COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

~~Index to Combined Notes To Consolidated Financial Statements~~

~~The notes to the consolidated financial statements that follow are a combined presentation. The following list indicates the Registrants to which the footnotes apply:~~

~~Applicable Notes~~

Note 1 — Significant Accounting Policies

Registrant 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20
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 . . . . . . . . . . . . .

1. ~~Basis of Presentation~~Significant Accounting Policies (All Registrants)

Description of Business ~~(All Registrants)~~

Exelon is a utility services holding company engaged ~~through its principal subsidiaries~~ in the energy ~~generation~~transmission and ~~energy~~ distribution ~~and transmission businesses. Prior to March 23, 2016, Exelon's principal, wholly owned subsidiaries included Generation,~~businesses through ComEd, PECO, and BGE. On March 23, 2016, in conjunction with the Amended and Restated Agreement and Plan of Merger (the PHI Merger Agreement), Purple Acquisition Corp, a wholly owned subsidiary of Exelon, merged with and into PHI, with PHI continuing as the surviving entity as a wholly owned subsidiary of Exelon. PHI is a utility services holding company engaged through its principal wholly owned subsidiaries,BGE, Pepco, DPL, and ~~ACE, in~~ACE.

On February 21, 2021, Exelon's Board of Directors approved a plan to separate the ~~energy distribution~~Utility Registrants and ~~transmission businesses. Refer to~~Generation. The separation was completed on February 1, 2022, creating two publicly traded companies, Exelon and Constellation. See Note ~~4 - Mergers, Acquisitions and Dispositions~~2 — Discontinued Operations for ~~further information regarding the merger transaction.~~additional information.

~~The energy generation business includes:~~

~~Generation~~: 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 six reportable segments consisting of the Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions.

~~The energy delivery businesses include:~~

~~ComEd: Purchase and regulated retail sale of electricity and the provision of electric distribution and transmission services in northern Illinois, including the City of Chicago.~~

~~PECO~~: Purchase and regulated retail sale of electricity and the provision of electric 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 natural gas distribution services in the Pennsylvania counties surrounding the City of Philadelphia.

~~BGE~~: Purchase and regulated retail sale of electricity and the provision of electric 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 natural gas distribution services in central Maryland, including the City of Baltimore.

~~Table of Contents~~

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

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

~~Pepco~~:Purchase and regulated retail sale of electricity and the provision of electric distribution and transmission services in the District of Columbia and major portions of Prince George's County and Montgomery County in Maryland.

~~DPL~~: Purchase and regulated retail sale of electricity and the provision of electric distribution and transmission services in portions of Maryland and Delaware, and the purchase and regulated retail sale of natural gas and the provision of natural gas distribution services in northern Delaware.

~~ACE: Purchase and regulated retail sale of electricity and the provision of electric distribution and transmission services in southern New Jersey.~~

Name of Registrant

Business

Service Territories

Commonwealth Edison Company

Purchase and regulated retail sale of electricity

Northern Illinois, including the City of Chicago

Transmission and distribution of electricity to retail customers

PECO Energy Company

Purchase and regulated retail sale of electricity and natural gas

Southeastern Pennsylvania, including the City of Philadelphia (electricity)

Transmission and distribution of electricity and distribution of natural gas to retail customers

Pennsylvania counties surrounding the City of Philadelphia (natural gas)

Baltimore Gas and Electric Company

Purchase and regulated retail sale of electricity and natural gas

Central Maryland, including the City of Baltimore (electricity and natural gas)

Transmission and distribution of electricity and distribution of natural gas to retail customers

Pepco Holdings LLC

Utility services holding company engaged, through its reportable segments Pepco, DPL, and ACE

Service Territories of Pepco, DPL, and ACE

Potomac Electric
Power Company

Purchase and regulated retail sale of electricity

District of Columbia, and major portions of Montgomery and Prince George’s Counties, Maryland

Transmission and distribution of electricity to retail customers

Delmarva Power &
Light Company

Purchase and regulated retail sale of electricity and natural gas

Portions of Delaware and Maryland (electricity)

Transmission and distribution of electricity and distribution of natural gas to retail customers

Portions of New Castle County, Delaware (natural gas)

Atlantic City Electric Company

Purchase and regulated retail sale of electricity

Portions of Southern New Jersey

Transmission and distribution of electricity to retail customers

Basis of Presentation ~~(All Registrants)~~

AsThis is a ~~result~~combined quarterly report of ~~the acquisition of PHI, Exelon’s financial reporting reflects PHI’s consolidated financial results subsequent~~all Registrants. The Notes to the March 23, 2016, acquisition date. Exelon has accounted for the merger transaction applying the acquisition method of accounting, which requires that identifiable assets acquired and liabilities assumed by Exelon to be reported in Exelon’s financial statements at fair value, with any excess of the purchase price over the fair value of net assets acquired reported as goodwill. Exelon has pushed-down the application of the acquisition method of accountingConsolidated Financial Statements apply to the ~~consolidated financial statements of PHI such that~~Registrants as indicated parenthetically next to each corresponding disclosure. When appropriate, the ~~assets~~Registrants are named specifically for their related activities and liabilities of PHI are similarly recorded at their respective fair values, and goodwill has been established as of the acquisition date. Accordingly, the consolidated financial statements of PHI for periods before and after the March 23, 2016, acquisition date reflect different bases of accounting, and the financial positions and the results of operations of the predecessor and successor periods are not comparable. The acquisition method of accounting has not been pushed down to PHI’s wholly owned subsidiary utility registrants, Pepco, DPL and ACE.

~~For financial statement purposes, beginning on March 24, 2016, disclosures related to Exelon now also apply to PHI, Pepco, DPL and ACE, unless otherwise noted.~~

disclosures. Each of the Registrant’s Consolidated Financial Statements includes the accounts of its subsidiaries. All intercompany transactions have been ~~eliminated.~~eliminated, except for the historical transactions between the Utility Registrants and Generation for the purposes of presenting discontinued operations in all periods presented in the Consolidated Statements of Operations and Comprehensive Income.

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, finance, 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” in the consolidated financial statements and include intercompany eliminations unless otherwise disclosed.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Note 1 — Significant Accounting Policies

The accompanying consolidated financial statements as of September 30, ~~2017 and 2016~~2023 and for the three and nine months ~~then~~ ended September 30, 2023 and 2022 are unaudited but, in the opinion of each Registrant's management, the ~~management of each Registrant~~Registrants include all adjustments that are considered necessary for a fair statement of the Registrants’ respective financial statements in accordance with GAAP. All adjustments are of a normal, recurring nature, except as otherwise disclosed. The December 31, ~~2016~~2022 Consolidated Balance Sheets were derived from audited financial statements. ~~Financial~~The interim financial statements are to be read in conjunction with prior annual financial statements and notes. Additionally, financial results for interim periods are not necessarily indicative of results that may be expected for any other interim period or for the fiscal year ending December 31, ~~2017.~~2023. These Combined Notes to Consolidated Financial Statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations.

~~2. New~~The separation of Constellation, including Generation and its subsidiaries, met the criteria for discontinued operations and as such, results of operations are presented as discontinued operations and have been excluded from continuing operations for all periods presented. Accounting ~~Standards (All Registrants)~~

~~New Accounting Standards Issued~~rules require that certain BSC costs previously allocated to Generation be presented as part of Exelon’s continuing operations as these costs do not qualify as expenses of the discontinued operations. Comprehensive income, shareholders' equity, and ~~Not Yet Adopted:~~ ~~The following new authoritative accounting guidance issued by~~cash flows related to Constellation have not been segregated and are included in the FASB has not yet been adopted and reflected by the Registrants in their consolidated financial statements. Unless otherwise indicated, the Registrants are currently assessing the impacts such guidance may have (which could be material) on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Changes in Shareholders’ Equity, and Consolidated Statements of Cash Flows, respectively, for the nine months ended September 30, 2022. See Note 2 — Discontinued Operations for additional information.

