td>2</td><td>—</td><td></td><td>2</td><td></td><td>2</td></tr></table>

(a) Primarily charges for late payments.

(b) Write-off of individual accounts receivable.



## (7) Pepco

(i) Financial Statements (Item 8):
Report of Independent Registered Public Accounting Firm dated February 11, 2020 of PricewaterhouseCoopers LLP
Statements of Operations and Comprehensive Income for the Years Ended December 31, 2019, 2018 and 2017
Statements of Cash Flows for the Years Ended December 31, 2019, 2018 and 2017

Balance Sheets at December 31, 2019 and 2018

Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2019, 2018 and 2017

Notes to Financial Statements

(ii) Financial Statement Schedule:

Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2019, 2018 and 2017

Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto

394



## Potomac Electric Power Company

## Schedule II – Valuation and Qualifying Accounts

<table><tr><td>Column A</td><td colspan="2">Column B</td><td colspan="2">Column C</td><td>Column D</td><td>Column E</td></tr><tr><td></td><td></td><td colspan="3">Additions and adjustments</td><td></td><td></td></tr><tr><td>Description</td><td>Balance at Beginning of Period</td><td>Charged to Costs and Expenses</td><td>Charged to Other Accounts</td><td>Deductions</td><td>Balance at End of Period</td><td></td></tr><tr><td></td><td></td><td></td><td>(in millions)</td><td></td><td></td><td></td></tr><tr><td>For the year ended December 31, 2019</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Allowance for uncollectible accounts</td><td>$ 21</td><td>$ 7</td><td>$ 2</td><td>(a)</td><td>$ 10</td><td>(b)</td></tr><tr><td>Reserve for obsolete materials</td><td>1</td><td>—</td><td>—</td><td>—</td><td></td><td>1</td></tr><tr><td>For the year ended December 31, 2018</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Allowance for uncollectible accounts</td><td>$ 21</td><td>$ 11</td><td>$ 3</td><td>(a)</td><td>$ 14</td><td>(b)</td></tr><tr><td>Reserve for obsolete materials</td><td>1</td><td>—</td><td>—</td><td>—</td><td></td><td>1</td></tr><tr><td>For the year ended December 31, 2017</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Allowance for uncollectible accounts</td><td>$ 29</td><td>$ 8</td><td>$ 2</td><td>(a)</td><td>$ 18</td><td>(b)</td></tr><tr><td>Reserve for obsolete materials</td><td>1</td><td>1</td><td>—</td><td>1</td><td></td><td>1</td></tr></table>

(a) Primarily charges for late payments.

(b) Write-off of individual accounts receivable.



## (8) DPL

(i) Financial Statements (Item 8):
Report of Independent Registered Public Accounting Firm dated February 11, 2020 of PricewaterhouseCoopers LLP
Statements of Operations and Comprehensive Income for the Years Ended December 31, 2019, 2018 and 2017
Statements of Cash Flows for the Years Ended December 31, 2019, 2018 and 2017

Balance Sheets at December 31, 2019 and 2018

Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2019, 2018 and 2017

Notes to Financial Statements

(ii) Financial Statement Schedule:
Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2019, 2018 and 2017

Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto



## Delmarva Power & Light Company

## Schedule II – Valuation and Qualifying Accounts

<table><tr><td>Column A</td><td colspan="2">Column B</td><td colspan="2">Column C</td><td>Column D</td><td>Column E</td></tr><tr><td></td><td></td><td></td><td colspan="2">Additions and adjustments</td><td></td><td></td></tr><tr><td>Description</td><td>Balance at Beginning of Period</td><td></td><td>Charged to Costs and Expenses</td><td>Charged to Other Accounts</td><td>Deductions</td><td>Balance at End of Period</td></tr><tr><td></td><td></td><td></td><td></td><td>(in millions)</td><td></td><td></td></tr><tr><td>For the year ended December 31, 2019</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Allowance for uncollectible accounts</td><td>$     13</td><td>$     4</td><td>$     3</td><td>(a)</td><td>$     5</td><td>(b)</td></tr><tr><td>Reserve for obsolete materials</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>For the year ended December 31, 2018</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Allowance for uncollectible accounts</td><td>$     16</td><td>$     6</td><td>$     2</td><td>(a)</td><td>$     11</td><td>(b)</td></tr><tr><td>Reserve for obsolete materials</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td><td>—</td></tr><tr><td>For the year ended December 31, 2017</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Allowance for uncollectible accounts</td><td>$     24</td><td>$     3</td><td>$     2</td><td>(a)</td><td>$     13</td><td>(b)</td></tr><tr><td>Reserve for obsolete materials</td><td>—</td><td>1</td><td>—</td><td>1</td><td>—</td><td>—</td></tr></table>

(a) Primarily charges for late payments.

(b) Write-off of individual accounts receivable.



## Atlantic City Electric Company and Subsidiary Company

## (9) ACE

(i) Financial Statements (Item 8):

Report of Independent Registered Public Accounting Firm dated February 11, 2020 of PricewaterhouseCoopers LLP

Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2019, 2018 and 2017

Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 2018 and 2017

Consolidated Balance Sheets at December 31, 2019 and 2018

Consolidated Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2019, 2018 and 2017

Notes to Consolidated Financial Statements

(ii) Financial Statement Schedule:

Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2019, 2018 and 2017

Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto



## Atlantic City Electric Company and Subsidiary Company

## Schedule II – Valuation and Qualifying Accounts

<table><tr><td>Column A</td><td colspan="2">Column B</td><td colspan="2">Column C</td><td>Column D</td><td>Column E</td></tr><tr><td></td><td></td><td colspan="3">Additions and adjustments</td><td></td><td></td></tr><tr><td>Description</td><td>Balance at Beginning of Period</td><td>Charged to Costs and Expenses</td><td>Charged to Other Accounts</td><td>Deductions</td><td>Balance at End of Period</td><td></td></tr><tr><td></td><td></td><td></td><td>(in millions)</td><td></td><td></td><td></td></tr><tr><td>For the year ended December 31, 2019</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Allowance for uncollectible accounts</td><td>$     19</td><td>$     5</td><td>$     2</td><td>(a)</td><td>$     8</td><td>(b)</td></tr><tr><td>Reserve for obsolete materials</td><td>1</td><td>—</td><td>—</td><td>—</td><td>—</td><td>1</td></tr><tr><td>For the year ended December 31, 2018</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Allowance for uncollectible accounts</td><td>$     18</td><td>$     11</td><td>$     2</td><td>(a)</td><td>$     12</td><td>(b)</td></tr><tr><td>Reserve for obsolete materials</td><td>1</td><td>—</td><td>—</td><td>—</td><td>—</td><td>1</td></tr><tr><td>For the year ended December 31, 2017</td><td></td><td></td><td></td><td></td><td></td><td></td></tr><tr><td>Allowance for uncollectible accounts</td><td>$     27</td><td>$     8</td><td>$     2</td><td>(a)</td><td>$     19</td><td>(b)</td></tr><tr><td>Reserve for obsolete materials</td><td>1</td><td>—</td><td>—</td><td>—</td><td>—</td><td>1</td></tr></table>

(a) Primarily charges for late payments.

(b) Write-off of individual accounts receivable.



## Exhibits required by Item 601 of Regulation S-K:

Certain of the following exhibits are incorporated herein by reference under Rule 12b-32 of the Securities and Exchange Act of 1934, as amended. 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 Commission upon request.

<table><tr><td>Exhibit No.</td><td>Description</td></tr><tr><td>2-1</td><td>Agreement and Plan of Merger dated as of April 28, 2011 by and among Exelon Corporation, Bolt Acquisition Corporation and Constellation Energy Group, Inc. (File No. 001-16169, Form 8-K dated April 28, 2011, Exhibit No. 2-1).</td></tr><tr><td>2-2</td><td>Distribution and Assignment Agreement, dated as of March 12, 2012, by and among Exelon Corporation, Constellation Energy Group, Inc. and RF HoldCo LLC (File No. 001-16169, Form 8-K dated March 14, 2012, Exhibit No. 2-3).</td></tr><tr><td>2-3</td><td>Contribution and Assignment Agreement, dated as of March 12, 2012, by and among Exelon Corporation, Exelon Energy Delivery Company, LLC and RF HoldCo LLC (File No. 001-16169, Form 8-K dated March 14, 2012, Exhibit No. 2-4).</td></tr><tr><td>2-4</td><td>Contribution Agreement, dated as of March 12, 2012, by and among Exelon Corporation, Exelon Ventures Company, LLC and Exelon Generation Company, LLC (File No. 001-16169, Form 8-K dated March 14, 2012, Exhibit No. 2-5).</td></tr><tr><td>2-5</td><td>Purchase Agreement dated as of August 8, 2012 by and between Constellation Power Source Generation, Inc. and Raven Power Holdings, LLC. (File No. 333-85496, Form 10-Q for the quarter ended September 30, 2012, Exhibit 2-1).</td></tr><tr><td>2-6</td><td>Master Agreement, dated as of October 26, 2010, by and between Electricite de France, S.A. and Constellation Energy Group, Inc. (Designated as Exhibit No. 2.1 to the Current Report on Form 8-K dated November 1, 2010, filed by Constellation Energy Group, Inc., File No. 1-12869).</td></tr><tr><td>2-7</td><td>Put Termination Agreement dated as of November 3, 2010, by and among EDF Inc. (formerly known as EDF Development, Inc.), E.D.F. International S.A., Constellation Nuclear, LLC, and Constellation Energy Nuclear Group, LLC. (Designated as Exhibit No. 2.1 to the Current Report on Form 8-K dated November 8, 2010, filed by Constellation Energy Group, Inc., File No. 1-12869).</td></tr><tr><td>2-8</td><td>Contribution Agreement, dated as of February 4, 2010, by and among Constellation Energy Group, Inc., Baltimore Gas and Electric Company and RF HoldCo LLC. (Designated as Exhibit No. 99.2 to the Current Report on Form 8-K dated February 4, 2010, filed by Constellation Energy Group, Inc., File Nos. 1-12869 and 1-1910).</td></tr><tr><td>2-9</td><td>Amended and Restated Agreement and Plan of Merger, dated as of July 18, 2014, among Pepco Holdings, Inc., Exelon Corporation and Purple Acquisition Corp. (File No. 001-16169, Form 8-K dated July 21, 2014, Exhibit 2.1).</td></tr><tr><td>3-1</td><td>Amended and Restated Articles of Incorporation of Exelon Corporation, as amended July 24, 2018 (File No. 001-16169, Form 8-K dated July 27, 2018, Exhibit 3.1).</td></tr><tr><td>3-2</td><td>Exelon Corporation Amended and Restated Bylaws, as amended on September 25, 2019 (File No. 001-16169, Form 8-K dated September 13, 2019, Exhibit 3.1).</td></tr><tr><td>3-3</td><td>Certificate of Formation of Exelon Generation Company, LLC (Registration Statement No. 333-85496, Form S-4, Exhibit 3-1).</td></tr></table>



<table><tr><td>Exhibit No.</td><td>Description</td></tr><tr><td>3-4</td><td>Second Amended and Restated Operating Agreement of Exelon Generation Company, LLC dated of October 30, 2019 (File No. 333-85496, Form 10-Q dated October 31, 2019, Exhibit 3.1).</td></tr><tr><td>3-5</td><td>Restated Articles of Incorporation of Commonwealth Edison Company Effective February 20, 1985, including Statements of Resolution Establishing Series, relating to the establishment of three new series of Commonwealth Edison Company preference stock known as the &#x27;$9.00 Cumulative Preference Stock,&#x27; the &#x27;$6.875 Cumulative Preference Stock&#x27; and the &#x27;$2.425 Cumulative Preference Stock&#x27; (File No. 1-1839, 1994 Form 10-K, Exhibit 3-2).</td></tr><tr><td>3-6</td><td>Commonwealth Edison Company Amended and Restated By-Laws, Effective June 11, 2019 (File No. 001-1839, Information Statement on Schedule 14C, Appendix B).</td></tr><tr><td>3-7</td><td>Amended and Restated Articles of Incorporation of PECO Energy Company (File No. 1-01401, 2000 Form 10-K, Exhibit 3-3).</td></tr><tr><td>3-8</td><td>PECO Energy Company Amended and Restated Bylaws dated May 1, 2019 (File 000-16844, Form 10-Q dated May 2, 2019, Exhibit 3.2).</td></tr><tr><td>3-9</td><td>Articles of Amendment to the Charter of Baltimore Gas and Electric Company as of February 2, 2010. (File No. 1-1910, Form 8-K dated February 4, 2010).</td></tr><tr><td>3-10</td><td>Articles of Restatement to the Charter of Baltimore Gas and Electric Company, restated as of August 16, 1996. (File No. 1-1910, Form 10-Q dated November 14, 1996, Exhibit No. 3).</td></tr><tr><td>3-11</td><td>Amended and Restated Bylaws of Baltimore Gas and Electric Company dated May 1, 2019 (File No. 1-1910, Form 10-Q dated May 2, 2019, Exhibit 3.1).</td></tr><tr><td>3-12</td><td>Certificate of Formation of Pepco Holdings LLC, dated March 23, 2016 (File No. 001-31403, Form 8-K dated March 24, 2016, Exhibit 3.2)</td></tr><tr><td>3-13</td><td>Amended and Restated Limited Liability Company Agreement of Pepco Holdings LLC, dated May 1, 2019 (File No. 001-31403, Form 10-Q dated May 2, 2019, Exhibit 3.3)</td></tr><tr><td>3-14</td><td>Potomac Electric Power Company Restated Articles of Incorporation and Articles of Restatement of (as filed in the District of Columbia) (File No. 001-31403, Form 10-Q dated May 5, 2006, Exhibit 3.1)</td></tr><tr><td>3-15</td><td>Potomac Electric Power Company Restated Articles of Incorporation and Articles of Restatement of (as filed in Virginia) (File No. 001-01072, Form 10-Q dated November 4, 2011, Exhibit 3.3)</td></tr><tr><td>3-16</td><td>Delmarva Power &amp; Light Company Articles of Restatement of Certificate and Articles of Incorporation (filed in Delaware and Virginia 02/22/07) (File No. 001-01405, Form 10-K dated March 1, 2007, Exhibit 3.3)</td></tr><tr><td>3-17</td><td>Atlantic City Electric Company Restated Certificate of Incorporation (filed in New Jersey on August 9, 2002) (File No. 001-03559, Amendment No. 1 to Form U5B dated February 13, 2003, Exhibit B.8.1)</td></tr><tr><td>3-18</td><td>Bylaws of Potomac Electric Power Company (File No. 001-01072, Form 10-Q dated May 5, 2006, Exhibit 3.2)</td></tr><tr><td>3-19</td><td>Bylaws of Delmarva Power &amp; Light Company (File No. 001-01405, Form 10-Q dated May 9, 2005, Exhibit 3.2.1)</td></tr><tr><td>3-20</td><td>Bylaws of Atlantic City Electric Company (File No. 001-03559, Form 10-Q dated May 9, 2005, Exhibit 3.2.2)</td></tr></table>



<table><tr><td>Exhibit No.</td><td>Description</td><td></td><td></td></tr><tr><td>4-1</td><td>First and Refunding Mortgage dated May 1, 1923 between The Counties Gas and Electric Company (predecessor to PECO Energy Company) and Fidelity Trust Company, Trustee (U.S. Bank National Association, as current successor trustee), (Registration No. 2-2281, Exhibit B-1).(a)</td><td></td><td></td></tr><tr><td>4-1-1</td><td>Supplemental Indentures to PECO Energy Company&#x27;s First and Refunding Mortgage:</td><td></td><td></td></tr><tr><td></td><td>Dated as of</td><td>File Reference</td><td>Exhibit No.</td></tr><tr><td></td><td>December 1, 1941</td><td>2-4863(a)</td><td>B-1(h)</td></tr><tr><td></td><td>April 15, 2004</td><td>0-6844, September 30, 2004 Form 10-Q(a)</td><td>4-1-1</td></tr><tr><td></td><td>September 15, 2006</td><td>000-16844, Form 8-K dated September 25, 2006</td><td>4.1</td></tr><tr><td></td><td>March 1, 2007</td><td>000-16844, Form 8-K dated March 19, 2007</td><td>4.1</td></tr><tr><td></td><td>September 1, 2012</td><td>000-16844, Form 8-K dated September 17, 2012</td><td>4.1</td></tr><tr><td></td><td>September 15, 2013</td><td>000-16844, Form 8-K dated September 23, 2013</td><td>4.1</td></tr><tr><td></td><td>September 1, 2014</td><td>000-16844, Form 8-K dated September 15, 2014</td><td>4.1</td></tr><tr><td></td><td>September 15, 2015</td><td>000-16844, Form 8-K dated October 5, 2015</td><td>4.1</td></tr><tr><td></td><td>September 1, 2016</td><td>000-16844, Form 8-K dated September 21, 2016</td><td>4.1</td></tr><tr><td></td><td>September 1, 2017</td><td>000-16844, Form 8-K dated September 18, 2017</td><td>4.1</td></tr><tr><td></td><td>February 1, 2018</td><td>000-16844, Form 8-K dated February 23, 2018</td><td>4.1</td></tr><tr><td></td><td>September 1, 2018</td><td>000-16844, Form 8-K dated September 11, 2018</td><td>4.1</td></tr><tr><td></td><td>August 15, 2019</td><td>000-16844, Form 8-K dated September 10, 2019</td><td>4.1</td></tr><tr><td>Exhibit No.</td><td>Description</td><td></td><td></td></tr><tr><td>4-2</td><td>Exelon Corporation Direct Stock Purchase Plan (Registration Statement No. 333-206474, Form S-3, Prospectus).</td><td></td><td></td></tr><tr><td>4-3</td><td colspan="3">Mortgage of Commonwealth Edison Company to Illinois Merchants Trust Company, Trustee (BNY Mellon Trust Company of Illinois, as current successor Trustee), dated July 1, 1923, as supplemented and amended by Supplemental Indenture thereto dated August 1, 1944. (Registration No. 2-60201, Form S-7, Exhibit 2-1).(a)</td></tr></table>



<table><tr><td>Dated as of</td><td>File Reference</td></tr><tr><td>January 13, 2003</td><td>001-01839, Form 8-K dated February 13, 2003</td></tr><tr><td>February 22, 2006</td><td>001-01839, Form 8-K dated March 6, 2006</td></tr><tr><td>August 1, 2006</td><td>001-01839, Form 8-K dated August 28, 2006</td></tr><tr><td>September 15, 2006</td><td>001-01839, Form 8-K dated October 2, 2006</td></tr><tr><td>March 1, 2007</td><td>001-01839, Form 8-K dated March 23, 2007</td></tr><tr><td>August 30, 2007</td><td>001-01839, Form 8-K dated September 10, 2007</td></tr><tr><td>December 20, 2007</td><td>001-01839, Form 8-K dated January 16, 2008</td></tr><tr><td>March 10, 2008</td><td>001-01839, Form 8-K dated March 27, 2008</td></tr><tr><td>July 12, 2010</td><td>001-01839, Form 8-K dated August 2, 2010</td></tr><tr><td>August 22, 2011</td><td>001-01839, Form 8-K dated September 7, 2011</td></tr><tr><td>September 17, 2012</td><td>001-01839, Form 8-K dated October 1, 2012</td></tr><tr><td>August 1, 2013</td><td>001-01839, Form 8-K dated August 19, 2013</td></tr><tr><td>January 2, 2014</td><td>001-01839, Form 8-K dated January 10, 2014</td></tr><tr><td>October 28, 2014</td><td>001-01839, Form 8-K dated November 10, 2014</td></tr><tr><td>February 18, 2015</td><td>001-01839, Form 8-K dated March 2, 2015</td></tr><tr><td>November 4, 2015</td><td>001-01839, Form 8-K dated November 19, 2015</td></tr><tr><td>June 15, 2016</td><td>001-01839, Form 8-K dated June 27, 2016</td></tr><tr><td>August 9, 2017</td><td>001-01839, Form 8-K dated August 23, 2017</td></tr></table>



<table><tr><td>Dated as of</td><td>File Reference</td></tr><tr><td>February 6, 2018</td><td>001-01839, Form 8-K dated February 20, 2018</td></tr><tr><td>July 26, 2018</td><td>001-01839, Form 8-K dated August 14, 2018</td></tr><tr><td>February 7, 2019</td><td>001-01839, Form 8-K dated February 19, 2019</td></tr><tr><td>October 29, 2019</td><td>001-01839, Form 8-K dated November 12, 2019</td></tr></table>

## Exhibit No.

## Description

Instrument of Resignation, Appointment and Acceptance dated as of February 20, 2002, under the provisions of the Mortgage of Commonwealth Edison Company dated July 1, 1923, and Indentures Supplemental thereto, regarding corporate trustee (File No. 1-1839, 2001 Form 10-K, Exhibit 4-4-2).

Instrument dated as of January 31, 1996, under the provisions of the Mortgage of Commonwealth Edison Company dated July 1, 1923 and Indentures Supplemental thereto, regarding individual trustee (File No. 1-1839, 1995 Form 10-K, Exhibit 4-29).

Indenture to Subordinated Debt Securities dated as of June 24, 2003 between PECO Energy Company, as Issuer, and U.S. Bank National Association, as Trustee (File No. 000-16844, June 30, 2003 Form 10-Q, Exhibit 4.1).

Form of 4.25% Senior Note due 2022 issued by Exelon Generation Company, LLC. (File 333-85496, Form 8-K dated June 18, 2012, Exhibit 4.1).

Form of 5.60% Senior Note due 2042 issued by Exelon Generation Company, LLC. (File 333-85496, Form 8-K dated June 18, 2012, Exhibit 4.2).

Form of 2.80% Senior Note due 2022 issued by Baltimore Gas and Electric Company. (File 1-1910, Form 8-K dated August 17, 2012, Exhibit 4.1).

Form of 3.35% Senior Note due 2023 Baltimore Gas and Electric Company. (File 1-1910, Form 8-K dated June 17, 2013, Exhibit 4.1).

Form of 6.000% Senior Notes due 2033 issued by Exelon Generation Company, LLC (File No. 333-85496, Form 8-K dated September 30, 2013, Exhibit No. 4.1).

Preferred Securities Guarantee Agreement between PECO Energy Company, as Guarantor, and U.S. Bank National Association, as Trustee, dated as of June 24, 2003 (File No. 000-16844, June 30, 2003 Form 10-Q, Exhibit 4.2).

PECO Energy Capital Trust IV Amended and Restated Declaration of Trust among PECO Energy Company, as Sponsor, U.S. Bank Trust National Association, as Delaware Trustee and Property Trustee, and J. Barry Mitchell, George R. Shicora and Charles S. Walls as Administrative Trustees dated as of June 24, 2003 (File No. 000-16844, June 30, 2003 Form 10-Q, Exhibit 4.3).

Indenture dated May 1, 2001 between Exelon Corporation and The Bank of New York Mellon Trust Company, National Association, as trustee (File No. 1-16169, June 30, 2005 Form 10-Q, Exhibit 4-10).

Form of $500,000,000 5.625% senior notes due 2035 dated June 9, 2005 issued by Exelon Corporation (File No. 1-16169, Form 8-K dated June 9, 2005, Exhibit 99.3).



<table><tr><td>Exhibit No.</td><td>Description</td></tr><tr><td>4-16</td><td>Indenture dated as of September 28, 2007 from Exelon Generation Company, LLC to U.S. Bank National Association, as trustee (File 333-85496, Form 8-K dated September 28, 2007, Exhibit 4.1).</td></tr><tr><td>4-17</td><td>Form of 6.25% Exelon Generation Company, LLC Senior Note due 2039 (File 333-85496, Form 8-K dated September 23, 2009, Exhibit 4.2).</td></tr><tr><td>4-18</td><td>Form of 4.00% Exelon Generation Company, LLC Senior Note due 2020 (File No. 333-85496, Form 8-K dated September 30, 2010, Exhibit 4.1).</td></tr><tr><td>4-19</td><td>Form of 5.75% Exelon Generation Company, LLC Senior Note due 2041 (File No. 333-85496, Form 8-K dated September 30, 2010, Exhibit 4.2).</td></tr><tr><td>4-20</td><td>Indenture between Constellation Energy Group, Inc. and the Bank of New York, Trustee dated as of March 24, 1999. (Designated as Exhibit No. 4(a) to the Registration Statement on Form S-3 dated March 29, 1999, filed by Constellation Energy Group, Inc., File No. 333-75217.)</td></tr><tr><td>4-21</td><td>First Supplemental Indenture between Constellation Energy Group, Inc. and the Bank of New York, Trustee dated as of January 24, 2003. (Designated as Exhibit No. 4(b) to the Registration Statement on Form S-3 dated January 24, 2003, filed by Constellation Energy Group, Inc., File No. 333-102723).</td></tr><tr><td>4-22</td><td>Indenture dated as of July 24, 2006 between Constellation Energy Group, Inc. and Deutsche Bank Trust Company Americas, as trustee. (Designated as Exhibit No. 4(a) to the Registration Statement on Form S-3 filed July 24, 2006, filed by Constellation Energy Group, Inc., File No. 333-135991).</td></tr><tr><td>4-23</td><td>First Supplemental Indenture between Constellation Energy Group, Inc. and Deutsche Bank Trust Company Americas, as trustee, dated as of June 27, 2008. (Designated as Exhibit 4(a) to the Current Report on Form 8-K dated June 30, 2008, filed by Constellation Energy Group, Inc., File No. 1-12869).</td></tr><tr><td>4-24</td><td>Indenture dated June 19, 2008 between Constellation Energy Group, Inc. and Deutsche Bank Trust Company Americas, as trustee. (Designated as Exhibit No. 4(a) to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2008, filed by Constellation Energy Group, Inc., File Nos. 1-12869 and 1-1910).</td></tr><tr><td>4-25</td><td>Indenture, dated as of September 30, 2013, among Continental Wind, LLC, the guarantors party thereto and Wilmington Trust, National Association, as trustee (File No. 333-85496, Form 8-K dated September 30, 2013, Exhibit No. 4.1).</td></tr><tr><td>4-26</td><td>Indenture dated July 1, 1985, between Baltimore Gas and Electric Company and The Bank of New York (Successor to Mercantile-Safe Deposit and Trust Company), Trustee. (Designated as Exhibit 4(a) to the Registration Statement on Form S-3, File No. 2-98443); as supplemented by Supplemental Indentures dated as of October 1, 1987 (Designated as Exhibit 4(a) to the Current Report on Form 8-K, dated November 13, 1987, File No. 1-1910) and as of January 26, 1993 (Designated as Exhibit 4(b) to the Current Report on Form 8-K, dated January 29, 1993, filed by Baltimore Gas and Electric Company, File No. 1-1910).(a)</td></tr><tr><td>4-27</td><td>Indenture dated as of July 24, 2006 between Baltimore Gas and Electric Company and Deutsche Bank Trust Company Americas, as trustee. (Designated as Exhibit 4(b) to the Registration Statement on Form S-3 filed July 24, 2006, filed by Constellation Energy Group, Inc., File No. 333-135991).</td></tr><tr><td>4-28</td><td>Indenture dated as of June 29, 2007, by and between RSB BondCo LLC and Deutsche Bank Trust Company Americas, as Trustee and Securities Intermediary. (Designated as Exhibit 4.1 to the Current Report on Form 8-K dated July 5, 2007, filed by Baltimore Gas and Electric Company, File No. 1-1910).</td></tr></table>



<table><tr><td>Exhibit No.</td><td>Description</td></tr><tr><td>4-29</td><td>Series Supplement to Indenture dated as of June 29, 2007 by and between RSB BondCo LLC and Deutsche Bank Trust Company Americas, as Trustee and Securities Intermediary (Designated as Exhibit No. 4(b) to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, filed by Baltimore Gas and Electric Company, File No. 1-1910).</td></tr><tr><td>4-30</td><td>Replacement Capital Covenant dated June 27, 2008. (Designated as Exhibit No. 4(b) to the Current Report on Form 8-K dated June 30, 2008, filed by Constellation Energy Group, Inc., File No. 1-12869).</td></tr><tr><td>4-31</td><td>Amendment to Replacement Capital Covenant, dated as of March 12, 2012, amending the Replacement Capital Covenant, dated as of June 27, 2008 (File No. 001-16169, Form 8-K dated March 14, 2012, Exhibit No. 99.4).</td></tr><tr><td>4-32</td><td>Officers&#x27; Certificate, dated December 14, 2010, establishing the 5.15% Notes due December 1, 2020 of Constellation Energy Group, Inc., with the form of Notes attached thereto. (Designated as Exhibit No. 4 (b) to the Current Report on Form 8-K dated December 14, 2010, filed by Constellation Energy Group, Inc., File No. 1-12869).</td></tr><tr><td>4-33</td><td>Officers&#x27; Certificate, November 16, 2011, establishing the 3.50% Notes due November 15, 2021 of Baltimore Gas and Electric Company, with the form of Notes attached thereto. (Designated as Exhibit No. 4(b) to the Current Report on Form 8-K dated November 16, 2011, filed by Baltimore Gas and Electric Company, File No. 1-1910).</td></tr><tr><td>4-34</td><td>Indenture, dated as of June 17, 2014, between Exelon Corporation and The Bank of New York Mellon Trust Company, N.A., as Trustee, (File No. 001-16169, Form 8-K dated June 23, 2014, Exhibit 4.1).</td></tr><tr><td>4-35-1</td><td>First Supplemental Indenture, dated as of June 17, 2014, between Exelon Corporation and The Bank of New York Mellon Trust Company, N.A., as Trustee. (File No. 001-16169, Form 8-K dated June 23, 2014, Exhibit 4.2).</td></tr><tr><td>4-35-2</td><td>Form of 2.50% Notes due 2024 (File No. 001-16169, Form 8-K dated June 23, 2014, Exhibit 4.2, Exhibit A).</td></tr><tr><td>4-35-3</td><td>Purchase Contract and Pledge Agreement, between Exelon Corporation and The Bank of New York Mellon Trust Company, N.A., as Purchase Contract Agent, Collateral Agent, Custodial Agent and Securities Intermediary. (File No. 001-16169, Form 8-K dated June 23, 2014, Exhibit 4.4).</td></tr><tr><td>4-35-4</td><td>Form of Remarketing Agreement (File No. 001-16169, Form 8-K dated June 23, 2014, Exhibit 4.4, Exhibit P).</td></tr><tr><td>4-35-5</td><td>Form of Corporate Unit (File No. 001-16169, Form 8-K dated June 23, 2014, Exhibit 4.4, Exhibit A).</td></tr><tr><td>4-35-6</td><td>Form of Treasury Unit (File No. 001-16169, Form 8-K dated June 23, 2014, Exhibit 4.4, Exhibit B).</td></tr><tr><td>4-36</td><td>Indenture, dated as of June 11, 2015, among Exelon Corporation and The Bank of New York Mellon Trust Company, National Association, as trustee (incorporated herein by reference to Exhibit 4.1 to Exelon Corporation&#x27;s Current Report on Form 8-K, filed on June 11, 2015).</td></tr><tr><td>4-36-1</td><td>First Supplemental Indenture, dated as of June 11, 2015, among Exelon Corporation and The Bank of New York Mellon Trust Company, National Association, as trustee (incorporated herein by reference to Exhibit 4.2 to Exelon Corporation&#x27;s Current Report on Form 8-K, filed on June 11, 2015).</td></tr></table>



<table><tr><td>Exhibit No.</td><td>Description</td></tr><tr><td>4-36-2</td><td>Second Supplemental Indenture, dated as of December 2, 2015, among Exelon Corporation and The Bank of New York Mellon Trust Company, National Association, as trustee (incorporated herein by reference to Exhibit 4.1 to Exelon Corporation&#x27;s Current Report on Form 8-K, filed on December 2, 2015).</td></tr><tr><td>4-37</td><td>Form of Conversion Supplemental Indenture, dated March 23, 2016 (File No. 001-31403, Form 8-K dated March 24, 2016, Exhibit 4.1)</td></tr><tr><td>4-38</td><td>Third Supplemental Indenture, dated as of April 7, 2016, among Exelon Corporation and The Bank of New York Mellon Trust Company, N.A., as trustee (File No. 001-16169, Form 8-K dated April 7, 2016, Exhibit 4.2)</td></tr><tr><td>4-39</td><td>Mortgage and Deed of Trust, dated July 1, 1936, of Potomac Electric Power Company to The Bank of New York Mellon as successor trustee, securing First Mortgage Bonds of Potomac Electric Power Company, and Supplemental Indenture dated July 1, 1936 (File No. 2-2232, Registration Statement dated June 19, 1936, Exhibit B-4)(a)</td></tr><tr><td>4-39-1</td><td>Supplemental Indentures to Potomac Electric Power Company Mortgage.</td></tr><tr><td></td><td>Dated as of</td><td>File Reference</td></tr><tr><td></td><td>December 10, 1939</td><td>Form 8-K, 1/3/40(a)</td></tr><tr><td></td><td>March 16, 2004</td><td>001-01072, Form 8-K, 3/23/04</td></tr><tr><td></td><td>May 24, 2005</td><td>001-01072, Form 8-K, 5/26/05</td></tr><tr><td></td><td>November 13, 2007</td><td>001-01072, Form 8-K, 11/15/07</td></tr><tr><td></td><td>March 24, 2008</td><td>001-01072, Form 8-K, 3/28/08</td></tr><tr><td></td><td>December 3, 2008</td><td>001-01072, Form 8-K, 12/8/08</td></tr><tr><td></td><td>March 28, 2012</td><td>001-01072, Form 8-K, 3/29/12</td></tr><tr><td></td><td>March 11, 2013</td><td>001-01072, Form 8-K, 3/12/13</td></tr><tr><td></td><td>November 14, 2013</td><td>001-01072, Form 8-K, 11/15/13</td></tr><tr><td></td><td>March 11, 2014</td><td>001-01072, Form 8-K, 3/12/14</td></tr><tr><td></td><td>March 9, 2015</td><td>001-01072, Form 8-K, 3/10/15</td></tr><tr><td></td><td>May 15, 2017</td><td>001-01072, Form 8-K, 5/22/17</td></tr><tr><td></td><td>June 1, 2018</td><td>001-01072, Form 8-K, 6/21/18</td></tr><tr><td></td><td>May 2, 2019</td><td>001-01072, Form 8-K, 6/13/19</td></tr></table>