2. Discontinued Operations (Exelon)

On February 21, 2021, Exelon's Board of Directors approved a plan to separate the Utility Registrants and ~~disclosures, as well as~~ Generation, creating two publicly traded companies ("the ~~potential~~separation"). Exelon completed the separation on February 1, 2022. Constellation was newly formed and incorporated in Pennsylvania on June 15, 2021 for the purposes of separation and holds Generation (including Generation's subsidiaries). Pursuant to ~~early adopt where applicable. The Registrants~~the separation, Exelon contributed its equity ownership interest in Generation to Constellation. Exelon no longer retains any equity ownership interest in Generation or Constellation. See Note 2 — Discontinued Operations of the 2022 Form 10-K for additional information.

Continuing Involvement

In order to govern the ongoing relationships between Exelon and Constellation after the separation, and to facilitate an orderly transition, Exelon and Constellation have ~~assessed other FASB issuances of new standards which are not listed below given~~entered into several agreements, including the ~~current expectation such standards will not significantly impact~~following:

•Separation Agreement – governs the ~~Registrants' financial reporting.~~

~~Revenue from Contracts with Customers (Issued May 2014~~rights and ~~subsequently amended~~obligations between Exelon and Constellation regarding certain actions to ~~address implementation questions):~~ Changes the criteria for recognizing revenue from a contract with a customer. The new revenue recognition guidance, including subsequent amendments, is effective for annual reporting periods beginning on or after December 15, 2017,be taken in connection with the ~~option~~separation, among others, including the allocation of assets and liabilities between Exelon and Constellation.

•Transition Services Agreement (TSA) – governs the terms and conditions of the services that Exelon provides to ~~early adopt~~Constellation and Constellation provides to Exelon for an expected period of two years, provided that certain services may be longer than the ~~standard~~term and services may be extended with approval from both parties. The services include specified accounting, finance, information technology, human resources, employee benefits and other services that have historically been provided on a centralized basis by BSC. For the three and nine months ended September 30, 2023, the amounts Exelon billed Constellation and Constellation billed Exelon for ~~annual periods beginning on or after December 15, 2016.~~these services were $33 million and $127 million recorded in Other income, net and $4 million and $13 million recorded in Operating and maintenance expense, respectively. For the three months ended September 30, 2022, the amounts Exelon ~~has not early adopted this standard.~~

billed Constellation and Constellation billed Exelon for these services were $68 million recorded in Other income, net and $12 million recorded in Operating and maintenance expense, respectively. Additionally, for the period from February 1, 2022 to September 30, 2022, the amounts Exelon billed Constellation and Constellation billed Exelon for these services were $193 million recorded in Other income, net and $32 million recorded in Operating and maintenance expense, respectively.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 2 — Discontinued Operations

~~The new standard replaces existing guidance on revenue recognition,~~•Tax Matters Agreement (TMA) – governs the respective rights, responsibilities and obligations of Exelon and Constellation with respect to all tax matters, including ~~most industry specific guidance,~~tax liabilities and benefits, tax attributes, tax returns, tax contests and other tax sharing regarding U.S. federal, state, local and foreign income taxes, other tax matters and related tax returns. See Note 7 — Income Taxes for additional information.

In addition, the Utility Registrants will continue to incur expenses from transactions with ~~a five step model for recognizing~~Constellation after the separation. Prior to the separation, such expenses were primarily recorded as Purchased power from affiliates and ~~measuring revenue~~an immaterial amount recorded as Operating and maintenance expense from ~~contracts~~affiliates at the Utility Registrants. After the separation, such expenses are primarily recorded as Purchased power and an immaterial amount recorded as Operating and maintenance expense at the Utility Registrants.

•ComEd had an ICC-approved RFP contract with ~~customers. The objective of the new standard is~~Constellation to provide a ~~single, comprehensive revenue recognition model~~portion of ComEd’s electric supply requirements. ComEd also purchased RECs and ZECs from Constellation.

•PECO received electric supply from Constellation under contracts executed through PECO’s competitive procurement process. In addition, PECO had a ten-year agreement with Constellation to sell solar AECs.

•BGE received a portion of its energy requirements from Constellation under its MDPSC-approved market-based SOS and gas commodity programs.

•Pepco received electric supply from Constellation under contracts executed through Pepco’s competitive procurement process approved by the MDPSC and DCPSC.

•DPL received a portion of its energy requirements from Constellation under its MDPSC and DEPSC approved market-based SOS commodity programs.

•ACE received electric supply from Constellation under contracts executed through ACE’s competitive procurement process approved by the NJBPU.

ComEd and PECO also have receivables with Constellation for ~~all contracts with customers~~estimated excess funds at the end of decommissioning the Regulatory Agreement Units, such amounts are due back to ~~improve comparability within industries, across industries,~~ComEd and ~~across capital markets.~~ PECO, as applicable, for payment to their respective customers. See Note 3 — Regulatory Matters and Note 23 — Related Party Transactions of the 2022 Form 10-K for additional information.

Discontinued Operations

The ~~underlying principle is~~separation represented a strategic shift that ~~an entity will recognize revenue to depict~~would have a major effect on Exelon’s operations and financial results. Accordingly, the ~~transfer of goods or services to customers at an amount that~~separation meets the ~~entity expects to be entitled to in exchange~~criteria for ~~those goods or services. The guidance also requires a number of disclosures regarding~~discontinued operations.

There were no results from discontinued operations for the ~~nature, amount, timing,~~three and ~~uncertainty of revenue~~nine months ended September 30, 2023 and the ~~related cash flows.~~three months ended September 30, 2022. The ~~guidance can be applied retrospectively~~following table presents the results of Constellation that have been reclassified from continuing operations and included in discontinued operations within Exelon’s Consolidated Statements of Operations and Comprehensive Income for the nine months ended September 30, 2022.

These results are primarily Generation, which is comprised of Exelon’s Mid-Atlantic, Midwest, New York, ERCOT, and Other Power Regions reportable segments, and include the impact of transaction costs, certain BSC costs, including any transition costs, that were historically allocated and directly attributable to each prior reporting period presented (full retrospective method) or retrospectively with a cumulative effect adjustment to retained earnings for initial application of the guidance at the date of initial adoption (modified retrospective method).

The Registrants have assessed the revenue recognition standard and are executing a detailed implementation plan in preparation for adoption on January 1, 2018. The Registrants have also actively participated in the AICPA Power and Utilities Industry Task Force (Industry Task Force) process to identify implementation issues and support the development of related implementation guidance. In coordination with the Industry Task Force, the Registrants have reached conclusions on the following key accounting issues:

The Utility Registrants’ tariff sale contracts, including those with lower credit quality customers, are generally deemed to be probable of collection under the guidance and, thus, the timing of revenue recognition will continue to be concurrent with the delivery of electricity or natural gas, consistent with current practice;

Consistent with current industry practice, revenues recognized from sales of bundled energy commodities (i.e., contracts involving the delivery of multiple energy commodities such as electricity, capacity, ancillary services, etc.) are generally expected to be recognized upon delivery to the customer in an amount based on the invoice price given that it corresponds directly with the value of the commodities transferred to the customer; and

~~Contributions in aid of construction are outside of the scope of the standard and, therefore, will continue to be accounted for as a reduction to Property, Plant, and Equipment.~~

~~The Registrants have also completed the following key activities in their implementation plan:~~

Evaluated existing contracts and revenue streams for potential changes in revenue recognition under the new guidance. Based on these assessments, the Registrants have identified the following items that will be accounted for differently under the new revenue guidance as compared to current guidance:

Costs to acquire certain contracts (e.g., sales commissions associated with retail power contracts) will be deferred and amortized ratably over the term of the contract rather than being expensed as incurred; and

~~Variable consideration within certain contracts (e.g., performance bonuses) will be estimated and recognized as revenue over the term of the contract rather than being recognized when realized~~

~~Notwithstanding these identified changes, Exelon does not expect the new guidance will have a material impact on the amount and timing of revenue recognition;~~

~~Currently expect to apply the new guidance using the full retrospective method; and~~

Generation, ~~expects to disclose disaggregated revenue by operating segment and further differentiation by major products (i.e., electric power and gas)~~transactions between Generation and the Utility Registrants, ~~expect to disclose disaggregated revenue by major customer class (i.e., residential~~ and ~~commercial & industrial) separately~~tax-related adjustments. Transaction costs include costs for ~~electric~~external bankers, accountants, appraisers, lawyers, external counsels and ~~gas~~other advisors, among others, who are involved in the ~~Combined Notes~~negotiation, appraisal, due diligence and regulatory approval of the separation. Transition costs are primarily employee-related costs such as recruitment expenses, costs to ~~Consolidated Financial Statements.~~

~~Improving the Presentation of Net Periodic Pension Cost~~establish certain stand-alone functions and ~~Net Periodic Postretirement Benefit Cost (Issued March 2017):~~ The new standard will require significant changes to the accounting and presentation of pension and OPEB costs at the plan sponsor (i.e., Exelon) level. This guidance requires plan sponsors to report the service costinformation technology systems, professional services fees and other ~~non-service cost components~~separation-related costs during the transition to separate Generation. For the purposes of ~~net periodic pension cost and net periodic OPEB cost (together, net benefit cost) separately. Under current GAAP, net benefit cost is recorded as part of income from~~reporting discontinued operations, these results also include transactions between Generation and the ~~components are disclosed in the Retirement Benefits footnote. Service cost~~Utility Registrants that were historically eliminated within Exelon’s Consolidated Statements of Operations as these transactions will be ongoing after the separation. Certain BSC costs that were historically allocated to Generation are presented as part of ~~income from~~continuing operations ~~and~~in Exelon’s Consolidated Statements of Operations as these costs do not qualify as expenses of the ~~other non-service cost components will be classified outside of income from~~discontinued operations onper the ~~Consolidated~~

accounting rules.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 2 — Discontinued Operations

~~Statements~~


	Nine Months Ended September 30,
	2022
Operating revenues
Competitive business revenues	$	1,855
Competitive business revenues from affiliates	161
Total operating revenues	2,016
Operating expenses
Competitive businesses purchased power and fuel	1,138

Operating and maintenance(a)	371

Depreciation and amortization	94
Taxes other than income taxes	44
Total operating expenses	1,647
Gain on sales of assets and businesses	10
Operating income	379
Other income and (deductions)
Interest expense, net	(20)

Other, net	(281)
Total other income and (deductions)	(301)
Income before income taxes	78
Income taxes	(40)
Equity in losses of unconsolidated affiliates	(1)
Net income	117
Net income attributable to noncontrolling interests	1
Net income from discontinued operations	$	116

__________

(a)Includes transaction and transition costs related to the separation of Operations and Comprehensive Income. Additionally, service cost is the only component eligible for capitalization (whereas under current GAAP, all components of net benefit cost are eligible for capitalization).

Generation, ComEd, PECO, BGE, BSC, PHI, Pepco, DPL, ACE and PHISCO participate in Exelon’s single employer pension and OPEB plans and apply multi-employer accounting. Multi-employer accounting is not impacted by this standard, so Exelon's subsidiary financial statements will not change. On Exelon’s consolidated financial statements, non-service cost components of pension and OPEB cost capitalizable under a regulatory framework will be reported as regulatory assets (currently, they are capitalizable under pension and OPEB accounting guidance and reported as PP&E). These regulatory assets will be amortized outside of operating income.

~~The standard is effective January 1, 2018 and requires retrospective application~~$52 million for the ~~presentation~~nine months ended September 30, 2022.

There were no assets or liabilities of the service cost component and the other non-service cost components of net benefit cost and prospective application for the capitalization of only the service cost component of net benefit cost. Exelon will not early adopt this standard.

~~Leases (Issued February 2016):~~ Increases transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The guidance requires lessees to recognize both the right-of-use assets and lease liabilitiesdiscontinued operations included in the balance sheet for most leases, whereas today only financing type lease liabilities (capital leases) are recognized in the balance sheet. This is expected to require significant changes to systems, processes and procedures in order to recognize and measure leases recorded on the balance sheet that are currently classified as operating leases. In addition, the definition of a lease has been revised in regards to when an arrangement conveys the right to control the use of the identified asset under the arrangement which may result in changes to the classification of an arrangement as a lease. The recognition, measurement, and presentation of expenses and cash flows arising from a lease by a lessee have not significantly changed from current GAAP. The accounting applied by a lessor is largely unchanged from that applied under current GAAP. The standard is effective January 1, 2019. Early adoption is permitted, however the Registrants do not expect to early adopt the standard. Lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. Refer to Note 24 — Commitments and Contingencies of the Combined Notes to theExelon's Consolidated ~~Financial Statements in the Exelon 2016 Form 10-K for additional information regarding operating leases.~~

~~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 the entity’s current estimate of credit losses expected to be incurred over the life of the financial instrument. The standard does not make changes to the existing impairment models for non-financial assets such as fixed assets, intangibles and goodwill. The standard will be effective January 1, 2020 (with early adoption as of January 1, 2019 permitted) and, for most debt instruments, requires a modified retrospective transition approach through a cumulative-effect adjustment to retained earnings as of the beginning of the period of adoption.

~~Derivatives and Hedging (Issued September 2017):~~ Allows more financial and nonfinancial hedging strategies to be eligible for hedge accounting. The amendments are intended to more closely align hedge accounting with companies’ risk management strategies, simplify the application of hedge accounting, and increase transparency as to the scope and results of hedging programs. There are also amendments related to effectiveness testing and disclosure requirements. The guidance is effective January 1, 2019 and early adoption is permitted with a modified retrospective transition approach. The Registrants are currently assessing this standard but do not currently expect a significant impact given the limited activity for which the Registrants elect hedge accounting and because the Registrants do not anticipate increasing their use of hedge accounting as a result of this standard.

~~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. Exelon, Generation, ComEd, PHI, and DPL have goodwillBalance Sheet as of September 30, ~~2017. This updated guidance is not currently expected~~2023 and December 31, 2022. Constellation had net assets of $11,573 million that separated on February 1, 2022 that resulted in a reduction to ~~impact~~Exelon's equity during the ~~Registrants’~~year ended December 31, 2022. Refer to the Distribution of Constellation line in Exelon's Consolidated Statement of Changes in Shareholders' Equity for further information.

There were no discontinued operations included within Exelon’s Consolidated Statements of Cash Flows for the nine months ended September 30, 2023. The following table presents selected financial ~~reporting. The standard is effective January 1, 2020, with early adoption permitted, and must be applied on a prospective basis.~~

information regarding cash flows of the discontinued operations that are included within Exelon’s Consolidated Statements of Cash Flows for the nine months ended September 30, 2022.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 2 — Discontinued Operations

~~Clarifying the Definition of a Business (Issued January 2017):~~ Clarifies the definition of a business with the objective of addressing whether acquisitions (or dispositions) should be accounted for as acquisitions/dispositions of assets or as acquisitions/dispositions of businesses. If substantially all the fair value of the assets acquired/disposed of is concentrated in a single identifiable asset or a group of similar identifiable assets, the set of transferred assets and activities is not a business. If the fair value of the assets acquired/disposed of is not concentrated in a single identifiable asset or a group of similar identifiable assets, then an entity must evaluate whether an input and a substantive process exist, which together significantly contribute to the ability to produce outputs. The standard also revises the definition of outputs to focus on goods and services to customers. The standard will likely result in more acquisitions being accounted for as asset acquisitions. The standard is effective January 1, 2018, with early adoption permitted, and must be applied on a prospective basis.


	Nine Months Ended September 30,
	2022
Non-cash items included in net income from discontinued operations:
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization	$	207

Loss on sales of assets and businesses	9
Deferred income taxes and amortization of investment tax credits	(143)
Net fair value changes related to derivatives	(59)
Net realized and unrealized losses on NDT fund investments	205
Net unrealized losses on equity investments	16
Other decommissioning-related activity	36
Cash flows from investing activities:
Capital expenditures	(227)
Collection of DPP	169
Supplemental cash flow information:
Decrease in capital expenditures not paid	(128)
Increase in DPP	348
Increase in PP&E related to ARO update	335

~~Intra-Entity Transfers of Assets Other Than Inventory (Issued October 2016):~~ Requires entities to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs (current GAAP prohibits the recognition of current and deferred income taxes for an intra-entity asset transfer until the asset has been sold to an outside party). The standard is effective January 1, 2018 with early adoption permitted. The guidance requires a modified retrospective transition approach through a cumulative-effect adjustment to retained earnings as of the beginning of the period of adoption.