<table><tr><td>Exhibit No.</td><td>Description</td></tr><tr><td>4-40</td><td>Indenture, dated as of July 28, 1989, between Potomac Electric Power Company and The Bank of New York Mellon, Trustee, with respect to Medium-Term Note Program (File No. 001-01072, Form 8-K dated June 21, 1990, Exhibit 4)(a)</td></tr><tr><td>4-41</td><td>Senior Note Indenture, dated November 17, 2003 between Potomac Electric Power Company and The Bank of New York Mellon (File No. 001-01072, Form 8-K dated November 21, 2003, Exhibit 4.2)</td></tr><tr><td>4-41-1</td><td>Supplemental Indenture, dated March 31, 2008, to Senior Note Indenture between Potomac Electric Power Company and The Bank of New York Mellon (File No. 001-01072, Form 10-K dated March 2, 2009, Exhibit 4.3)</td></tr><tr><td>4-42</td><td>Mortgage and Deed of Trust of Delaware Power &amp; Light Company to The Bank of New York Mellon (ultimate successor to the New York Trust Company), as trustee, dated as of October 1, 1943, and copies of the First through Sixty-Eighth Supplemental Indentures thereto (File No. 33-1763, Registration Statement dated November 27, 1985, Exhibit 4-A)(a)</td></tr><tr><td>4-42-1</td><td>Supplemental Indentures to Delmarva Power &amp; Light Company Mortgage.</td></tr><tr><td></td><td>Dated as of File Reference Exhibit No.</td></tr><tr><td></td><td>October 1, 1993 33-53855, Registration Statement, 1/30/95(a) 4-L</td></tr><tr><td></td><td>October 1, 1994 33-53855, Registration Statement, 1/30/95(a) 4-N</td></tr><tr><td></td><td>January 1, 1997 001-01405, Form 10-K, 2/24/12 4.4</td></tr><tr><td></td><td>November 7, 2013 001-01405, Form 8-K, 11/8/13 4.2</td></tr><tr><td></td><td>June 2, 2014 001-01405, Form 8-K, 6/3/14 4.3</td></tr><tr><td></td><td>May 4, 2015 001-01405, Form 8-K, 5/5/15 4.2</td></tr><tr><td></td><td>December 5, 2016 001-01405, Form 8-K, 12/12/16 4.2</td></tr><tr><td></td><td>April 5, 2017 001-01405, Form 10-Q, 5/3/17 4.5</td></tr><tr><td></td><td>April 3, 2018 000-01405, Form 10-Q, 5/2/18 4.3</td></tr><tr><td></td><td>June 1, 2018 000-01405, Form 8-K, 6/21/18 4.2</td></tr><tr><td></td><td>April 3, 2019 001-01405, Form 10-Q, 5/2/19 4.2</td></tr><tr><td></td><td>May 2, 2019 001-01405, Form 8-K, 12/12/19 4.2</td></tr></table>



<table><tr><td>Exhibit No.</td><td>Description</td><td></td></tr><tr><td>4-43</td><td>Indenture between Delmarva Power &amp; Light Company and The Bank of New York Mellon Trust Company, N.A. (ultimate successor to Manufacturers Hanover Trust Company), as trustee, dated as of November 1, 1988 (File No. 33-46892, Registration Statement dated April 1, 1992, Exhibit 4-G)(a)</td><td></td></tr><tr><td>4-44</td><td>Mortgage and Deed of Trust, dated January 15, 1937, between Atlantic City Electric Company and The Bank of New York Mellon (formerly Irving Trust Company), as trustee (File No. 2-66280, Registration Statement dated December 21, 1979, Exhibit 2(a))(a)</td><td></td></tr><tr><td>4-44-1</td><td>Supplemental Indentures to Atlantic City Electric Company Mortgage.</td><td></td></tr><tr><td></td><td>Dated as of</td><td>File Reference</td></tr><tr><td></td><td>June 1, 1949</td><td>2-66280, Registration Statement, 12/21/79(a)</td></tr><tr><td></td><td>March 1, 1991</td><td>Form 10-K, 3/28/91(a)</td></tr><tr><td></td><td>April 1, 2004</td><td>001-03559, Form 8-K, 4/6/04</td></tr><tr><td></td><td>March 8, 2006</td><td>001-03559, Form 8-K, 3/17/06</td></tr><tr><td></td><td>March 29, 2011</td><td>001-03559, Form 8-K, 4/1/11</td></tr><tr><td></td><td>August 18, 2014</td><td>001-03559, Form 8-K, 8/19/14</td></tr><tr><td></td><td>December 1, 2015</td><td>001-03559, Form 8-K, 12/2/15</td></tr><tr><td></td><td>October 9, 2018</td><td>001-03559, Form 8-K, 10/16/18</td></tr><tr><td></td><td>May 2, 2019</td><td>001-03559, Form 8-K, 5/21/19</td></tr><tr><td>Exhibit No.</td><td>Description</td><td></td></tr><tr><td>4-45</td><td>Indenture, dated as of March 1, 1997, between Atlantic City Electric Company and The Bank of New York Mellon, as trustee (File No. 001-03559, Form 8-K dated March 24, 1997, Exhibit 4.2)</td><td></td></tr><tr><td>4-46</td><td>Senior Note Indenture, dated as of April 1, 2004, between Atlantic City Electric Company and The Bank of New York Mellon, as trustee (File No. 001-03559, Form 8-K dated April 6, 2004, Exhibit 4.2)</td><td></td></tr><tr><td>4-47</td><td>Indenture, dated as of December 19, 2002 between Atlantic City Electric Transition Funding LLC and The Bank of New York Mellon, as trustee (File No. 333-59558, Form 8-K dated December 23, 2002, Exhibit 4.1)</td><td></td></tr><tr><td>4-48</td><td>2002-1 Series Supplement, dated as of December 19, 2002 between Atlantic City Electric Transition Funding LLC and The Bank of New York Mellon, as trustee (File No. 333-59558, Form 8-K dated December 23, 2002, Exhibit 4.2)</td><td></td></tr><tr><td>4-49</td><td>2003-1 Series Supplement, dated as of December 23, 2003 between Atlantic City Electric Transition Funding LLC and The Bank of New York Mellon, as trustee (File No. 333-59558, Form 8-K dated December 23, 2003, Exhibit 4.2)</td><td></td></tr><tr><td>4-50</td><td>Indenture, dated September 6, 2002, between Pepco Holdings, Inc. and The Bank of New York Mellon, as trustee (File No. 333-100478, Registration Statement on Form S-3 dated October 10, 2002, Exhibit 4.03)</td><td></td></tr></table>



<table><tr><td>Exhibit No.</td><td>Description</td></tr><tr><td>4-51</td><td>Corporate Commercial Paper Master Note (File No. 001-31403, Form 10-K dated February 24, 2012, Exhibit 4.13)</td></tr><tr><td>4-52</td><td>Pepco Holdings, Inc. Certificate of Series A Non-Voting Non-Convertible Preferred Stock (File No. 001-31403, Form 8-k dated April 30, 2014, Exhibit 3.1)</td></tr><tr><td>4-53</td><td>Form of 2.400% notes due 2026 (File No. 001-01910, Form 8-K dated August 18, 2016, Exhibit 4.1)</td></tr><tr><td>4-54</td><td>Form of 3.500% notes due 2046 (File No. 001-01910, Form 8-K dated August 18, 2016, Exhibit 4.2)</td></tr><tr><td>4-55</td><td>Form of Exelon Generation Company, LLC 2.950% senior notes due 2020 (File No. 333-85496, Form 8-K dated March 10, 2017, Exhibit 4.1)</td></tr><tr><td>4-56</td><td>Form of Exelon Generation Company, LLC 3.400% notes due 2022 (File No. 333-85496, Form 8-K dated March 10, 2017, Exhibit 4.2)</td></tr><tr><td>4-57</td><td>Second Supplemental Indenture, dated April 3, 2017, between Exelon and The Bank of New York Mellon Trust Company, N.A., as trustee, to that certain Indenture (For Unsecured Subordinated Debt Securities), dated June 17, 2014 (File No. 001-16169, Form 8-K dated April 4, 2017, Exhibit 4.3)</td></tr><tr><td>4-58</td><td>Form of Exelon Corporation 3.497% junior subordinated notes due 2022 (File No. 001-16169, Form 8-K dated April 4, 2017, Exhibit 4.4)</td></tr><tr><td>4-59</td><td>Form of First Mortgage Bond, 4.15% Series due March 15, 2043 (File No. 001-01072, Form 8-K dated May 22, 2017, Exhibit 4.2)</td></tr><tr><td>4-60</td><td>BGE Form of 3.750% notes due 2047 (File No. 001-01910, Form 8-K dated August 24, 2017, Exhibit 4.1)</td></tr><tr><td>4-61</td><td>Exempt Facilities Loan Agreement dated as of June 1, 2019 between the Maryland Economic Development Corporation and Potomac Electric Power Company (File No. 001-01072, Form 8-K dated June 27, 2019, Exhibit 4.1)</td></tr><tr><td>4-62</td><td>Indenture, dated as of September 1, 2019, between Baltimore Gas and Electric Company and U.S. Bank National Association, as trustee (File No. 001-01910, Form 8-K dated September 12, 2019, Exhibit 4.1)</td></tr><tr><td>4-63</td><td>Description of Exelon Securities</td></tr><tr><td>4-64</td><td>Description of PECO Securities</td></tr><tr><td>4-65</td><td>Description of ComEd Securities</td></tr><tr><td>10-1</td><td>Exelon Corporation Non-Employee Directors&#x27; Deferred Stock Unit Plan (As Amended and Restated Effective September 25, 2019). * (File No. 001-16169, Form 10-Q dated October 31, 2019, Exhibit 10.1).</td></tr><tr><td>10-2</td><td>Form of Exelon Corporation Unfunded Deferred Compensation Plan for Directors (as amended and restated Effective March 12, 2012). * (File No. 1-16169, 2015 Form 10-K, Exhibit 10-3)</td></tr><tr><td>10-3</td><td>Form of Restricted Stock Award Agreement under the Exelon Corporation Long-Term Incentive Plan* (File No. 1-16169, Form 10-Q dated October 31, 2019, Exhibit 10.2).</td></tr></table>



<table><tr><td>Exhibit No.</td><td>Description</td></tr><tr><td>10-4</td><td>Unicom Corporation Deferred Compensation Unit Plan, as amended (File Nos. 1-11375 and 1-1839, 1995 Form 10-K, Exhibit 10-12).</td></tr><tr><td>10-5</td><td>Amendment Number One to the Unicom Corporation Deferred Compensation Unit Plan, as amended January 1, 2008 * (File No. 001-16169, 2008 Form 10-K, Exhibit 10.16).</td></tr><tr><td>10-6</td><td>Exelon Corporation Supplemental Management Retirement Plan (As Amended and Restated Effective January 1, 2009) * (File No. 001-16169, 2008 Form 10-K, Exhibit 10.19).</td></tr><tr><td>10-7</td><td>PECO Energy Company Supplemental Pension Benefit Plan (As Amended and Restated Effective January 1, 2009) (File No. 000-16844, 2008 Form 10-K, Exhibit 10.20).</td></tr><tr><td>10-8</td><td>Exelon Corporation Annual Incentive Plan for Senior Executives (As Amended Effective January 1, 2014 * (File No. 1-16169, Exelon Proxy Statement dated April 1, 2014, Appendix A).</td></tr><tr><td>10-9</td><td>Exelon Corporation Employee Stock Purchase Plan, as amended and restated effective September 25, 2019 (File No. 1-16169, Form 10-Q dated October 31, 2019, Exhibit 10.3).</td></tr><tr><td>10-10</td><td>Exelon Corporation 2006 Long-Term Incentive Plan (Registration Statement No. 333-122704, Form S-4, Joint Proxy Statement-Prospectus pursuant to Rule 424(b)(3) filed June 3, 2005, Annex H).</td></tr><tr><td>10-11</td><td>Form of Stock Option Grant Instrument under the Exelon Corporation 2006 Long-Term Incentive Plan (File No. 1-16169, Form 8-K filed January 27, 2006, Exhibit 99.2).</td></tr><tr><td>10-12</td><td>Exelon Corporation Employee Stock Purchase Plan for Unincorporated Subsidiaries, as amended and restated effective September 25, 2019 (File No. 1-16169, Form 10-Q dated October 31, 2019, Exhibit 10.4).</td></tr><tr><td>10-13</td><td>Exelon Corporation Senior Management Severance Plan (As Amended and Restated Effective January 1, 2020) *</td></tr><tr><td>10-14</td><td>Exelon Corporation Executive Death Benefits Plan dated as of January 1, 2003 * (File No. 1-16169, 2006 Form 10-K, Exhibit 10-52).</td></tr><tr><td>10-15</td><td>First Amendment to Exelon Corporation Executive Death Benefits Plan, Effective January 1, 2006 * (File No. 1-16169, 2006 Form 10-K, Exhibit 10-53).</td></tr><tr><td>10-16</td><td>Amendment Number One to the Exelon Corporation 2006 Long-Term Incentive Plan, Effective December 4, 2006 (File No. 1-16169, 2006 Form 10-K, Exhibit 10-54).</td></tr><tr><td>10-17</td><td>Exelon Corporation Deferred Compensation Plan (As Amended and Restated Effective January 1, 2005) (File No. 1-16169, 2006 Form 10-K, Exhibit 10-56).</td></tr><tr><td>10-18</td><td>Exelon Corporation Stock Deferral Plan (As Amended and Restated Effective September 25, 2019) (File No. 1-16169, Form 10-Q dated October 31, 2019, Exhibit 10.5).</td></tr><tr><td>10-19</td><td>Restricted stock unit award agreement (File 1-16169, Form 8-K dated August 31, 2007, Exhibit 99.1).</td></tr><tr><td>10-20</td><td>Form of Exelon Corporation 2011 Long-Term Incentive Plan, as amended effective December 18, 2014. * (File No. 1-16169, 2015 Form 10-K, Exhibit 10-34)</td></tr><tr><td>10-20-1</td><td>Form of Exelon Corporation Long-Term Incentive Program, as amended and restated as of January 1, 2020. *</td></tr><tr><td>10-20-2</td><td>Amendment Number Two to the Exelon Corporation 2011 Long-Term Incentive Plan (As Amended and Restated Effective January 21, 2014), Effective October 26, 2015. * (File No. 1-16169, 2015 Form 10-K, Exhibit 10-34-3)</td></tr></table>



<table><tr><td>Exhibit No.</td><td>Description</td></tr><tr><td>10-21</td><td>Form of Separation Agreement under Exelon Corporation Senior Management Severance Plan (As Amended and Restated Effective January 1, 2020)</td></tr><tr><td>10-22</td><td>Credit Agreement for $500,000,000 dated as of March 23, 2011 between Exelon Corporation and Various Financial Institutions (File No. 001-16169, Form 8-K dated March 23, 2011, Exhibit No. 99.1).</td></tr><tr><td>10-23</td><td>Credit Agreement for $5,300,000,000 dated as of March 23, 2011 between Exelon Generation Company, LLC and Various Financial Institutions (File No. 333-85496, Form 8-K dated March 23, 2011, Exhibit No. 99.2).</td></tr><tr><td>10-24</td><td>Credit Agreement for $600,000,000 dated as of March 23, 2011 between PECO Energy Company and Various Financial Institutions (File No. 000-16844, Form 8-K dated March 23, 2011, Exhibit No. 99.3).</td></tr><tr><td>10-25</td><td>Credit Agreement dated as of March 28, 2012 among Commonwealth Edison Company, Various Financial Institutions, as Lenders, and JP Morgan Chase Bank, N.A., as Administrative Agent (File No. 001-01839, Form 8-K dated March 28, 2012, Exhibit No. 99-1).</td></tr><tr><td>10-26</td><td>Amendment No. 3 to Credit Agreement dated as of March 23, 2011 among Exelon Corporation, as Borrower, the various financial institutions named therein, as Lenders, and JPMorgan Chase Bank, N.A., as Administrative Agent (File No. 001-16169, Form 8-K dated August 10, 2013, Exhibit No. 99-1).</td></tr><tr><td>10-27</td><td>Amendment No. 1 to Credit Agreement dated as of March 28, 2012 among Commonwealth Edison Company, as Borrower, the various financial institutions named therein, as Lenders and JPMorgan Chase Bank, N.A., as Administrative Agent (File No. 001-1839, Form 8-K dated August 10, 2013, Exhibit No. 99-2).</td></tr><tr><td>10-28</td><td>Amendment No. 1 to Credit Agreement, dated as of December 21, 2011, to the Credit Agreement dated as of March 23, 2011, among Exelon Generation Company, LLC, the lenders party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent (File No. 001-16169, Form 8-K dated March 14, 2012, Exhibit No. 4-6).</td></tr><tr><td>10-29</td><td>Constellation Energy Group, Inc. Nonqualified Deferred Compensation Plan, as amended and restated. * (Designated as Exhibit No. 10(b) to the Constellation Annual Report on Form 10-K for the year ended December 31, 2008, filed by Constellation Energy Group, Inc., File Nos. 1-12869 and 1-1910).</td></tr><tr><td>10-30</td><td>Constellation Energy Group, Inc. Deferred Compensation Plan for Non-Employee Directors, as amended and restated. * (Designated as Exhibit No. 10(c) to the Constellation Annual Report on Form 10-K for the year ended December 31, 2008, filed by Constellation Energy Group, Inc., File Nos. 1-12869 and 1-1910).</td></tr><tr><td>10-31</td><td>Constellation Energy Group, Inc. Benefits Restoration Plan, amended and restated effective June 1, 2010. * (Designated as Exhibit No. 10(b) to the Constellation Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, filed by Constellation Energy Group, Inc., File Nos. 1-12869 and 1-1910).</td></tr><tr><td>10-32</td><td>Constellation Energy Group, Inc. Supplemental Pension Plan, as amended and restated. * (Designated as Exhibit No. 10(e) to the Constellation Annual Report on Form 10-K for the year ended December 31, 2008, filed by Constellation Energy Group, Inc., File Nos. 1-12869 and 1-1910).</td></tr><tr><td>10-33</td><td>Constellation Energy Group, Inc. Senior Executive Supplemental Plan, as amended and restated. * (Designated as Exhibit No. 10(f) to the Constellation Annual Report on Form 10-K for the year ended December 31, 2008, filed by Constellation Energy Group, Inc., File Nos. 1-12869 and 1-1910).</td></tr></table>



<table><tr><td>Exhibit No.</td><td>Description</td></tr><tr><td>10-34</td><td>Constellation Energy Group, Inc. Executive Supplemental Benefits Plan, as amended and restated. * (Designated as Exhibit No. 10(a) to the Constellation Quarterly Report on Form 10-Q for the quarter ended June 30, 2008, filed by Constellation Energy Group, Inc., File Nos. 1-12869 and 1-1910).</td></tr><tr><td>10-35</td><td>Constellation Energy Group, Inc. Amended and Restated 2007 Long-Term Incentive Plan. * (Designated as Exhibit No. 10.1 to the Current Report on Form 8-K dated June 4, 2010, filed by Constellation Energy Group, Inc., File No. 1-12869).</td></tr><tr><td>10-36</td><td>Second Amended and Restated Operating Agreement, dated as of November 6, 2009, by and among Constellation Energy Nuclear Group, LLC, Constellation Nuclear, LLC, CE Nuclear, LLC, EDF Development Inc., and for certain limited purposes, E.D.F. International S.A. and Constellation Energy Group, Inc. (Designated as Exhibit No. 10.1 to the Current Report on Form 8-K dated November 12, 2009, filed by Constellation Energy Group, Inc., File No. 1-12869).</td></tr><tr><td>10-37</td><td>Amendment No. 1 to the Second Amended and Restated Operating Agreement of Constellation Energy Nuclear Group, LLC, by and among Constellation Nuclear, LLC, CE Nuclear, LLC, EDF Inc. (formerly known as EDF Development, Inc.), and E.D.F. International S.A. (Designated as Exhibit No. 10(s) to the Annual Report on Form 10-K for the year ended December 31, 2010, filed by Constellation Energy Group, Inc., File Nos. 1-12869 and 1-1910).</td></tr><tr><td>10-38</td><td>Amendment No. 2 to the Second Amended and Restated Operating Agreement of Constellation Energy Nuclear Group, LLC, by and among Constellation Nuclear, LLC, CE Nuclear, LLC, EDF Inc. (formerly known as EDF Development, Inc.), and E.D.F. International S.A. (Designated as Exhibit No. 10(t) to the Annual Report on Form 10-K for the year ended December 31, 2010, filed by Constellation Energy Group, Inc., File Nos. 1-12869 and 1-1910).</td></tr><tr><td>10-39</td><td>Amendment No. 3 to the Second Amended and Restated Operating Agreement of Constellation Energy Nuclear Group, LLC, by and among Constellation Nuclear, LLC, CE Nuclear, LLC, EDF Inc. (formerly known as EDF Development, Inc.), and E.D.F. International S.A. (Designated as Exhibit No. 10.1 to the Current Report on Form 8-K dated November 3, 2010, filed by Constellation Energy Group, Inc., File No. 1-12869).</td></tr><tr><td>10-40</td><td>Termination Agreement dated as of November 3, 2010, by and among EDF Inc. (formerly known as EDF Development, Inc.), E.D.F. International S.A., and Constellation Energy Group, Inc. (Designated as Exhibit No. 10.2 to the Current Report on Form 8-K dated November 3, 2010, filed by Constellation Energy Group, Inc., File No. 1-12869).</td></tr><tr><td>10-41</td><td>Settlement Agreement between EDF Inc., Exelon Corporation, Exelon Energy Delivery Company, LLC, Constellation Energy Group, Inc. and Baltimore Gas and Electric Company dated January 16, 2012. (Designated as Exhibit No. 10.1 to the Current Report on Form 8-K dated January 19, 2012, File Nos. 1-12869 and 1-1910).</td></tr><tr><td>10-42-1</td><td>Confirmation of Base Issuer Forward Transaction, dated June 11, 2014, between Exelon Corporation and Barclays Capital, Inc., acting as Agent for Barclays Bank PLC (File No. 001-16169, Form 8-K dated June 17, 2014, Exhibit 10.1).</td></tr><tr><td>10-42-2</td><td>Confirmation of Base Issuer Forward Transaction, dated June 11, 2014, between Exelon Corporation and Goldman Sachs &amp; Co. (File No. 001-16169, Form 8-K dated June 17, 2014, Exhibit 10.2).</td></tr><tr><td>10-42-3</td><td>Confirmation of Additional Issuer Forward Transaction, dated June 13, 2014, between Exelon Corporation and Barclays Capital, Inc., acting as Agent for Barclays Bank PLC (File No. 001-16169, Form 8-K dated June 17, 2014, Exhibit 10.3).</td></tr><tr><td>10-42-4</td><td>Confirmation of Additional Issuer Forward Transaction, dated June 13, 2014, between Exelon Corporation and Goldman Sachs &amp; Co. (File No. 001-16169, Form 8-K dated June 17, 2014, Exhibit 10.4).</td></tr><tr><td>10-43</td><td>Bondable Transition Property Sale Agreement, dated as of December 19, 2002, between ACE Funding and ACE (File No. 333-59558, Form 8-K dated December 23, 2002, Exhibit 10.1)</td></tr></table>



<table><tr><td>Exhibit No.</td><td>Description</td></tr><tr><td>10-44</td><td>Bondable Transition Property Servicing Agreement, dated as of December 19, 2002, between ACE Funding and ACE (File No. 333-59558, Form 8-K dated December 23, 2002, Exhibit 10.2)</td></tr><tr><td>10-45</td><td>Purchase Agreement, dated as of April 20, 2010, by and among Pepco Holdings, Inc., Conectiv, LLC, Conectiv Energy Holding Company, LLC and New Development Holdings, LLC (File No. 001-31403, Form 8-K dated July 8, 2010, Exhibit 2.1)</td></tr><tr><td>10-46</td><td>Purchase Agreement, dated March 9, 2015, among Potomac Electric Power Company and BNY Mellon Capital Markets, LLC, Morgan Stanley &amp; Co, LLC, and RBS Securities Inc., as representatives of the several underwriters named therein (File No. 001-01072, Form 8-K dated March 10, 2015, Exhibit 1.1)</td></tr><tr><td>10-47</td><td>Purchase Agreement, May 4, 2015, among Delmarva Power &amp; Light Company and J.P. Morgan Securities LLC, Merrill Lynch, Pierce, Fenner &amp; Smith Incorporated, and Scotia Capital (USA) Inc., as representatives of the several underwriters named therein (File No. 001-01405, Form 8-K dated May 5, 2015, Exhibit 1.1)</td></tr><tr><td>10-48</td><td>Bond Purchase Agreement, dated December 1, 2015, among Atlantic City Electric Company and the purchasers signatory thereto (File No. 001-03559, Form 8-K dated December 2, 2015, Exhibit 1.1)</td></tr><tr><td>10-49</td><td>$300,000,000 Term Loan Agreement by and among PHI, The Bank of Nova Scotia, as Administrative Agent, and the lenders party thereto, dated July 30, 2015 (File No. 001-31403, Form 8-K dated July 30, 2015, Exhibit 10)</td></tr><tr><td>10-50</td><td>First Amendment to Term Loan Agreement, dated as of October 29, 2015, by and among PHI, The Bank of Nova Scotia, as Administrative Agent, and the lenders party thereto (File No. 001-31403, Form 8-K dated October 29, 2015, Exhibit 10.2)</td></tr><tr><td>10-51</td><td>$500,000,000 Term Loan Agreement by and among PHI, The Bank of Nova Scotia, as Administrative Agent, and the lenders party thereto, dated January 13, 2016 (File No. 001-31403, Form 8-K dated January 14, 2016, Exhibit 10)</td></tr><tr><td>10-52</td><td>Second Amended and Restated Credit Agreement, dated as of August 1, 2011, by and among Pepco Holdings, Inc., Potomac Electric Power Company, Delmarva Power &amp; Light Company and Atlantic City Electric Company, the lenders party thereto, Wells Fargo Bank, National Association, as agent, issuer and swingline lender, Bank of America, N.A., as syndication agent and issuer, The Royal Bank of Scotland plc and Citicorp USA, Inc., as co-documentation agents, Wells Fargo Securities, LLC and Merrill Lynch, Pierce, Fenner and Smith Incorporated, as active joint lead arrangers and joint book runners, and Citigroup Global Markets Inc. and RBS Securities, Inc. as passive joint lead arrangers and joint book runners (File No. 001-31403, Form 10-Q dated August 3, 2011, Exhibit 10.1)</td></tr><tr><td>10-52-1</td><td>First Amendment, dated as of August 2, 2012, to Second Amended and Restated Credit Agreement, dated as of August 1, 2011, by and among Pepco Holdings, Inc., Potomac Electric Power Company, Delmarva Power &amp; Light Company and Atlantic City Electric Company, the various financial institutions party thereto, Wells Fargo Bank, National Association, as agent, issuer of letters of credit and swingline lender, Bank of America, N.A., as syndication agent and issuer of letters of credit, and The Royal Bank of Scotland plc and Citibank, N.A., as co-documentation agents (File No. 001-31403, Form 10-K dated March 1, 2013, Exhibit 10.25.1)</td></tr><tr><td>10-52-2</td><td>Amendment and Consent to Second Amended and Restated Credit Agreement, dated as of May 20, 2014, by and among Pepco Holdings, Inc., Potomac Electric Power Company, Delmarva Power &amp; Light Company and Atlantic City Electric Company, the various financial institutions from time to time party thereto, Bank of America, N.A. and Wells Fargo Bank, National Association (File No. 001-31403, Form 8-K dated May 20, 2014, Exhibit 10.1)</td></tr><tr><td>10-52-3</td><td>Third Amendment to Second Amended and Restated Credit Agreement, dated as of May 1, 2015, by and among Pepco Holdings, Inc., Potomac Electric Power Company, Delmarva Power &amp; Light Company and Atlantic City Electric Company, the various financial institutions from time to time party thereto, Bank of America, N.A. and Wells Fargo Bank, National Association (File No. 001-31403, Form 8-K dated May 1, 2015, Exhibit 10.1)</td></tr><tr><td>10-52-4</td><td>Consent, dated as of October 29, 2015, by and among Pepco Holdings, Inc., Potomac Electric Power Company, Delmarva Power &amp; Light Company and Atlantic City Electric Company, the various financial institutions from time to time party thereto, Bank of America, N.A. and Wells Fargo Bank, National Association (File No. 001-31403, Form 8-K dated October 29, 2015, Exhibit 10.1)</td></tr></table>



<table><tr><td>Exhibit No.</td><td>Description</td></tr><tr><td>10-53</td><td>Asset Purchase and Sale Agreement for Generating Plants and Related Assets, dated as of June 7, 2000, by and between Pepco and Southern Energy, Inc. (File No. 001-01072, Form 8-K dated June 13, 2000, Exhibit 10)</td></tr><tr><td>10-53-1</td><td>Amendment No. 1 to the Asset Purchase and Sale Agreement for Generating Plants and Related Assets, dated September 18, 2000, by and between Potomac Electric Power Company and Southern Energy, Inc. (File No. 001-01072, Form 8-K dated December 19, 2000, Exhibit 10.1)</td></tr><tr><td>10-53-2</td><td>Amendment No. 2 to the Asset Purchase and Sale Agreement for Generating Plants and Related Assets, dated December 19, 2000, by and between Potomac Electric Power Company and Southern Energy, Inc. (File No. 001-01072, Form 8-K dated December 19, 2000, Exhibit 10.2)</td></tr><tr><td>10-54</td><td>First Amendment to Loan Agreement, by and between Pepco Holdings LLC and The Bank of Nova Scotia, as administrative agent and lender, dated March 28, 2016 (File No. 001-31403, Form 8-K dated March 28, 2016, Exhibit 10)</td></tr><tr><td>10-55</td><td>Amendment No. 7 to Credit Agreement, dated as of March 23, 2011, among Exelon Corporation, as Borrower, the various financial institutions named therein, as Lenders, and JPMorgan Chase Bank, N.A., as Administrative Agent (File No. 001-16169, Form 8-K dated May 27, 2016, Exhibit 99.1)</td></tr><tr><td>10-56</td><td>Amendment No. 7 to Credit Agreement, dated as of March 23, 2011, among Exelon Generation Company, LLC, as Borrower, the various financial institutions named therein, as Lenders, and JPMorgan Chase Bank, N.A., as Administrative Agent (File No. 333-85496, Form 8-K dated May 27, 2016, Exhibit 99.2)</td></tr><tr><td>10-57</td><td>Amendment No. 4 to Credit Agreement, dated as of March 23, 2011, among Commonwealth Edison Company, as Borrower, the various financial institutions named therein, as Lenders, and JPMorgan Chase Bank, N.A., as Administrative Agent (File No. 333-85496, Form 8-K dated May 27, 2016, Exhibit 99.3)</td></tr><tr><td>10-58</td><td>Amendment No. 6 to Credit Agreement, dated as of March 23, 2011, among PECO Energy Company, as Borrower, the various financial institutions named therein, as Lenders, and JPMorgan Chase Bank, N.A., as Administrative Agent (File No. 000-16844, Form 8-K dated May 27, 2016, Exhibit 99.4)</td></tr><tr><td>10-59</td><td>Amendment No. 5 to Credit Agreement, dated as of March 23, 2011, among Baltimore Gas and Electric Company, as Borrower, the various financial institutions named therein, as Lenders, and JPMorgan Chase Bank, N.A., as Administrative Agent (File No. 001-01910, Form 8-K dated May 27, 2016, Exhibit 99.5)</td></tr><tr><td>10-60</td><td>Fourth Amendment to Second Amended and Restated Credit Agreement, dated as of August 1, 2011, among Pepco Holdings LLC, Potomac Electric Power Company, Delmarva Power &amp; Light Company and Atlantic City Electric Company, as Borrowers, the various financial institutions named therein, as Lenders, and Wells Fargo Bank, National Association, as Administrative Agent (File No. 001-31403, Form 8-K dated May 27, 2016, Exhibit 99.6)</td></tr><tr><td>10-61</td><td>2016 Form of Exelon Corporation Change in Control Agreement (File No. 001-16169, Form 10-Q dated October 26, 2016, Exhibit 10.1)</td></tr><tr><td>10-62</td><td>Execution Version-ZEC Standard Contract by and between the NYSERDA and Nine Mile Point Nuclear Station, LLC dated Nov. 18, 2016 (File No. 001-16169, Form 8-K dated November 18, 2016, Exhibit 10.1)</td></tr><tr><td>10-63</td><td>Execution Version-ZEC Standard Contract by and between the NYSERDA and R. E. Ginna Nuclear Power Plant, LLC dated Nov. 18, 2016 (File No. 001-16169, Form 8-K dated November 18, 2016, Exhibit 10.2)</td></tr><tr><td>10-64</td><td>Credit Agreement, dated as of November 28, 2017, as thereafter amended and conformed among ExGen Renewables IV, LLC, ExGen Renewables IV Holding, LLC, Morgan Stanley Senior Funding, Inc. as administrative agent, Wilmington Trust, National Association, as depository bank and collateral agent, and the lenders and other agents party thereto. (Certain portions of this exhibit have been omitted by redacting a portion of text, as indicated by asterisks in the text. This exhibit has been filed separately with the U.S. Securities and Exchange Commission pursuant to a request for confidential treatment.)</td></tr></table>



<table><tr><td>Exhibit No.</td><td>Description</td></tr><tr><td>10-65</td><td>Purchase Agreement, dated June 8, 2018 among Delmarva Power &amp; Light Company and the purchasers&#x27; signatory thereto (File No. 001-01405, Form 8-K dated June 21, 2018, Exhibit 1.1)</td></tr><tr><td>10-66</td><td>Purchase Agreement, dated June 8, 2018, among Potomac Electric Power Company and the purchasers&#x27; signatory thereto (File No. 001-01072, Form 8-K dated June 21, 2018, Exhibit 1.1)</td></tr><tr><td>10-67</td><td>Letter Agreement, dated May 7, 2018, between Exelon Corporation and Denis P. O&#x27;Brien (File No. 001-16169, Form 10-Q dated August 2, 2018, Exhibit 10.3)</td></tr><tr><td>10-68</td><td>Letter Agreement, dated May 7, 2018, between Exelon Corporation and Jonathan W. Thayer (File No. 001-16169, Form 10-Q dated August 2, 2018, Exhibit 10.4)</td></tr><tr><td>14</td><td>Exelon Code of Conduct, as amended March 12, 2012 (File No. 1-16169, Form 8-K dated March 14, 2012, Exhibit No. 14-1),</td></tr><tr><td></td><td>Subsidiaries</td></tr><tr><td>21-1</td><td>Exelon Corporation</td></tr><tr><td>21-2</td><td>Exelon Generation Company, LLC</td></tr><tr><td>21-3</td><td>Commonwealth Edison Company</td></tr><tr><td>21-4</td><td>PECO Energy Company</td></tr><tr><td>21-5</td><td>Baltimore Gas and Electric Company</td></tr><tr><td>21-6</td><td>Pepco Holdings LLC</td></tr><tr><td>21-7</td><td>Potomac Electric Power Company</td></tr><tr><td>21-8</td><td>Delmarva Power &amp; Light Company</td></tr><tr><td>21-9</td><td>Atlantic City Electric Company</td></tr><tr><td></td><td>Consent of Independent Registered Public Accountants</td></tr><tr><td>23-1</td><td>Exelon Corporation</td></tr><tr><td>23-2</td><td>Exelon Generation Company, LLC</td></tr><tr><td>23-3</td><td>Commonwealth Edison Company</td></tr><tr><td>23-4</td><td>PECO Energy Company</td></tr><tr><td>23-5</td><td>Baltimore Gas and Electric Company</td></tr><tr><td>23-6</td><td>Potomac Electric Power Company</td></tr><tr><td>23-7</td><td>Delmarva Power &amp; Light Company</td></tr><tr><td>23-8</td><td>Atlantic City Electric Company</td></tr><tr><td></td><td>Power of Attorney (Exelon Corporation)</td></tr><tr><td>24-1</td><td>Anthony K. Anderson</td></tr><tr><td>24-2</td><td>Ann C. Berzin</td></tr><tr><td>24-3</td><td>Laurie Brlas</td></tr><tr><td>24-4</td><td>Christopher M. Crane</td></tr><tr><td>24-5</td><td>Yves C. de Balmann</td></tr><tr><td>24-6</td><td>Nicholas DeBenedictis</td></tr></table>