~~Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments (Issued August 2016) and Restricted Cash (Issued November 2016):~~ In 2016, the FASB issued two standards impacting the Statement of Cash Flows. The first adds or clarifies guidance on the classification of certain cash receipts and payments on the statement of cash flows as follows: debt prepayment or extinguishment costs, settlement of zero-coupon bonds, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies and bank-owned life insurance policies, distributions received from equity method investees, beneficial interest in securitization transactions, and the application of the predominance principle to separately identifiable cash flows. The second states that amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows (instead of being presented as cash flow activities). The Registrants will adopt both standards on January 1, 2018 on a retrospective basis. Adoption of the second standard will result in a change in presentation of restricted cash on the face of the Statement of Cash Flows; otherwise the Registrants do not expect that this guidance will have a significant impact on the Registrants’ Consolidated Statements of Cash Flows and disclosures.

~~Recognition and Measurement of Financial Assets and Financial Liabilities (Issued January 2016):~~ (i) Requires all investments in equity securities, including other ownership interests such as partnerships, unincorporated joint ventures and limited liability companies, to be carried at fair value through net income, (ii) requires an incremental recognition and disclosure requirement related to the presentation of fair value changes of financial liabilities for which the fair value option has been elected, (iii) amends several disclosure requirements, including the methods and significant assumptions used to estimate fair value or a description of the changes in the methods and assumptions used to estimate fair value, and (iv) requires disclosure of the fair value of financial assets and liabilities measured at amortized cost at the amount that would be received to sell the asset or paid to transfer the liability. The standard is effective January 1, 2018 with early adoption permitted. The guidance requires a modified retrospective transition approach with a cumulative effect adjustment to retained earnings for initial application of the guidance at the date of adoption. The Registrants will not early adopt this standard. The Registrants do not expect that this guidance will have a significant impact on the Registrants' Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, and Consolidated Statements of Cash Flows.

3. ~~Variable Interest Entities~~Regulatory Matters (All Registrants)

~~A VIE is a legal entity that possesses any~~ As discussed in Note 3 — Regulatory Mattersof the 2022 Form 10-K, the Registrants are involved in rate and regulatory proceedings at FERC and their state commissions. The following ~~characteristics: an insufficient amount of equity at risk~~discusses developments in 2023 and updates to ~~finance its activities, equity owners who do not have~~ the ~~power to direct~~2022 Form 10-K.

Distribution Base Rate Case Proceedings

The following tables show the significant activities of the entity (or have voting rights that are disproportionate to their ownership interest) or equity owners who do not have the obligation to absorb expected losses or the right to receive the expected residual returns of the entity. Companies are required to consolidate a VIE if they are its primary beneficiary, which is the enterprise that has the power to direct the activities that most significantly affect the entity’s economic performance.completed and pending distribution base rate case proceedings in 2023.

At September 30, 2017 and December 31, 2016, Exelon, Generation, BGE, PHI and ACE collectively consolidated six and nine VIEs or VIE groups, respectively, for which the applicable Registrant was the primary beneficiary (~~see~~Completed Distribution Base Rate Case Proceedings

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 3 — Regulatory Matters

~~Consolidated Variable Interest Entities below). As~~


Registrant/Jurisdiction	Filing Date	Service	Requested Revenue Requirement Increase		Approved Revenue Requirement Increase		Approved ROE		Approval Date	Rate Effective Date
ComEd - Illinois(a)	April 15, 2022	Electric	$	199	$	199	7.85	%	November 17, 2022	January 1, 2023
PECO - Pennsylvania	March 31, 2022	Natural Gas	82		55		N/A(b)		October 27, 2022	January 1, 2023
BGE - Maryland(c)	May 15, 2020 (amended September 11, 2020)	Electric	203		140		9.50	%	December 16, 2020	January 1, 2021
		Natural Gas	108		74		9.65	%

Pepco - Maryland(d)	October 26, 2020 (amended March 31, 2021)	Electric	104		52		9.55	%	June 28, 2021	June 28, 2021
DPL - Maryland(e)	May 19, 2022	Electric	38		29		9.60	%	December 14, 2022	January 1, 2023

__________

(a)ComEd's 2023 approved revenue requirement above reflects an increase of ~~September 30, 2017~~$144 million for the initial year revenue requirement for 2023 and December 31, 2016, Exelon and Generation collectively had significant interests in seven and eight, respectively, 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 Variable Interest Entities below)~~.

~~Consolidated Variable Interest Entities~~

~~In July 2017, Generation entered into~~ an ~~arrangement to sell a 49% interest in ExGen Renewables Partners, LLC (the Renewable JV) to an outside investor for $400~~increase of $55 million of cash plus immaterial working capital and other customary post-closing adjustments. The Renewable JV meets the definition of a VIE because the Renewable JV has a similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner. Additionally, under the VIE guidance Generation is the primary beneficiary because Generation maintains the controlling financial interest; therefore, Generation will continue to consolidate the Renewable JV.

Generation owned 90% of a biomass fueled, combined heat and power company. In the second quarter of 2015, the entity was deemed to be a VIE because the entity required additional subordinated financial support in the form of a parental guarantee provided by Generation for up to $275 million in support of the payment obligations related to the ~~Engineering, Procurement~~annual reconciliation for 2021. The revenue requirement for 2023 provides for a weighted average debt and ~~Construction (EPC) contract (see Note 14 - Debt~~equity return on distribution rate base of 5.94%, inclusive of an allowed ROE of 7.85%, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. The reconciliation revenue requirement for 2021 provides for a weighted average debt and ~~Credit Agreements~~equity return on distribution rate base of 5.91%, inclusive of an allowed ROE of 7.78%, reflecting the monthly yields on 30-year treasury bonds plus 580 basis points less a performance metrics penalty of 7 basis points. This is ComEd's last performance-based electric distribution formula rate established under EIMA. See discussion of CEJA below for ~~additional~~ details on ~~Albany Green Energy, LLC). During~~ the ~~third quarter~~transition away from the electric distribution formula rate.

(b)The PECO natural gas base rate case proceeding was resolved through a settlement agreement, which did not specify an approved ROE.

(c)Reflects a three-year cumulative multi-year plan for 2021 through 2023. BGE proposed to use certain tax benefits to fully offset the increases in 2021 and 2022 and partially offset the increase in 2023. The MDPSC awarded BGE electric revenue requirement increases of ~~2017,~~$59 million, $39 million, and $42 million, before offsets, in 2021, 2022, and 2023, respectively, and natural gas revenue requirement increases of $53 million, $11 million, and $10 million, before offsets, in 2021, 2022, and 2023, respectively. However, the ~~ownership~~MDPSC utilized the tax benefits to fully offset the increases in 2021 and January 2022 such that customer rates remained unchanged. For the remainder of 2022, the MDPSC chose to offset only 25% of the ~~entity increased~~cumulative 2021 and 2022 electric revenue requirement increases and 50% of the cumulative gas revenue requirement increases. In 2021, the MDPSC deferred a decision on whether to ~~99%, all payment obligations related~~use certain tax benefits to offset the ~~EPC contract were satisfied,~~revenue requirement increases in 2023 and directed BGE to make another proposal at the ~~parental guarantee provided by Generation was terminated. As~~end of 2022. In September 2022, BGE proposed that tax benefits not be used to offset the 2023 revenue requirement increases. On October 26, 2022, the MDPSC accepted BGE's recommendation to not use tax benefits to offset the 2023 revenue requirement increases.