Exhibit No. Description
24-7 Linda P. Jojo
24-8 Paul Joskow
24-9 Robert J. Lawless
24-10 Richard W. Mies
24-11 Reserved.
24-12 Mayo A. Shattuck III
24-13 Stephen D. Steinour
24-14 John F. Young
24-15 John Richardson
Power of Attorney (Commonwealth Edison Company)
24-16 James W. Compton
24-17 Christopher M. Crane
24-18 A. Steven Crown
24-19 Nicholas DeBenedictis
24-20 Joseph Dominguez
24-21 Peter V. Fazio, Jr.
24-22 Michael H. Moskow
24-23 Calvin G. Butler
24-24 Juan Ochoa
Power of Attorney (PECO Energy Company)
24-25 Christopher M. Crane
24-26 Reserved.
24-27 Nicholas DeBenedictis
24-28 Nelson A. Diaz
24-29 John S. Grady
24-30 Rosemarie B. Greco
24-31 Michael A. Innocenzo
24-32 Charisse R. Lillie
24-33 Calvin G. Butler
Power of Attorney (Baltimore Gas and Electric Company)
24-34 Ann C. Berzin
24-35 Carim V. Khouzami
24-36 Christopher M. Crane



<table><tr><td>Exhibit No.</td><td>Description</td></tr><tr><td>24-37</td><td>Michael E. Cryor</td></tr><tr><td>24-38</td><td>James R. Curtiss</td></tr><tr><td>24-39</td><td>Joseph Haskins, Jr.</td></tr><tr><td>24-40</td><td>Calvin G. Butler</td></tr><tr><td>24-41</td><td>Michael D. Sullivan</td></tr><tr><td>24-42</td><td>Maria Harris Tildon</td></tr><tr><td></td><td>Power of Attorney (Pepco Holdings LLC)</td></tr><tr><td>24-43</td><td>Christopher M. Crane</td></tr><tr><td>24-44</td><td>Linda W. Cropp</td></tr><tr><td>24-45</td><td>Michael E. Cryor</td></tr><tr><td>24-46</td><td>Ernest Dianastasis</td></tr><tr><td>24-47</td><td>Debra P. DiLorenzo</td></tr><tr><td>24-48</td><td>Calvin G. Butler</td></tr><tr><td>24-49</td><td>David M. Velazquez</td></tr><tr><td></td><td>Power of Attorney (Potomac Electric Power Company)</td></tr><tr><td>24-50</td><td>J. Tyler Anthony</td></tr><tr><td>24-51</td><td>Phillip S. Barnett</td></tr><tr><td>24-52</td><td>Christopher M. Crane</td></tr><tr><td>24-53</td><td>Melissa A. Lavinson</td></tr><tr><td>24-54</td><td>Kevin M. McGowan</td></tr><tr><td>24-55</td><td>Calvin G. Butler</td></tr><tr><td>24-56</td><td>David M. Velazquez</td></tr><tr><td></td><td>Power of Attorney (Delmarva Power &amp; Light Company)</td></tr><tr><td>24-57</td><td>Calvin G. Butler</td></tr><tr><td>24-58</td><td>David M. Velazquez</td></tr><tr><td></td><td>Power of Attorney (Atlantic City Electric Company)</td></tr><tr><td>24-59</td><td>David M. Velazquez</td></tr></table>

Certifications Pursuant to Rule 13a-14(a) and 15d-14(a) of the Securities and Exchange Act of 1934 as to the Annual Report on Form 10-K for the year ended December 31, 2018 filed by the following officers for the following registrants:

Exhibit No. Description

31-1 Filed by Christopher M. Crane for Exelon Corporation

31-2 Filed by Joseph Nigro for Exelon Corporation

31-3 Filed by Kenneth W. Cornew for Exelon Generation Company, LLC

31-4 Filed by Bryan P. Wright for Exelon Generation Company, LLC



<table><tr><td>Exhibit No.</td><td>Description</td></tr><tr><td>31-5</td><td>Filed by Joseph Dominguez for Commonwealth Edison Company</td></tr><tr><td>31-6</td><td>Filed by Jeanne M. Jones for Commonwealth Edison Company</td></tr><tr><td>31-7</td><td>Filed by Michael A. Innocenzo for PECO Energy Company</td></tr><tr><td>31-8</td><td>Filed by Robert J. Stefani for PECO Energy Company</td></tr><tr><td>31-9</td><td>Filed by Carim V. Khouzami for Baltimore Gas and Electric Company</td></tr><tr><td>31-10</td><td>Filed by David M. Vahos for Baltimore Gas and Electric Company</td></tr><tr><td>31-11</td><td>Filed by David M. Velazquez for Pepco Holdings LLC</td></tr><tr><td>31-12</td><td>Filed by Phillip S. Barnett for Pepco Holdings LLC</td></tr><tr><td>31-13</td><td>Filed by David M. Velazquez for Potomac Electric Power Company</td></tr><tr><td>31-14</td><td>Filed by Phillip S. Barnett for Potomac Electric Power Company</td></tr><tr><td>31-15</td><td>Filed by David M. Velazquez for Delmarva Power &amp; Light Company</td></tr><tr><td>31-16</td><td>Filed by Phillip S. Barnett for Delmarva Power &amp; Light Company</td></tr><tr><td>31-17</td><td>Filed by David M. Velazquez for Atlantic City Electric Company</td></tr><tr><td>31-18</td><td>Filed by Phillip S. Barnett for Atlantic City Electric Company</td></tr></table>

Certifications Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code as to the Annual Report on Form 10-K for the year ended December 31, 2018 filed by the following officers for the following registrants:

<table><tr><td>32-1</td><td>Filed by Christopher M. Crane for Exelon Corporation</td></tr><tr><td>32-2</td><td>Filed by Joseph Nigro for Exelon Corporation</td></tr><tr><td>32-3</td><td>Filed by Kenneth W. Cornew for Exelon Generation Company, LLC</td></tr><tr><td>32-4</td><td>Filed by Bryan P. Wright for Exelon Generation Company, LLC</td></tr><tr><td>32-5</td><td>Filed by Joseph Dominguez for Commonwealth Edison Company</td></tr><tr><td>32-6</td><td>Filed by Jeanne M. Jones for Commonwealth Edison Company</td></tr><tr><td>32-7</td><td>Filed by Michael A. Innocenzo for PECO Energy Company</td></tr><tr><td>32-8</td><td>Filed by Robert J. Stefani for PECO Energy Company</td></tr><tr><td>32-9</td><td>Filed by Carim V. Khouzami for Baltimore Gas and Electric Company</td></tr><tr><td>32-10</td><td>Filed by David M. Vahos for Baltimore Gas and Electric Company</td></tr><tr><td>32-11</td><td>Filed by David M. Velazquez for Pepco Holdings LLC</td></tr><tr><td>32-12</td><td>Filed by Phillip S. Barnett for Pepco Holdings LLC</td></tr><tr><td>32-13</td><td>Filed by David M. Velazquez for Potomac Electric Power Company</td></tr><tr><td>32-14</td><td>Filed by Phillip S. Barnett for Potomac Electric Power Company</td></tr><tr><td>32-15</td><td>Filed by David M. Velazquez for Delmarva Power &amp; Light Company</td></tr><tr><td>32-16</td><td>Filed by Phillip S. Barnett for Delmarva Power &amp; Light Company</td></tr><tr><td>32-17</td><td>Filed by David M. Velazquez for Atlantic City Electric Company</td></tr><tr><td>32-18</td><td>Filed by Phillip S. Barnett for Atlantic City Electric Company</td></tr></table>



## Table of Contents

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 Labels 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)

 \( ^{*} \)  Compensatory plan or arrangements in which directors or officers of the applicable registrant participate and which are not available to all employees.
(a) These filings are not available electronically on the SEC website as they were filed in paper previous to the electronic system that is currently in place.



## ITEM 16. FORM 10-K SUMMARY

## All Registrants

Registrants may voluntarily include a summary of information required by Form 10-K under this Item 16. The Registrants have elected not to include such summary information.



## SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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, in the City of Chicago and State of Illinois on the 11th day of February, 2020.

EXELON CORPORATION

By: /s/ CHRISTOPHER M. CRANE

Name: Christopher M. Crane

Title: President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on the 11th day of February, 2020.

<table><tr><td>Signature</td><td>Title</td></tr><tr><td>/s/ CHRISTOPHER M. CRANE</td><td>President, Chief Executive Officer (Principal Executive Officer) and Director</td></tr><tr><td>Christopher M. Crane</td><td></td></tr><tr><td>/s/ JOSEPH NIGRO</td><td>Senior Executive Vice President and Chief Financial Officer (Principal Financial Officer)</td></tr><tr><td>Joseph Nigro</td><td></td></tr><tr><td>/s/ FABIAN E. SOUZA</td><td>Senior Vice President and Corporate Controller (Principal Accounting Officer)</td></tr><tr><td>Fabian E. Souza</td><td></td></tr></table>

This annual report has also been signed below by Thomas S. O'Neill, Attorney-in-Fact, on behalf of the following Directors on the date indicated:

Anthony K. Anderson

Ann C. Berzin

Robert J. Lawless

Richard W. Mies

Laurie Brlas

John M. Richardson

Yves C. de Balmann

Mayo A. Shattuck III

Nicholas DeBenedictis

Stephen D. Steinour

Linda P. Jojo

John F. Young

Paul L. Joskow

By: /s/ THOMAS S. O'NEILL

Name: Thomas S. O'Neill

February 11, 2020



## SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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, in the City of Chicago and State of Illinois on the 11th day of February, 2020.

EXELON GENERATION COMPANY, LLC

By: /s/ KENNETH W. CORNEW

Name: Kenneth W. Cornew

Title: President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on the 11th day of February, 2020.

<table><tr><td>Signature</td><td>Title</td></tr><tr><td>/s/ KENNETH W. CORNEW</td><td>President and Chief Executive Officer (Principal Executive Officer)</td></tr><tr><td>Kenneth W. Cornew</td><td></td></tr><tr><td>/s/ BRYAN P. WRIGHT</td><td>Senior Vice President and Chief Financial Officer (Principal Financial Officer)</td></tr><tr><td>Bryan P. Wright</td><td></td></tr><tr><td>/s/ MATTHEW N. BAUER</td><td>Vice President and Controller (Principal Accounting Officer)</td></tr><tr><td>Matthew N. Bauer</td><td></td></tr></table>



## SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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, in the City of Chicago and State of Illinois on the 11th day of February, 2020.

COMMONWEALTH EDISON COMPANY

By: /s/ JOSEPH DOMINGUEZ

Name: Joseph Dominguez

Title: Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on the 11th day of February, 2020.

<table><tr><td>Signature</td><td>Title</td></tr><tr><td>/s/ JOSEPH DOMINGUEZ</td><td>Chief Executive Officer (Principal Executive Officer) and Director</td></tr><tr><td>Joseph Dominguez</td><td></td></tr><tr><td>/s/ JEANNE M. JONES</td><td>Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)</td></tr><tr><td>Jeanne M. Jones</td><td></td></tr><tr><td>/s/ GERALD J. KOZEL</td><td>Vice President and Controller (Principal Accounting Officer)</td></tr><tr><td>Gerald J. Kozel</td><td></td></tr></table>

This annual report has also been signed below by Joseph Dominguez, Attorney-in-Fact, on behalf of the following Directors on the date indicated:

Calvin G. Butler

James W. Compton

Christopher M. Crane

A. Steven Crown

By: /s/ JOSEPH DOMINGUEZ

Name: Joseph Dominguez

February 11, 2020



## SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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, in the City of Chicago and State of Illinois on the 11th day of February, 2020.

PECO ENERGY COMPANY

By: /s/ MICHAEL A. INNOCENZO

Name: Michael A. Innocenzo

Title: President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on the 11th day of February, 2020.

<table><tr><td>Signature</td><td>Title</td></tr><tr><td>/s/ MICHAEL A. INNOCENZO</td><td>President, Chief Executive Officer (Principal Executive Officer) and Director</td></tr><tr><td>Michael A. Innocenzo</td><td></td></tr><tr><td>/s/ ROBERT J. STEFANI</td><td>Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)</td></tr><tr><td>Robert J. Stefani</td><td></td></tr><tr><td>/s/ SCOTT A. BAILEY</td><td>Vice President and Controller (Principal Accounting Officer)</td></tr><tr><td>Scott A. Bailey</td><td></td></tr></table>

This annual report has also been signed below by Michael A. Innocenzo, Attorney-in-Fact, on behalf of the following Directors on the date indicated:

Calvin G. Butler

Christopher M. Crane

Nicholas DeBenedictis

Nelson A. Diaz

By: /s/ MICHAEL A. INNOCENZO

Name: Michael A. Innocenzo

John S. Grady

Rosemarie B. Greco

Charisse R. Lillie

February 11, 2020



## SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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, in the City of Chicago and State of Illinois on the 11th day of February, 2020.

BALTIMORE GAS AND ELECTRIC COMPANY

By: /s/ CARIM V. KHOUZAMI

Name: Carim V. Khouzami

Title: Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on the 11th day of February, 2020.

<table><tr><td>Signature</td><td>Title</td></tr><tr><td>/s/ CARIM V. KHOUZAMI</td><td>Chief Executive Officer (Principal Executive Officer) and Director</td></tr><tr><td>Carim V. Khouzami</td><td></td></tr><tr><td>/s/ DAVID M. VAHOS</td><td>Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)</td></tr><tr><td>David M. Vahos</td><td></td></tr><tr><td>/s/ ANDREW W. HOLMES</td><td>Vice President and Controller (Principal Accounting Officer)</td></tr><tr><td>Andrew W. Holmes</td><td></td></tr></table>

This annual report has also been signed below by Carim V. Khouzami, Attorney-in-Fact, on behalf of the following Directors on the date indicated:

Ann C. Berzin

Calvin G. Butler

Christopher M. Crane

Michael E. Cryor

By:

Name:

Carim V. Khouzami

James R. Curtiss

Joseph Haskins, Jr.

Michael D. Sullivan

Maria Harris Tildon

February 11, 2020



## SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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, in the City of Chicago and State of Illinois on the 11th day of February, 2020.

PEPCO HOLDINGS LLC

By: /s/ DAVID M. VELAZQUEZ

Name: David M. Velazquez

Title: President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on the 11th day of February, 2020.

<table><tr><td>Signature</td><td>Title</td></tr><tr><td>/s/ DAVID M. VELAZQUEZ</td><td>President, Chief Executive Officer (Principal Executive Officer), and Director</td></tr><tr><td>David M. Velazquez</td><td></td></tr><tr><td>/s/ PHILLIP S. BARNETT</td><td>Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)</td></tr><tr><td>Phillip S. Barnett</td><td></td></tr><tr><td>/s/ ROBERT M. AIKEN</td><td>Vice President and Controller (Principal Accounting Officer)</td></tr><tr><td>Robert M. Aiken</td><td></td></tr></table>

This annual report has also been signed below by David M. Velazquez, Attorney-in-Fact, on behalf of the following Directors on the date indicated:

Calvin. G. Butler

Christopher M. Crane

Linda W. Cropp

By:

Name:

David M. Velazquez

Michael E. Cryor

Ernest Dianastasis

Debra P. DiLorenzo

February 11, 2020



## SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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, in the City of Chicago and State of Illinois on the 11th day of February, 2020.

POTOMAC ELECTRIC POWER COMPANY

By: /s/ DAVID M. VELAZQUEZ

Name: David M. Velazquez

Title: President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on the 11th day of February, 2020.

<table><tr><td>Signature</td><td>Title</td></tr><tr><td>/s/ DAVID M. VELAZQUEZ</td><td>President, Chief Executive Officer (Principal Executive Officer), and Director</td></tr><tr><td>David M. Velazquez</td><td></td></tr><tr><td>/s/ PHILLIP S. BARNETT</td><td>Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)</td></tr><tr><td>Philip S. Barnett</td><td></td></tr><tr><td>/s/ ROBERT M. AIKEN</td><td>Vice President and Controller (Principal Accounting Officer)</td></tr><tr><td>Robert M. Aiken</td><td></td></tr></table>

This annual report has also been signed below by David M. Velazquez, Attorney-in-Fact, on behalf of the following Directors on the date indicated:

J. Tyler Anthony

Phillip S. Barnett

Calvin G. Butler

By: /s/ DAVID M. VELAZQUEZ

Name: David M. Velazquez

Christopher M. Crane

Melissa A. Lavinson

Kevin M. McGowan

February 11, 2020



## SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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, in the City of Chicago and State of Illinois on the 11th day of February, 2020.

DELMARVA POWER & LIGHT COMPANY

By: /s/ DAVID M. VELAZQUEZ

Name: David M. Velazquez

Title: President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on the 11th day of February, 2020.

<table><tr><td>Signature</td><td>Title</td></tr><tr><td>/s/ DAVID M. VELAZQUEZ</td><td>President, Chief Executive Officer (Principal Executive Officer), and Director</td></tr><tr><td>David M. Velazquez</td><td></td></tr><tr><td>/s/ PHILLIP S. BARNETT</td><td>Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)</td></tr><tr><td>Philip S. Barnett</td><td></td></tr><tr><td>/s/ ROBERT M. AIKEN</td><td>Vice President and Controller (Principal Accounting Officer)</td></tr><tr><td>Robert M. Aiken</td><td></td></tr><tr><td colspan="2">This annual report has also been signed below by David M. Velazquez, Attorney-in-Fact, on behalf of the following Directors on the date indicated:</td></tr><tr><td colspan="2">Calvin G. Butler</td></tr><tr><td>By:</td><td>/s/ DAVID M. VELAZQUEZ</td></tr><tr><td>Name:</td><td>David M. Velazquez</td></tr></table>



## SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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, in the City of Chicago and State of Illinois on the 11th day of February, 2020.

ATLANTIC CITY ELECTRIC COMPANY

By: /s/ DAVID M. VELAZQUEZ

Name: David M. Velazquez

Title: President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on the 11th day of February, 2020.

<table><tr><td>Signature</td><td>Title</td></tr><tr><td>/s/ DAVID M. VELAZQUEZ</td><td>President, Chief Executive Officer (Principal Executive Officer), and Director</td></tr><tr><td>David M. Velazquez</td><td></td></tr><tr><td>/s/ PHILLIP S. BARNETT</td><td>Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)</td></tr><tr><td>Philip S. Barnett</td><td></td></tr><tr><td>/s/ ROBERT M. AIKEN</td><td>Vice President and Controller (Principal Accounting Officer)</td></tr><tr><td>Robert M. Aiken</td><td></td></tr></table>



# EXELON CORPORATION
DESCRIPTION OF SECURITIES

As of December 31, 2019, the common stock of Exelon Corporation (“Exelon” or the “Company”) is registered under Section 12(b) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”).

The summary of the general terms and provisions of the Company’s common stock set forth below does not purport to be complete and is subject to and qualified by reference to the Company’s Articles of Incorporation (as amended, the “Articles”) and Bylaws (as amended, the “Bylaws,” and together with the Articles, the “Charter Documents”), each of which is incorporated by reference as an exhibit to the Company’s Annual Report on Form 10-K filed with the Securities and Exchange Commission of which this Exhibit is a part. For additional information, please read the Company’s Charter Documents and the applicable provisions of the Pennsylvania Business Corporation Law of 1988 (as amended from time to time, the “PBCL”).

## Description of Capital Stock

Authorized Capital Stock. The Company is authorized under the Articles to issue 2,100,000,000 shares, divided into 2,000,000,000 shares of common stock, without par value, and 100,000,000 shares of preferred stock, without par value. As of December 31, 2019, the Company had 976,152,022 shares of common stock outstanding, and zero shares of preferred stock outstanding. The outstanding shares of the Company’s common stock are fully paid and nonassessable.

Voting Rights. Except as otherwise provided in the Charter Documents or by law, the holders of common stock have the exclusive voting power, and every holder of common stock is entitled to one vote for every share of common stock standing in the name of the shareholder on the Company's books. Except as otherwise provided in the PBCL or the Charter Documents, whenever any corporate action is to be taken by vote of the shareholders of the Company, it shall be authorized by a majority of the votes cast at a duly organized meeting of shareholders by the holders of shares entitled to vote thereon. The shareholders of the Company may act only at a duly organized meeting. The Board of Directors of the Company shall have the full authority permitted by law to determine the voting rights, if any, and designations, preferences, limitations, and special rights of any class or any series of any class of preferred stock that may be desired to the extent not determined by the Charter Documents.

Dividend Rights. Holders of common stock are entitled to receive ratably those dividends, if any, as may be declared from time to time by the Board of Directors, in its discretion, out of funds legally available therefor, subject to any preferential dividend rights of outstanding preferred stock.

Liquidation Rights. In the event of a liquidation, dissolution or winding up of the Company, the holders of the Company’s common stock are entitled to share ratably in all assets remaining



after the payment of all of the Company’s liabilities and subject to the liquidation preferences of any outstanding preferred stock.

Other Rights and Preferences. The Company’s common stock does not carry preemptive rights, is not redeemable, does not have any conversion rights, is not subject to further calls and is not subject to any sinking fund provisions. The rights and preferences of holders of the Company’s common stock are subject to the rights of any series of preferred stock that the Company may issue.

Listing. The Company’s common stock is listed on The Nasdaq Stock Market LLC under the trading symbol “EXC”.

## Certain Anti-Takeover Provisions

Potential Issuances of the Company’s Preferred Stock. Although the Company does not currently have any shares of preferred stock outstanding, it is authorized under the Articles to issue 100,000,000 shares of preferred stock, and the rights, preferences and privileges of holders of common stock are subject to, and may be adversely affected by, the rights of the holders of any series of preferred stock that the Company may designate and issue in the future. The Articles also authorize the Company’s Board of Directors to establish, from the authorized but unissued shares, one or more series of the shares of preferred stock and to determine, with respect to any such series of the Company’s preferred shares, the terms and rights of such series, including, for example, the designation, the number of shares, the dividend rate of the shares, the right, if any, of the Company to redeem shares, the voting power, if any, the obligation, if any, of the Company to retire shares, the terms and conditions, if any, upon which shares shall be convertible into or exchangeable for shares of stock of any other class or classes, and any other rights, preferences or limitations of the shares of such series.

The authorized shares of the Company, including shares of preferred stock and common stock, will be available for issuance without further action by the Company’s shareholders, unless such action is required by applicable law or the rules of any stock exchange or automated quotation system on which the Company’s securities may be listed or traded.

Provisions for Shareholder Nominations and Shareholder Proposals at Annual Meetings. The Company’s Bylaws establish an advance notice procedure for shareholders to nominate candidates for election as directors or to bring other business before annual meetings of the Company’s shareholders (the “Shareholder Notice Procedure”). The Shareholder Notice Procedure requires that written notice of nominations or proposals for substantive business must be received by the Company not less than 120 days nor more than 150 days prior to the first anniversary of the date on which the Company first mailed its proxy materials to shareholders for the prior year’s annual meeting of shareholders; provided, that nothing in the Bylaws affects any rights of shareholders to request inclusion of proposals in the Company’s proxy statement pursuant to Rule 14a-8 under the Exchange Act.



A shareholder who wishes to recommend a candidate (including a self-nomination) to be considered by the Corporate Governance Committee of the Board for nomination as a Director must submit the recommendation in writing to the Chair of the Corporate Governance Committee as set forth in the Bylaws. The Corporate Governance Committee will consider all recommended candidates and self-nominees when making its recommendation to the full Board of Directors to nominate a slate of Directors for election. A shareholder may also use one of two alternative provisions of the Bylaws to nominate a candidate for election as a Director. Under one provision of the Bylaws currently in effect, a shareholder must comply with the Shareholder Notice Procedure and the notice must include information set forth in the Bylaws. Under this procedure, any shareholder can nominate any number of candidates for Director for election at the annual meeting, but the shareholder's nominees will not be included in Exelon's proxy statement or form of proxy for the meeting.

In addition, A shareholder who meets criteria in the Exelon bylaws may also nominate a limited number of candidates for election as Directors through provisions commonly referred to as “proxy access.” Subject to the requirements set forth in the Bylaws, any shareholder or group of up to 20 shareholders holding both investment and voting rights with respect to at least 3% of Exelon’s outstanding common stock continuously for at least 3 years may nominate up to 20% of the Exelon Directors to be elected. The nominating shareholder(s) must comply with the Shareholder Notice Procedure and the notice must include information required under the Bylaws. Under this procedure, the shareholder’s nominees will be included in the Exelon proxy statement and the form of proxy for the meeting.

Provisions Relating to the Election of the Company’s Board of Directors. Under the Articles Articles, shareholders are entitled to only one vote for each share held in all elections for directors. Directors are elected by a plurality of votes cast. In addition, each director must meet the suitability requirements set forth in the Bylaws.

Removal of Company Directors. Under the Bylaws, the entire Board of Directors or any individual Director may be removed from office by vote of the shareholders entitled to vote thereon only for cause. In case the Board or any one or more Directors are so removed, new Directors may be elected at the same meeting.

Director Vacancies. Under the Bylaws, vacancies in the Board of Directors, including vacancies resulting from an increase in the number of Directors, may be filled by a majority vote of the remaining members of the Board though less than a quorum, or by a sole remaining director, and each person so selected shall be a Director to serve until the next annual meeting of shareholders, and until a successor has been selected and qualified or until his or her earlier death, resignation or removal.

Amendment to Articles. Any amendment to the articles requires the affirmative vote of a majority of the votes cast by all shareholders entitled to vote thereon and, if any class or series of shares is entitled to vote thereon as a class, the affirmative vote of a majority of the votes cast in each such class vote, except for amendments on matters specified in Section 1914(c) of the PBCL that do not require shareholder approval.



Amendment to Bylaws. Except as otherwise provided for in the express terms of any series of the shares of the Company, any one or more provisions of the Bylaws may be altered or repealed by the Board of Directors. The shareholders or the Board of Directors may adopt new, except that the Board of Directors may not adopt, alter or repeal bylaws that the PBCL specifies may be adopted only by shareholders, and the Board of Directors may not alter or repeal any bylaw adopted by the shareholders that presumes that such bylaw shall not be altered or repealed by the Board of Directors.

Special Meeting of Company Shareholders. The Charter Documents do not contain a provision permitting shareholders to call a special meeting.

Shareholder Action by Written Consent. The Charter Documents do not contain a provision permitting action by written consent of the shareholders.

Pennsylvania Anti-Takeover Statutes. Under Section 1715 of the PBCL, directors stand in a fiduciary relation to their corporation and, as such, are required to perform their duties in good faith, in a manner they reasonably believe to be in the best interests of the corporation and with such care, including reasonable inquiry, skill and diligence, as a person of ordinary prudence would use under similar circumstances. In discharging their duties, directors may, in considering the best interests of their corporation, consider various constituencies, including, shareholders, employees, suppliers, customers and creditors of the corporation, and upon communities in which offices or other establishments of the corporation are located. Absent a breach of fiduciary duty, a lack of good faith or self-dealing, any act of the Board of Directors, a committee thereof or an individual director is presumed to be in the best interests of the corporation. The PBCL expressly provides that the fiduciary duty of directors does not require them to (i) redeem or otherwise render inapplicable outstanding rights issued under any shareholder rights plan; (ii) render inapplicable the anti-takeover statutes set forth in Chapter 25 of the PBCL (described below); or (iii) take any action solely because of the effect it may have on a proposed acquisition or the consideration to be received by shareholders in such a transaction.

Chapter 25 of the PBCL contains several anti-takeover statutes applicable to publicly-traded corporations. Corporations may opt-out of such anti-takeover statutes under certain circumstances. The Company has not opted-out of any of such statutes.

Section 2538 of Subchapter 25D of the PBCL requires certain transactions with an “interested shareholder” to be approved by a majority of disinterested shareholders. “Interested shareholder” is defined broadly to include any shareholder who is a party to the transaction or who is treated differently than other shareholders and affiliates of the corporation.

Subchapter 25E of the PBCL requires a person or group of persons acting in concert which acquires 20% or more of the voting shares of the corporation to offer to purchase the shares of any other shareholder at “fair value.” “Fair value” means the value not less than the highest price paid by the controlling person or group during the 90-day period prior to the control transaction, plus a control premium. Among other exceptions, Subchapter 25E does not apply to shares acquired directly from the corporation in a transaction exempt from the registration requirements of the Securities Act of 1933, as amended, or to a one-step merger.



Subchapter 25F of the PBCL generally establishes a 5-year moratorium on a “business combination” with an “interested shareholder.” “Interested shareholder” is defined generally to be any beneficial owner of 20% or more of the corporation's voting stock. “Business combination” is defined broadly to include mergers, consolidations, asset sales and certain self-dealing transactions. Certain restrictions apply to business combination following the 5-year period. Among other exceptions, Subchapter 25F will be rendered inapplicable if the board of directors approves the proposed business combination or approves the interested shareholder's acquisition of 20% of the voting shares, in either case prior to the date on which the shareholder first becomes an interested shareholder.

Subchapter 25G of the PBCL provides that “control shares” lose voting rights unless such rights are restored by the affirmative vote of a majority of (i) the disinterested shares (generally, shares held by persons other than the acquirer, executive officers of the corporation and certain employee stock plans) and (ii) the outstanding voting shares of the corporation. “Control shares” are defined as shares which, upon acquisition, will result in a person or group acquiring for the first time voting control over (a) 20%, (b) 331/3% or (c) 50% or more of the outstanding shares, together with shares acquired within 180 days of attaining the applicable threshold and shares purchased with the intention of attaining such threshold. A corporation may redeem control shares if the acquiring person does not request restoration of voting rights as permitted by Subchapter 25G. Among other exceptions, Subchapter 25G does not apply to a merger, consolidation or a share exchange if the corporation is a party to the transaction agreement.

Subchapter 25H of the PBCL provides in certain circumstances for the recovery by the corporation of profits realized from the sale of its stock by a controlling person or group if the sale occurs within 18 months after the controlling person or group became a controlling person or group, and the stock was acquired during such 18-month period or within 24 months before such period. A controlling person or group is a person or group that has acquired, offered to acquire, or publicly disclosed an intention to acquire 20% or more of the voting shares of the corporation. Among other exceptions, Subchapter 25H does not apply to transactions approved by both the board of directors and the shareholders prior to the acquisition or distribution, as appropriate.

Subchapter 25I of the PBCL mandates severance compensation for eligible employees who are terminated within 24 months after the approval of a control share acquisition. Eligible employees generally are all employees employed in Pennsylvania for at least two years prior to the control share approval. Severance equals the weekly compensation of the employee multiplied by the employee's years of service (up to 26 years), less payments made due to the termination.

Subchapter 25J of the PBCL requires the continuation of certain labor contracts relating to business operations owned at the time of a control share approval.



# PECO ENERGY COMPANY
DESCRIPTION OF SECURITIES

As of December 31, 2019, PECO Energy Capital Trust III (the Trust), a statutory business trust and indirect, wholly owned subsidiary of PECO Energy Company (PECO), had 78,105 Capital Trust Pass-Through Securities (the Capital Securities) registered under Section 12(b) of the Securities Exchange Act of 1934, as amended (the Exchange Act). The Capital Securities each represent a 7.38% Cumulative Preferred Security, Series D (a Series D Preferred Security) of PECO Energy Capital, L.P., a limited partnership formed under the laws of the State of Delaware (PECO Energy Capital). Each share of the Series D Preferred Securities has a stated liquidation preference of $1,000.

The Trust used the proceeds from the sale of its Capital Securities to purchase the Series D Preferred Securities, which will be the sole assets of the Trust. PECO Energy Capital lent the proceeds from the sale of its Series D Preferred Securities, plus the capital contribution made by PECO Energy Capital Corp., a Delaware corporation and the sole general partner of PECO Energy Capital, to PECO, which loan was evidenced by PECO's 7.38% Subordinated Deferrable Interest Debentures, Series D, due 2028 (the Series D Subordinated Debt Securities).

Holders of the Capital Securities are entitled to receive distributions at the rate of 7.38% of the liquidation amount of $1,000 per Capital Security accumulating from the date of original issuance and payable (subject to any extension period) semiannually in arrears on April 30 and October 31, of each year, commencing April 30, 1998. Whenever the Trust receives any cash distribution representing a semiannual distribution on the Series D Preferred Securities (whether or not distributed by PECO Energy Capital on the regular semiannual distribution date therefor) or payment under the Payment and Guarantee Agreement (the Series D Guarantee) issued by PECO for the benefit of the holders of the Series D Preferred Securities, the Trust will distribute such amounts to the holders of the Capital Securities in proportion to their respective number of Series D Preferred Securities represented by such Capital Securities.

Through the Series D Guarantee, the Amended and Restated Trust Agreement relating to the Trust, the Indenture dated as of July 1, 1994 between PECO and First Union National Bank, as successor trustee, and the Series D Subordinated Debt Securities, taken together, PECO fully, irrevocably and unconditionally guarantees all of PECO Energy Capital's obligations under the Series D Preferred Securities. Under the Series D Guarantee, PECO will guarantee payment of accumulated and unpaid semiannual distributions, amounts payable upon redemption and amounts payable upon liquidation with respect to the Series D Preferred Securities, in each case, only to the extent that PECO Energy Capital has funds on hand legally available therefor and payment does not violate applicable law. The obligations of PECO under the Series D Guarantee are subordinate and junior in right of payment to all general liabilities of PECO and its obligations under the Series D Subordinated Debt Securities will be subordinate and junior in right of payment to all senior indebtedness of PECO.



# COMMONWEALTH EDISON COMPANY
DESCRIPTION OF SECURITIES

As of December 31, 2019, Commonwealth Edison Company (“ComEd” or the “Company”) had two classes of common stock purchase warrants registered under Section 12(g) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”); the Company’s common stock, into which both classes of warrants are exercisable, is not registered under Section 12 of the Exchange Act.

## 1971 Warrants

On April 13, 1971, the ComEd Board of Directors created a series of common stock purchase warrants (the 1971 Warrants), pursuant to which holders can convert the 1971 Warrants into the Company’s common stock at a rate of one (1) share of common stock for every three (3) warrants; prior to April 30, 1981, the 1971 Warrants were exercisable into shares of the Company’s common stock at a rate of one (1) share of common stock for every three (3) warrants at an exercise price of $30 per warrant. The 1971 Warrants do not have an expiration date.

The 1971 Warrants have no established trading market and there is no assurance concerning the liquidity of any market that may develop for the 1971 Warrants. Consequently, holders of the 1971 Warrants may not be able to liquidate their investment readily, and lenders may not readily accept the 1971 Warrants as collateral for loans.

As of December 31, 2019, there were 40,588 1971 Warrants outstanding.

## Series B Warrants

On February 1, 1972, the ComEd Board of Directors created a series of common stock purchase warrants (the Series B Warrants), pursuant to which holders can convert the Series B Warrants into the Company’s common stock at a rate of one (1) share of common stock for every three (3) warrants; prior to April 30, 1981, the Series B Warrants were exercisable into shares of the Company’s common stock at a rate of one (1) share of common stock for every three (3) warrants at an exercise price of $30 per warrant. The Series B Warrants do not have an expiration date.

The Series B Warrants have no established trading market and there is no assurance concerning the liquidity of any market that may develop for the Series B Warrants. Consequently, holders of the Series B Warrants may not be able to liquidate their investment readily, and lenders may not readily accept the Series B Warrants as collateral for loans.

As of December 31, 2019, there were 19,670 Series B Warrants outstanding.



# EXELON CORPORATION
SENIOR MANAGEMENT SEVERANCE PLAN
(As Amended and Restated)

## 1. PURPOSE OF THE PLAN

The Exelon Corporation Senior Management Severance Plan, as amended and restated herein (the “Plan”), is effective as of January 1, 2020 (the “Effective Date”) except as otherwise specifically provided herein, and supersedes in its entirety all prior versions of the Plan with respect to any Termination of Employment occurring on or after the Effective Date. The Plan is intended to encourage the attraction and retention of executives of Exelon Corporation (“Exelon”) and its participating subsidiaries.