(d)Reflects a ~~result,~~three-year cumulative multi-year plan for April 1, 2021 through March 31, 2024. The MDPSC awarded Pepco electric incremental revenue requirement increases of $21 million, $16 million, and $15 million, before offsets, for the ~~entity is now sufficiently capitalized~~12-month periods ending March 31, 2022, 2023, and ~~no longer meets~~2024, respectively. Pepco proposed to utilize certain tax benefits to fully offset the ~~definition~~increase through 2023 and partially offset customer rate increases in 2024. However, the MDPSC only utilized the acceleration of refunds for certain tax benefits to fully offset the increases such that customer rates remain unchanged through March 31, 2022. On February 23, 2022, the MDPSC chose to offset 25% of the cumulative revenue requirement increase for the 12-month period ending March 31, 2023. In 2021, the MDPSC deferred a ~~VIE. The entity was previously disclosed in “a group of companies formed by Generation~~decision on whether to ~~build, own and operate other generating facilities” as of~~use certain tax benefits to offset the revenue requirement increases for the 12-month period ending March 31, 2024. In December 2022 Pepco proposed that tax benefits not be used to offset the revenue requirement increases for this period. On January 25, 2023, the MDPSC accepted Pepco’s recommendations not to use tax benefits to offset revenue requirement increases for the 12-month period ending March 31, 2024.

(e)Reflects a three-year cumulative multi-year plan for January 1, 2023 through December 31, ~~2016. However, the biomass facility will continue to be consolidated by Generation under the voting interest model.~~

RSB BondCo LLC (BondCo) is a special purpose bankruptcy remote limited liability company formed by BGE to acquire, hold, issue and service bonds secured by rate stabilization property. BGE is required to remit all payments it receives from all residential customers through non-bypassable, rate stabilization charges to BondCo. In the second quarter2025. The MDPSC awarded DPL electric incremental revenue requirement increases of ~~2017 the rate stabilization bonds were fully redeemed and BGE remitted its final payment to BondCo. During the nine months ended September 30, 2017, BGE remitted $22~~$17 million, ~~to BondCo. During the three and nine months ended September 30, 2016, BGE remitted $27~~$6 million, and ~~$64~~$6 million ~~to BondCo,~~for 2023, 2024, and 2025, respectively. ~~Upon the redemption of the bonds, BondCo no longer meets the definition of a variable interest entity and is removed from the list of consolidated VIEs noted below.~~

During 2009, Constellation formed a retail gas group to enter into a collateralized gas supply agreement with a third-party gas supplier. The retail gas group was determined to be a VIE because there was not sufficient equity to fund the group’s activities without additional credit support and a $75 million parental guarantee provided by Generation. As the primary beneficiary, Generation consolidated the retail gas group. During the second quarter of 2017, the collateral structure was terminated with the third-party gas supplier except for the $75 million parental guarantee provided by Generation. Although the parental guarantee will remain, this is considered customary and reasonable for the unsecured position Generation has with the third-party gas supplier. As a result of the termination, the retail gas group no longer met the definition of a VIE and was removed from the list of consolidated VIEs noted below. However, the retail gas group continues to be consolidated by Generation under the voting interest model.

~~As of September 30, 2017, Exelon's and Generation's consolidated VIEs consist of:~~

Renewable energy project companies formed by Generation to build, own and operate renewable power facilities, which were previously separated into two separate VIE groups for solar project limited liability companies and wind project companies as of December 31, 2016,

Constellation EG, LLC (a company that operates back-up generation for a third-party), which was previously included in a group of companies formed by Generation to build, own and operate other generating facilities as of December 31, 2016,

~~certain retail power and gas companies for which Generation is the sole supplier of energy,~~

~~CENG,~~

~~2015 ESA Investco, LLC, a company that holds an equity method investment in a distributed energy company, and~~

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 3 — Regulatory Matters

AsPending Distribution Base Rate Case Proceedings

Registrant/Jurisdiction

Filing Date

Service

Requested Revenue Requirement Increase

Requested ROE

Expected Approval Timing

ComEd - Illinois(a)

January 17, 2023

Electric

1,487

10.50% to 10.65%

Fourth quarter of 2023

ComEd - Illinois(b)

April 21, 2023

Electric

247

8.91%

Fourth quarter of 2023

BGE - Maryland(c)

February 17, 2023

Electric

313

10.40%

Fourth quarter of 2023

Natural Gas

289

10.40%

Pepco - District of Columbia(d)

April 13, 2023

Electric

191

10.50%

Second quarter of 2024

Pepco - Maryland(e)

May 16, 2023

Electric

214

10.50%

Second quarter of 2024

DPL - Delaware(f)

December 15, 2022 (amended September 29, 2023)

Electric

10.50%

Second quarter of 2024

ACE - New Jersey(g)

February 15, 2023 (amended August 21, 2023)

Electric

10.50%

Fourth quarter of 2023

__________

(a)On September 27, 2023, ComEd filed its reply brief supporting its proposed multi-year rate and grid plans, as adjusted or modified by ComEd as of ~~September 30, 2017, Exelon's, PHI's~~the evidentiary hearing on August 22, 2023. The rate plan covers the period from January 1, 2024 to December 31, 2027 and ~~ACE's consolidated VIE consists of:~~includes total requested revenue requirement increases of $968 million effective January 1, 2024, $181 million effective January 1, 2025, $163 million effective January 1, 2026, and $175 million effective January 1, 2027, based on forecasted revenue requirements. If approved, the revenue requirement will provide for a weighted average debt and equity return on distribution rate base of 7.40% in 2024, 7.47% in 2025, 7.58% in 2026, and 7.65% in 2027, inclusive of an allowed ROE of 10.50% in 2024, 10.55% in 2025, 10.60% in 2026, and 10.65% in 2027. The requested revenue requirements are based on capital structures that reflect between 50.58% and 51.19% common equity. ComEd’s MRP also includes a proposed three-tranche rate phase-in to defer approximately $339 million, of the $968 million year-over-year revenue increase for 2024 from 2024 to 2026, approximately $52 million, of the $520 million year-over-year revenue increase for 2025 from 2025 to 2027, and approximately $75 million of the $215 million year-over-year revenue increase for 2026 from 2026 to 2028.

~~ATF~~, ~~a special purpose entity formed by ACE~~(b)On April 21, 2023, ComEd filed its proposed Delivery Reconciliation Amount of $247 million under Rider Delivery Service Pricing Reconciliation (Rider DSPR) which allows for the ~~purpose~~reconciliation of ~~securitizing authorized portions~~the revenue requirement in effect in the final years in which formula rates are determined and until such time as new rates are established under ComEd’s approved MRP. The 2023 filing reconciles the delivery service rates in effect in 2022 with the actual delivery service costs incurred in 2022. Final order is expected by December 2023, and the reconciliation amount will be in customer rates beginning January 1, 2024.

(c)Reflects a three-year cumulative multi-year plan for January 1, 2024 through December 31, 2026 submitted to the MDPSC. Inclusive of ~~ACE’s recoverable stranded costs~~the proposed acceleration of remaining electric tax benefits in 2024 and 2025, and remaining gas tax benefits in 2024, BGE requested total electric revenue requirement increases of $85 million, $103 million, and $125 million in 2024, 2025, and 2026, respectively, and natural gas revenue requirement increases of $158 million, $77 million, and $54 million in 2024, 2025, and 2026, respectively. Requested revenue requirement increases will be used to recover capital investments designed to increase the resilience of the electric and gas distribution systems and support Maryland’s climate and regulatory initiatives. The 2021 and 2022 reconciliation amounts are not included in the requested revenue requirement increase, as BGE is proposing that these amounts be recovered through the ~~issuance~~separate electric and ~~sale of transition bonds.~~

gas riders in 2024. The 2021 reconciliation amounts are $11 million and $7 million for electric and gas, respectively, and the 2022 reconciliation amounts are $44 million and $15 million for electric and gas, respectively. The requested electric revenue requirement includes approximately $25 million for a Customer Electrification Plan that the MDPSC struck from BGE's case in August 2023.

~~As of September 30, 2017 and~~(d)Reflects a three-year cumulative multi-year plan for January 1, 2024 through December 31, ~~2016, ComEd, PECO, Pepco and DPL did not have any material consolidated VIEs.~~

~~As of September 30, 2017 and December 31, 2016, Exelon and Generation provided the following support to their respective consolidated VIEs:~~

~~Generation provides operating and capital funding~~2026 submitted to the ~~renewable energy project companies~~DCPSC. Pepco requested total electric revenue requirement increases of $117 million, $37 million, and ~~there is limited recourse to Generation related to certain renewable energy project companies.~~

~~Generation provides operating and capital funding to Constellation EG, LLC.~~

~~Generation provides approximately $31~~$37 million in ~~credit~~2024, 2025, and 2026, respectively. Requested revenue requirement increases will be used to recover capital investments designed to advance system-readiness and support the District of Columbia’s climate and clean energy goals.

(e)Reflects a three-year cumulative multi-year plan for ~~the retail power and gas companies for which Generation is the sole supplier of energy.~~

Exelon and Generation, where indicated, provide the following support to CENG (see Note 5—Investment in Constellation Energy Nuclear Group, LLC and Note 27—Related Party Transactions of the Exelon 2016 Form 10-K for additional information regarding Generation's and Exelon’s transactions with CENG):

~~under the NOSA, Generation conducts all activities related~~April 1, 2024 through March 31, 2027 submitted to the ~~operation~~MDPSC. Pepco requested total electric revenue requirement increases of ~~the CENG nuclear generation fleet owned by CENG subsidiaries (the CENG fleet)~~$74 million, $60 million and provides corporate and administrative services for the remaining life and decommissioning of the CENG nuclear plants as if they were a part of the Generation nuclear fleet, subject to the CENG member rights of EDF,

~~under the Power Services Agency Agreement (PSAA), Generation provides scheduling, asset management and billing services to the CENG fleet for the remaining operating life of the CENG nuclear plants,~~$60 million effective April 1,

under power purchase agreements with CENG, Generation purchased or will purchase 50.01% of the available output generated by the CENG nuclear plants not subject to other contractual agreements from January 2015 through the end of the operating life of each respective plant. However, pursuant to amendments dated March 31, 2015, the energy obligations under the Ginna Nuclear Power Plant (Ginna) PPAs were suspended during the term of the Reliability Support Services Agreement (RSSA), through the end of March 31, 2017. With the expiration of the RSSA, the PPA was reinstated beginning April 1, 2017 (see Note 5 — ~~Regulatory Matters~~ ~~for additional details),~~

Generation provided a $400 million loan to CENG. As of September 30, 2017, the remaining obligation is $328 million, including accrued interest, which reflects the principal payment made in January 2015,

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 $637 million of contingent payment obligations for the payment of contingent retrospective premium adjustments for the nuclear liability insurance,~~

Generation provides a guarantee of approximately $8 million associated with hazardous waste management facilities and underground storage tanks. In addition, EDF executed a reimbursement agreement that provides reimbursement to Exelon for 49.99% of any amounts paid by Generation under this guarantee,

Generation and EDF are the members-insured with Nuclear Electric Insurance Limited and have assigned the loss benefits under the insurance and the NEIL premium costs to CENG and guarantee the obligations of CENG under these insurance programs in proportion to their respective member interests (see Note 18 — ~~Commitments and Contingencies~~ ~~for more details), and~~

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 3 — Regulatory Matters

~~Exelon has executed an agreement to provide up to $245~~2024, April 1, 2025, and April 1, 2026, respectively. The plan contains a proposed nine-month extension period with a requested revenue requirement increase of $20 million ~~to support the operations of CENG as well as a $165 million guarantee of CENG’s cash pooling agreement with its subsidiaries.~~

~~As of September 30, 2017 and~~effective April 1, 2027 through December 31, ~~2016, Exelon, PHI and ACE provided the following support to their respective consolidated VIE:~~

In the case of ATF, 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. During the three and nine months ended September 30, 2017, ACE transferred $11 million and $39 million to ATF, respectively. During the three and nine months ended September 30, 2016, ACE transferred $20 million and $47 million to ATF, respectively.

~~For each of the consolidated VIEs, except as otherwise noted:~~

~~the assets of the VIEs are restricted and can only~~2027. Requested revenue requirement increases will be used to ~~settle obligations of the respective VIE;~~

~~Exelon, Generation, PHI~~recover capital investments designed to advance system-readiness and ~~ACE did not provide any additional material financial~~ support ~~to the VIEs;~~

~~Exelon, Generation, PHI~~Maryland's climate and ~~ACE did not have any material contractual commitments or obligations to provide financial support to the VIEs; and~~

~~the creditors of the VIEs did not have recourse to Exelon’s, Generation’s, PHI's or ACE's general credit.~~

The carrying amounts and classification of the consolidated VIEs’ assets and liabilities included in the Registrants' consolidated financial statements at September 30, 2017 and December 31, 2016 are as follows:

September 30, 2017 December 31, 2016
Successor Successor

Exelon^(a)
Generation
PHI ^(a)
ACE
Exelon^(a)(b)
Generation BGE
PHI^(a)
ACE
Current assets $ 657
$ 644
$ 13
$ 9
$ 954
$ 916
$ 23
$ 14
$ 9
Noncurrent assets 9,252
9,222
30
22
8,563
8,525
3
35
23
Total assets $ 9,909

$ 9,866

$ 43
$ 31

$ 9,517

$ 9,441

$ 26

$ 49
$ 32
Current liabilities $ 404
$ 367
$ 37
$ 33
$ 885
$ 802
$ 42
$ 42
$ 37
Noncurrent liabilities 3,290
3,215
75
67
2,713
2,612
—
101
89
Total liabilities $ 3,694

$ 3,582

$ 112
$ 100

$ 3,598

$ 3,414

$ 42

$ 143
$ 126

~~_________~~


~~(a)~~	~~Includes certain purchase accounting adjustments not pushed down to the ACE standalone entity.~~


~~(b)~~	~~Includes certain purchase accounting adjustments not pushed down to the BGE standalone entity.~~

~~Table of Contents~~

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

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

~~Assets and Liabilities of Consolidated VIEs~~

Included within the balances above are assets and liabilities of certain consolidated VIEs for which the assets can only be used to settle obligations of those VIEs, and liabilities that creditors or beneficiaries do not have recourse to the general credit of the Registrants. As of September 30, 2017 and December 31, 2016, these assets and liabilities primarily consisted of the following:

September 30, 2017 December 31, 2016
Successor Successor

Exelon ^(a)

Generation
PHI ^(a)
ACE
Exelon^(a)(b)
Generation BGE
PHI^(a)
ACE
Cash and cash equivalents $ 130
$ 130
$ —
$ —
$ 150
$ 150
$ —
$ —
$ —
Restricted cash 85
76
9
9
59
27
23
9
9
Accounts receivable, net

Customer 139
139
—
—
371
371
—
—
—
Other 25
25
—
—
48
48
—
—
—
Mark-to-market derivatives assets —
—
—
—
31
31
—
—
—
Inventory

Materials and supplies 196
196
—
—
199
199
—
—
—
Other current assets 56
52
4
—
50
44
—
5
—
Total current assets 631

618

13
9
908

870

23

14
9
Property, plant and equipment, net 6,213
6,213
—
—
5,415
5,415
—
—
—
Nuclear decommissioning trust funds 2,415
2,415
—
—
2,185
2,185
—
—
—
Goodwill —
—
—
—
47
47
—
—
—
Mark-to-market derivative assets —
—
—
—
23
23
—
—
—
Other noncurrent assets 261
231
30
22
315
277
3
35
23
Total noncurrent assets 8,889

8,859

30
22
7,985

7,947

3

35
23
Total assets $ 9,520

$ 9,477

$ 43
$ 31
$ 8,893

$ 8,817

$ 26

$ 49
$ 32
Long-term debt due within one year $ 182
$ 146
$ 36
$ 32
$ 181
$ 99
$ 41
$ 40
$ 35
Accounts payable 104
104
—
—
269
269
—
—
—
Accrued expenses 90
89
1
1
119
116
1
2
2
Mark-to-market derivative liabilities —
—
—
—
60
60
—
—
—
Unamortized energy contract liabilities 17
17
—
—
15
15
—
—
—
Other current liabilities 11
11
—
—
30
30
—
—
—
Total current liabilities 404
367
37
33
674
589
42

42
37
Long-term debt 1,172
1,097
75
67
641
540
—
101
89
Asset retirement obligations 2,009
2,009
—
—
1,904
1,904
—
—
—
Pension obligation^(c)
—
—
—
—
9
9
—
—
—
Unamortized energy contract liabilities 9
9
—
—
22
22
—
—
—
Other noncurrent liabilities 94
94
—
—
106
106
—
—
—
Total noncurrent liabilities 3,284
3,209
75
67
2,682
2,581
—

101
89
Total liabilities $ 3,688
$ 3,576
$ 112
$ 100
$ 3,356
$ 3,170
$ 42

$ 143
$ 126

~~_________~~


~~(a)~~	~~Includes certain purchase accounting adjustments not pushed down to the ACE standalone entity.~~


~~(b)~~	~~Includes certain purchase accounting adjustments not pushed down to the BGE standalone entity.~~


~~(c)~~	Includes the retail gas pension obligation, which is presented as a net asset balance within the Prepaid pension asset line item on Generation’s Consolidated Balance Sheets. See Note 14 - Retirement Benefits for additional details.