## 2. ELIGIBILITY

Each employee of the Company selected by the Plan Administrator whose position is in Salary Band E09 or above (an “Executive”) shall be eligible to participate in the Plan in the event of his or her Termination of Employment, other than an Executive whose Termination of Employment is governed by the terms and conditions of another separation or change in control plan or agreement between such Executive and the Company or an affiliate thereof.

## 3. PARTICIPATION

Each eligible Executive shall become a participant in the Plan (a “Participant”) as of his or her Termination Date, subject to his or her timely execution of, and compliance with the terms and conditions of (a) a separation agreement with the Company (“Separation Agreement”), (b) a waiver and release of claims which has become irrevocable (“Waiver and Release”) and (c) non-solicitation, confidential information, and intellectual property covenants and, in the discretion of the Plan Administrator, non-competition covenants (collectively, “Restrictive Covenants”), each of the foregoing documents in such form as the Plan Administrator, in its sole discretion, may require.

## 4. BENEFITS

In addition to payment of all Accrued Obligations, a Participant shall be entitled to the following benefits upon his or her Termination of Employment:

4.1. Severance Pay. Continued payment of (a) his or her Base Salary, and (b) if the Participant is a participant in the Annual Incentive Award Plan for the year in which the Termination Date occurs, his or her Target Incentive, each payable during the Severance Period in substantially equal regular payroll installments commencing within 45 days after his or her Termination Date.

4.2. Annual Incentive Awards. Each Participant who is a participant in the Annual Incentive Award Plan for the year in which the Termination Date occurs shall remain eligible to receive a pro-rated Annual Incentive based on the number of days elapsed during such year as of the Termination Date, payable at the time such awards are paid to active



employees for such year (but not later than March 15 of the year following the Termination Date). A Participant who is not a participant in the Annual Incentive Award Plan for the year in which the Termination Date occurs shall not be entitled to an Annual Incentive for such year, and the amount (if any) payable under any other annual incentive plan in which the Participate participates for such year shall be determined by the Plan Administrator in its sole discretion.

4.3. Long-Term Incentive Awards. Each of the Participant’s outstanding awards (if any) under the LTIP, including stock options, restricted stock, restricted stock units, restricted cash, performance shares, performance units and similar stock or cash incentive awards, shall become vested and payable to a Participant solely to the extent (and at the time) provided under the terms of the LTIP, applicable program and/or award agreement under which such awards are granted.

## 4.4. Health Care Coverage.

(a) COBRA Coverage. During the Severance Period, a Participant (and his or her eligible dependents) who so elects shall be eligible to participate in the health care plans under which he or she was covered immediately prior to the Termination Date, in accordance with and subject to the terms and conditions of such plans as in effect from time to time. The Participant’s out of pocket costs (including premiums, deductibles and co-payments) for such coverage shall be the same as those in effect from time to time for active peer employees during such period. Such coverage shall be provided during the Severance Period in satisfaction of continuation coverage under Section 4980B of the Code and Section 601 to 609 of ERISA (“COBRA”) for such period. At the end of the Severance Period, COBRA continuation coverage at the Participant’s expense may be continued for any remaining balance of the statutory COBRA coverage period.

(b) Retiree Coverage. A Participant who, as of the last day of the Severance Period, has attained at least age 50 and completed at least 10 years of service (or who has completed such other age and service requirement then in effect under the Exelon Corporation Severance Benefit Plan or any successor plan as of the relevant time set forth in such plan) shall be entitled to elect to participate in such Company group health care programs that are then available to similarly situated retirees of his or her legacy Company. The eligibility for coverage and availability of programs or plans, the amounts charged for coverage, and the other terms, conditions and limitations under the Company’s group health care programs or plans shall remain subject to the Company’s right to amend, change or terminate such programs or plans at any time.

4.5. SERP / Other Deferred Compensation. With respect to a Participant who has a vested benefit and actively participates in the SERP as of his or her Termination Date, the Severance Period (but not to exceed 24 months unless such Participant was entitled to a



greater period as of January 1, 2004 under a plan or agreement then in effect) shall be taken into account as service solely for purposes of determining, to the extent relevant under the qualified defined benefit pension plan then covering the Participant, the amount of the Participant’s regular accrued SERP benefit, but not for purposes of determining eligibility for early retirement benefits (including any social security supplement) or any other purpose. In determining the amount of the Participant’s benefit, if any, the severance payments made under Section 4.1 shall be considered as if such payments were normal base salary and incentive payments. All amounts previously deferred by, or accrued to the benefit of, such Participant under a non-qualified deferred compensation plan of the Company shall, to the extent vested, be paid in accordance with the Participant’s distribution election in effect thereunder as of the Termination Date (or, if no affirmative election is in effect as of such date, the default election applicable to the Participant).

4.6. Life Insurance and Disability Coverage. A Participant shall be eligible for continued coverage under the applicable life insurance and executive-only long term disability plans sponsored by the Company (or other equivalent coverage or benefits) through the last day of the Severance Period applicable to such Participant on the same terms and subject to the same terms and conditions as are applicable to active peer employees (including, without limitation, submission of proof by an Executive who seeks long term disability benefits that such Executive would have satisfied the conditions for such benefits had the Executive been an employee during the Severance Period and terminated employment on or before the last day of such period).

4.7. Outplacement and Financial Counseling Services. During the twelve-month period following the Termination Date, the Company shall reimburse the Participant for reasonable fees as incurred for services rendered by a professional outplacement organization approved by the Plan Administrator to provide individual outplacement services, and the Participant shall be eligible to receive financial counseling services consistent with the terms and conditions applicable to active peer executives under Exelon’s executive perquisite policy.

## 5. CHANGE IN CONTROL BENEFITS

A Participant, whose Termination Date occurs during the period commencing ninety (90) days before a Change Date and ending on the second anniversary of such Change Date, shall be entitled to the payment of all Accrued Obligations and the following benefits in lieu of the benefits described in Section 4 hereof:

5.1. Severance Pay. Continued payment of (a) his or her Base Salary, and (b) if the Participant is a participant in the Annual Incentive Award Plan for the year in which the Termination Date occurs, his or her Target Incentive, each payable during the Severance Period in substantially equal regular payroll installments commencing within 45 days after his or her Termination Date.

5.2. Annual Incentive for Year of Termination. A pro-rated Annual Incentive under the annual incentive plan applicable to such Participant for the year in which the Termination Date



occurs, based on the number of days elapsed during such year as of the Termination Date, payable at the time such awards are paid to active employees for such year (but not later than March 15 of the year following the Termination Date).

## 5.3. Long-Term Incentive Awards.

(a) Stock Options. Each outstanding stock option granted to the Participant under the LTIP shall (i) become fully vested as of the Termination Date, and (ii) thereafter remain exercisable until the fifth anniversary of the Termination Date or, if earlier, the expiration date of any such stock option, provided that this provision shall not limit the right of the Company to cancel such stock options in connection with a Change in Control in accordance with the terms and conditions of the LTIP.

(b) Restricted Stock, Stock Unit and Cash Awards. All forfeiture conditions that are applicable as of the Termination Date to any outstanding shares of restricted stock, restricted stock units or restricted cash awarded to the Participant under the LTIP shall (except as expressly provided to the contrary in such awards) lapse and such awards shall become fully vested as of the Termination Date.

(c) Other LTIP Awards. To the extent the performance period applicable to any outstanding performance shares, performance units or similar stock or cash incentive awards granted to the Executive under the LTIP has ended as of the Termination Date (or, if later, the Change Date), including performance periods that are terminated early in connection with the Change in Control, such awards shall become fully vested and payable (to the extent not already paid), based on the performance level attained (or deemed to have been attained in connection with the Change in Control). To the extent the performance period applicable to any such award has not ended as of the Termination Date (or, if later, the Change Date), such award shall become fully vested and payable based on the extent to which the performance goals established under the LTIP for such performance period are attained as of the last day of the performance period.

5.4. Make-Whole if Termination Date Precedes Change Date. Notwithstanding the foregoing provisions of this Section 5, in the event the Participant’s Termination Date occurs during the 90-day period preceding the Change Date, then (i) any payments that would have been to the Participant earlier under Sections 5.1 or 5.2, had the Change Date preceded his or her Termination Date, will be paid in a lump sum within 45 days after the Change Date, (ii) none of the Participant’s LTIP awards described in Section 5.3 shall expire or be forfeited during the 90-day period preceding the Change Date, except to the extent they would have expired or been forfeited had the Participant remained employed until the Change Date, and (iii) any lapse of restrictions and vesting of such LTIP awards that would have occurred as of the Termination Date, had it been preceded by the Change Date, shall occur as of the Change Date.



## 5.5. Continuation of Welfare Benefits.

(a) COBRA Coverage. During the Severance Period, a Participant (and his or her dependents) who so elects shall be eligible to participate in the health care plans under which he or she was covered immediately prior to the Termination Date, in accordance with and subject to the terms and conditions of such plans as in effect from time to time. The Participant’s out of pocket costs (including premiums, deductibles and co-payments) for such coverage shall be the same as those in effect from time to time for active peer employees during such period. Such coverage shall be provided during the Severance Period in satisfaction of continuation coverage under COBRA for such period. At the end of the Severance Period, COBRA continuation coverage at the Participant’s expense may be continued for the remaining balance of the statutory COBRA coverage period, if any.

(b) Retiree Coverage. A Participant who, as of the last day of the Severance Period, has attained at least age 50 and completed at least 10 years of service (or who has completed such other age and service requirement then in effect under the Exelon Corporation Severance Benefit Plan or any successor plan as of the relevant time set forth in such plan) shall be entitled to elect to participate in such Company group health care programs that are then available to similarly situated retirees of his or her legacy Company. The eligibility for coverage and availability of programs or plans, the amounts charged for coverage, and the other terms, conditions and limitations under the Company’s group health care programs or plans shall remain subject to the Company’s right to amend, change or terminate such programs or plans at any time.

5.6. SERP/ Other Deferred Compensation. For purposes of the Participant’s SERP benefit (if the Participant then actively participates in the SERP), the Severance Period (but not to exceed 24 months unless such Participant was entitled to a greater period as of January 1, 2004 under a plan or agreement then in effect) shall be taken into account as service solely for purposes of determining whether the Participant is vested and, to the extent relevant under the qualified defined benefit pension plan then covering the Participant, the amount of the Participant’s regular accrued SERP benefit, but not for purposes of determining eligibility for early retirement benefits (including any social security supplement) or any other purpose. In determining the amount of the Participant’s vested benefit, if any, the severance payments made under Section 5.1 shall be considered as if such payments were normal base salary and incentive payments. All amounts previously deferred by, or accrued to the benefit of, such Participant under a non-qualified deferred compensation plan of the Company shall, to the extent vested, be paid in accordance with the Participant’s distribution election in effect thereunder as of the Termination Date (or, if no affirmative election is in effect as of such date, the default election applicable to the Participant)



5.7. Life Insurance and Disability Coverage. A Participant shall be eligible for continued coverage under the applicable life insurance and executive-only long term disability plans or programs sponsored by the Company (or other equivalent coverage or benefits) through the last day of the Severance Period applicable to such Participant on the same terms and subject to the same terms and conditions as are applicable to active peer employees (including, without limitation, submission of proof by an Executive who seeks long term disability benefits that such Executive would have satisfied the conditions for such benefits had the Executive been an employee during the Severance Period and terminated employment on or before the last day of such period).

5.8. Outplacement and Financial Counseling Services. During the 12-month period following the Termination Date, the Company shall pay or cause to be paid on behalf of such Participant, as incurred, all reasonable fees and costs charged by a nationally recognized outplacement firm selected by such Participant for outplacement services. During such period, the Participant also shall be eligible to receive financial counseling services consistent with the terms and conditions applicable to active peer executives under Exelon’s executive perquisite policy as of the Termination Date.

5.9. Procedural Requirements. The Company shall strictly observe or cause to be strictly observed each of the following procedures in connection with any termination for Cause during the period commencing on a Change Date and ending on the second anniversary of such Change Date: an eligible Executive’s termination of employment shall not be deemed to be for Cause unless and until there shall have been delivered to such Executive a written notice of the determination of the Chief Executive Officer of the Company which is the Executive’s employer (“CEO”) (after reasonable written notice of such consideration by the CEO of acts or omissions alleged to constitute Cause is provided to such Executive and such Executive is given an opportunity to present a written response to the CEO regarding such allegations), finding that, in his or her good faith opinion, such Executive’s acts, or failure to act, constitutes Cause and specifying the particulars thereof in detail.

5.10. Sole and Exclusive Obligations. The obligations of the Company under this Plan with respect to any Termination of Employment under this Section 5 shall supersede and not duplicate any severance obligations of the Company in any other plan of the Company or prior agreement between such Participant and the Company or its predecessor in interest.

5.11. Payment Capped. If the Plan Administrator determines that any benefits paid or payable under this Plan to a Participant would give rise to liability of the Participant for the excise tax imposed by Section 4999 of the Code or any successor provision, then the amount payable to the Participant hereunder shall be reduced by the Company to the extent necessary so that no portion is subject to such excise tax; provided, however, such reduction shall be made only if it results in the Participant retaining a greater amount of benefits on an after-tax basis (taking into account the excise tax and applicable federal, state, and local income and payroll taxes) than the amount of benefits on an after-tax basis (taking into account the excise tax and applicable federal state, and local income and payroll taxes) the Participant would have retained absent such reduction. In the event benefits are required to be reduced pursuant to this Section 5.11, then they shall be



reduced in the following order of priority in a manner consistent with Section 409A of the Code: (i) first from cash benefits (ii) next from performance-vested equity benefits, with benefits having later payments dates being reduced first; (iii) next from time-vested equity benefits, with benefits having later payment dates being reduced first; and (iv) in the case of equity benefits having the same payments dates, pro-rata amongst all such benefits. The Plan Administrator shall, in its sole discretion, choose an independent public accounting firm or professional consulting services provider of national reputation and experience to make in writing in good faith all calculations and determinations under this Section 5.11 including the assumptions to be used in arriving at any calculations. For purposes of making the calculations and determinations under this Section 5.11, the accountants may make reasonable assumptions and approximations concerning the application of Sections 280G and 4999 of the Code. The Plan Administrator shall furnish to the accountants information and documents as the Accountants may reasonably request to make the calculations and determinations under this Section 5.11 and shall bear all costs the accountants incur in connection with any calculations contemplated hereby.

## 6. TERMINATION OF PARTICIPATION; CESSATION OF BENEFITS; RECOUPMENT

A Participant’s benefits under the Plan shall terminate on the last day of the Participant’s Severance Period; provided that a Participant’s right to benefits shall terminate immediately on the date that the Participant breaches any of the terms of his or her Separation Agreement, Restrictive Covenants or Waiver and Release, or if at any time the Company determines (in accordance with Section 5.9 with respect to a Participant receiving benefits under Section 5) that in the course of his or her employment the Executive engaged in conduct described in Section 7.5(b), (c), (d) or (e), in which case the Company may require the repayment of amounts paid pursuant to Section 4 or Section 5 (other than any Accrued Obligations) prior to such breach or other conduct, and shall discontinue the payment of any additional amounts under the Plan.

To the extent that the Company makes payments and provides benefits to an Executive and the Executive either does not timely execute and deliver the Waiver and Release to the Company or revokes the Waiver and Release in accordance with its terms, Executive shall pay to the Company within 10 days following the expiration of the consideration period of the Waiver and Release or the date such Waiver and Release was revoked, a lump sum payment of all payments and the value of all benefits (other than Accrued Obligations) received by Executive to date hereunder.

Notwithstanding any provision of the Plan or any Separation Agreement to the contrary, benefits paid or payable to a Participant under the Plan shall be subject to any executive or officer recoupment or claw back policy of the Board of Directors as in effect as of the Termination Date. Any termination and/or recoupment of benefits under the Plan shall be in addition and without prejudice to any other remedies that the Company may elect to assert.

## 7. DEFINITIONS



In addition to terms previously defined, when used in the Plan, the following capitalized terms shall have the following meanings unless the context clearly indicates otherwise:

7.1. “Accrued Obligations” means, the sum of a Participant’s (a) Base Salary (b) any annual incentive with respect to the preceding fiscal year, (c) any unused vacation or paid time off days and (d) any properly reimbursable business expenses; in each case which are accrued but unpaid as of the Termination Date.

7.2. “Annual Incentive” means (a) for purposes of Section 4 hereof, an amount to which a Participant would have been entitled under the Annual Incentive Award Plan based on the actual performance goals established pursuant to such plan and assuming a “meaningful impact” individual performance rating, or (b) for purposes of Section 5 hereof, an amount to which a Participant would have been entitled under the Annual Incentive Award Plan (or any other short-term incentive plan of the Company or its successor applicable to such Participant in lieu of the Annual Incentive Award Plan) based on the actual achievement of performance goals established pursuant to such plan (or if such performance cannot reasonably be determined, the average of the actual Annual Incentives paid or payable to the Participant for each of the two calendar years preceding the Termination Date), assuming a “meaningful impact” individual performance rating (if applicable) and disregarding any reduction in a Participant’s Base Salary or Target Incentive (if any) occurring during the period beginning 90 days prior to the Change Date.

7.3. “Annual Incentive Award Plan”, means the Exelon Corporation Annual Incentive Award Plan (but not any other short-term incentive plan of a Company), or any successor plan thereto (including but not limited to any annual incentive plan of a successor to Exelon pursuant to a Change in Control).

7.4. “Base Salary” means (a) for purposes of Section 4, the annualized base salary payable to the Participant as of his or her Termination Date, and (b) for purposes of Section 5, the greater of the amount determined in the immediately preceding clause and 12 times the highest annualized base salary paid or payable to the Participant by the Company in respect of the 12-month period immediately before the Change Date.

7.5. “Cause” means, with respect to any Executive:

(a) the refusal to perform or habitual neglect in the performance of the Executive’s duties or responsibilities, or of specific directives of the Board of Directors of a Company or the officer or other executive to whom the Executive reports which are not materially inconsistent with the scope and nature of the Executive’s employment duties and responsibilities;

(b) the Executive’s willful or reckless commission of act(s) or omission(s) which have resulted in, or in the Company’s reasonable judgment are likely to result in, a material loss to, or material damage to the reputation of the Company or any of its affiliates, or that compromise the safety of any employee or other person;



(c) the Executive’s commission of a felony or any crime involving dishonesty or moral turpitude;

(d) the Executive’s material violation of Exelon’s or any of its affiliate’s Code of Business Conduct (including the corporate policies referenced therein), or of any statutory or common law duty of loyalty to Exelon or any of its affiliates; or

(e) any breach by the Executive of one or more of the Restrictive Covenants.

7.6. “Change Date” means the date on which a Change in Control occurs.

7.7. “Change in Control” has the meaning set forth in the definition of such term in the LTIP.

7.8. “COBRA” has the meaning set forth in Section 4.4 hereof.

7.9. “Code” means the Internal Revenue Code of 1986, as amended.

7.10. “Company” means, individually and collectively, Exelon, Atlantic City Electric Company, Baltimore Gas and Electric Company, Commonwealth Edison Company, Delmarva Power & Light Company, Exelon Business Services Company, LLC, Exelon Generation Company, LLC (including its Constellation business unit), PECO Energy Company, Pepco Holdings, LLC, Potomac Electric Power Company and any other subsidiary of the foregoing of which Exelon directly or indirectly owns at least 80% of the outstanding voting power and that is designated by the Plan Administrator as a participating employer in the Plan.

7.11. “ERISA” means the Employee Retirement Income Security Act of 1974, as amended.

7.12. “Executive” has the meaning set forth in Section 2 hereof.

7.13. “Exelon” has the meaning set forth in Section 1 hereof.

7.14. “Good Reason” means:

(a) for purposes of Section 4 hereof,

(i) a material reduction of an Executive’s base salary unless such reduction is part of a policy, program or arrangement applicable to peer executives of the Company or of the Executive’s business unit;

(ii) a demotion below the Executive level; or

(iii) with respect to Exelon’s Chief Executive Officer, a material adverse reduction in his or her position or duties, but excluding any such change caused solely by a disposition of all or a significant portion of a Company’s business or operations.



(b) for purposes of Section 5 hereof, the occurrence of any one or more of the following actions or omissions that occurs during the period commencing on a Change Date and ending on the second anniversary of such Change Date:

(i) a material reduction of an Executive’s base salary, incentive compensation opportunity or aggregate benefits;

(ii) a material adverse reduction in the Executive’s position, duties or responsibilities (excluding, with respect to an Executive other than the Chief Executive Officer of a Company, a change in the position or level of officer to whom the Executive reports);

(iii) a relocation by more than 50 miles of (A) the Executive’s primary workplace, or (B) the principal offices of Exelon or its successor (if such offices are such Executive’s workplace), in each case without the Executive’s consent; provided, however, in both cases of (A) and (B) of this subsection (b) (iii), such new location is farther from the Executive’s residence than the prior location; or

(iv) a material breach of this Plan by Exelon or its successor.

(c) Limitations on Good Reason. Notwithstanding the foregoing provisions of this Section, no act or omission shall constitute a material breach of this Plan by Exelon, nor grounds for “Good Reason”:

(i) unless the Executive gives the Plan Administrator a Notice of Termination at least 30 days prior to the Executive’s Termination Date, and the Company fails to cure such act or omission within the 30-day period;

(ii) if the Executive first acquired knowledge of such act or omission more than 90 days before such Participant gives the Plan Administrator such Notice or Termination; or

(iii) if the Executive has consented in writing to such act or omission.

7.15. “including” means including without limitation.

7.16. “LTIP” means the Exelon Corporation Long-Term Incentive Plan, as amended from time to time, or any successor thereto.

7.17. “Notice of Termination” means a written notice given by an Executive to the executive or officer to whom he or she reports and to the Plan Administrator which sets forth in reasonable detail the specific facts and circumstances claimed to provide a basis for a Termination of Employment for Good Reason.



7.18. “Participant” has the meaning set forth in Section 3 hereof.

7.19. “Person” means any individual, sole proprietorship, partnership, joint venture, limited liability company, trust, unincorporated organization, association, corporation, institution, public benefit corporation, entity or government instrumentality, division, agency, body or department.

7.20. “Plan Administrator” means Exelon’s Vice President, Corporate Compensation or, in the event the person holding such position as of a Change Date ceases to hold such position during the succeeding 24 months, a person appointed by the majority of the member of the board of directors who were directors of Exelon immediately prior to the Change Date.

7.21. “Restrictive Covenants” has the meaning set forth in Section 3 hereof.

7.22. “Section” means, unless the context otherwise requires, a section of this Plan.

7.23. “Senior Executive Management” means (a) Exelon’s Chief Executive Officer and each Senior Vice President or above of Exelon who reports directly to Exelon’s Chief Executive Officer and/or who is Exelon’s Chief Financial, Human Resources or Legal Officer, and (b) any other Executive who was a member of Senior Executive Management as of December 31, 2019 (as defined in the Plan as of such date).

7.24. “Separation Agreement” has the meaning set forth in Section 3 hereof.

7.25. “SERP” means the non-qualified supplemental defined benefit pension plan of the Company, if any, in which an Executive actively participates as of his or her Termination Date.

7.26. “Severance Period” means the period during which Base Salary and Target Incentive is payable to a Participant, based on his or her level of seniority and period of continuous service with the Company immediately preceding the Termination Date, as set forth below.

(a) For purposes of Section 4 hereof, the Severance Period with respect to:

(i) Senior Executive Management shall be 24 months (18 months if less than 2 continuous years of service; 12 months if less than one continuous year of service);

(ii) any other Senior Vice President or above of Exelon or a Chief Executive Officer of a Company other than Exelon shall be 18 months (12 months if less than 2 continuous years of service; 6 months if less than 1 continuous year of service); and

(iii) any other Executive shall be 15 months (12 months if less than 2 continuous years of service; 6 months if less than 1 continuous year of service).



(b) For purposes of Section 5 (i.e., Change in Control) hereof, the Severance Period with respect to:

(i) Senior Executive Management shall be 2.99 years;

(ii) any other Senior Vice President or above of Exelon or a Chief Executive Officer of a Company other than Exelon shall be 24 months;

(iii) a Senior Vice President or above of a Company other than Exelon shall be 18 months; and

(iv) any other Executive shall be 15 months.

7.27. “Specified Employee” means a “specified employee” within the meaning of Section 409A of the Code.

7.28. “Target Incentive” means an amount equal to the percentage of the Participant’s Base Salary (if any) to which he or she would have been entitled immediately prior to such date under the Annual Incentive Award Plan for the year in which the Termination Date occurs if the Participant were employed for the entire year and the performance goals established pursuant to such plan were achieved at the 100% (target) level.

7.29. “Termination Date” means the effective date of an eligible Executive’s Termination of Employment with the Company, which shall be the date on which such Executive has a “separation from service,” within the meaning of Section 409A of the Code; provided, however, that if the Executive terminates his or her employment for Good Reason, the Termination Date shall not be earlier than the thirtieth day following the Company’s receipt of such Executive’s Notice of Termination, unless the Plan Administrator consents in writing to an earlier Termination Date.

7.30. “Termination of Employment” means:

(a) a termination of an eligible Executive’s employment by the Company for reasons other than for Cause or disability; or

(b) a resignation by an eligible Executive for Good Reason.

The following shall not constitute a Termination of Employment for purposes of the Plan: (i) a termination of employment for Cause, (ii) an Executive’s resignation for any reason other than for Good Reason, (iii) the cessation of an Executive’s employment with the Company or any Affiliate due to death or disability (as determined by the Plan Administrator in good faith), or (iv) the cessation of an Executive’s employment with the Company or any subsidiary thereof as the result of the sale, spin-off or other divestiture of a plant, division, business unit or subsidiary or a merger or other business combination followed by employment or reemployment with the purchaser or successor in interest to the Executive’s employer with regard to such plant, division, business unit or subsidiary,



or an offer of employment by such purchaser or successor in interest on terms and conditions substantially comparable in the aggregate (as determined by the Plan Administrator in its sole discretion) to the terms and conditions of the Executive’s employment with the Company or its subsidiary immediately prior to such transaction.

7.31 “Waiver and Release” has the meaning set forth in Section 3 hereof.

## 8. FUNDING

The Plan is an unfunded employee welfare benefit plan maintained for the purpose of providing severance benefits to a select group of management or highly compensated employees. Nothing in the Plan shall be interpreted as requiring the Company to set aside any of its assets for the purpose of funding its obligations under the Plan. No person entitled to benefits under the Plan shall have any right, title or claim in or to any specific assets of the Company, but shall have the right only as a general creditor to receive benefits from the Company on the terms and conditions provided in the Plan.

## 9. ADMINISTRATION OF THE PLAN

The Plan shall be administered on a day-to-day basis by the Plan Administrator. The Plan Administrator has the sole and absolute power and authority to interpret and apply the provisions of this Plan to a particular circumstance, make all factual and legal determinations, construe uncertain or disputed terms and make eligibility and benefit determinations in such manner and to such extent as the Plan Administrator, in his or her sole discretion may determine. Benefits under the Plan will be paid only if the Plan Administrator, in his or her discretion, determines that an individual is entitled to them; provided, however, that any dispute after the claims procedure under Section 10 has been exhausted regarding whether an Executive’s termination of employment for purposes of Section 5 is based on either Good Reason or Cause may, at the election of the Executive, be submitted to binding arbitration pursuant to Section 11.

The Plan Administrator may promulgate any rules and regulations it deems necessary to carry out the purposes of the Plan or to interpret the terms and conditions of the Plan; provided, however, that no rule, regulation or interpretation shall be contrary to the provisions of the Plan. The rules, regulations and interpretations made by the Plan Administrator shall, where appropriate, be applied on a consistent basis with respect to similarly situated Executives, and shall be final and binding on any Executive or former Executive and any successor in interest.

The Plan Administrator may delegate any administrative duties, including, without limitation, duties with respect to the processing, review, investigation, approval and payment of severance pay and provision of severance benefits, to designated individuals or committees. The Plan Administrator may amend any Participant’s Separation Agreement to the extent the Plan Administrator determines it is reasonably necessary or appropriate to do so to comply with section 409A of the Code.

## 10. CLAIMS PROCEDURE

The Plan Administrator shall determine the status of an individual as an Executive and the eligibility and rights of any Executive or former Executive as a Participant to any severance



pay or benefits hereunder. Any Executive or former Executive who believes that he or she is entitled to receive severance pay or benefits under the Plan, including severance pay or benefits other than those initially determined by the Plan Administrator, may file a claim in writing with the Plan Administrator. Within 90 days after the receipt of the claim the Plan Administrator shall either allow or deny the claim in writing, unless special circumstances require an extension of time for processing, in which case a decision shall be rendered as soon as practicable, but not later than 180 days after receipt of a request for review.

A claimant whose claim is denied (or his or her duly authorized representative) may, within 60 days after receipt of the denial of his or her claim, request a review upon written application to Exelon’s Chief Human Resources Officer or other officer designated by Exelon and specified in the claim denial; review (without charge) relevant documents; and submit written comments, documents, records and other information relating to the claim.

The Chief Human Resources Officer or other designated officer shall notify the claimant of his or her decision on review within 60 days after receipt of a request for review unless special circumstances require an extension of time for processing, in which case a decision shall be rendered as soon as possible, but not later than 120 days after receipt of a request for review. Notice of the decision on review shall be in writing. The officer’s decision on review shall be final and binding on any claimant or any successor in interest.

In reviewing a claim or an appeal of a claim denial, the Plan Administrator and the Chief Human Resources Officer or other officer designated by Exelon shall have all of the powers and authority granted to the Plan Administrator pursuant to Section 9.

## 11. STATUTE OF LIMITATIONS; ARBITRATION

No Executive (or representative thereof) may bring any legal or equitable action to recover benefits under the Plan until he or she has exhausted the internal claims and appeals process described above. Any such action must be commenced no later than the first anniversary of a final decision on a claim for benefits (or such earlier date provided in any applicable statute of limitations). Any such action shall be brought exclusively in the federal courts in the Northern District of Illinois, provided that any dispute, controversy or claim between the parties hereto concerning whether an Executive’s termination of employment for purposes of Section 5 is based on either Good Reason or Cause may, at the election of the Executive, be settled by binding arbitration in Chicago, Illinois, before an impartial arbitrator pursuant to the rules and regulations of the American Arbitration Association (“AAA”) pertaining to the arbitration of commercial disputes. The costs and fees of the arbitrator shall be borne equally by the parties, regardless of the result of the arbitration. Notwithstanding anything to the contrary contained in this Section or elsewhere in this Plan, any party may seek relief in the form of specific performance, injunctive or other equitable relief in order to enforce the decision of the arbitrator, and the Company may seek injunctive relief to enforce the above-referenced statutes of limitations.

## 12. AMENDMENT OR TERMINATION OF PLAN

The Compensation and Leadership Development Committee of Exelon’s Board of Directors (or its delegate) may amend, modify or terminate the Plan at any time, and Exelon’s



Chief Human Resources Officer may amend the Plan with respect to matters other than eligibility and severance levels of executive officers at any time; provided, however, that no amendment, modification or termination shall deprive any Participant of any payment or benefit that the Plan Administrator previously has determined is payable under the Plan. Notwithstanding the foregoing, no amendment or termination that reduces the severance payments or materially adversely affects any Participant’s other benefits under Section 5 shall become effective as to such Participant during the 24-month period following a Change Date unless such Participant consents to such termination or amendment. Any purported Plan termination or amendment in violation of this Section 12 shall be void and of no effect.

## 13. MISCELLANEOUS

13.1. Limitation on Rights. Participation in the Plan is limited to the individuals described in Sections 2 and 3, and the benefits under the Plan shall not be payable with respect to any voluntary or involuntary termination of employment that is not a Termination of Employment.

## 13.2. Offset; No Mitigation.

(a) To the extent permitted by Section 409A of the Code, the amount of a Participant’s payments under Section 4 of this Plan may be reduced to the extent necessary to defray amounts owed by the Participant due to unused expense account balances, overpayment of salary, awards or bonuses, advances or loans.

(b) A Participant shall not have any duty to mitigate the amounts payable by the Company under this Plan by seeking new employment following termination. Except as specifically otherwise provided in this Plan, all amounts payable pursuant to this Plan shall be paid without reduction regardless of any amounts of salary, compensation or other amounts which may be paid or payable to the Executive as the result of the Executive’s employment by another, unaffiliated employer.

13.3. Indemnification. Each Participant shall be indemnified and held harmless by the Company to the greatest extent permitted under applicable law and the Company’s by-laws (as in effect immediately preceding the Change Date with respect to a termination pursuant to Section 5) if such Participant was, is, or is threatened to be, made a party to any pending, completed or threatened action, suit, arbitration, alternate dispute resolution mechanism, investigation, administrative hearing or any other proceeding brought by a third party whether civil, criminal, administrative or investigative, and whether formal or informal, by reason of the fact that such Participant is or was, or had agreed to become, a director, officer, employee, agent, or fiduciary of the Company or any other entity which such Participant is or was serving at the request of the Company (“Proceeding”), against all expenses (including all reasonable attorneys’ fees) and all claims, damages, liabilities and losses incurred or suffered by such Participant or to which such Participant may become subject for any reason; provided, that the Participant provides the Plan Administrator written notice of any such Proceeding promptly after receipt and such that



the Company’s ability to defend shall not be prejudiced in any fashion and the Company shall have the right to direct the defense, approve any settlement and shall not be required to indemnify the Participant in connection with any proceeding initiated by the Participant, including a counterclaim or crossclaim.

13.4. Severability. If any one or more Sections, subsections or other portions of this Plan are declared by any court or governmental authority to be unlawful or invalid, such unlawfulness or invalidity shall not serve to invalidate any Section, subsection or other portion not so declared to be unlawful or invalid. Any Section, subsection or other portion so declared to be unlawful or invalid shall be construed so as to effectuate the terms of such Section, subsection or other portion to the fullest extent possible while remaining lawful and valid. Notwithstanding the foregoing, in the event a determination is made that the Restrictive Covenants are invalid or unenforceable in whole or in part, then the Separation Agreement with respect to the Participant subject to such determination shall be void and the Company shall have no obligation to provide benefits under this Plan to such Participant.

13.5. Governing Law. The Plan shall be construed and enforced in accordance with the applicable provisions of ERISA and Section 409A of the Code.

13.6. No Right to Continued Employment. Nothing in this Plan shall guarantee the right of a Participant to continue in employment, and the Company retains the right to terminate a Participant’s employment at any time for any reason or for no reason.

13.7. Successors and Assigns. This Plan shall be binding upon and inure to the benefit of Exelon and its successors and assigns and shall be binding upon and inure to the benefit of a Participant and his or her legal representatives, heirs and legatees. No rights, obligations or liabilities of a Participant hereunder shall be assignable without the Plan Administrator’s prior written consent. In the event of the death of a Participant prior to receipt of severance pay or benefits to which he or she is entitled hereunder (and, with respect to benefits under Section 4 or Section 5, after he or she has signed the Waiver and Release), the severance pay described in Section 4.1 or 5.1, as applicable, shall be paid to his or her estate, and the Participant’s dependents who are covered under any health care plans maintained by the Company shall be entitled to continued rights under Section 4.4 or Section 5.5, as applicable; provided that the estate or other successor of the Participant has not revoked such Waiver and Release.