~~Unconsolidated Variable Interest Entities~~

~~Exelon’s and Generation’s variable interests in unconsolidated VIEs generally include equity investments and~~clean energy purchase and sale contracts. For the equity investments, the carrying amount of the investments is reflected on 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

~~Table of Contents~~

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

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

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. Further, Exelon and Generation have not provided material debt or equity support, liquidity arrangements or performance guarantees associated with these commercial agreements.

~~As of September 30, 2017, Exelon's and Generation's unconsolidated VIEs consist of:~~

~~Energy purchase and sale agreements with VIEs for which Generation has concluded that consolidation is not required.~~

~~Asset sale agreement with ZionSolutions, LLC and EnergySolutions, Inc. in which Generation has a variable interest but has concluded that consolidation is not required.~~

~~Equity investments in distributed energy companies and energy generating facilities for which Generation has concluded that consolidation is not required.~~

~~As of September 30, 2017 and December 31, 2016, ComEd, PECO, BGE, PHI, Pepco, ACE, and DPL did not have any material unconsolidated VIEs.~~

As of September 30, 2017 and December 31, 2016, Exelon and Generation had significant unconsolidated variable interests in seven and eight VIEs, respectively, for which Exelon or Generation, as applicable, was not the primary beneficiary; including certain equity investments and certain commercial agreements. The decrease in the number of unconsolidated VIEs is due to the sale of an equity investment in an energy generating facility. Exelon and Generation only include unconsolidated VIEs that are individually material in the tables below. However, Generation has several individually immaterial VIEs that in aggregate represent a total investment of $17 million. These immaterial VIEs are equity and debt securities in energy development companies. The maximum exposure to loss related to these securities is limited to the $17 million included in Investments on Exelon’s and Generation’s Consolidated Balance Sheets. ~~The risk of a loss was assessed to be remote and, accordingly, Exelon and Generation have not recognized a liability associated with any portion of the maximum exposure to loss.~~

In June 2015, 2015 ESA Investco, LLC, then a wholly owned subsidiary of Generation, entered into an arrangement to purchase a 90% equity interest and 99% of the tax attributes of a distributed energy company, which is an unconsolidated VIE. In November 2015, Generation sold 69% of its equity interest in 2015 ESA Investco, LLC to a tax equity investor. Generation and the tax equity investor contributed a total of $227 million of equity incrementally from inception through the first quarter of 2017 in proportion of their ownership interests. Generation and the tax equity investor provided a parental guarantee of up to $275 million in proportion to their ownership interests in support of 2015 ESA Investco, LLC's obligation to make equity contributions to the distributed energy company. As all equity contributions were made as of the first quarter 2017, there is no further payment obligation under the parental guarantee.

~~Table of Contents~~

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

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

~~The following tables present summary information about Exelon's and Generation’s significant unconsolidated VIE entities:~~

September 30, 2017
Commercial
Agreement
VIEs

Equity
Investment
VIEs
Total
Total assets^(a)
$ 635
$ 519
$ 1,154
Total liabilities^(a)
39
229
268
Exelon's ownership interest in VIE^(a)
—
259
259
Other ownership interests in VIE^(a)
596
31
627
Registrants’ maximum exposure to loss:
Carrying amount of equity method investments —
259
259
Contract intangible asset 9
—
9
Debt and payment guarantees —
—
—
Net assets pledged for Zion Station decommissioning^(b)
4
—
4

December 31, 2016
Commercial
Agreement
VIEs

Equity
Investment
VIEs
Total
Total assets^(a)
$ 638
$ 567
$ 1,205
Total liabilities^(a)
215
287
502
Exelon's ownership interest in VIE^(a)
—
248
248
Other ownership interests in VIE^(a)
423
32
455
Registrants’ maximum exposure to loss:
Carrying amount of equity method investments —
264
264
Contract intangible asset 9
—
9
Debt and payment guarantees —
3
3
Net assets pledged for Zion Station decommissioning^(b)
9
—
9

~~_________~~


~~(a)~~	These items represent amounts on the unconsolidated VIE balance sheets, not on Exelon’s or Generation’s Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs.

~~(b)~~

These items represent amounts on Exelon’s and Generation’s Consolidated Balance Sheets related to the asset sale agreement with ZionSolutions, LLC. The net assets pledged for Zion Station decommissioning includes gross pledged assets of $57 million and $113 million as of September 30, 2017 and December 31, 2016, respectively; offset by payables to ZionSolutions LLC of $53 million and $104 million as of September 30, 2017 and December 31, 2016, respectively. These items are included to provide information regarding the relative size of the ZionSolutions LLC unconsolidated VIE. See Note 13 - Nuclear Decommissioning for additional details.

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. In addition, there are no material agreements with, or commitments by, third parties that would affect the fair value or risk of their variable interests in these VIEs.

~~BGE~~

The financing trust of BGE, BGE Capital Trust II, was created in 2003 for the purpose of issuing mandatorily redeemable trust preferred securities. In the third quarter of 2017, BGE redeemed the securities pursuant to the optional redemption provisions of the Indenture, under which the subordinated debt securities were issued, and dissolved BGE Capital Trust II. Prior to dissolution the BGE Capital Trust II was not consolidated in Exelon's or BGE's financial statements. BGE concluded it did not have a significant variable interest in BGE Capital Trust II as BGE financed its equity interest in the financing trust through the issuance of subordinated debt and, therefore, had no equity at risk. See Note 14 - Debt and Credit Agreements of the Exelon 2016 Form 10-K for additional information.

~~Table of Contents~~

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

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

~~4. Mergers, Acquisitions and Dispositions (Exelon, Generation, PHI, Pepco and DPL)~~

~~Acquisition of James A. FitzPatrick Nuclear Generating Station (Exelon and Generation)~~

goals. On March 31, 2017, Generation acquired the 838 MW 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 acquisition agreements, Generation provided nuclear fuel and reimbursed Entergy for incremental costs to prepare for and conduct a plant refueling outage; and Generation reimbursed Entergy for incremental costs to operate and maintain the plant for the period after the refueling outage through the acquisition closing date. These reimbursements covered costs that Entergy otherwise would have avoided had it shut down the plant as originally intended in January 2017. The amounts reimbursed by Generation were offset by FitzPatrick's electricity and capacity sales revenues for this same post-outage period. 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. As of September 30, 2017, Generation had remitted purchase price consideration of $289 million (including $235 million of cash and $54 million of nuclear fuel) to and on behalf of Entergy.

The fair values of FitzPatrick’s assets and liabilities were determined based on significant estimates and assumptions that are judgmental in nature, including projected future cash flows (including timing), discount rates reflecting risk inherent in the future cash flows and future power and fuel market prices. The valuations performed in the first quarter of 2017 to determine the fair value of the FitzPatrick assets acquired and liabilities assumed were preliminary. Accounting guidance provides that the allocation of the purchase price may be modified up to one year from the date of the acquisition to the extent that additional information is obtained about the facts and circumstances that existed as of the acquisition date.