13.8. Notices. All notices and other communications under this Plan shall be in writing and delivered by hand, by nationally recognized delivery service that promises overnight delivery, or by first-class registered or certified mail, return receipt requested, postage prepaid, addressed as follows:

(a) If to a Participant, to such Participant at his most recent home address on file with the Company;

(b) If to the Company, to the Plan Administrator;



(c) or to such other address as either party shall have furnished to the other in writing. Notice and communications shall be effective upon notice of delivery to the addressee.

13.9. Tax Withholding. The Company may withhold from any amounts payable under this Plan or otherwise payable to a Participant or beneficiary any federal, state, city and other taxes the Company determines to be appropriate under applicable law and may report all such amounts payable to such authority in accordance with any applicable law or regulation.

13.10. Section 409A and Changes to Law.

(a) It is the intention of the Company that the provisions of this Plan comply with Section 409A of the Code, and all provisions of this Plan shall be construed and interpreted in a manner consistent with Section 409A of the Code. The Company shall administer and operate this Plan in compliance with Section 409A of the Code and any rules, regulations or other guidance promulgated thereunder as in effect from time to time and in the event that the Company determines that any provision of this Plan does not comply with Section 409A of the Code or any such rules, regulations or guidance and that as a result any Participant may become subject to a tax under Section 409A of the Code, notwithstanding Section 12, the Company shall have the discretion to amend or modify such provision to avoid the application of such tax, and in no event shall any Participant’s consent be required for such amendment or modification. Notwithstanding any provision of this Plan to the contrary, each Participant shall be solely responsible and liable for the satisfaction of all taxes and penalties that may arise in connection with amounts payable pursuant to this Plan (including any taxes arising under Section 409A of the Code), and the Company not shall have any obligation to indemnify or otherwise hold such Participant harmless from any or all of such taxes.

(b) In the event that the Company determines that any provision of this Plan violates, or would result in any material liability (other than liabilities for the severance benefits) to the Company, under any law, regulation, rule or similar authority of any governmental agency the Company shall be entitled, notwithstanding Section 12, to amend or modify such provision as the Company determines in its discretion to be necessary or desirable to avoid such violation or liability, and in no event shall any Participant’s consent be required for such amendment or modification.

(c) The payments under this Plan are designated as separate payments for purposes of the short-term deferral rule under Treasury Regulation Section 1.409A-1(b)(4), the exemption for involuntary terminations under separation pay plans under Treasury Regulation Section 1.409A 1(b)(9)(iii), and the exemption for medical expense reimbursements under Treasury Regulation Section 1.409A 1(b)(9)(v)(B). As a result, (A)



payments that are made on or before the 15th day of the third month of the calendar year following the year that includes the Participant’s Termination Date, (B) any additional payments that are made on or before the last day of the second calendar year following the year of the Participant’s Termination Date and do not exceed the lesser of two times the Participant’s annual rate of pay in the year prior to his termination or two times the limit under Section 401(a)(17) of the Code then in effect, and (C) continued medical expense reimbursements during the applicable COBRA period, are exempt from the requirements of Section 409A of the Code.

(d) To the extent any amounts under this Plan are payable by reference to a Participant’s Termination of Employment, such term and similar terms shall be deemed to refer to such Participant’s “separation from service,” within the meaning of Section 409A of the Code. Notwithstanding any other provision in this Plan, to the extent any payments hereunder constitute “nonqualified deferred compensation,” within the meaning of Section 409A of the Code (a “Section 409A Payment”), and the Participant is a specified employee, within the meaning of Treasury Regulation Section 1.409A 1(i), as determined by the Company in accordance with any method permitted under Section 409A of the Code, as of the date of the Participant’s separation from service, each such Section 409A Payment that is payable upon such Participant’s separation from service and would have been paid prior to the six-month anniversary of such Participant’s separation from service, shall be delayed until the earlier to occur of (i) the six-month anniversary of Participant’s separation from service and (ii) the date of Participant’s death. Further, to the extent that any amount is a Section 409A Payment and such payment is conditioned upon Participant’s execution of a release and which is to be paid or provided during a designated period that begins in one taxable year and ends in a second taxable year, then such Section 409A Payment shall be paid or provided in the later of the two taxable years.

(e) Any reimbursements payable to a Participant pursuant to this Plan or otherwise shall be paid to such Participant in no event later than the last day of the calendar year following the calendar year in which such Participant incurred the reimbursable expense. Any amount of expenses eligible for reimbursement, or in-kind benefit provided, during a calendar year shall not affect the amount of expenses eligible for reimbursement, or in-kind benefit to be provided, during any other calendar year. The right to any reimbursement or in-kind benefit pursuant to this Plan shall not be subject to liquidation or exchange for any other benefit. Any tax gross-up payment payable to a Participant, whether under this Plan or otherwise, shall be paid to the Participant or to the applicable taxing authorities on the Participant’s behalf as soon as practicable after the related taxes are due, but in any event not later than the last day of the calendar year



following the calendar year in which the related taxes are remitted to the taxing authorities

EXELON CORPORATION

By:

Senior Vice President and
Chief Human Resources Officer



# SEPARATION AGREEMENT

THIS SEPARATION AGREEMENT (this “Agreement”) is entered into as of ___, 20___ between Exelon Corporation (“Exelon”), ___ (“Subsidiary”, and, collectively with Exelon, the “Company”) and ___ (the “Executive”).

## W I T N E S S E T H:

WHEREAS, the Executive is separating from all positions with the Company and its respective affiliates.

NOW, THEREFORE, in consideration of the mutual promises and agreements contained herein, the adequacy and sufficiency of which are hereby acknowledged, the Company and the Executive agree as follows:

1. Resignation & Termination of Employment. The Executive’s employment will be terminated and Executive hereby resigns, each effective as of the close of business on ___, 20___(the “Termination Date”), from his or her position as ___ and from all other positions as an officer or director of Exelon and its subsidiaries and affiliates. [During the period commencing on the date hereof and ending on the Termination Date, Executive shall cooperate with and assist in the orderly transition of his or her duties, and shall diligently perform such other services reasonably consistent with his or her position as may be requested from time to time. Executive’s current base salary and annual incentive target shall remain in effect, and Executive (and his or her eligible dependents) shall also remain eligible to participate in the Company’s applicable employee benefit plans, and shall remain subject to and comply with the Company’s code of business conduct and other employment policies.]

2. Payment of Accrued Amounts. The Company shall pay to the Executive the portion of his or her annual salary that has accrued but is unpaid as of the Termination Date and an additional amount representing the Executive’s accrued but unused vacation days as of the Termination Date, in each case not later than the second payroll date after the Termination Date.

3. Severance Payments. The Company shall pay to the Executive:

(a) cash severance payments in an aggregate amount equal to  \( [2.0 \)  for named executive officers; 1.25 - 2.0 for other officers] times the sum of (i)  \) \text{Sh} \( , which is equal to the product of (representing the Executive’s annual base salary) and (ii)  \) \text{S} \(  (representing the Executive’s target annual incentive). For named executive officers and other “specified employees” within the meaning of section 409A of the Code, payment shall commence in the form of a lump sum payment of  \) \text{S} \(  to be made as of the first payroll date occurring on or after the date that is six months after the Termination Date, followed by substantially equal regular payroll installments of the remainder over a period of [eighteen for named executive officers; twelve to eighteen for other officers] months; for other officers, payment shall commence not later than 45 days after the Termination Date in substantially equal payroll installments over a period of [15 - 24 months]; and

(b) a pro-rated annual incentive award for [the year in which the Termination Date occurs] based on the number of days elapsed during such year as of the Termination Date, the amount of which (if any) shall be determined based on business performance measures in a manner consistent with that applied to active peer executives of Subsidiary (assuming a meaningful impact performance rating) and payable at the time such awards are paid to such executives (but not later than [March 15 of the following year]), and each such payment shall be considered a separate short-term deferral for purposes of section 409A of the Internal Revenue Code (“Code”).

4. Tax Withholding. The Company shall deduct from the amounts payable to the Executive pursuant to this Agreement the amount of all required federal, state and local withholding taxes in accordance with the Executive’s Form W-4 on file with the Company and all applicable social security and Medicare taxes.

5. Outplacement Assistance and Financial Counseling Services. During the twelve-month period following the Termination Date, the Company shall reimburse the Executive for reasonable fees incurred for services rendered to the Executive by a professional outplacement organization selected by the Executive and reasonably acceptable to the Company to provide individual outplacement services, and Executive shall be eligible to receive financial counseling services consistent with the terms and conditions applicable to active peer executives under Exelon’s executive perquisite policy. Executive may apply for external positions via search firms which also recruit executives for the Company.

## 6. Long Term Incentive Awards.

(a) Executive shall remain eligible to receive long-term [performance share awards for generation/business services company executives /or/ performance cash awards for utility executives] under Exelon’s long-term incentive program for the performance cycles commencing in the year in which the Termination Date occurs and the two preceding years to the extent provided under the terms and conditions of the program in effect at the time of grant, and the respective payout amounts (if any) of which shall be determined in a manner consistent with that used to determine the amounts of such awards payable to active executives for such respective periods, and each such award shall be payable at the time or times such respective awards are paid to active executives and considered a separate, short-term deferral for purposes of section 409A of the Code; and



(b) Executive’s options to purchase common stock of Exelon granted by the Company shall, to the extent not exercised as of the Termination Date, remain exercisable until the (i) the earlier of the respective expiration dates of such options and the date that is ninety days after the Termination Date with respect to merger options other than those granted in 2012 if the Executive has not attained at least age 50 and completed at least 10 years of service, and (ii) until the respective expiration dates of such options with respect to merger options granted in 2012 and other options if the Executive is at least age 50 and has completed 10 or more years of service; and

(c) the non-vested portions of Executive’s [restricted stock unit for generation and business services company executives /or/ restricted cash for utility executives] awards under Exelon’s long term incentive program in effect on the date of grant shall vest to the extent provided under the terms and conditions of the program as of the Termination Date [and, with respect to named executive officers and other “specified employees”, payable six months after the Termination Date].

All such awards payable in shares shall be subject to the Company’s applicable resale restrictions, if any.

7. Supplemental Executive Retirement Benefits. The Executive shall be eligible for a retirement benefit under the Company’s applicable supplemental non-qualified pension plan, if any (the “SERP”), in accordance with the terms and conditions thereof, except that in determining such benefit, the Executive shall be subject to the Executive’s timely execution of the Waiver and Release, be credited with [24 months for named executive officers; 15 -24 months for other officers] additional service calculated as though he or she received the severance benefits specified in Section 3(a) as regular salary and incentive pay over such period (and limited in its application to the amounts of such payments that exceed the compensation limitations applicable to qualified pension plans under the Code) and any other service previously granted to such Executive. Such benefit shall be paid as provided in Section 8(c).

## 8. Employee and Other Benefits.

(a) During the period commencing on the Termination Date and ending [24 months for named executive officers; 15 - 24 months for other officers] after the Termination Date (the “Severance Period”) and in satisfaction of COBRA continuation coverage during such period with respect to healthcare benefits, (i) the Executive (and his or her participating dependents) shall be eligible to participate in, and shall receive benefits under Exelon’s welfare benefit plans (including medical, dental and vision) in which the Executive (and his or her eligible dependents) were participating immediately prior to the Termination Date, and (ii) the Executive shall be eligible to participate in the life insurance programs in which he or she was a participant immediately prior to the Termination Date, in each case on the same basis as if the Executive had remained actively employed during the Severance Period.

(b) Following the Severance Period, if the Executive has attained at least age 50 and has completed at least 10 years of service as of the end of the Severance Period, the Executive (and his or her eligible dependents) shall be eligible for retiree benefits in accordance with and subject to the terms and conditions of the Company’s applicable health care plans, as in effect for employees of his or her legacy business unit from time to time (including the Company’s right to amend or terminate such plans at any time). Such benefits shall not duplicate any benefits that may then be available to the Executive from any other employer and shall be secondary to Medicare.

(c) The Company shall pay to the Executive, in the time and manner specified in the terms and conditions of such plans and any distribution elections by the Executive in effect thereunder, his or her account balances (if any) under Exelon’s applicable deferred compensation plans, as adjusted by any applicable earnings and losses on such account balances, and the Executive’s benefit under the supplemental executive retirement plan.

(d) The Executive shall be entitled to purchase the laptop computer furnished by the Company for his or her use, subject to removal of data and programs as determined by the Company. The Executive shall be responsible for payment of expenses incurred after the

Termination Date with respect to the Company-owned cellular phone furnished for his or her use.

(e) If the Executive is entitled to any benefit under any employee benefit plan of the Company that is accrued and vested on the Termination Date and that is not expressly referred to in this Agreement, such benefit shall be provided to the Executive in accordance with the terms of such employee benefit plan.

(f) Notwithstanding Section 8(e) or anything else contained in this Agreement to the contrary, the Executive acknowledges and agrees that he or she is not and shall not be entitled to benefits under any other severance or change in control plan, program, agreement or arrangement, and that the benefits provided under this Agreement shall be the sole and exclusive benefits to which the Executive may become entitled upon his or her termination of employment. In the event the Executive dies prior to executing the Waiver and Release, neither he or she, his or her estate, nor any other person shall be entitled to any further compensation or benefits under this Agreement, unless and until the executor of the Executive’s estate (and/or such other heirs or representatives as may be requested by the Company) executes upon Company request and does not revoke such a Waiver and Release.

9. Waiver and Release. Notwithstanding anything herein to the contrary, Executive’s right to the payments and benefits under this Agreement shall be contingent upon (a) Executive having executed and delivered to the Company a waiver and general release agreement in the form attached hereto (the “Waiver and Release”) not earlier than the Termination Date but in no event more than 21 days [45 days if a group termination] after the Termination Date (the “Consideration Period”), (b) Executive not revoking such release in accordance with the terms of the release and (c) Executive not violating any of Executive’s on-going obligations under this Agreement; provided, however, that the Company has the discretion to pay such benefits prior to receipt of the Waiver and Release and/or the expiration of the revocation period; provided further that if Executive does not execute and deliver the Waiver and Release to the



Company prior to the expiration of the Consideration Period or if the Executive revokes the Waiver and Release in accordance with its terms, Executive shall pay to the Company within 10 days following the expiration of the Consideration Period or the date such release was revoked, a lump sum payment of all payments received by Executive to date hereunder.

## 10. Restrictive Covenants. The Executive acknowledges and agrees that he or she is bound by, and subject to, the Non-Solicitation and Confidentiality Agreement dated as of (the “Restrictive Covenants”) and the

Waiver and Release. The Executive shall comply with, and observe, the Restrictive Covenants including, without limitation, the confidential information, non-solicitation and intellectual property provisions and related covenants contained therein, all of which are hereby incorporated by reference. In the event that Executive has breached any of the Restrictive Covenants or the Waiver and Release or has engaged in conduct during his or her employment with the Company that would constitute grounds for termination for Cause (as defined in the Exelon Corporation Senior Management Severance Plan), benefits under this Agreement shall terminate immediately, and Executive shall reimburse Exelon for any benefits received.

## 11. Certain Tax Matters.

(a) If it is determined by Exelon’s independent auditors that any severance payment, benefit or enhancement provided to the Executive pursuant to the terms of the this Agreement is or will become subject to any excise tax under section 4999 of the Code, or any similar tax payable under any United States federal, state, local, foreign or other law (“Excise Taxes”), then such payment, benefit or enhancement shall be reduced to the largest amount which would not cause any such Excise Tax to by payable be the Executive and not cause a loss of the related income tax deduction by the Company.

(b) The parties intend for this Agreement to comply with section 409A of the Code. In the event the timing of any payment or benefit under this Agreement would result in any tax or penalty under section 409A of the Code, the Company may reasonably adjust the timing of such payment or benefit if doing so will eliminate or materially reduce such tax or penalty and amend this Agreement accordingly. Executive acknowledges that Executive has been advised to consult Executive’s personal tax advisor concerning this Agreement, and has not relied on the Company for tax advice.

12. Non-disparagement. The Executive shall not publish, comment upon or disseminate any public statements suggesting or accusing the Company or any of its affiliates, employees, officers, directors or agents of any misconduct or unlawful behavior, or that brings the Company or any of its affiliates or the employees, officers, directors or agents of the Company or any of its affiliates into disrepute, or tarnish any of their images or reputations. The provisions of this Section 12 shall not apply to truthful testimony as a witness, compliance with other legal obligations, assertion of or defense against any claim of breach of this Agreement, or any activity that otherwise may be required or permitted by the lawful order of a court or agency of competent jurisdiction, and shall not require the Executive to make false statements or disclosures.

13. Publicity. Executive shall not issue or cause the publication of any press release or other announcement with respect to the terms or provisions of this Agreement, nor disclose the contents hereof to any third party (other than to members of his or her immediate family or to tax, financial and legal advisors), without obtaining the consent of Exelon, except where such release, announcement or disclosure shall be required by applicable law or administrative regulation or agency or other legal process.

14. Other Employment: Other Plans. The Executive shall not be obligated to seek other employment or take any other action by way of mitigation of the amounts payable to the Executive under any provision of this Agreement. The amounts payable hereunder shall not be reduced by any payments received by the Executive from any other employer; provided, however, that any continued welfare benefits provided for by Section 8(a) shall not duplicate any benefits that are provided to the Executive and his or her family by such other employer and shall be secondary to any coverage provided by Medicare.

15. Cooperation by the Executive. During the Severance Period, the Executive shall (a) be reasonably available to the Company to respond to requests by them for information pertaining to or relating to matters which may be within the knowledge of the Executive and (b) cooperate with the Company in connection with any existing or future litigation or other proceedings brought by or against the Company, its subsidiaries or affiliates, to the extent Exelon reasonably deems the Executive's cooperation necessary, including truthful testimony in any related proceeding.

16. Successors; Binding Agreement. This Agreement shall inure to the benefit of and be binding upon the Company and its successors, and by the Executive, his or her spouse, personal or legal representatives, executors, administrators and heirs. This Agreement, being personal, may not be assigned by Executive.

17. Governing Law: Validity. This Agreement shall be interpreted, construed and enforced in accordance with the terms of the Exelon Corporation Senior Management Severance Plan, and the applicable provisions of the Employee Retirement Income Security Act of 1974, as amended (“ERISA”) and section 409A of the Code.

18. Entire Agreement. This Agreement and the Waiver and Release constitute the entire agreement and understanding between the parties with respect to the subject matter hereof and supersede and preempt any other understandings, agreements or representations by or between the parties, written or oral, which may have related in any



manner to the subject matter hereof. Executive acknowledges that the Company has made no representations regarding the tax consequences of payments under this Agreement and has had the opportunity to consult Executive’s tax advisor.

19. Counterparts. This Agreement may be executed in two counterparts, each of which shall be deemed to be an original and both of which together shall constitute one and the same instrument.

20. Miscellaneous. No provision of this Agreement may be modified or waived unless such modification or waiver is agreed to in writing and executed by the Executive and by a duly authorized officer of the Company. No waiver by either party hereto at any time of any breach by the other party hereto or, or compliance with, any condition or provision of this Agreement to be performed by such other party shall be deemed a waiver of similar or dissimilar provisions or conditions at the same or at any prior or subsequent time. Failure by the Executive or the Company to insist upon strict compliance with any provision of this Agreement or to assert any right which the Executive or the Company may have hereunder shall not be deemed to be a waiver of such provision or right or any other provision or right of this Agreement.

21. Beneficiary. If the Executive dies prior to receiving all of the amounts payable hereunder (other than amounts payable under any plan referenced in Section 8, which shall be governed by any beneficiary designation in effect thereunder) but after executing the Waiver and Release, such amounts shall be paid, except as may be otherwise expressly provided herein or in the applicable plans, to the beneficiary ("Beneficiary") designated with respect to this Agreement by the Executive in writing to the Vice President, Corporate Compensation of the Company during his or her lifetime, which the Executive may change from time to time by new designation filed in like manner without the consent of any Beneficiary; or if no such Beneficiary is designated, to his or her surviving spouse, and if there be none, to his or her estate.

22. Nonalienation of Benefits. Benefits payable under this Agreement shall not be subject in any manner to anticipation, alienation, sale, transfer, assignment, pledge, encumbrance, charge, prior to actually being received by the Executive, and any such attempt to dispose of any right to benefits payable hereunder shall be void.

23. Severability. If all or any part of this Agreement is declared by any court or governmental authority to be unlawful or invalid, such unlawfulness or invalidity shall not serve to invalidate any portion of this Agreement not declared to be unlawful or invalid, except that in the event a determination is made that the Restrictive Covenants as applied to the Executive are invalid or unenforceable in whole or in part, then this Agreement shall be void and the Company shall have no obligation to provide benefits hereunder. Any paragraph or part of a paragraph so declared to be unlawful or invalid shall, if possible, be construed in a manner which will give effect to the terms of such paragraph or part of a paragraph to the fullest extent possible while remaining lawful and valid.

24. Communications. Nothing in this Agreement or the Waiver and Release shall be construed to prohibit or limit the Executive from filing a charge with, or reporting possible violations of law or regulation to any governmental agency or entity, including but not limited to the National Labor Relations Board, Nuclear Regulatory Commission, U.S. Equal Opportunity Commission, the Department of Labor, the Department of Justice, the Securities Exchange Commission, the Congress, and any agency Inspector General, or making other disclosures that are protected under the whistleblower provisions of applicable law or regulation, or taking any other action protected under section 211 of the Energy Reorganization Act. The Executive does not need the prior authorization of the Company to make any such charges, reports or disclosures, and is not required to notify the Company that Executive has made such charges reports or disclosures, and no such report or disclosure shall be considered a violation of Section 12 of this Agreement or the Waiver and Release. In addition, neither this Agreement nor the Waiver and Release limits the Executive’s ability to receive a monetary award from a government-administered whistleblower award program for providing any such reports or disclosures directly to a governmental agency. Executive acknowledges, however, that the Waiver and Release requires Executive to specifically waive all rights to recover any monetary damages from the Company, including but not limited to lost wages and benefits, lost pay, damages for emotional distress, punitive damages, reinstatement, and attorneys’ fees and costs.

Sections. Except where otherwise indicated by the context, any reference to a “Section” shall be to a Section of this Agreement.

IN WITNESS WHEREOF, Exelon and Subsidiary have caused this Agreement to be executed by their duly authorized officers and the Executive has executed this Agreement as of the day and year first above written.

EXELON CORPORATION

By:

Senior Vice President & Chief Human Resource Officer

SUBSIDIARY



Vice President, Human Resources

EXECUTIVE



# WAIVER AND RELEASE UNDER
SEPARATION AGREEMENT

In consideration for the Executive’s receiving severance benefits under the Separation Agreement (as defined below), (the “Executive”) hereby agrees as follows:

1. Release. Except with respect to the Company’s obligations under the Separation Agreement by and between Exelon Corporation, [Executive’s employing subsidiary] (collectively, the “Company”) and the Executive dated as of “Separation Agreement”), the Executive, on behalf of Executive and his or her heirs, executors, assigns, agents, legal representatives and personal representatives, hereby releases, acquits and forever discharges the Company, its agents, 20 (the subsidiaries, affiliates, and their respective officers, directors, agents, servants, employees, attorneys, shareholders, successors, assigns and affiliates, of and from any and all claims, liabilities, demands, causes of action, costs, expenses, attorneys fees, damages, indemnities and obligations of every kind and nature, in law, equity, or otherwise, known and unknown, foreseen or unforeseen, disclosed and undisclosed, suspected and unsuspected, arising out of or in any way related to agreements, events, acts or conduct at any time prior to the day of execution of this Waiver and Release, including but not limited to any and all such claims and demands directly or indirectly arising out of or in any way connected with the Executive’s employment or other service with the Company, or any of its Subsidiaries or affiliates; the Executive’s termination of employment and other service with the Company or any of its subsidiaries or affiliates; claims or demands related to salary, bonuses, commissions, stock, stock options, restricted stock or any other ownership interests in the Company or any of its subsidiaries and affiliates, vacation pay, fringe benefits, expense reimbursements, sabbatical benefits, severance, change in control or other separation benefits, or any other form of compensation or equity; and claims pursuant to any federal, state, local law, statute, ordinance, common law or other cause of action including but not limited to, the federal Civil Rights Act of 1964, as amended; the federal Age Discrimination in Employment Act of 1967, as amended; the federal Americans with Disabilities Act of 1990; the Employee Retirement Income Security Act of 1974, as amended, tort law; contract law; wrongful discharge; discrimination; fraud; defamation; harassment; emotional distress; or breach of the covenant of good faith and fair dealing. This Waiver and Release does not apply to (a) the payment of any benefits to which the Executive may be entitled under the terms of a Company-sponsored tax qualified retirement or savings plan or (b) Executive’s entitlement to indemnification, and coverage as an insured, with respect to his service as an officer, director, employee or agent in accordance with the terms and conditions of Article VII of the Exelon Corporation Amended and Restated Bylaws.

2. No Inducement. The Executive agrees that no promise or inducement to enter into this Waiver or Release has been offered or made except as set forth in this Waiver and Release and the Separation Agreement, that the Executive is entering into this Waiver and Release without any threat or coercion and without reliance on any statement or representation made on behalf of the Company or any of its subsidiaries or affiliates, or by any person employed by or representing the Company or any of its subsidiaries or affiliates, except for the written provisions and promises contained in this Waiver and Release and the Separation Agreement.

3. Advice of Counsel; Time to Consider; Revocation. The Executive acknowledges the following:

(a) The Executive has read this Waiver and Release, and understands its legal and binding effect, including that by signing and not revoking this Waiver and Release the Executive waives and releases any and all claims under the Age Discrimination in Employment Act of 1967, as amended, including but not limited to the Older Workers Benefits Protection Act. The Executive is acting voluntarily and of the Executive’s own free will in executing this Waiver and Release.

(b) The Executive has been advised to seek and has had the opportunity to seek legal counsel in connection with this Waiver and Release.

(c) The Executive was given at least [twenty-one (21) / forty-five (45)] days to consider the terms of this Waiver and Release before signing it.

(d) At the time Executive was given this Waiver and Release, Executive was informed that his or her termination was not part of a group separation.

The Executive understands that, if the Executive signs the Waiver and Release, the Executive may revoke it within seven (7) days after signing it, provided that Executive will not receive any severance benefits under the Separation Agreement. The Executive understands that this Waiver and Release will not be effective until after the seven-day period has expired and no consideration will be due the Executive.

4. Severability. If all or any part of this Waiver and Release is declared by any court or governmental authority to be unlawful or invalid, such unlawfulness or invalidity shall not invalidate any other portion of this Waiver and Release. Any Section or a part of a Section declared to be unlawful or invalid shall, if possible, be construed in a manner which will give effect to the terms of the Section to the fullest extent possible while remaining lawful and valid.



5. Amendment. This Waiver and Release shall not be altered, amended, or modified except by written instrument executed by the Company and the Executive. A waiver of any portion of this Waiver and Release shall not be deemed a waiver of any other portion of this Waiver and Release.

6. Applicable Law. The provisions of this Waiver and Release shall be interpreted and construed in accordance with the laws of the State of Illinois without regard to its choice of law principles.

IN WITNESS WHEREOF, the Executive has executed this Waiver and Release as of the date specified below.

DATE:

EXECUTIVE



# EXELON CORPORATION
LONG-TERM INCENTIVE PROGRAM

(As in effect as of January 1, 2020)

1. Purpose. The purpose of this Exelon Corporation Long-Term Incentive Program (the “Program”) is to set forth certain provisions which shall be deemed a part of, and govern, equity compensation awards granted by Exelon Corporation, a Pennsylvania corporation (the "Company"), on or after January 1, 2011 to executives, key managers and other select management employees pursuant to the Exelon Corporation 2011 Long-Term Incentive Plan, as amended (the "Plan").

## 2. Certain Definitions.

Except as otherwise set forth herein, the defined terms used in this Program shall have the meanings set forth below or in the Plan.



(a) “Administrator” shall have the meaning set forth in Section 14 below.

(b) “Award” shall mean an award granted under this Program.

(c) “Award Notice” shall mean a notice of a Participant’s Award, issued by the Company in written or electronic form, which shall set forth the type of the Award, the number of shares or amount of cash (or target share or cash opportunity that, together with the Program summary, sets forth the number of shares or amount of cash) of Common Stock subject to such Award and any other terms of the Award not set forth in the Plan, this Program or the Program summary.

(d) “Board” shall mean the board of directors of the Company.

(e) “Transition Award” shall mean a Performance Share Unit Award granted on a one-time basis in 2013 (or 2014, in certain cases such as new hires, promotions or transfers) in order to transition from a one-year Performance Cycle to a three-year Performance Cycle.

(f) “Committee” shall mean the compensation and leadership development committee of the Board.

(g) “Dividend Payment Date” shall mean each date on which the Company pays a regular cash dividend to record owners of shares of Common Stock.

(h) “Earned Cash” shall be the dollar amount of cash subject to a Performance Cash Unit Award that have been earned based on the achievement of the performance goals for the applicable Performance Cycle).

(i) “Earned Shares” shall mean shares of Common Stock (or cash representing shares, as applicable) subject to a Performance Share Unit Award that have been earned based on the achievement of the performance goals for the applicable Performance Cycle (or portion thereof, in the case of Transition Awards).

(j) “Effective Date” shall mean January 1, 2011.

(k) “First Tranche” shall mean one-third of the Performance Share Units granted under a Transition Award.



(l) “Grant Date” shall mean the date on which an Award is granted, as set forth in the applicable Award Notice

(m) “LTPP” means a long-term performance program award, which is a Restricted Cash Award subject to a performance condition or conditions in addition to a vesting requirement, and which is granted to key managers and executives below the level of Senior Vice President of a Utility.

(n) “Option” shall mean a nonqualified option to purchase shares of Common Stock upon and subject to the satisfaction of the vesting conditions set forth in Section 5 of this Program.

(o) “Participant” shall mean the recipient of an Award granted under this Program.

(p) “Performance Cycle” shall mean (A) for Performance Share Unit Awards granted prior to January 1, 2013, the one-year period beginning on January 1 of the year in which the Award is granted (and any applicable look-back period), (B) for the Transition Awards, the two-year period beginning on January 1, 2013 and (C) for Performance Share Unit Awards granted on or after January 1, 2013 (other than Transition Awards) and Performance Cash Awards granted on or after January 1, 2014, the three-year period beginning on January 1 of the year in which the Performance Share Unit Award is granted.

(q) “Performance Cash Unit” shall mean a right granted to a Participant employed in a Utility Company to receive an amount of cash subject to the achievement of the applicable performance goals and the satisfaction of the vesting conditions set forth in Section 3 of this Program.

(r) “Performance Share Unit” shall mean a right to receive shares of Common Stock or a cash equivalent (as applicable) subject to the achievement of the applicable performance goals and the satisfaction of the vesting conditions set forth in Section 3 of this Program.

(s) “Restricted Cash Award” shall mean a right to receive an amount in cash upon and subject to the satisfaction of the vesting conditions set forth in Section 4 of this Program, which is granted to key managers of business units other than a Utility.

(t) “Restricted Stock Unit” shall mean a right to receive shares of Common Stock upon and subject to the satisfaction of the vesting conditions set forth in Section 4 of this Program.

(u) “Restrictive Covenants” shall mean any noncompetition, nonsolicitation, confidentiality, intellectual property or other restrictive covenants to which a Participant is subject, required as a condition to receipt of an Award, or which is contained in any other agreement between the Participant and the Company or any of its affiliates.



(v) “Retirement” shall mean a Participant’s termination of employment (other than a termination upon death, disability or involuntary termination for cause) on or after the date as of which the Participant has attained age 55 (age 50 with respect to Awards granted prior to January 1, 2013) and completed at least ten years of service with the Company and the Subsidiaries. For purposes of this definition, the holder’s age and service shall be determined taking into account any deemed age or service awarded to the holder for benefit accrual purposes under any nonqualified defined benefit retirement plan of the Company in which the holder is a participant.

(w) “Second Tranche” shall mean two-thirds of the Performance Share Units granted under a Transition Award

(x) “Utility Company” shall mean Baltimore Gas & Electric Company, Commonwealth Edison Company, PECO Energy Company, Pepco Holdings Company, and the Exelon Utility Group (which may include Transmission Operations) within Exelon Business Services Company, LLC.

## 3. Long Term Performance Share Award and Performance Cash Award Program.

(a) Granting of Awards. Within the first 90 days (or later, with respect to a new hire or promotion) of each Performance Cycle beginning on or after the Effective Date, the Committee may grant Performance Share Unit Awards to employees who are employed in a Vice President or more senior position, including without limitation Nuclear Plant Managers, as selected by the Committee in its sole discretion. Effective January 1, 2014, the Committee may grant Performance Cash Units in lieu of Performance Share Unit Awards to such designated employees who are employed in a Utility Company. Performance Share Unit Awards and Performance Cash Unit Awards shall be subject to the respective applicable terms and conditions set forth in this Section 3, and shall contain such additional terms and conditions, not inconsistent with the terms of this Program, as the Committee shall deem advisable and set forth in the applicable Program summary or Award Notice.

(b) Number of Shares (or Amount of Cash) and Other Terms. The number of shares of Common Stock represented by a Performance Share Unit Award, and the amount of cash represented by a Performance Cash Award, for any Performance Cycle shall be determined based on the achievement of performance goals established by the Committee and set forth in the Program summary for such Performance Cycle and the administrative guidelines approved by the Committee. Each performance goal shall be assigned a weighting and scored at the end of each calendar year within the Performance Cycle. For Performance Cycles beginning on or after January 1, 2013, at the end of the Performance Cycle, the number of Earned Shares (or the amount of Earned Cash) is determined based on the annual performance results determined by the Committee, subject to adjustment as set forth in the Program summary and/or administrative guidelines. Notwithstanding the foregoing, the maximum number of shares of Common Stock that may



become subject to Performance Share Unit Awards and Performance Cash Awards granted in any calendar year beginning prior to January 1, 2019 to Participants the Company has determined as of the Grant Date may be “covered employees” (within the meaning of Section 162(m)(3) of the Code) for such year or for any subsequent year in which such Award may be outstanding, shall be equal to the lesser of (i) the number determined by (A) multiplying 1.5% of the Company’s Operating Income for such year by the allocation percentage approved by Committee for such Participant within the first 90 days of the applicable Performance Cycle and (B) dividing such dollar amount by the closing price of a share of Common Stock on the last trading day of such year and (ii) the per person limit set forth in Section 1.6 of the Plan. For purposes of this Section 3(b), the “Operating Income” of the Company for such year shall be as reported in the Company’s financial statements for such year according to generally accepted accounting principles and as reviewed or accepted, as the case may be, by the Company’s independent public accountants, and certified by the Committee in accordance with section 162(m) of the Code. The Committee reserves the right in its sole discretion to determine that the number of Earned Shares for any Performance Cycle shall be zero in the event of materially adverse business or financial circumstances as determined by the Committee.

## (c) Vesting and Forfeiture.

(i) Awards Granted prior to January 1, 2013. Except as provided in Section 3(f)(i) of the Program, Earned Shares granted prior to January 1, 2013 shall become vested (i) on the date of the first regular meeting of the Committee held in the calendar year following the calendar year in which the Grant Date occurs with respect to one-third of the number of Earned Shares, (ii) on the date of the first regular meeting of the Committee held in the second calendar year following the calendar in which the Grant Date occurs with respect to an additional one-third of the number of Earned Shares, and (iii) on the date of the first regular meeting of the Committee held in the third calendar year following the calendar year in which the Grant Date occurs with respect to the remaining Earned Shares (but, with respect to each such year, not later than March 15), in each case subject to the Participant’s continuous employment with the Company through the applicable vesting date.

(ii) Transition Awards. Except as provided in Section 3(f)(ii) of the Program, Performance Share Units subject to a Transition Award shall be earned and become vested (i) with respect to the First Tranche, on the date of the first regular meeting of the Committee held in 2014 and (ii) with respect to the Second Tranche, on the date of the first regular meeting of the Committee held in 2015 (but, with respect to each such year, not later than March 15), in each case subject to the Participant’s continuous employment with the Company through the applicable vesting date.



(iii)Awards Granted on or after January 1, 2013 (Other than Transition Awards). Except as provided in Section 3(f) (ii) of the Program, Performance Share Units and Performance Cash Units subject to an Award (other than a Transition Award) and granted on or after January 1, 2013 shall be earned and become fully vested on the date of the first regular meeting of the Committee held in the third calendar year following the calendar year in which the Grant Date occurs (but, with respect to each such Performance Cycle, not later than March 15 of such year), in each case subject to the Participant’s continuous employment with the Company through the applicable vesting date.

(d) Dividend Equivalents. As of each Dividend Payment Date, the Company shall pay to the Participant a cash payment (or, in the discretion of the Committee, reinvest in additional shares subject to such Award) in an amount equal to the dollar amount of the cash dividend paid per share of Common Stock multiplied by the number of Earned Shares (if any) that are subject to a Performance Share Unit Award immediately prior to the record date for such Dividend Payment Date, but that have not been issued pursuant to Section 3(e) as of such record date.

(e) Settlement of Vested Awards. Subject to the withholding of taxes pursuant to Section 8 of the Program, within 45 days after the vesting of a Performance Share Unit Award, in whole or in part (or at such later time as may be required pursuant to this Section 3(e)), the Company shall issue or transfer to the Participant the number of Earned Shares that have become vested. The Company may effect such transfer either by the delivery of one or more certificates of Common Stock to the Participant or by an appropriate entry on the books of the Company or of a duly authorized transfer agent of the Company, and in either case by issuing such shares in the Participant’s name or in such other name as is acceptable to the Company and designated in writing by the Participant. All such Awards payable for 2012 or thereafter shall be paid 50% in Common Stock and 50% in cash; provided, however, that effective for Awards granted on or after January 1, 2013 (including Transition Awards), a Participant whose title is Executive Vice President or above and who has achieved 200% or more of his or her stock ownership target by September 30 of the calendar year prior to payout of the Award shall be paid in cash. The Company shall pay all original issue or transfer taxes and all fees and expenses incident to such delivery, except as otherwise provided in Section 8 of the Program. Prior to the settlement of a Performance Share Unit Award, the holder of such Award shall have no rights as a stockholder of the Company with respect to the shares of Common Stock subject to such Award. Performance Cash Unit Awards shall be paid in cash within 45 days after vesting. Notwithstanding the foregoing, if a Participant is a “Specified Employee,” within the meaning of section 409A of the Code, and such Participant is or will become eligible for Retirement prior to the calendar year in which the Performance Share Unit Award is scheduled to become fully vested, then any Earned Shares subject to the Award or payment under a Performance Cash Unit which become vested upon the Participant’s termination of employment in accordance with Section 3(f) of this Program shall be issued to the



Participant as of the earlier to occur of the six-month anniversary of such Participant’s separation from service or the date of the Participant’s death.

(f) Termination of Employment. Except as otherwise provided in this Program or the Plan:

(i) Retirement, Disability, Death or Involuntary Termination Without Cause – Awards Granted prior to January 1, 2013 and prior to January 1, 2020. If a Participant’s employment with the Company terminates by reason of Retirement, Disability, death or an involuntary termination of employment by the Company for a reason other than Cause, and such Participant has not breached his or her obligations to the Company or any of its affiliates under any Restrictive Covenant, then all Earned Shares subject to such Participant’s Performance Share Unit Award and earned cash subject to a Performance Cash Unit shall become fully vested as of the effective date of the Participant’s termination of employment or date of death, as the case may be. To the extent the Award has not been earned as of the date of the Participant’s termination of employment or death (i.e. as to which the current Performance Cycle has not elapsed), the Participant shall become vested in a pro-rated Award based on the number of elapsed days in the current Performance Cycle as of the termination date (or fully vested with respect to such an Award for 2012 upon an involuntary termination without Cause) and the extent to which the Company performance goals established under the Program for such Performance Cycle are attained as of the last day of the year in which the termination date occurs, and such Award shall be payable as of the date Awards for such Performance Cycle are payable to Participants who remain actively employed with the Company.

(ii) Retirement, Disability, Death or Involuntary Termination Without Cause – Awards Granted on or after January 1, 2013 (Including Transition Awards) and prior to January 1, 2020. If a Participant’s employment with the Company terminates by reason of Retirement, Disability, death or an involuntary termination of employment by the Company for a reason other than Cause (subject to timely execution of a waiver and release provided by the Company), and such Participant has not breached his or her obligations to the Company or any of its affiliates under any Restrictive Covenant, then (A) if such event occurs within the first 12 months of the Performance Cycle, then the Participant shall earn and become vested in a pro-rated Award based on the number of elapsed days in such 12-month period as of the termination date (pro-ration determined by dividing the number of elapsed days by 365) and the extent to which the performance goals established under the Program for such Performance Cycle (or portion thereof, in the case of the Transition Awards) are attained, and (B) if such event occurs after the first 12 months of the Performance Cycle,



then the Participant shall become fully vested in all Earned Shares (the number determined in accordance with Section 3(b) above) or earned cash, as applicable. In either event, the Earned Shares or cash shall be payable on the payout date applicable to Participants who remain actively employed with the Company.

(iii) Retirement, Disability or Death or Involuntary Termination Without Cause – Awards granted on or after January 1, 2020.

(A) If a Participant’s employment with the Company terminates by reason of Retirement, Disability or Death, and such Participant has not breached his or her obligations to the Company or any of its affiliates under any Restrictive Covenant, then (I) if such event occurs within the first 12 months of the Performance Cycle, then the Participant shall earn and become vested in a pro-rated Award based on the number of elapsed days in such 12-month period as of the termination date and the extent to which the performance goals established under the Program for such Performance Cycle are attained and (II) if such event occurs after the first 12 months of the Performance Cycle, then the Participant shall become fully vested in all Earned Shares (the number determined in accordance with Section 3(b) above) or earned cash, as applicable; and

(B) If a Participant’s employment with the Company terminates by reason of involuntary separation without Cause, and such Participant has not breached his or her obligations to the Company or any of its affiliates under any Restrictive Covenant, then, subject to such Participant’s timely execution of a waiver and release provided by the Company, the Participant shall earn and become vested in a pro-rated Award based on the number of elapsed days in such 36-month period as of the termination date and the extent to which the performance goals established under the Program for such Performance Cycle are attained. In either event, the Earned Shares or Earned Cash shall be payable on the next payout date applicable to Participants who remain actively employed with the Company.

(iv) Termination for Other Reasons. If a Participant’s employment with the Company terminates for any reason other than as described in clause (i), (ii) or (iii) of this Section 3(f) or if the Participant has breached his or her obligations to the Company or any of its affiliates under any Restrictive Covenant or waiver and release, the unvested portion of such Participant’s Award shall be forfeited and terminate as of the date of such termination of employment.

(g) Restriction on Sale of Shares by Senior Officers. Shares of Common Stock issued under an Award pursuant to Section 3(e) to a Participant who is employed as of the Grant Date in a position of, or more senior than, Senior Vice President



may not be sold or transferred by such Participant until the earlier to occur of (i) the date as of which the final third of such Award is scheduled to become vested pursuant to Section 3(c) (even if such Award actually vests earlier pursuant to Section 3(f)) or (ii) the date of the Participant’s death, regardless of when such shares are issued or transferred to such Participant. Effective January 1, 2013, this provision shall no longer be effective.

(h) Awards Granted to Employees of Commonwealth Edison Company Prior to 2014. If Performance Share Unit Awards are granted to Participants who are employed by Commonwealth Edison Company, an Illinois corporation and subsidiary of the Company (“ComEd”), then unless the Committee determines otherwise, (i) the number of such Participant’s Earned Shares shall be determined based on the achievement of performance criteria established by the Board of Directors of ComEd and ratified by the Committee, subject to the maximum number of Earned Shares that may be subject to a Performance Share Unit Award, as set forth in Section 3(b), and (ii) such Performance Share Unit Awards for 2011 shall be settled (subject to the vesting and other conditions herein) in a cash payment made by ComEd to the Participant in an amount equal to the Fair Market Value of the number of such Participant’s Earned Shares, determined as of the applicable vesting date.



4. Restricted Stock Unit, Restricted Cash and Long-Term Performance Program Awards, and Constellation Short-Term Incentives and Commissions Payable as Restricted Stock Units.

(a) Granting of Awards. The Committee may grant Restricted Stock Unit, Restricted Cash and LTPP Awards to employees who are employed (i) in a Vice President or other executive position (including without limitation Nuclear Plant Managers) and (ii) key managers and other select management employees, in each case as selected by the Committee in its sole discretion and as provided herein.

(b) Terms of Awards. Awards shall be subject to the following terms and conditions and shall contain such additional terms and conditions, not inconsistent with the terms of this Program, as the Committee shall deem advisable and set forth in the applicable Award Notice.

(c) Number of Shares and Other Terms. The number of shares of Common Stock subject to a Restricted Stock Unit Award, or the amount of cash subject to a Restricted Cash or LTPP Award, shall be determined by the Committee and set forth in the applicable Program summary or Award Notice (which may reference a number of shares or cash value).

(d) Vesting and Forfeiture. Except to the extent an Award becomes immediately vested upon a termination of the Participant’s employment pursuant to Section 4(g) of the Program, the shares subject to a Restricted Stock Unit Award or the amount of cash subject to a Restricted Cash or LTPP Award, shall become vested (i) on the date of the first regular meeting of the Committee in the calendar year following the calendar year in which the Grant Date occurs with respect to one-third of the number of shares of Common Stock or amount of cash subject to the Award on the Grant Date, (ii) on the date of the first regular meeting of the Committee in the second calendar year following the calendar year in which the Grant Date occurs with respect to an additional one-third of the number of shares of Common Stock or amount of cash subject to the Award on the Grant Date, and (iii) on the date of the first regular meeting of the Committee in the third calendar year following the calendar year in which the Grant Date occurs with respect to the remaining shares of Common Stock or amount subject to the Award on the Grant Date (but, with respect to each such year, not later than March 15), in each case subject to the Participant’s continuous employment with the Company through the applicable vesting date and, in the case of an LTPP Award, achievement of applicable performance goals.

(e) Dividend Equivalents. As of each Dividend Payment Date, the number of shares of Common Stock that are subject to a Restricted Stock Unit Award shall be increased by (i) the product of the total number of shares of Common Stock that are subject to such Restricted Stock Unit Award immediately prior to the record date for such Dividend Payment Date, but that have not been issued pursuant to Section 4(f) as of such record date, multiplied by the dollar amount of the cash dividend paid per share of Common Stock, divided by (ii) the Fair Market Value of a share of Common Stock on such Dividend



Payment Date. Such additional Restricted Stock Units shall be subject to all of the terms and conditions of the Award, including the vesting conditions set forth in Section 4(d).

(f) Settlement of Vested Awards. Subject to the withholding of taxes pursuant to Section 8 of the Program, within 45 days after the vesting of a Restricted Stock Unit Award, in whole or in part (or at such later time as may be required pursuant to this Section 4(f)), the Company shall issue or transfer to the Participant the number of shares of Common Stock that have become vested. The Company may effect such transfer either by the delivery of one or more certificates of Common Stock to the Participant or by an appropriate entry on the books of the Company or of a duly authorized transfer agent of the Company, and in either case by issuing such shares in the Participant’s name or in such other name as is acceptable to the Company and designated in writing by the Participant. The Company shall pay all original issue or transfer taxes and all fees and expenses incident to such delivery, except as otherwise provided in Section 8 of the Program. Prior to the settlement of a Restricted Stock Unit Award, the holder of such Award shall have no rights as a stockholder of the Company with respect to the shares of Common Stock subject to such Award. Notwithstanding the foregoing, if a Participant is a “Specified Employee,” within the meaning of section 409A of the Code, and such Participant is or will become eligible for Retirement prior to the calendar year in which the Restricted Stock Unit Award is scheduled to become fully vested, then any shares of Common Stock subject to the Award which become vested upon the Participant’s termination of employment in accordance with Section 4(g) of this Program shall be issued to the Participant as of the earlier to occur of the six-month anniversary of such Participant’s separation from service or the date of the Participant’s death.

(g) Termination of Employment. Except as otherwise provided in this Program or the Plan:

(i) Retirement, Disability or Death. If a Participant’s employment with the Company terminates by reason of Retirement, Disability or death, and such Participant has not breached his or her obligations to the Company or any of its affiliates under any Restrictive Covenant, then all shares or cash subject to such Participant’s Award shall become fully vested as of the effective date of the Participant’s termination of employment or date of death, as the case may be.

(ii) Termination for Other Reasons. If a Participant’s employment with the Company terminates for any reason other than as described in clause (i) of this Section 4(g) or the Participant’s breach of his or her obligations to the Company or any of its affiliates under any Restrictive Covenant, then, subject to the Participant’s timely execution of a waiver and release provided by the Company, the unvested portion of such Participant’s Award granted prior to January 1, 2020 shall become fully vested upon an involuntary termination without Cause, and an Award granted on or after January 1, 2020 shall become vested in the aggregate (if at all) on a pro-



rated basis (taking into account for this purpose any portion of the Award which previously became vested) based on the number of shares (plus any reinvested dividends) or amount of cash originally subject to such Award and the number of elapsed days in a 36-month period from January 1 of the year of the grant date.



## 5. Stock Option Award Program.

(a) Granting of Awards. The Committee may grant Option Awards to employees who are employed in a Senior Vice President or more senior position, as selected by the Committee in its sole discretion or, to the extent permitted by the Plan, the Chief Executive Officer of the Company.

(b) Terms of Awards. Awards shall be subject to the following terms and conditions and shall contain such additional terms and conditions, not inconsistent with the terms of this Program, as the Committee shall deem advisable and set forth in the applicable Award Notice.

(c) Number of Shares. The number of shares of Common Stock subject to an Option Award shall be determined by the Committee and set forth in the applicable Award Notice.

(d) Term of Option. Except to the extent earlier terminated or exercised, each Option shall expire on, and in no event may any portion of such Option be exercised after, the tenth anniversary of the Grant Date (the “Expiration Date”).

(e) Vesting and Forfeiture. Except to the extent the Award becomes immediately vested upon a termination of the Participant’s employment pursuant to Section 5(g) of the Program, the Option shall become vested and exercisable (i) on the first anniversary of the Grant Date with respect to one-fourth of the number of shares of Common Stock subject to the Award on the Grant Date, (ii) on the second anniversary of the Grant Date with respect to an additional one-fourth of the number of shares of Common Stock subject to the Award on the Grant Date with respect to an additional one-fourth of the number of shares of Common Stock subject (iii) on the third anniversary of the Grant Date with respect to an additional one-fourth of the number of shares of Common Stock subject to the Award on the Grant Date, and (iv) on the fourth anniversary of the Grant Date with respect to the remaining shares of Common Stock subject to the award on the Grant Date, in each case subject to the Participant’s continuous employment with the Company through the applicable vesting date.

(f) Method of Exercise. To the extent permitted by the Administrator, a Participant may exercise an Option (i) by giving written notice to the Company (or its designated agent) specifying the number of whole shares of Common Stock to be purchased and accompanying such notice with payment therefor in full, and without any extension of credit, either (A) in cash, (B) by delivery (either actual delivery or by attestation procedures established by the Company) to the Company of previously owned whole shares of Common Stock having a Fair Market Value, determined as of the date of exercise, equal to the aggregate purchase price payable by reason of such exercise, (C) authorizing the Company to withhold whole shares of Common Stock which would otherwise be delivered having an aggregate Fair Market Value, determined as of the date of exercise, equal to the amount necessary to satisfy such obligation, provided that the Committee determines that such withholding of shares does not cause the Company to recognize an increased compensation expense under applicable accounting principles, (D) except as may be prohibited by applicable law, in cash by a broker-dealer acceptable to the Company to whom the Participant has submitted an irrevocable notice of



exercise or (E) a combination of (A), (B) and (C) and (ii) by executing such documents as the Company may reasonably request. Any fraction of a share of Common Stock which would be required to pay such purchase price shall be disregarded and the remaining amount due shall be paid in cash by the Participant. No shares of Common Stock shall be issued and no certificate representing Common Stock shall be delivered until the full purchase price therefor and any withholding taxes thereon, as described in Section 8, have been paid.

## (g) Termination of Employment.

(i) Retirement or Disability. If the Company ceases to employ a Participant by reason of such Participant’s Retirement or Disability, each Option held by such Participant shall be fully exercisable, and may thereafter be exercised by such Participant (or such Participant’s legal representative or similar person) until and including the earlier to occur of (i) the fifth anniversary of the effective date of such Participant’s termination of employment and (ii) the Expiration Date.

(ii) Death. If the Company ceases to employ a Participant by reason of such Participant’s death, each Option held by such Participant shall be fully exercisable, and may thereafter be exercised by such Participant’s executor, administrator, legal representative, beneficiary or similar person until and including the earlier to occur of (i) the third anniversary of the date of death and (ii) the Expiration Date.

(iii) Cause. If the Company ceases to employ a Participant due to a termination of employment by the Company for Cause, each Option held by such Participant shall be cancelled and cease to be exercisable as of the earlier to occur of (i) the effective date of such termination of employment and (ii) the date on which the Participant first engaged in conduct giving rise to a termination for Cause, and the Company thereafter may require the repayment of any amounts received by such Participant in connection with an exercise of such Option following such cancellation date.

(iv) Other Termination. Subject to clauses (v), (vi) and (vii) below, if the Company ceases to employ a Participant for any reason other than as described in clause (i), (ii) or (iii) above, then each Option held by such Participant shall be exercisable only to the extent that such Option is exercisable on the effective date of such Participant’s termination of employment, and may thereafter be exercised by such Participant (or such Participant’s legal representative or similar person) until and including the earlier to occur of (i) the date which is 90 days after the effective date of such Participant’s termination of employment and (ii) the Expiration Date.

(v) Death Following Termination of Employment. If a Participant dies during the applicable post-termination exercise period described in clause (iv), each Option held by such Participant shall be exercisable only to the



extent that such Option is exercisable on the date of such Participant’s death and may thereafter be exercised by the Participant’s executor, administrator, legal representative, beneficiary or similar person until and including the earlier to occur of (i) the first anniversary of the date of death and (ii) the expiration date of the term of such Option.

(vi) Breach of Restrictive Covenant. Notwithstanding clauses (i) through (v), if a Participant breaches his or her obligations to the Company or any of its affiliates under a Restrictive Covenant, each Option held by such Participant shall be cancelled and cease to be exercisable as of the date on which the Participant first breached such Restrictive Covenant, and the Company thereafter may require the repayment of any amounts received by such Participant in connection with an exercise of such Option following such cancellation date.

(h) Termination of Option. In no event may an Option be exercised after it terminates as set forth in this Section 5(h). An Option shall terminate, to the extent not earlier exercised or terminated pursuant to Section 5(g), on the Expiration Date. Upon the termination of the Option, the Option and all rights thereunder shall immediately become null and void.

6. Employment. For purposes of this Program, references to employment with the Company shall include (i) employment with an Affiliate of the Company and (ii) any period during which the Participant is on a leave of absence approved by the Company.

7. Limited Transferability of Awards. Except as may otherwise be expressly provided in an Award Notice, an Award may be transferred by the Participant only (1) by will, (2) the laws of descent and distribution or (3) pursuant to beneficiary designation procedures approved by the Company. Except to the extent permitted by the foregoing, an Award may not be sold, transferred, assigned, pledged, hypothecated, encumbered or otherwise disposed of (whether by operation of law or otherwise) or be subject to execution, attachment or similar process or domestic relations order. Upon any attempt so to sell, transfer, assign, pledge, hypothecate, encumber or otherwise dispose of an Award, such Award and all rights thereunder shall immediately become null and void.



8. Withholding Taxes. The Company shall have the right to require, prior to the issuance or delivery of any shares of Common Stock or the payment of any cash pursuant to an Award, or upon the vesting of any Award that is considered deferred compensation, payment by the Participant of any federal, state, local or other taxes which may be required to be withheld or paid in connection with such Award. The Company may withhold whole shares of Common Stock which would otherwise be delivered to a Participant, having an aggregate Fair Market Value determined as of the Tax Date, or withhold an amount of cash which would otherwise be payable to a Participant, in the amount necessary to satisfy any such obligation. The Participant may elect to satisfy any such obligation by any of the following means, to the extent permitted by the Administrator: (A) a cash payment to the Company, (B) authorizing the Company to withhold whole shares of Common Stock which would otherwise be delivered having an aggregate Fair Market Value, determined as of the Tax Date, or withhold an amount of cash which would otherwise be payable to the Participant, equal to the amount necessary to satisfy any such obligation, (C) in the case of the exercise of an Option and except as may be prohibited by applicable law, a cash payment by a broker-dealer acceptable to the Company to whom the Participant has submitted an irrevocable notice of exercise or (D) any combination of (A) and (B). Shares of Common Stock to be delivered or withheld may not have an aggregate Fair Market Value in excess of the amount determined by applying the minimum statutory withholding rate. Any fraction of a share of Common Stock which would be required to satisfy such an obligation shall be disregarded and the remaining amount due shall be paid in cash by the Participant.

9. Adjustment: Change in Control or Corporate Transaction. The number and class of securities subject to an Award shall be subject to adjustment as provided in Section 5.7 of the Plan. In the event of a Change in Control or Corporate Transaction, Awards shall be subject to the terms of Section 5.8 of the Plan, as determined by the Committee. The decision of the Committee regarding any such adjustment, Change in Control and/or Corporate Transaction shall be final, binding and conclusive.

10. Compliance with Applicable Law. Each Award is subject to the condition that if the listing, registration or qualification of the shares subject to such Award upon any securities exchange or under any law, or the consent or approval of any governmental body, or the taking of any other action is necessary or desirable as a condition of, or in connection with, the delivery of shares hereunder, such Award may not be settled, in whole or in part, unless such listing, registration, qualification, consent or approval shall have been effected or obtained, free of any conditions not acceptable to the Company.



11. Award Subject to the Plan and Claw-back Policy. Each Award is subject to the provisions of the Plan, and each Award and this Program shall be interpreted in accordance therewith. Notwithstanding any provision of the Program to the contrary, each Award shall be subject to a clawback pursuant to the Exelon Executive Officer Compensation Recoupment Policy contained in the Exelon Corporation Board of Directors Corporate Governance Principles, as in effect from time to time, including any amendments thereto or new clawback policies required under the Dodd-Frank Wall Street Reform and Consumer Protection Act and implementing applicable stock exchange listing standards or rules and regulations thereunder, or as otherwise required by law or regulation.

12. Investment Representation. By accepting an Award, the Participant represents and covenants that (a) any share of Common Stock acquired upon the vesting of the Award will be acquired for investment and not with a view to the distribution thereof within the meaning of the Securities Act of 1933, as amended (the “Securities Act”), unless such acquisition has been registered under the Securities Act and any applicable state securities law; (b) any subsequent sale of any such shares shall be made either pursuant to an effective registration statement under the Securities Act and any applicable state securities laws, or pursuant to an exemption from registration under the Securities Act and such state securities laws; and (c) if requested by the Company, the Participant shall submit a written statement, in form satisfactory to the Company, to the effect that such representation (x) is true and correct as of the date of acquisition of any shares hereunder or (y) is true and correct as of the date of any sale of any such shares, as applicable. As a further condition precedent to the delivery to the Participant of any shares subject to the Award, the Participant shall comply with all regulations and requirements of any regulatory authority having control of or supervision over the issuance of the shares and, in connection therewith, shall execute any documents which the Company shall in its sole discretion deem necessary or advisable.

13. Award Confers No Rights to Continued Employment. In no event shall the granting of an Award or its acceptance by a Participant give or be deemed to give the Participant any right to continued employment by the Company.

14. Administrator. This Program shall be administered by the Company’s Vice President, Corporate Compensation (the “Administrator”). Except for authority reserved to the Board or the Committee, the Administrator shall have the right to interpret the Program, make any determinations hereunder, and take any necessary or appropriate actions with respect to the administration of the Program or in connection with each Award. Any such interpretation, determination or other action made or taken by the regarding this Program or an Award shall be final, binding and conclusive. The Administrator may adopt such rules and procedures as it deems appropriate for the administration of the Plan, including but not limited to rules and procedures governing the administration and treatment (e.g., pro-ration, vesting, etc.) of Awards to Participants in situations involving transfers between business units and eligible and ineligible positions, which may be set forth in the applicable Program summary or Award Notice.

## 15. Miscellaneous Provisions.



(a) Successors. This Program and each Award shall be binding upon and inure to the benefit of any successor or successors of the Company and any person or persons who shall, upon the death of a Participant, acquire any rights under such Award in accordance with this Program or the Plan.

(b) Notices. All notices, requests or other communications provided for in this Program (other than the exercise of a stock option) shall be made, if to the Company, to Exelon Corporation, 10 South Dearborn Street, Chicago, Illinois 60603, Attention: Vice President, Corporate Compensation, and if to the Participant, to his or her then current work location. All notices, requests or other communications provided for in this Program shall be made in writing either (a) by personal delivery to the party entitled thereto, (b) by facsimile with confirmation of receipt, (c) by mailing in the United States mails to the last known address of the party entitled thereto or (d) by express courier service. The notice, request or other communication shall be deemed to be received upon personal delivery, upon confirmation of receipt of facsimile transmission, or upon receipt by the party entitled thereto if by United States mail or express courier service; provided, however, that if a notice, request or other communication is not received during regular business hours, it shall be deemed to be received on the next succeeding business day of the Company.

(c) Section 409A. This Program and the Awards granted hereunder are intended to comply with the requirements of section 409A of the Code and shall be interpreted and construed consistently with such intent. Awards granted pursuant to this Program are also intended to be exempt from Section 409A of the Code to the maximum extent possible as short-term deferrals pursuant to Treasury regulation §1.409A-1(b)(4), and for this purpose each payment shall be considered a separate payment. In the event the terms of an Award would subject a Participant to taxes or penalties under Section 409A of the Code (“409A Penalties”), the Company may modify the terms of such Award to avoid such 409A Penalties, to the extent possible; provided that in no event shall the Company be responsible for any 409A Penalties that arise in connection with any Award. To the extent the timing of payment under an Award is determined by reference to a Participant’s “termination of employment,” such term shall be deemed to refer to the Participant’s “separation from service,” within the meaning of section 409A of the Code. Notwithstanding any other provision in this Program, if a Participant is a “specified employee,” as defined in Section 409A of the Code, as of the date of such Participant’s separation from service, then to the extent any amount payable to the Participant (i) constitutes the payment of nonqualified deferred compensation, within the meaning of Section 409A of the Code, (ii) is payable upon the Participant’s separation from service and (iii) under the terms of this Program would be payable prior to the six-month anniversary of the Participant’s separation from service, such payment shall be delayed until the earlier to occur of (A) the six-month anniversary of the separation from service and (B) the date of the Participant’s death.

(d) Amendment. The terms of this Program may be amended by the Committee or the Board (or their respective delegates), provided that the Chief Human Resources Officer or the Vice President, Corporate Compensation, of the Company may



amend the Program to comply with applicable law, to make administrative changes or to carry out directives of the Board or the Committee.

(e) Governing Law. This Program and each Award granted thereunder, and all determinations made and actions taken pursuant thereto, to the extent not governed by the laws of the United States, shall be governed by the laws of the Commonwealth of Pennsylvania and construed in accordance therewith without giving effect to principles of conflicts of laws.

IN WITNESS WHEREOF, Exelon Corporation has caused this instrument to be executed by its Senior Vice President & Chief Human Resources Officer, effective as of January 1, 2020.

EXELON CORPORATION

By:___

Senior Vice President &

Chief Human Resources Officer



Exelon Corporation (50% and Greater)
12/31/2019

<table><tr><td>Subsidiary</td><td>Jurisdiction</td></tr><tr><td>2014 ESA HoldCo, LLC</td><td>Delaware</td></tr><tr><td>2014 ESA Project Company, LLC</td><td>Delaware</td></tr><tr><td>2015 ESA Holdco, LLC</td><td>Delaware</td></tr><tr><td>2015 ESA Investco, LLC</td><td>Delaware</td></tr><tr><td>2015 ESA Project Company, LLC</td><td>Delaware</td></tr><tr><td>A/C Fuels Company</td><td>Pennsylvania</td></tr><tr><td>Aerolab Enterprises, LLC</td><td>Delaware</td></tr><tr><td>Albany Green Energy, LLC</td><td>Georgia</td></tr><tr><td>AMP Funding, L.L.C.</td><td>Delaware</td></tr><tr><td>Annova LNG Brownsville A, LLC</td><td>Delaware</td></tr><tr><td>Annova LNG Brownsville B, LLC</td><td>Delaware</td></tr><tr><td>Annova LNG Brownsville C, LLC</td><td>Delaware</td></tr><tr><td>Annova LNG Common Infrastructure, LLC</td><td>Delaware</td></tr><tr><td>Annova LNG, LLC</td><td>Delaware</td></tr><tr><td>APS Constellation, LLC</td><td>Delaware</td></tr><tr><td>Atlantic City Electric Company</td><td>New Jersey</td></tr><tr><td>Atlantic City Electric Transition Funding LLC</td><td>Delaware</td></tr><tr><td>Atlantic Generation, Inc.</td><td>New Jersey</td></tr><tr><td>Atlantic Southern Properties, Inc.</td><td>New Jersey</td></tr><tr><td>ATNP Finance Company</td><td>Delaware</td></tr><tr><td>AV Solar Ranch 1, LLC</td><td>Delaware</td></tr><tr><td>Baltimore Gas and Electric Company</td><td>Maryland</td></tr><tr><td>BC Energy LLC</td><td>Minnesota</td></tr><tr><td>Beebe 1B Renewable Energy, LLC</td><td>Delaware</td></tr><tr><td>Beebe Renewable Energy, LLC</td><td>Delaware</td></tr><tr><td>Bennett Creek Windfarm, LLC</td><td>Idaho</td></tr><tr><td>Bethlehem Renewable Energy, LLC</td><td>Delaware</td></tr><tr><td>BGE Home Products &amp; Services, LLC</td><td>Delaware</td></tr><tr><td>Big Top, LLC</td><td>Oregon</td></tr><tr><td>Blue Breezes II, L.L.C.</td><td>Minnesota</td></tr><tr><td>Blue Breezes, L.L.C.</td><td>Minnesota</td></tr><tr><td>Blue Ridge Renewable Energy, LLC</td><td>Delaware</td></tr><tr><td>Bluestem Wind Energy Holdings, LLC</td><td>Delaware</td></tr><tr><td>Bluestem Wind Energy Member Holdings, LLC</td><td>Delaware</td></tr><tr><td>Bluestem Wind Energy Member, LLC</td><td>Delaware</td></tr><tr><td>Bluestem Wind Energy, LLC</td><td>Delaware</td></tr><tr><td>Breakerbox, LLC</td><td>Pennsylvania</td></tr></table>



<table><tr><td>Butter Creek Power, LLC</td><td>Oregon</td></tr><tr><td>California PV Energy 2, LLC</td><td>Delaware</td></tr><tr><td>California PV Energy 3, LLC</td><td>Delaware</td></tr><tr><td>California PV Energy, LLC</td><td>Delaware</td></tr><tr><td>Calvert Cliffs Nuclear Power Plant, LLC</td><td>Maryland</td></tr><tr><td>Cassia Gulch Wind Park LLC</td><td>Idaho</td></tr><tr><td>Cassia Wind Farm LLC</td><td>Idaho</td></tr><tr><td>CD Panther I, Inc.</td><td>Maryland</td></tr><tr><td>CD Panther II, LLC</td><td>Delaware</td></tr><tr><td>CD Panther Partners, L.P.</td><td>Delaware</td></tr><tr><td>CD SEGS V, Inc.</td><td>Maryland</td></tr><tr><td>CD SEGS VI, Inc.</td><td>Maryland</td></tr><tr><td>CE Culm, Inc.</td><td>Maryland</td></tr><tr><td>CE FundingCo, LLC</td><td>Delaware</td></tr><tr><td>CE Nuclear, LLC</td><td>Delaware</td></tr><tr><td>CER Generation, LLC</td><td>Delaware</td></tr><tr><td>CEU Arkoma West, LLC</td><td>Delaware</td></tr><tr><td>CEU CoLa, LLC</td><td>Delaware</td></tr><tr><td>CEU East Fort Peck, LLC</td><td>Delaware</td></tr><tr><td>CEU Fayetteville, LLC</td><td>Delaware</td></tr><tr><td>CEU Floyd Shale, LLC</td><td>Delaware</td></tr><tr><td>CEU Holdings, LLC</td><td>Delaware</td></tr><tr><td>CEU Huntsville, LLC</td><td>Delaware</td></tr><tr><td>CEU Kingston, LLC</td><td>Delaware</td></tr><tr><td>CEU Niobrara, LLC</td><td>Delaware</td></tr><tr><td>CEU Ohio Shale, LLC</td><td>Delaware</td></tr><tr><td>CEU Paradigm, LLC</td><td>Delaware</td></tr><tr><td>CEU Pinedale, LLC</td><td>Delaware</td></tr><tr><td>CEU Plymouth, LLC</td><td>Delaware</td></tr><tr><td>CEU Simplicity, LLC</td><td>Delaware</td></tr><tr><td>CEU W&amp;D, LLC</td><td>Delaware</td></tr><tr><td>Chesapeake HVAC, Inc.</td><td>Delaware</td></tr><tr><td>CII Solarpower I, Inc.</td><td>Maryland</td></tr><tr><td>Clean Jobs for Pennsylvania, LLC</td><td>Delaware</td></tr><tr><td>Clinton Battery Utility, LLC</td><td>Delaware</td></tr><tr><td>CLT Energy Services Group, L.L.C.</td><td>Pennsylvania</td></tr><tr><td>CNE Gas Holdings, LLC</td><td>Kentucky</td></tr><tr><td>CNEG Holdings, LLC</td><td>Delaware</td></tr><tr><td>CNEGH Holdings, LLC</td><td>Delaware</td></tr><tr><td>CoLa Resources LLC</td><td>Delaware</td></tr><tr><td>Colorado Bend II Power, LLC</td><td>Delaware</td></tr></table>



<table><tr><td>Colorado Bend Services, LLC</td><td>Delaware</td></tr><tr><td>ComEd Financing III</td><td>Delaware</td></tr><tr><td>Commonwealth Edison Company</td><td>Illinois</td></tr><tr><td>Commonwealth Edison Company of Indiana, Inc.</td><td>Indiana</td></tr><tr><td>Conectiv Communications, Inc.</td><td>Delaware</td></tr><tr><td>Conectiv Energy Supply, Inc.</td><td>Delaware</td></tr><tr><td>Conectiv North East, LLC</td><td>Delaware</td></tr><tr><td>Conectiv Properties and Investments, Inc.</td><td>Delaware</td></tr><tr><td>Conectiv Solutions LLC</td><td>Delaware</td></tr><tr><td>Conectiv, LLC</td><td>Delaware</td></tr><tr><td>Constellation Connect, LLC</td><td>Delaware</td></tr><tr><td>Constellation DCO Albany Power Holdings, LLC</td><td>Delaware</td></tr><tr><td>Constellation EG, LLC</td><td>Delaware</td></tr><tr><td>Constellation Energy Canada, Inc.</td><td>Ontario</td></tr><tr><td>Constellation Energy Commodities Group Maine, LLC</td><td>Delaware</td></tr><tr><td>Constellation Energy Gas Choice, LLC</td><td>Delaware</td></tr><tr><td>Constellation Energy Nuclear Group, LLC</td><td>Maryland</td></tr><tr><td>Constellation Energy Power Choice, LLC</td><td>Delaware</td></tr><tr><td>Constellation Energy Resources, LLC</td><td>Delaware</td></tr><tr><td>Constellation Energy Upstream Holdings, LLC</td><td>Delaware</td></tr><tr><td>Constellation Holdings, LLC</td><td>Maryland</td></tr><tr><td>Constellation LNG, LLC</td><td>Delaware</td></tr><tr><td>Constellation Mystic Power, LLC</td><td>Delaware</td></tr><tr><td>Constellation NewEnergy - Gas Division, LLC</td><td>Kentucky</td></tr><tr><td>Constellation NewEnergy, Inc.</td><td>Delaware</td></tr><tr><td>Constellation Nuclear Power Plants, LLC</td><td>Delaware</td></tr><tr><td>Constellation Nuclear, LLC</td><td>Delaware</td></tr><tr><td>Constellation Power Source Generation, LLC</td><td>Maryland</td></tr><tr><td>Constellation Power, Inc.</td><td>Maryland</td></tr><tr><td>Constellation Solar Arizona 2, LLC</td><td>Delaware</td></tr><tr><td>Constellation Solar Arizona, LLC</td><td>Delaware</td></tr><tr><td>Constellation Solar California, LLC</td><td>Delaware</td></tr><tr><td>Constellation Solar Connecticut, LLC</td><td>Delaware</td></tr><tr><td>Constellation Solar DC, LLC</td><td>Delaware</td></tr><tr><td>Constellation Solar Federal, LLC</td><td>Delaware</td></tr><tr><td>Constellation Solar Georgia 2, LLC</td><td>Delaware</td></tr><tr><td>Constellation Solar Georgia, LLC</td><td>Georgia</td></tr><tr><td>Constellation Solar Holding, LLC</td><td>Delaware</td></tr><tr><td>Constellation Solar Horizons, LLC</td><td>Delaware</td></tr><tr><td>Constellation Solar Illinois 2, LLC</td><td>Delaware</td></tr><tr><td>Constellation Solar Illinois, LLC</td><td>Delaware</td></tr></table>



<table><tr><td>Constellation Solar Maryland II, LLC</td><td>Delaware</td></tr><tr><td>Constellation Solar Maryland, LLC</td><td>Delaware</td></tr><tr><td>Constellation Solar Massachusetts, LLC</td><td>Delaware</td></tr><tr><td>Constellation Solar MC, LLC</td><td>Delaware</td></tr><tr><td>Constellation Solar Net Metering, LLC</td><td>Delaware</td></tr><tr><td>Constellation Solar New Jersey II, LLC</td><td>Delaware</td></tr><tr><td>Constellation Solar New Jersey III, LLC</td><td>Delaware</td></tr><tr><td>Constellation Solar New Jersey, LLC</td><td>Delaware</td></tr><tr><td>Constellation Solar New York, LLC</td><td>Delaware</td></tr><tr><td>Constellation Solar Ohio, LLC</td><td>Delaware</td></tr><tr><td>Constellation Solar Rhode Island, LLC</td><td>Delaware</td></tr><tr><td>Constellation Solar Texas, LLC</td><td>Delaware</td></tr><tr><td>Constellation Solar, LLC</td><td>Delaware</td></tr><tr><td>Continental Wind Holding, LLC</td><td>Delaware</td></tr><tr><td>Continental Wind, LLC</td><td>Delaware</td></tr><tr><td>COSI Central Wayne, Inc.</td><td>Maryland</td></tr><tr><td>COSI Sunnyside, Inc.</td><td>Maryland</td></tr><tr><td>Cow Branch Wind Power, L.L.C.</td><td>Missouri</td></tr><tr><td>CP Sunnyside I, Inc.</td><td>Maryland</td></tr><tr><td>CP Windfarm, LLC</td><td>Minnesota</td></tr><tr><td>CR Clearing, LLC</td><td>Missouri</td></tr><tr><td>Criterion Power Partners, LLC</td><td>Delaware</td></tr><tr><td>Data Center Enterprise, LLC</td><td>Delaware</td></tr><tr><td>DE Asset Operations, LLC</td><td>Delaware</td></tr><tr><td>DE ESCO, LLC</td><td>Delaware</td></tr><tr><td>Delaware Operating Services Company, LLC</td><td>Delaware</td></tr><tr><td>Delmarva Power &amp; Light Company</td><td>Delaware &amp; Virginia</td></tr><tr><td>Denver Airport Solar, LLC</td><td>Delaware</td></tr><tr><td>Distributed Generation Partners, LLC</td><td>Delaware</td></tr><tr><td>Distrigas of Massachusetts LLC</td><td>Delaware</td></tr><tr><td>E&amp;W Development Corporation</td><td>Florida</td></tr><tr><td>EdiSun, LLC</td><td>Delaware</td></tr><tr><td>Energy Performance Services, Inc.</td><td>Pennsylvania</td></tr><tr><td>ETT Canada, Inc.</td><td>New Brunswick</td></tr><tr><td>Everett LNG LLC</td><td>Delaware</td></tr><tr><td>Ewington Energy Systems LLC</td><td>Minnesota</td></tr><tr><td>Exelon AVSR Holding, LLC</td><td>Delaware</td></tr><tr><td>Exelon AVSR, LLC</td><td>Delaware</td></tr><tr><td>Exelon Business Services Company, LLC</td><td>Delaware</td></tr><tr><td>Exelon Energy Delivery Company, LLC</td><td>Delaware</td></tr><tr><td>Exelon Enterprises Company, LLC</td><td>Pennsylvania</td></tr></table>



<table><tr><td>Exelon FitzPatrick, LLC</td><td>Delaware</td></tr><tr><td>Exelon Framingham, LLC</td><td>Delaware</td></tr><tr><td>Exelon Fulton, LLC</td><td>Delaware</td></tr><tr><td>Exelon Generation Acquisitions, LLC</td><td>Delaware</td></tr><tr><td>Exelon Generation Company, LLC</td><td>Pennsylvania</td></tr><tr><td>Exelon Generation Consolidation, LLC</td><td>Illinois</td></tr><tr><td>Exelon Generation Finance Company, LLC</td><td>Delaware</td></tr><tr><td>Exelon Generation Limited</td><td>United Kingdom</td></tr><tr><td>Exelon Genesis, LLC</td><td>Delaware</td></tr><tr><td>Exelon InQB8R, LLC</td><td>Delaware</td></tr><tr><td>Exelon Mechanical, LLC</td><td>Delaware</td></tr><tr><td>Exelon Microgrid, LLC</td><td>Delaware</td></tr><tr><td>Exelon New Boston, LLC</td><td>Delaware</td></tr><tr><td>Exelon New England Holdings, LLC</td><td>Delaware</td></tr><tr><td>Exelon Nuclear Partners, LLC</td><td>Delaware</td></tr><tr><td>Exelon Nuclear Security, LLC</td><td>Delaware</td></tr><tr><td>Exelon PowerLabs, LLC</td><td>Pennsylvania</td></tr><tr><td>Exelon Solar Chicago LLC</td><td>Delaware</td></tr><tr><td>Exelon Transmission Company, LLC</td><td>Delaware</td></tr><tr><td>Exelon VTI, LLC</td><td>Delaware</td></tr><tr><td>Exelon West Medway II, LLC</td><td>Delaware</td></tr><tr><td>Exelon West Medway, LLC</td><td>Delaware</td></tr><tr><td>Exelon Wind 1, LLC</td><td>Texas</td></tr><tr><td>Exelon Wind 2, LLC</td><td>Texas</td></tr><tr><td>Exelon Wind 3, LLC</td><td>Texas</td></tr><tr><td>Exelon Wind Canada Inc.</td><td>Canada</td></tr><tr><td>Exelon Wind, LLC</td><td>Delaware</td></tr><tr><td>Exelon Wyman, LLC</td><td>Delaware</td></tr><tr><td>Exelorate Enterprises, LLC</td><td>Delaware</td></tr><tr><td>Ex-FM, Inc.</td><td>New York</td></tr><tr><td>Ex-FME, Inc.</td><td>Delaware</td></tr><tr><td>ExGen Energy, S. de R.L. de C.V.</td><td>Mexico</td></tr><tr><td>ExGen Handley Power, LLC</td><td>Delaware</td></tr><tr><td>ExGen Renewables Holdings II, LLC</td><td>Delaware</td></tr><tr><td>ExGen Renewables Holdings, LLC</td><td>Delaware</td></tr><tr><td>ExGen Renewables I Holding, LLC</td><td>Delaware</td></tr><tr><td>ExGen Renewables I, LLC</td><td>Delaware</td></tr><tr><td>ExGen Renewables II, LLC</td><td>Delaware</td></tr><tr><td>ExGen Renewables IV Holding, LLC</td><td>Delaware</td></tr><tr><td>ExGen Renewables IV, LLC</td><td>Delaware</td></tr><tr><td>ExGen Renewables Partners, LLC</td><td>Delaware</td></tr></table>



<table><tr><td>ExGen Texas II Power Holdings, LLC</td><td>Delaware</td></tr><tr><td>ExGen Texas II Power, LLC</td><td>Delaware</td></tr><tr><td>ExGen Texas Power Services, LLC</td><td>Delaware</td></tr><tr><td>ExGen Ventures International Holdings II Limited</td><td>United Kingdom</td></tr><tr><td>ExGen Ventures International Holdings Limited</td><td>United Kingdom</td></tr><tr><td>ExTel Corporation, LLC</td><td>Delaware</td></tr><tr><td>EZEV Enterprise, LLC</td><td>Delaware</td></tr><tr><td>F &amp; M Holdings Company, L.L.C.</td><td>Delaware</td></tr><tr><td>Fair Wind Power Partners, LLC</td><td>Delaware</td></tr><tr><td>Fauquier Landfill Gas, L.L.C.</td><td>Delaware</td></tr><tr><td>Four Corners Windfarm, LLC</td><td>Oregon</td></tr><tr><td>Four Mile Canyon Windfarm, LLC</td><td>Oregon</td></tr><tr><td>Fourmile Wind Energy, LLC</td><td>Maryland</td></tr><tr><td>Friendly Skies, Inc.</td><td>U.S. Virgin Islands</td></tr><tr><td>Gateway Solar LLC</td><td>Delaware</td></tr><tr><td>Grande Prairie Generation, Inc.</td><td>Alberta</td></tr><tr><td>Greensburg Wind Farm, LLC</td><td>Delaware</td></tr><tr><td>Handsome Lake Energy, LLC</td><td>Maryland</td></tr><tr><td>Harvest II Windfarm, LLC</td><td>Delaware</td></tr><tr><td>Harvest Windfarm, LLC</td><td>Michigan</td></tr><tr><td>High Mesa Energy, LLC</td><td>Idaho</td></tr><tr><td>High Plains Wind Power, LLC</td><td>Texas</td></tr><tr><td>Holyoke Solar, LLC</td><td>Delaware</td></tr><tr><td>Hot Springs Windfarm, LLC</td><td>Idaho</td></tr><tr><td>JBAB Solar I, LLC</td><td>Delaware</td></tr><tr><td>JExel Nuclear Company</td><td>Japan</td></tr><tr><td>K &amp; D Energy LLC</td><td>Minnesota</td></tr><tr><td>KC Energy LLC</td><td>Minnesota</td></tr><tr><td>KSS Turbines LLC</td><td>Minnesota</td></tr><tr><td>Lake Houston Power, LLC</td><td>Delaware</td></tr><tr><td>Loess Hills Wind Farm, LLC</td><td>Missouri</td></tr><tr><td>Michigan Wind 1, LLC</td><td>Delaware</td></tr><tr><td>Michigan Wind 2, LLC</td><td>Delaware</td></tr><tr><td>Michigan Wind 3, LLC</td><td>Delaware</td></tr><tr><td>Millennium Account Services, LLC</td><td>Delaware</td></tr><tr><td>Minergy LLC</td><td>Wisconsin</td></tr><tr><td>Mohave Sunrise Solar I, LLC</td><td>Arizona</td></tr><tr><td>Mountain Top Wind Power, LLC</td><td>Maryland</td></tr><tr><td>Nine Mile Point Nuclear Station, LLC</td><td>Delaware</td></tr><tr><td>North Shore District Energy, LLC</td><td>Delaware</td></tr><tr><td>Northwind Thermal Technologies Canada Inc.</td><td>New Brunswick</td></tr></table>



<table><tr><td>Oregon Trail Windfarm, LLC</td><td>Oregon</td></tr><tr><td>Outback Solar, LLC</td><td>Oregon</td></tr><tr><td>Pacific Canyon Windfarm, LLC</td><td>Oregon</td></tr><tr><td>Panther Creek Holdings, Inc.</td><td>Delaware</td></tr><tr><td>Panther Creek Partners</td><td>Delaware</td></tr><tr><td>PCI - BT Investing, L.L.C.</td><td>Delaware</td></tr><tr><td>PCI Air Management Corporation</td><td>Nevada</td></tr><tr><td>PCI Air Management Partners, L.L.C.</td><td>Delaware</td></tr><tr><td>PEC Financial Services, LLC</td><td>Pennsylvania</td></tr><tr><td>PECO Energy Capital Corp.</td><td>Delaware</td></tr><tr><td>PECO Energy Capital Trust III</td><td>Delaware</td></tr><tr><td>PECO Energy Capital Trust IV</td><td>Delaware</td></tr><tr><td>PECO Energy Capital, L.P.</td><td>Delaware</td></tr><tr><td>PECO Energy Company</td><td>Pennsylvania</td></tr><tr><td>PECO Wireless, LLC</td><td>Delaware</td></tr><tr><td>Pegasus Power Company, Inc.</td><td>California</td></tr><tr><td>Pepco Building Services Inc.</td><td>Delaware</td></tr><tr><td>Pepco Energy Cogeneration LLC</td><td>Delaware</td></tr><tr><td>Pepco Energy Solutions LLC</td><td>Delaware</td></tr><tr><td>Pepco Government Services LLC</td><td>Delaware</td></tr><tr><td>Pepco Holdings LLC</td><td>Delaware</td></tr><tr><td>PFMG Construction, Ltd.</td><td>California</td></tr><tr><td>PFMG Solar Baldwin Park, LLC</td><td>Delaware</td></tr><tr><td>PFMG Solar Etiwanda Falcon, LLC</td><td>Delaware</td></tr><tr><td>PFMG Solar Long Beach, LLC</td><td>Delaware</td></tr><tr><td>PFMG Solar PUSD, LLC</td><td>Delaware</td></tr><tr><td>PFMG Solar San Diego, LLC</td><td>Delaware</td></tr><tr><td>PFMG Solar, LLC</td><td>Delaware</td></tr><tr><td>PH Holdco LLC</td><td>Delaware</td></tr><tr><td>PHI Service Company</td><td>Delaware</td></tr><tr><td>Pinedale Energy, LLC</td><td>Colorado</td></tr><tr><td>POM Holdings, Inc.</td><td>Delaware</td></tr><tr><td>Potomac Capital Investment Corporation</td><td>Delaware</td></tr><tr><td>Potomac Delaware Leasing Corporation</td><td>Delaware</td></tr><tr><td>Potomac Electric Power Company</td><td>District of Columbia &amp; Virginia</td></tr><tr><td>Potomac Leasing Associates, L.P.</td><td>Delaware</td></tr><tr><td>Potomac Power Resources, LLC</td><td>Delaware</td></tr><tr><td>Prairie Wind Power LLC</td><td>Minnesota</td></tr><tr><td>R.E. Ginna Nuclear Power Plant, LLC</td><td>Maryland</td></tr><tr><td>Ramp Investments, L.L.C.</td><td>Delaware</td></tr><tr><td>Renewable Power Generation Holdings, LLC</td><td>Delaware</td></tr></table>



<table><tr><td>Renewable Power Generation, LLC</td><td>Delaware</td></tr><tr><td>RF HoldCo LLC</td><td>Delaware</td></tr><tr><td>RITELine Illinois, LLC</td><td>Illinois</td></tr><tr><td>RITELine Transmission Development, LLC</td><td>Delaware</td></tr><tr><td>Rolling Hills Landfill Gas, LLC</td><td>Delaware</td></tr><tr><td>Sacramento PV Energy, LLC</td><td>Delaware</td></tr><tr><td>Sand Ranch Windfarm, LLC</td><td>Oregon</td></tr><tr><td>Scherer Holdings 1, LLC</td><td>Delaware</td></tr><tr><td>Scherer Holdings 2, LLC</td><td>Delaware</td></tr><tr><td>Scherer Holdings 3, LLC</td><td>Delaware</td></tr><tr><td>Sendero Wind Energy, LLC</td><td>Delaware</td></tr><tr><td>Series A of Annova LNG, LLC</td><td>Delaware</td></tr><tr><td>Series B of Annova LNG, LLC</td><td>Delaware</td></tr><tr><td>Series C of Annova LNG, LLC</td><td>Delaware</td></tr><tr><td>Series Z of Annova LNG, LLC</td><td>Delaware</td></tr><tr><td>Shooting Star Wind Project, LLC</td><td>Delaware</td></tr><tr><td>Sky Valley, LLC</td><td>Delaware</td></tr><tr><td>SolGen Holding, LLC</td><td>Delaware</td></tr><tr><td>SolGen, LLC</td><td>Delaware</td></tr><tr><td>Sugar Beet Wind, LLC</td><td>Delaware</td></tr><tr><td>Sunnyside II, Inc.</td><td>Delaware</td></tr><tr><td>Sunnyside II, L.P.</td><td>Delaware</td></tr><tr><td>Sunnyside III, Inc.</td><td>Delaware</td></tr><tr><td>Threemile Canyon Wind I, LLC</td><td>Oregon</td></tr><tr><td>Titan STC, LLC</td><td>Delaware</td></tr><tr><td>Tuana Springs Energy, LLC</td><td>Idaho</td></tr><tr><td>UII, LLC</td><td>Illinois</td></tr><tr><td>V.G. Investment Holdings, LLC</td><td>Delaware</td></tr><tr><td>Vineland Cogeneration Limited Partnership</td><td>Delaware</td></tr><tr><td>Vineland General, Inc.</td><td>Delaware</td></tr><tr><td>Vineland Ltd., Inc.</td><td>Delaware</td></tr><tr><td>Volta SPV CMX, LLC</td><td>Delaware</td></tr><tr><td>Volta SPV NSC, LLC</td><td>Delaware</td></tr><tr><td>Volta SPV NTR, LLC</td><td>Delaware</td></tr><tr><td>W&amp;D Gas Partners, LLC</td><td>Delaware</td></tr><tr><td>Wagon Trail, LLC</td><td>Oregon</td></tr><tr><td>Wansley Holdings 1, LLC</td><td>Delaware</td></tr><tr><td>Wansley Holdings 2, LLC</td><td>Delaware</td></tr><tr><td>Ward Butte Windfarm, LLC</td><td>Oregon</td></tr><tr><td>Water &amp; Energy Savings Company, LLC</td><td>Delaware</td></tr><tr><td>Whitetail Wind Energy, LLC</td><td>Delaware</td></tr></table>



<table><tr><td>Wildcat Finance, LLC</td><td>Delaware</td></tr><tr><td>Wildcat Wind LLC</td><td>New Mexico</td></tr><tr><td>Wind Capital Holdings, LLC</td><td>Missouri</td></tr><tr><td>Wolf Hollow II Power, LLC</td><td>Delaware</td></tr><tr><td>Wolf Hollow Services, LLC</td><td>Delaware</td></tr></table>



Exelon Generation Company, LLC (50% and Greater)
12/31/2019

<table><tr><td>Subsidiary</td><td>Jurisdiction</td></tr><tr><td>2014 ESA HoldCo, LLC</td><td>Delaware</td></tr><tr><td>2014 ESA Project Company, LLC</td><td>Delaware</td></tr><tr><td>2015 ESA Holdco, LLC</td><td>Delaware</td></tr><tr><td>2015 ESA Investco, LLC</td><td>Delaware</td></tr><tr><td>2015 ESA Project Company, LLC</td><td>Delaware</td></tr><tr><td>A/C Fuels Company</td><td>Pennsylvania</td></tr><tr><td>Albany Green Energy, LLC</td><td>Georgia</td></tr><tr><td>Annova LNG Brownsville A, LLC</td><td>Delaware</td></tr><tr><td>Annova LNG Brownsville B, LLC</td><td>Delaware</td></tr><tr><td>Annova LNG Brownsville C, LLC</td><td>Delaware</td></tr><tr><td>Annova LNG Common Infrastructure, LLC</td><td>Delaware</td></tr><tr><td>Annova LNG, LLC</td><td>Delaware</td></tr><tr><td>APS Constellation, LLC</td><td>Delaware</td></tr><tr><td>Atlantic Generation, Inc.</td><td>New Jersey</td></tr><tr><td>AV Solar Ranch 1, LLC</td><td>Delaware</td></tr><tr><td>BC Energy LLC</td><td>Minnesota</td></tr><tr><td>Beebe 1B Renewable Energy, LLC</td><td>Delaware</td></tr><tr><td>Beebe Renewable Energy, LLC</td><td>Delaware</td></tr><tr><td>Bennett Creek Windfarm, LLC</td><td>Idaho</td></tr><tr><td>Bethlehem Renewable Energy, LLC</td><td>Delaware</td></tr><tr><td>BGE Home Products &amp; Services, LLC</td><td>Delaware</td></tr><tr><td>Big Top, LLC</td><td>Oregon</td></tr><tr><td>Blue Breezes II, L.L.C.</td><td>Minnesota</td></tr><tr><td>Blue Breezes, L.L.C.</td><td>Minnesota</td></tr><tr><td>Blue Ridge Renewable Energy, LLC</td><td>Delaware</td></tr><tr><td>Bluestem Wind Energy Holdings, LLC</td><td>Delaware</td></tr><tr><td>Bluestem Wind Energy Member Holdings, LLC</td><td>Delaware</td></tr><tr><td>Bluestem Wind Energy Member, LLC</td><td>Delaware</td></tr><tr><td>Bluestem Wind Energy, LLC</td><td>Delaware</td></tr><tr><td>Breakerbox, LLC</td><td>Pennsylvania</td></tr><tr><td>Butter Creek Power, LLC</td><td>Oregon</td></tr><tr><td>California PV Energy 2, LLC</td><td>Delaware</td></tr><tr><td>California PV Energy 3, LLC</td><td>Delaware</td></tr><tr><td>California PV Energy, LLC</td><td>Delaware</td></tr><tr><td>Calvert Cliffs Nuclear Power Plant, LLC</td><td>Maryland</td></tr><tr><td>Cassia Gulch Wind Park LLC</td><td>Idaho</td></tr><tr><td>Cassia Wind Farm LLC</td><td>Idaho</td></tr><tr><td>CD Panther I, Inc.</td><td>Maryland</td></tr></table>



<table><tr><td>CD Panther II, LLC</td><td>Delaware</td></tr><tr><td>CD Panther Partners, L.P.</td><td>Delaware</td></tr><tr><td>CD SEGS V, Inc.</td><td>Maryland</td></tr><tr><td>CD SEGS VI, Inc.</td><td>Maryland</td></tr><tr><td>CE Culm, Inc.</td><td>Maryland</td></tr><tr><td>CE FundingCo, LLC</td><td>Delaware</td></tr><tr><td>CE Nuclear, LLC</td><td>Delaware</td></tr><tr><td>CER Generation, LLC</td><td>Delaware</td></tr><tr><td>CEU Arkoma West, LLC</td><td>Delaware</td></tr><tr><td>CEU CoLa, LLC</td><td>Delaware</td></tr><tr><td>CEU East Fort Peck, LLC</td><td>Delaware</td></tr><tr><td>CEU Fayetteville, LLC</td><td>Delaware</td></tr><tr><td>CEU Floyd Shale, LLC</td><td>Delaware</td></tr><tr><td>CEU Holdings, LLC</td><td>Delaware</td></tr><tr><td>CEU Huntsville, LLC</td><td>Delaware</td></tr><tr><td>CEU Kingston, LLC</td><td>Delaware</td></tr><tr><td>CEU Niobrara, LLC</td><td>Delaware</td></tr><tr><td>CEU Ohio Shale, LLC</td><td>Delaware</td></tr><tr><td>CEU Paradigm, LLC</td><td>Delaware</td></tr><tr><td>CEU Pinedale, LLC</td><td>Delaware</td></tr><tr><td>CEU Plymouth, LLC</td><td>Delaware</td></tr><tr><td>CEU Simplicity, LLC</td><td>Delaware</td></tr><tr><td>CEU W&amp;D, LLC</td><td>Delaware</td></tr><tr><td>Chesapeake HVAC, Inc.</td><td>Delaware</td></tr><tr><td>CII Solarpower I, Inc.</td><td>Maryland</td></tr><tr><td>Clinton Battery Utility, LLC</td><td>Delaware</td></tr><tr><td>CLT Energy Services Group, L.L.C.</td><td>Pennsylvania</td></tr><tr><td>CNE Gas Holdings, LLC</td><td>Kentucky</td></tr><tr><td>CNEG Holdings, LLC</td><td>Delaware</td></tr><tr><td>CNEGH Holdings, LLC</td><td>Delaware</td></tr><tr><td>CoLa Resources LLC</td><td>Delaware</td></tr><tr><td>Colorado Bend II Power, LLC</td><td>Delaware</td></tr><tr><td>Colorado Bend Services, LLC</td><td>Delaware</td></tr><tr><td>Conectiv Energy Supply, Inc.</td><td>Delaware</td></tr><tr><td>Conectiv North East, LLC</td><td>Delaware</td></tr><tr><td>Conectiv, LLC</td><td>Delaware</td></tr><tr><td>Constellation Connect, LLC</td><td>Delaware</td></tr><tr><td>Constellation DCO Albany Power Holdings, LLC</td><td>Delaware</td></tr><tr><td>Constellation EG, LLC</td><td>Delaware</td></tr><tr><td>Constellation Energy Canada, Inc.</td><td>Ontario</td></tr><tr><td>Constellation Energy Commodities Group Maine, LLC</td><td>Delaware</td></tr></table>



<table><tr><td>Constellation Energy Gas Choice, LLC</td><td>Delaware</td></tr><tr><td>Constellation Energy Nuclear Group, LLC</td><td>Maryland</td></tr><tr><td>Constellation Energy Power Choice, LLC</td><td>Delaware</td></tr><tr><td>Constellation Energy Resources, LLC</td><td>Delaware</td></tr><tr><td>Constellation Energy Upstream Holdings, LLC</td><td>Delaware</td></tr><tr><td>Constellation Holdings, LLC</td><td>Maryland</td></tr><tr><td>Constellation LNG, LLC</td><td>Delaware</td></tr><tr><td>Constellation Mystic Power, LLC</td><td>Delaware</td></tr><tr><td>Constellation NewEnergy - Gas Division, LLC</td><td>Kentucky</td></tr><tr><td>Constellation NewEnergy, Inc.</td><td>Delaware</td></tr><tr><td>Constellation Nuclear Power Plants, LLC</td><td>Delaware</td></tr><tr><td>Constellation Nuclear, LLC</td><td>Delaware</td></tr><tr><td>Constellation Power Source Generation, LLC</td><td>Maryland</td></tr><tr><td>Constellation Power, Inc.</td><td>Maryland</td></tr><tr><td>Constellation Solar Arizona 2, LLC</td><td>Delaware</td></tr><tr><td>Constellation Solar Arizona, LLC</td><td>Delaware</td></tr><tr><td>Constellation Solar California, LLC</td><td>Delaware</td></tr><tr><td>Constellation Solar Connecticut, LLC</td><td>Delaware</td></tr><tr><td>Constellation Solar DC, LLC</td><td>Delaware</td></tr><tr><td>Constellation Solar Federal, LLC</td><td>Delaware</td></tr><tr><td>Constellation Solar Georgia 2, LLC</td><td>Delaware</td></tr><tr><td>Constellation Solar Georgia, LLC</td><td>Georgia</td></tr><tr><td>Constellation Solar Holding, LLC</td><td>Delaware</td></tr><tr><td>Constellation Solar Horizons, LLC</td><td>Delaware</td></tr><tr><td>Constellation Solar Illinois 2, LLC</td><td>Delaware</td></tr><tr><td>Constellation Solar Illinois, LLC</td><td>Delaware</td></tr><tr><td>Constellation Solar Maryland II, LLC</td><td>Delaware</td></tr><tr><td>Constellation Solar Maryland, LLC</td><td>Delaware</td></tr><tr><td>Constellation Solar Massachusetts, LLC</td><td>Delaware</td></tr><tr><td>Constellation Solar MC, LLC</td><td>Delaware</td></tr><tr><td>Constellation Solar Net Metering, LLC</td><td>Delaware</td></tr><tr><td>Constellation Solar New Jersey II, LLC</td><td>Delaware</td></tr><tr><td>Constellation Solar New Jersey III, LLC</td><td>Delaware</td></tr><tr><td>Constellation Solar New Jersey, LLC</td><td>Delaware</td></tr><tr><td>Constellation Solar New York, LLC</td><td>Delaware</td></tr><tr><td>Constellation Solar Ohio, LLC</td><td>Delaware</td></tr><tr><td>Constellation Solar Rhode Island, LLC</td><td>Delaware</td></tr><tr><td>Constellation Solar Texas, LLC</td><td>Delaware</td></tr><tr><td>Constellation Solar, LLC</td><td>Delaware</td></tr><tr><td>Continental Wind Holding, LLC</td><td>Delaware</td></tr><tr><td>Continental Wind, LLC</td><td>Delaware</td></tr></table>



<table><tr><td>COSI Central Wayne, Inc.</td><td>Maryland</td></tr><tr><td>COSI Sunnyside, Inc.</td><td>Maryland</td></tr><tr><td>Cow Branch Wind Power, L.L.C.</td><td>Missouri</td></tr><tr><td>CP Sunnyside I, Inc.</td><td>Maryland</td></tr><tr><td>CP Windfarm, LLC</td><td>Minnesota</td></tr><tr><td>CR Clearing, LLC</td><td>Missouri</td></tr><tr><td>Criterion Power Partners, LLC</td><td>Delaware</td></tr><tr><td>DE Asset Operations, LLC</td><td>Delaware</td></tr><tr><td>DE ESCO, LLC</td><td>Delaware</td></tr><tr><td>Delaware Operating Services Company, LLC</td><td>Delaware</td></tr><tr><td>Denver Airport Solar, LLC</td><td>Delaware</td></tr><tr><td>Distributed Generation Partners, LLC</td><td>Delaware</td></tr><tr><td>Distrigas of Massachusetts LLC</td><td>Delaware</td></tr><tr><td>Energy Performance Services, Inc.</td><td>Pennsylvania</td></tr><tr><td>Everett LNG LLC</td><td>Delaware</td></tr><tr><td>Ewington Energy Systems LLC</td><td>Minnesota</td></tr><tr><td>Exelon AVSR Holding, LLC</td><td>Delaware</td></tr><tr><td>Exelon AVSR, LLC</td><td>Delaware</td></tr><tr><td>Exelon FitzPatrick, LLC</td><td>Delaware</td></tr><tr><td>Exelon Framingham, LLC</td><td>Delaware</td></tr><tr><td>Exelon Fulton, LLC</td><td>Delaware</td></tr><tr><td>Exelon Generation Acquisitions, LLC</td><td>Delaware</td></tr><tr><td>Exelon Generation Consolidation, LLC</td><td>Illinois</td></tr><tr><td>Exelon Generation Finance Company, LLC</td><td>Delaware</td></tr><tr><td>Exelon Generation Limited</td><td>United Kingdom</td></tr><tr><td>Exelon New Boston, LLC</td><td>Delaware</td></tr><tr><td>Exelon New England Holdings, LLC</td><td>Delaware</td></tr><tr><td>Exelon Nuclear Partners, LLC</td><td>Delaware</td></tr><tr><td>Exelon Nuclear Security, LLC</td><td>Delaware</td></tr><tr><td>Exelon PowerLabs, LLC</td><td>Pennsylvania</td></tr><tr><td>Exelon Solar Chicago LLC</td><td>Delaware</td></tr><tr><td>Exelon West Medway II, LLC</td><td>Delaware</td></tr><tr><td>Exelon West Medway, LLC</td><td>Delaware</td></tr><tr><td>Exelon Wind 1, LLC</td><td>Texas</td></tr><tr><td>Exelon Wind 2, LLC</td><td>Texas</td></tr><tr><td>Exelon Wind 3, LLC</td><td>Texas</td></tr><tr><td>Exelon Wind Canada Inc.</td><td>Canada</td></tr><tr><td>Exelon Wind, LLC</td><td>Delaware</td></tr><tr><td>Exelon Wyman, LLC</td><td>Delaware</td></tr><tr><td>ExGen Energy, S. de R.L. de C.V.</td><td>Mexico</td></tr><tr><td>ExGen Handley Power, LLC</td><td>Delaware</td></tr></table>



<table><tr><td>ExGen Renewables Holdings II, LLC</td><td>Delaware</td></tr><tr><td>ExGen Renewables Holdings, LLC</td><td>Delaware</td></tr><tr><td>ExGen Renewables I Holding, LLC</td><td>Delaware</td></tr><tr><td>ExGen Renewables I, LLC</td><td>Delaware</td></tr><tr><td>ExGen Renewables II, LLC</td><td>Delaware</td></tr><tr><td>ExGen Renewables IV Holding, LLC</td><td>Delaware</td></tr><tr><td>ExGen Renewables IV, LLC</td><td>Delaware</td></tr><tr><td>ExGen Renewables Partners, LLC</td><td>Delaware</td></tr><tr><td>ExGen Texas II Power Holdings, LLC</td><td>Delaware</td></tr><tr><td>ExGen Texas II Power, LLC</td><td>Delaware</td></tr><tr><td>ExGen Texas Power Services, LLC</td><td>Delaware</td></tr><tr><td>ExGen Ventures International Holdings II Limited</td><td>United Kingdom</td></tr><tr><td>ExGen Ventures International Holdings Limited</td><td>United Kingdom</td></tr><tr><td>Fair Wind Power Partners, LLC</td><td>Delaware</td></tr><tr><td>Fauquier Landfill Gas, L.L.C.</td><td>Delaware</td></tr><tr><td>Four Corners Windfarm, LLC</td><td>Oregon</td></tr><tr><td>Four Mile Canyon Windfarm, LLC</td><td>Oregon</td></tr><tr><td>Fourmile Wind Energy, LLC</td><td>Maryland</td></tr><tr><td>Gateway Solar LLC</td><td>Delaware</td></tr><tr><td>Grande Prairie Generation, Inc.</td><td>Alberta</td></tr><tr><td>Greensburg Wind Farm, LLC</td><td>Delaware</td></tr><tr><td>Handsome Lake Energy, LLC</td><td>Maryland</td></tr><tr><td>Harvest II Windfarm, LLC</td><td>Delaware</td></tr><tr><td>Harvest Windfarm, LLC</td><td>Michigan</td></tr><tr><td>High Mesa Energy, LLC</td><td>Idaho</td></tr><tr><td>High Plains Wind Power, LLC</td><td>Texas</td></tr><tr><td>Holyoke Solar, LLC</td><td>Delaware</td></tr><tr><td>Hot Springs Windfarm, LLC</td><td>Idaho</td></tr><tr><td>JBAB Solar I, LLC</td><td>Delaware</td></tr><tr><td>JExel Nuclear Company</td><td>Japan</td></tr><tr><td>K &amp; D Energy LLC</td><td>Minnesota</td></tr><tr><td>KC Energy LLC</td><td>Minnesota</td></tr><tr><td>KSS Turbines LLC</td><td>Minnesota</td></tr><tr><td>Lake Houston Power, LLC</td><td>Delaware</td></tr><tr><td>Loess Hills Wind Farm, LLC</td><td>Missouri</td></tr><tr><td>Michigan Wind 1, LLC</td><td>Delaware</td></tr><tr><td>Michigan Wind 2, LLC</td><td>Delaware</td></tr><tr><td>Michigan Wind 3, LLC</td><td>Delaware</td></tr><tr><td>Minergy LLC</td><td>Wisconsin</td></tr><tr><td>Mohave Sunrise Solar I, LLC</td><td>Arizona</td></tr><tr><td>Mountain Top Wind Power, LLC</td><td>Maryland</td></tr></table>



<table><tr><td>Nine Mile Point Nuclear Station, LLC</td><td>Delaware</td></tr><tr><td>North Shore District Energy, LLC</td><td>Delaware</td></tr><tr><td>Oregon Trail Windfarm, LLC</td><td>Oregon</td></tr><tr><td>Outback Solar, LLC</td><td>Oregon</td></tr><tr><td>Pacific Canyon Windfarm, LLC</td><td>Oregon</td></tr><tr><td>Panther Creek Holdings, Inc.</td><td>Delaware</td></tr><tr><td>Panther Creek Partners</td><td>Delaware</td></tr><tr><td>Pegasus Power Company, Inc.</td><td>California</td></tr><tr><td>Pepco Building Services Inc.</td><td>Delaware</td></tr><tr><td>Pepco Energy Cogeneration LLC</td><td>Delaware</td></tr><tr><td>Pepco Energy Solutions LLC</td><td>Delaware</td></tr><tr><td>Pepco Government Services LLC</td><td>Delaware</td></tr><tr><td>Pepco Holdings LLC</td><td>Delaware</td></tr><tr><td>PFMG Construction, Ltd.</td><td>California</td></tr><tr><td>PFMG Solar Baldwin Park, LLC</td><td>Delaware</td></tr><tr><td>PFMG Solar Etiwanda Falcon, LLC</td><td>Delaware</td></tr><tr><td>PFMG Solar Long Beach, LLC</td><td>Delaware</td></tr><tr><td>PFMG Solar PUSD, LLC</td><td>Delaware</td></tr><tr><td>PFMG Solar San Diego, LLC</td><td>Delaware</td></tr><tr><td>PFMG Solar, LLC</td><td>Delaware</td></tr><tr><td>Pinedale Energy, LLC</td><td>Colorado</td></tr><tr><td>Potomac Power Resources, LLC</td><td>Delaware</td></tr><tr><td>Prairie Wind Power LLC</td><td>Minnesota</td></tr><tr><td>R.E. Ginna Nuclear Power Plant, LLC</td><td>Maryland</td></tr><tr><td>Renewable Power Generation Holdings, LLC</td><td>Delaware</td></tr><tr><td>Renewable Power Generation, LLC</td><td>Delaware</td></tr><tr><td>Rolling Hills Landfill Gas, LLC</td><td>Delaware</td></tr><tr><td>Sacramento PV Energy, LLC</td><td>Delaware</td></tr><tr><td>Sand Ranch Windfarm, LLC</td><td>Oregon</td></tr><tr><td>Sendero Wind Energy, LLC</td><td>Delaware</td></tr><tr><td>Series A of Annova LNG, LLC</td><td>Delaware</td></tr><tr><td>Series B of Annova LNG, LLC</td><td>Delaware</td></tr><tr><td>Series C of Annova LNG, LLC</td><td>Delaware</td></tr><tr><td>Series Z of Annova LNG, LLC</td><td>Delaware</td></tr><tr><td>Shooting Star Wind Project, LLC</td><td>Delaware</td></tr><tr><td>Sky Valley, LLC</td><td>Delaware</td></tr><tr><td>SolGen Holding, LLC</td><td>Delaware</td></tr><tr><td>SolGen, LLC</td><td>Delaware</td></tr><tr><td>Sugar Beet Wind, LLC</td><td>Delaware</td></tr><tr><td>Sunnyside II, Inc.</td><td>Delaware</td></tr><tr><td>Sunnyside II, L.P.</td><td>Delaware</td></tr></table>



<table><tr><td>Sunnyside III, Inc.</td><td>Delaware</td></tr><tr><td>Threemile Canyon Wind I, LLC</td><td>Oregon</td></tr><tr><td>Titan STC, LLC</td><td>Delaware</td></tr><tr><td>Tuana Springs Energy, LLC</td><td>Idaho</td></tr><tr><td>V.G. Investment Holdings, LLC</td><td>Delaware</td></tr><tr><td>Vineland Cogeneration Limited Partnership</td><td>Delaware</td></tr><tr><td>Vineland General, Inc.</td><td>Delaware</td></tr><tr><td>Vineland Ltd., Inc.</td><td>Delaware</td></tr><tr><td>W&amp;D Gas Partners, LLC</td><td>Delaware</td></tr><tr><td>Wagon Trail, LLC</td><td>Oregon</td></tr><tr><td>Ward Butte Windfarm, LLC</td><td>Oregon</td></tr><tr><td>Water &amp; Energy Savings Company, LLC</td><td>Delaware</td></tr><tr><td>Whitetail Wind Energy, LLC</td><td>Delaware</td></tr><tr><td>Wildcat Finance, LLC</td><td>Delaware</td></tr><tr><td>Wildcat Wind LLC</td><td>New Mexico</td></tr><tr><td>Wind Capital Holdings, LLC</td><td>Missouri</td></tr><tr><td>Wolf Hollow II Power, LLC</td><td>Delaware</td></tr><tr><td>Wolf Hollow Services, LLC</td><td>Delaware</td></tr></table>



## Commonwealth Edison Company (50% and Greater)
12/31/2019

<table><tr><td>Subsidiary</td><td>Jurisdiction</td></tr><tr><td>Commonwealth Edison Company of Indiana, Inc.</td><td>Indiana</td></tr><tr><td>ComEd Financing III</td><td>Delaware</td></tr><tr><td>EdiSun, LLC</td><td>Delaware</td></tr><tr><td>RITELine Illinois, LLC</td><td>Illinois</td></tr></table>



## PECO Energy Company (50% and Greater)
12/31/2019

<table><tr><td>Subsidiary</td><td>Jurisdiction</td></tr><tr><td>ATNP Finance Company</td><td>Delaware</td></tr><tr><td>ExTel Corporation, LLC</td><td>Delaware</td></tr><tr><td>PEC Financial Services, LLC</td><td>Pennsylvania</td></tr><tr><td>PECO Energy Capital Corp.</td><td>Delaware</td></tr><tr><td>PECO Energy Capital, L.P.</td><td>Delaware</td></tr><tr><td>PECO Energy Capital Trust III</td><td>Delaware</td></tr><tr><td>PECO Energy Capital Trust IV</td><td>Delaware</td></tr><tr><td>PECO Wireless, LLC</td><td>Delaware</td></tr></table>



Baltimore Gas and Electric Company (50% and Greater)
12/31/2019

Subsidiary

Jurisdiction



## Pepco Holdings LLC (50% and Greater)
12/31/2019

<table><tr><td>Subsidiary</td><td>Jurisdiction</td></tr><tr><td>Atlantic City Electric Company</td><td>New Jersey</td></tr><tr><td>Atlantic City Electric Transition Funding LLC</td><td>Delaware</td></tr><tr><td>Delmarva Power &amp; Light Company</td><td>Delaware &amp; Virginia</td></tr><tr><td>Millennium Account Services, LLC</td><td>Delaware</td></tr><tr><td>PHI Service Company</td><td>Delaware</td></tr><tr><td>Potomac Electric Power Company</td><td>District of Columbia &amp; Virginia</td></tr><tr><td>POM Holdings, Inc.</td><td>Delaware</td></tr></table>



Potomac Electric Power Company (50% and Greater)
12/31/2019

<table><tr><td>Subsidiary</td><td>Jurisdiction</td></tr><tr><td>POM Holdings, Inc.</td><td>Delaware</td></tr></table>



Delmarva Power & Light Company
12/31/2019

Subsidiary

Jurisdiction

None



Atlantic City Electric Company (50% and Greater)
12/31/2019

Subsidiary

Atlantic City Electric Transition Funding LLC

Jurisdiction

New Jersey



## CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (No. 333-233543 and No. 333-222989), Form S-4 (No. 333-209209) and on Form S-8 (No. 333-219037, No. 333-215114, No. 333-189849, No. 333-175162, No. 333-127377, No. 333-37082, No. 333-49780 and No. 333-61390) of Exelon Corporation of our report dated February 11, 2020 relating to the financial statements, financial statement schedules and the effectiveness of internal control over financial reporting, which appears in this Form 10-K.

/s/ PricewaterhouseCoopers LLP

Chicago, Illinois

February 11, 2020



## CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (No. 333-233543-01) and Form S-4 (No. 333-184712) of Exelon Generation Company, LLC of our report dated February 11, 2020 relating to the financial statements and financial statement schedule, which appears in this Form 10-K.

/s/ PricewaterhouseCoopers LLP

Baltimore, Maryland

February 11, 2020



## CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-233543-02) of Commonwealth Edison Company of our report dated February 11, 2020 relating to the financial statements and financial statement schedule, which appears in this Form 10-K.

/s/ PricewaterhouseCoopers LLP

Chicago, Illinois

February 11, 2020



## CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-233543-03) of PECO Energy Company of our report dated February 11, 2020 relating to the financial statements and financial statement schedule, which appears in this Form 10-K.

/s/ PricewaterhouseCoopers LLP

Philadelphia, Pennsylvania

February 11, 2020



## CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-233543-04) of Baltimore Gas and Electric Company of our report dated February 11, 2020 relating to the financial statements and financial statement schedule, which appears in this Form 10-K.

/s/ PricewaterhouseCoopers LLP

Baltimore, Maryland

February 11, 2020



## CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-233543-05) of Potomac Electric Power Company of our report dated February 11, 2020 relating to the financial statements and financial statement schedule, which appears in this Form 10-K.

/s/ PricewaterhouseCoopers LLP

Washington, DC

February 11, 2020



## CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No.333-233543-06) of Delmarva Power & Light Company of our report dated February 11, 2020 relating to the financial statements and financial statement schedule, which appears in this Form 10-K.

/s/ PricewaterhouseCoopers LLP
Washington, DC

February 11, 2020



## CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-233543-07) of Atlantic City Electric Company of our report dated February 11, 2020 relating to the financial statements and financial statement schedule, which appears in this Form 10-K.

/s/ PricewaterhouseCoopers LLP

Washington, DC

February 11, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, Anthony K. Anderson, do hereby appoint Christopher M. Crane and Thomas S. O'Neill, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of Exelon Corporation, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.

/s/ ANTHONY K. ANDERSON

Anthony K. Anderson

DATE: January 28, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, Ann C. Berzin, do hereby appoint Christopher M. Crane and Thomas S. O'Neill, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of Exelon Corporation, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.

/s/ ANN C. BERZIN

Ann C. Berzin

DATE: January 28, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, Laurie Brlas, do hereby appoint Christopher M. Crane and Thomas S. O'Neill, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of Exelon Corporation, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.

/s/ LAURIE BRLAS

Laurie Brlas

DATE: January 28, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, Christopher M. Crane, do hereby appoint Thomas S. O'Neill attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of Exelon Corporation, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.

/s/ CHRISTOPHER M. CRANE

Christopher M. Crane

DATE: January 15, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, Yves C. de Balmann, do hereby appoint Christopher M. Crane and Thomas S. O'Neill, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of Exelon Corporation, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.

/s/ YVES C. DE BALMANN

Yves C. de Balmann

DATE: January 28, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, Nicholas DeBenedictis, do hereby appoint Christopher M. Crane and Thomas S. O'Neill, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of Exelon Corporation, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.

/s/ NICHOLAS DEBENEDICTIS

Nicholas DeBenedictis

DATE: January 22, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, Linda P. Jojo, do hereby appoint Christopher M. Crane and Thomas S. O'Neill, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of Exelon Corporation, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.

/s/ LINDA P. JOJO

Linda P. Jojo

DATE: January 28, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, Paul Joskow, do hereby appoint Christopher M. Crane and Thomas S. O'Neill, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of Exelon Corporation, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.

/s/ PAUL L. JOSKOW

Paul L. Joskow

DATE: January 28, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, Robert J. Lawless, do hereby appoint Christopher M. Crane and Thomas S. O'Neill, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of Exelon Corporation, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.

/s/ ROBERT J. LAWLESS

Robert J. Lawless

DATE: January 28, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, Richard W. Mies, do hereby appoint Christopher M. Crane and Thomas S. O'Neill, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of Exelon Corporation, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.

/s/ RICHARD W. MIES

Richard W. Mies

DATE: January 28, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, Mayo A. Shattuck III, do hereby appoint Christopher M. Crane and Thomas S. O'Neill, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of Exelon Corporation, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.

/s/ MAYO A. SHATTUCK III

Mayo A. Shattuck III

DATE: January 28, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, Stephen D. Steinour, do hereby appoint Christopher M. Crane and Thomas S. O'Neill, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of Exelon Corporation, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.

/s/ STEPHEN D. STEINOUR

Stephen D. Steinour

DATE: January 28, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, John F. Young, do hereby appoint Christopher M. Crane and Thomas O'Neill, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of Exelon Corporation, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.

/s/ JOHN F. YOUNG

John F. Young

DATE: January 28, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, John Richardson, do hereby appoint Christopher M. Crane and Thomas O'Neill, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of Exelon Corporation, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.

/s/ JOHN RICHARDSON

John Richardson

DATE: January 28, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, James W. Compton, do hereby appoint Joseph Dominguez and Verónica Gómez, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of Commonwealth Edison Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.

/s/ JAMES W. COMPTON

James W. Compton

DATE: January 30, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, Christopher M. Crane, do hereby appoint Joseph Dominguez and Verónica Gómez, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of Commonwealth Edison Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.

/s/ CHRISTOPHER M. CRANE

Christopher M. Crane

DATE: January 15, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, A. Steven Crown, do hereby appoint Joseph Dominguez and Verónica Gómez, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of Commonwealth Edison Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.

/s/ A. STEVEN CROWN

A. Steven Crown

DATE: January 30, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, Nicholas DeBenedictis, do hereby appoint Joseph Dominguez and Verónica Gómez, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of Commonwealth Edison Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.

/s/ NICHOLAS DEBENEDICTIS

Nicholas DeBenedictis

DATE: January 22, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, Joseph Dominguez, do hereby appoint Verónica Gómez attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of Commonwealth Edison Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.

/s/ JOSEPH DOMINGUEZ

Joseph Dominguez

DATE: January 15, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, Peter V. Fazio, Jr., do hereby appoint Joseph Dominguez and Verónica Gómez, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of Commonwealth Edison Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.

/s/ PETER V. FAZIO, JR.

Peter V. Fazio, Jr.

DATE: January 30, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, Michael H. Moskow, do hereby appoint Joseph Dominguez and Verónica Gómez, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of Commonwealth Edison Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.

/s/ MICHAEL H. MOSKOW

Michael H. Moskow

DATE: February 10, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, Calvin G. Butler, do hereby appoint Joseph Dominguez and Verónica Gómez, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of Commonwealth Edison Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.

/s/ CALVIN G. BUTLER

Calvin G. Butler

DATE: January 15, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, Juan Ochoa, do hereby appoint Joseph Dominguez and Verónica Gómez, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of Commonwealth Edison Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.

/s/ JUAN OCHOA

Juan Ochoa

DATE: January 30, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, Christopher M. Crane, do hereby appoint Michael A. Innocenzo and Anthony E. Gay, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of PECO Energy Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.

/s/ CHRISTOPHER M. CRANE

Christopher M. Crane

DATE: January 15, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, Nicholas DeBenedictis, do hereby appoint Michael A. Innocenzo and Anthony E. Gay, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of PECO Energy Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.

/s/ NICHOLAS DEBENEDICTIS

Nicholas DeBenedictis

DATE: January 22, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, Nelson A. Diaz, do hereby appoint Michael A. Innocenzo and Anthony E. Gay, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of PECO Energy Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.

/s/ NELSON A. DIAZ

Nelson A. Diaz

DATE: January 23, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, John S. Grady, do hereby appoint Michael A. Innocenzo and Anthony E. Gay, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of PECO Energy Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.

/s/ JOHN S. GRADY

John S. Grady

DATE: January 23, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, Rosemarie B. Greco, do hereby appoint Michael A. Innocenzo and Anthony E. Gay, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of PECO Energy Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.

/s/ ROSEMARIE B. GRECO

Rosemarie B. Greco

DATE: February 5, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, Michael A. Innocenzo, do hereby appoint Anthony E. Gay attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of PECO Energy Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.

/s/ MICHAEL A. INNOCENZO

Michael A. Innocenzo

DATE: January 15, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, Charisse R. Lillie, do hereby appoint Michael A. Innocenzo and Anthony E. Gay, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of PECO Energy Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.

/s/ CHARISSE R. LILLIE

Charisse R. Lillie

DATE: January 30, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, Calvin G. Butler, do hereby appoint Michael A. Innocenzo and Anthony E. Gay, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of PECO Energy Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.

/s/ CALVIN G. BUTLER

Calvin G. Butler

DATE: January 15, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, Ann C. Berzin, do hereby appoint Carim V. Khouzami and John D. Corse, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of Baltimore Gas & Electric Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.

/s/ ANN C. BERZIN

Ann C. Berzin

DATE: January 28, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, Carim V. Khouzami, do hereby appoint John D. Corse attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of Baltimore Gas & Electric Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.

/s/ CARIM V. KHOUZAMI

Carim V. Khouzami

DATE: January 15, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, Christopher M. Crane, do hereby appoint Carim V. Khouzami and John D. Corse, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of Baltimore Gas & Electric Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.

/s/ CHRISTOPHER M. CRANE

Christopher M. Crane

DATE: January 15, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, Michael E. Cryor, do hereby appoint Carim V. Khouzami and John D. Corse, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of Baltimore Gas & Electric Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.

/s/ MICHAEL E. CRYOR

Michael E. Cryor

DATE: January 23, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, James R. Curtiss, do hereby appoint Carim V. Khouzami and John D. Corse, or either of them, for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of Baltimore Gas & Electric Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.

/s/ JAMES R. CURTISS

James R. Curtiss

DATE: January 27, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, Joseph Haskins, Jr., do hereby appoint Carim V. Khouzami and John D. Corse, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of Baltimore Gas & Electric Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.

/s/ JOSEPH HASKINS, JR.

Joseph Haskins, Jr.

DATE: January 30, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, Calvin G. Butler, do hereby appoint Carim V. Khouzami and John D. Corse, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of Baltimore Gas & Electric Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.

/s/ CALVIN G. BUTLER

Calvin G. Butler

DATE: January 15, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, Michael D. Sullivan, do hereby appoint Carim V. Khouzami, and John D. Corse, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of Baltimore Gas & Electric Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.

/s/ MICHAEL D. SULLIVAN

Michael D. Sullivan

DATE: January 27, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, Maria Harris Tildon, do hereby appoint Carim V. Khouzami, and John D. Corse, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of Baltimore Gas & Electric Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.

/s/ MARIA HARRIS TILDON

Maria Harris Tildon

DATE: January 28, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, Christopher M. Crane, do hereby appoint David M. Velazquez and Wendy E. Stark, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of Pepco Holdings LLC, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.

/s/ CHRISTOPHER M. CRANE

Christopher M. Crane

Date: January 15, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, Linda W. Cropp, do hereby appoint David M. Velazquez and Wendy E. Stark, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of Pepco Holdings LLC, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.

/s/ LINDA W. CROPP

Linda W. Cropp

Date: February 8, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, Michael E. Cryor, do hereby appoint David M. Velazquez and Wendy E. Stark, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of Pepco Holdings LLC, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.

/s/ MICHAEL CRYOR

Michael Cryor

Date: January 23, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, Ernest Dianastasis, do hereby appoint David M. Velazquez and Wendy E. Stark, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of Pepco Holdings LLC, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.

/s/ ERNEST DIANASTASIS

Ernest Dianastasis

Date: January 23, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, Debra P. DiLorenzo, do hereby appoint David M. Velazquez and Wendy E. Stark, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of Pepco Holdings LLC, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.

/s/ DEBRA P. DILORENZO

Debra P. DiLorenzo

Date: February 3, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, Calvin G. Butler, do hereby appoint David M. Velazquez and Wendy E. Stark, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of Pepco Holdings LLC, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.

/s/ CALVIN G. BUTLER

Calvin G. Butler

Date: January 25, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, David M. Velazquez, do hereby appoint Wendy E. Stark as attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of Pepco Holdings LLC, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.

/s/ DAVID M. VELAZQUEZ

David M. Velazquez

DATE: January 15, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, J. Tyler Anthony, do hereby appoint David M. Velazquez and Wendy E. Stark, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of Potomac Electric Power Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.

/s/ J. TYLER ANTHONY

J. Tyler Anthony

DATE: January 15, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, Phillip S. Barnett, do hereby appoint David M. Velazquez and Wendy E. Stark, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of Potomac Electric Power Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.

/s/ PHILLIP S. BARNETT

Phillip S. Barnett

DATE: January 16, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, Christopher M. Crane, do hereby appoint David M. Velazquez and Wendy E. Stark, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of Potomac Electric Power Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.

/s/ CHRISTOPHER M. CRANE

Christopher M. Crane

DATE: January 15, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, Melissa A. Lavinson, do hereby appoint David M. Velazquez and Wendy E. Stark, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of Potomac Electric Power Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.

/s/ MELISSA A. LAVINSON

Melissa A. Lavinson

DATE: January 15, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, Kevin M. McGowan, do hereby appoint David M. Velazquez and Wendy E. Stark, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of Potomac Electric Power Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.

/s/ KEVIN M. MCGOWAN

Kevin M. McGowan

DATE: January 15, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, Calvin G. Butler, do hereby appoint David M. Velazquez and Wendy E. Stark, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of Potomac Electric Power Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.

/s/ CALVIN G. BUTLER

Calvin G. Butler

DATE: January 15, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, David M. Velazquez, do hereby appoint Wendy E. Stark, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of Potomac Electric Power Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.

/s/ DAVID M. VELAZQUEZ

David M. Velazquez

DATE: January 15, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, Calvin G. Butler, do hereby appoint David M. Velazquez and Wendy E. Stark, or either of them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of Delmarva Power & Light Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.

/s/ CALVIN G. BUTLER

Calvin G. Butler

DATE: January 15, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, David M. Velazquez, do hereby appoint Wendy E. Stark as attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of Delmarva Power & Light Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectively in all respects as I could do if personally present.

/s/ DAVID M. VELAZQUEZ

David M. Velazquez

DATE: January 15, 2020



## POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS that I, David M. Velazquez, do hereby appoint Wendy E. Stark as attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 of Atlantic City Electric Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectively in all respects as I could do if personally present.

/s/ DAVID M. VELAZQUEZ

David M. Velazquez

DATE: January 15, 2020



# CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES AND EXCHANGE ACT OF 1934

I, Christopher M. Crane, certify that:

1. I have reviewed this annual report on Form 10-K of Exelon Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ CHRISTOPHER M. CRANE

President and Chief Executive Officer

(Principal Executive Officer)

Date: February 11, 2020



# CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES AND EXCHANGE ACT OF 1934

I, Joseph Nigro, certify that:

1. I have reviewed this annual report on Form 10-K of Exelon Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ JOSEPH NIGRO

Senior Executive Vice President and Chief Financial Officer

(Principal Financial Officer)

Date: February 11, 2020



# CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES AND EXCHANGE ACT OF 1934

I, Kenneth W. Cornew, certify that:

1. I have reviewed this annual report on Form 10-K of Exelon Generation Company, LLC;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

/s/ KENNETH W. CORNEW

President and Chief Executive Officer

(Principal Executive Officer)

Date: February 11, 2020



# CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES AND EXCHANGE ACT OF 1934

I, Bryan P. Wright, certify that:

1. I have reviewed this annual report on Form 10-K of Exelon Generation Company, LLC;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

/s/ BRYAN P. WRIGHT

Senior Vice President and Chief Financial Officer

(Principal Financial Officer)

Date: February 11, 2020



# CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES AND EXCHANGE ACT OF 1934

I, Joseph Dominguez, certify that:

1. I have reviewed this annual report on Form 10-K of Commonwealth Edison Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

/s/ JOSEPH DOMINGUEZ

Chief Executive Officer

(Principal Executive Officer)

Date: February 11, 2020



# CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES AND EXCHANGE ACT OF 1934

I, Jeanne M. Jones, certify that:

1. I have reviewed this annual report on Form 10-K of Commonwealth Edison Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ JEANNE M. JONES

Senior Vice President, Chief Financial Officer and Treasurer

(Principal Financial Officer)

Date: February 11, 2020



# CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES AND EXCHANGE ACT OF 1934

I, Michael A. Innocenzo, certify that:

1. I have reviewed this annual report on Form 10-K of PECO Energy Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

/s/ MICHAEL A. INNOCENZO

President and Chief Executive Officer

(Principal Executive Officer)

Date: February 11, 2020



# CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES AND EXCHANGE ACT OF 1934

I, Robert J. Stefani, certify that:

1. I have reviewed this annual report on Form 10-K of PECO Energy Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

/s/ ROBERT. J STEFANI

Senior Vice President, Chief Financial Officer and Treasurer

(Principal Financial Officer)

Date: February 11, 2020



# CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES AND EXCHANGE ACT OF 1934

I, Carim V. Khouzami, certify that:

1. I have reviewed this annual report on Form 10-K of Baltimore Gas and Electric Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

/s/ CARIM V. KHOZAMI

Chief Executive Officer

(Principal Executive Officer)

Date: February 11, 2020



# CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES AND EXCHANGE ACT OF 1934

I, David M. Vahos, certify that:

1. I have reviewed this annual report on Form 10-K of Baltimore Gas and Electric Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

/s/ DAVID M. VAHOS

Senior Vice President, Chief Financial Officer and Treasurer

(Principal Financial Officer)

Date: February 11, 2020



# CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES AND EXCHANGE ACT OF 1934

I, David M. Velazquez, certify that:

1. I have reviewed this annual report on Form 10-K of Pepco Holdings LLC;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ DAVID M. VELAZQUEZ

President and Chief Executive Officer

(Principal Executive Officer)

Date: February 11, 2020



# CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES AND EXCHANGE ACT OF 1934

I, Phillip S. Barnett, certify that:

1. I have reviewed this annual report on Form 10-K of Pepco Holdings LLC;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ PHILLIP S. BARNETT

Senior Vice President, Chief Financial Officer and Treasurer

(Principal Financial Officer)

Date: February 11, 2020



# CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES AND EXCHANGE ACT OF 1934

I, David M. Velazquez, certify that:

1. I have reviewed this annual report on Form 10-K of Potomac Electric Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ DAVID M. VELAZQUEZ

President and Chief Executive Officer

(Principal Executive Officer)

Date: February 11, 2020



# CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES AND EXCHANGE ACT OF 1934

I, Phillip S. Barnett, certify that:

1. I have reviewed this annual report on Form 10-K of Potomac Electric Power Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ PHILLIP S. BARNETT

Senior Vice President, Chief Financial Officer and Treasurer

(Principal Financial Officer)

Date: February 11, 2020



# CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES AND EXCHANGE ACT OF 1934

I, David M. Velazquez, certify that:

1. I have reviewed this annual report on Form 10-K of Delmarva Power & Light Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ DAVID M. VELAZQUEZ

President and Chief Executive Officer

(Principal Executive Officer)

Date: February 11, 2020



# CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES AND EXCHANGE ACT OF 1934

1. Phillip S. Barnett, certify that:

1. I have reviewed this annual report on Form 10-K of Delmarva Power & Light Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ PHILLIP S. BARNETT

Senior Vice President, Chief Financial Officer and Treasurer

(Principal Financial Officer)

Date: February 11, 2020



# CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES AND EXCHANGE ACT OF 1934

I, David M. Velazquez, certify that:

1. I have reviewed this annual report on Form 10-K of Atlantic City Electric Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ DAVID M. VELAZQUEZ

President and Chief Executive Officer

(Principal Executive Officer)

Date: February 11, 2020



# CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES AND EXCHANGE ACT OF 1934

1. Phillip S. Barnett, certify that:

1. I have reviewed this annual report on Form 10-K of Atlantic City Electric Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ PHILLIP S. BARNETT

Senior Vice President, Chief Financial Officer and Treasurer

(Principal Financial Officer)

Date: February 11, 2020



## Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code

The undersigned officer hereby certifies, as to the Report on Form 10-K of Exelon Corporation for the year ended December 31, 2019, that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in the report fairly presents, in all material respects, the financial condition and results of operations of Exelon Corporation.

/s/ CHRISTOPHER M. CRANE

Christopher M. Crane

President and Chief Executive Officer

Date: February 11, 2020



## Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code

The undersigned officer hereby certifies, as to the Report on Form 10-K of Exelon Corporation for the year ended December 31, 2019, that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in the report fairly presents, in all material respects, the financial condition and results of operations of Exelon Corporation.

/s/ JOSEPH NIGRO

Joseph Nigro

Senior Executive Vice President and Chief Financial Officer

Date: February 11, 2020



## Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code

The undersigned officer hereby certifies, as to the Report on Form 10-K of Exelon Generation Company, LLC for the year ended December 31, 2019, that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in the report fairly presents, in all material respects, the financial condition and results of operations of Exelon Generation Company, LLC.

/s/ KENNETH W. CORNEW

Kenneth W. Cornew

President and Chief Executive Officer

Date: February 11, 2020



## Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code

The undersigned officer hereby certifies, as to the Report on Form 10-K of Exelon Generation Company, LLC for the year ended December 31, 2019, that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in the report fairly presents, in all material respects, the financial condition and results of operations of Exelon Generation Company, LLC.

/s/ BRYAN P. WRIGHT

Bryan P. Wright

Senior Vice President and Chief Financial Officer

Date: February 11, 2020



## Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code

The undersigned officer hereby certifies, as to the Report on Form 10-K of Commonwealth Edison Company for the year ended December 31, 2019, that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in the report fairly presents, in all material respects, the financial condition and results of operations of Commonwealth Edison Company.

/s/ JOSEPH DOMINGUEZ

Joseph Dominguez

Chief Executive Officer

Date: February 11, 2020



## Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code

The undersigned officer hereby certifies, as to the Report on Form 10-K of Commonwealth Edison Company for the year ended December 31, 2019, that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in the report fairly presents, in all material respects, the financial condition and results of operations of Commonwealth Edison Company.

/s/ JEANNE M. JONES

Jeanne M. Jones

Senior Vice President, Chief Financial Officer and Treasurer

Date: February 11, 2020



## Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code

The undersigned officer hereby certifies, as to the Report on Form 10-K of PECO Energy Company for the year ended December 31, 2019, that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in the report fairly presents, in all material respects, the financial condition and results of operations of PECO Energy Company.

/s/ MICHAEL A. INNOCENZO

Michael A. Innocenzo

President and Chief Executive Officer

Date: February 11, 2020



## Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code

The undersigned officer hereby certifies, as to the Report on Form 10-K of PECO Energy Company for the year ended December 31, 2019, that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in the report fairly presents, in all material respects, the financial condition and results of operations of PECO Energy Company.

/s/ ROBERT J. STEFANI

Robert J. Stefani

Senior Vice President, Chief Financial Officer and Treasurer

Date: February 11, 2020



## Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code

The undersigned officer hereby certifies, as to the Report on Form 10-K of Baltimore Gas and Electric Company for the year ended December 31, 2019, that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in the report fairly presents, in all material respects, the financial condition and results of operations of Baltimore Gas and Electric Company.

/s/ CARIM V. KHOUZAMI

Carim V. Khouzami

Chief Executive Officer

Date: February 11, 2020



## Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code

The undersigned officer hereby certifies, as to the Report on Form 10-K of Baltimore Gas and Electric Company for the year ended December 31, 2019, that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in the report fairly presents, in all material respects, the financial condition and results of operations of Baltimore Gas and Electric Company.

/s/ DAVID M. VAHOS

David M. Vahos

Senior Vice President, Chief Financial Officer and Treasurer

Date: February 11, 2020



## Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code

The undersigned officer hereby certifies, as to the Report on Form 10-K of Pepco Holdings LLC for the year ended December 31, 2019, that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in the report fairly presents, in all material respects, the financial condition and results of operations of Pepco Holdings LLC.

/s/ DAVID M. VELAZQUEZ

David M. Velazquez

President and Chief Executive Officer

Date: February 11, 2020



## Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code

The undersigned officer hereby certifies, as to the Report on Form 10-K of Pepco Holdings LLC for the year ended December 31, 2019, that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in the report fairly presents, in all material respects, the financial condition and results of operations of Pepco Holdings LLC.

/s/ PHILLIP S. BARNETT

Phillip S. Barnett

Senior Vice President, Chief Financial Officer and Treasurer

Date: February 11, 2020



## Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code

The undersigned officer hereby certifies, as to the Report on Form 10-K of Potomac Electric Power Company for the year ended December 31, 2019, that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in the report fairly presents, in all material respects, the financial condition and results of operations of Potomac Electric Power Company.

/s/ DAVID M. VELAZQUEZ

David M. Velazquez

President and Chief Executive Officer

Date: February 11, 2020



## Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code

The undersigned officer hereby certifies, as to the Report on Form 10-K of Potomac Electric Power Company for the year ended December 31, 2019, that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in the report fairly presents, in all material respects, the financial condition and results of operations of Potomac Electric Power Company.

/s/ PHILLIP S. BARNETT

Phillip S. Barnett

Senior Vice President, Chief Financial Officer and Treasurer

Date: February 11, 2020



## Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code

The undersigned officer hereby certifies, as to the Report on Form 10-K of Delmarva Power & Light Company for the year ended December 31, 2019, that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in the report fairly presents, in all material respects, the financial condition and results of operations of Delmarva Power & Light Company.

/s/ DAVID M. VELAZQUEZ

David M. Velazquez

President and Chief Executive Officer

Date: February 11, 2020



## Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code

The undersigned officer hereby certifies, as to the Report on Form 10-K of Delmarva Power & Light Company for the year ended December 31, 2019, that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in the report fairly presents, in all material respects, the financial condition and results of operations of Delmarva Power & Light Company.

/s/ PHILLIP S. BARNETT

Phillip S. Barnett

Senior Vice President, Chief Financial Officer and Treasurer

Date: February 11, 2020



## Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code

The undersigned officer hereby certifies, as to the Report on Form 10-K of Atlantic City Electric Company for the year ended December 31, 2019, that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in the report fairly presents, in all material respects, the financial condition and results of operations of Atlantic City Electric Company.

/s/ DAVID M. VELAZQUEZ

David M. Velazquez

President and Chief Executive Officer

Date: February 11, 2020



## Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code

The undersigned officer hereby certifies, as to the Report on Form 10-K of Atlantic City Electric Company for the year ended December 31, 2019, that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in the report fairly presents, in all material respects, the financial condition and results of operations of Atlantic City Electric Company.

/s/ PHILLIP S. BARNETT

Phillip S. Barnett

Senior Vice President, Chief Financial Officer and Treasurer

Date: February 11, 2020