During the third quarter of 2017, certain modifications were made to the initial preliminary valuation amounts for acquired property, plant and equipment, the decommissioning ARO, pension and OPEB obligations and related deferred tax liabilities, resulting in a $3 million net increase in assets acquired and liabilities assumed. Additionally, in the third quarter a purchase price settlement payment of $4 million was received from Entergy. Consequently, Exelon and Generation recorded an additional after-tax bargain purchase gain of $7 million for the three months ended September 30, 2017. For the nine months ended September 30, 2017, the after-tax bargain purchase gain of $233 million is included within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income and primarily reflects differences in strategies between Generation and Entergy for the intended use and ultimate decommissioning of the plant. There are no further adjustments expected to be made to the allocation of the purchase price. See Note 13 - Nuclear Decommissioning and Note 14 - Retirement Benefits for additional information regarding the FitzPatrick decommissioning ARO and pension and OPEB updates.

~~Table of Contents~~

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

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

The following table summarizes the acquisition-date fair value of the consideration transferred and the assets and liabilities assumed for the FitzPatrick acquisition by Generation as of September 30, 2017:

Cash paid for purchase price $ 110
Cash paid for net cost reimbursement 125
Nuclear fuel transfer 54
Total consideration transferred $ 289

Identifiable assets acquired and liabilities assumed
Current assets $ 60
Property, plant and equipment 298
Nuclear decommissioning trust funds 807
Other assets^(a)
114
Total assets $ 1,279

Current liabilities $ 6
Nuclear decommissioning ARO 444
Pension and OPEB obligations 33
Deferred income taxes 149
Spent nuclear fuel obligation 110
Other liabilities 15
Total liabilities $ 757
Total net identifiable assets, at fair value $ 522

Bargain purchase gain (after-tax) $ 233

~~_________~~


~~(a)~~	Includes a $110 million asset associated with a contractual right to reimbursement from the New York Power Authority (NYPA), a prior owner of FitzPatrick, associated with the DOE one-time fee obligation. See Note 24-Commitments and Contingencies of the Exelon 2016 Form 10-K for additional background regarding SNF obligations to the DOE.

For the three and nine months ended September 30, 2017, Exelon and Generation incurred $6 million and $53 million, respectively, of merger and integration related costs which are included within Operating and maintenance expense in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.

~~Acquisition of ConEdison Solutions (Exelon and Generation)~~

On September 1, 2016, Generation acquired the competitive retail electricity and natural gas business of Consolidated Edison Solutions, Inc. (ConEdison Solutions), a subsidiary of Consolidated Edison, Inc. 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 Solutions are excluded from the transaction.

The fair values of ConEdison Solutions' assets and liabilities were determined based on significant estimates and assumptions that are judgmental in nature, including projected future cash flows (including timing), discount rates reflecting risk inherent in the future cash flows and future power and fuel market prices. The purchase price equaled the estimated fair value of the net assets acquired and the liabilities assumed and, therefore, no goodwill or bargain purchase was recorded as of the acquisition date. The purchase price allocation is now final.

~~Table of Contents~~

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

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

~~The following table summarizes the final acquisition-date fair value of the consideration transferred and the assets and liabilities assumed for the ConEdison Solutions acquisition by Generation:~~

Total consideration transferred $ 257

Identifiable assets acquired and liabilities assumed
Working capital assets $ 204
Property, plant and equipment 2
Mark-to-market derivative assets 6
Unamortized energy contract assets 100
Customer relationships 9
Other assets 1
Total assets $ 322

Mark-to-market derivative liabilities $ 65
Total liabilities $ 65
Total net identifiable assets, at fair value $ 257

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

~~Description of Transaction~~

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 Pepco Holdings, Inc. (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 Exelon Energy Delivery Company, LLC (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.

~~Regulatory Matters~~

Approval of the merger in Delaware, New Jersey, Maryland and the District of Columbia was conditioned upon Exelon and PHI agreeing to certain commitments including where applicable: customer rate credits, funding for energy efficiency and delivery system modernization programs, a green sustainability fund, workforce development initiatives, charitable contributions, renewable generation and other required commitments. In addition, the orders approving the merger in Delaware, New Jersey, and Maryland include a “most favored nation” provision which, generally, requires allocation of merger benefits proportionally across all the jurisdictions.

During the third and fourth quarters of 2016, Exelon and PHI filed proposals in Delaware, New Jersey and Maryland for amounts and allocations reflecting the application of the most favored nation provision, resulting in a total nominal cost of commitments of $513 million, excluding renewable generation commitments (approximately $444 million on a net present value basis amount, excluding renewable generation commitments and charitable contributions). These filings reflected agreements reached with certain parties to the merger proceedings in these jurisdictions. In 2016, the DPSC and NJBPU approved the amounts and allocations of the additional merger benefits for Delaware and New Jersey, respectively. On April 12, 2017,August 7, 2023, the MDPSC issued an order approving a settlement agreement which allows Pepco to establish a revenue deferral mechanism to recover its full Commission-authorized year 1 increase between July 1, 2024 through March 31, 2025 and extend the ~~amounts~~procedural schedule to address intervenor resource constraints.

(f)The rates went into effect on July 15, 2023, subject to refund.

(g)Requested increases are before New Jersey sales and use tax. ACE’s procedural schedule was suspended on September 6, 2023. On October 21, 2023, ACE filed a stipulation of settlement with the NJBPU. Subsequently, on October 24, 2023, the administrative law judge presiding over the case recommended the settlement with all parties be approved. ACE is awaiting final approval of the ~~additional merger benefits for Maryland, but amending~~settlement from the ~~proposed allocations of~~NJBPU and it is expected during the ~~benefits. The amended allocations do not have a material effect on any of the Registrants' financial statements. No changes in commitment cost levels are required in the District of Columbia.~~

~~During the second~~fourth quarter of 2017, Exelon finalized the application of $8 million funding for low- and moderate-income customers in the Pepco Maryland and DPL Maryland service territories. This resulted in an adjustment to merger commitment costs recorded at Exelon Corporate, Pepco, and DPL. Exelon Corporate recorded an increase of $8 million and Pepco and DPL recorded a decrease of $6 million and $2 million, respectively, in Operating and maintenance expense.2023.

~~Table of Contents~~

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

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

Transmission Formula Rates

The ~~following amounts represent total commitment costs for Exelon, PHI, Pepco, DPL and ACE that have been recorded since the acquisition date:~~

Expected Payment Period Successor
Description Pepco DPL ACE PHI Exelon
Rate credits 2016 - 2017 $ 91
$ 67
$ 101
$ 259
$ 259
Energy efficiency 2016 - 2021 —
—
—
—
122
Charitable contributions 2016 - 2026 28
12
10
50
50
Delivery system modernization Q2 2017 —
—
—
—
22
Green sustainability fund Q2 2017 —
—
—
—
14
Workforce development 2016 - 2020 —
—
—
—
17
Other 1
5
—
6
29
Total $ 120
$ 84
$ 111
$ 315
$ 513

Pursuant to the orders approving the merger, Exelon made $73 million, $46 million and $49 million of equity contributions to Pepco, DPL and ACE, respectively, in the second quarter of 2016 to fund the after-tax amounts of the customer bill credit and the customer base rate credit commitments.

~~In addition, Exelon is committed to develop or to assist in the commercial development of approximately 37 MWs of new generation in Maryland, District of Columbia, and Delaware, 27 MWs of which~~Utility Registrants' transmission rates are expected to be completed by 2018. These investments are expected to total approximately $137 million, are expected to be primarily capital in nature, and will generate future earnings at Exelon and Generation. Investment costs will be recognized as incurred and recordedeach established based on Exelon's and Generation's financial statements. Exelon has also committed to purchase 100 MWs of wind energy in PJM, to procure 120 MWs of wind RECs for the purpose of meeting Delaware's renewable portfolio standards, and to maintain and promote energy efficiency and demand response programs in the PHI jurisdictions.

~~Pursuant to the various jurisdictions' merger approval conditions, over specified periods~~a FERC-approved formula. ComEd, BGE, Pepco, DPL, and ACE are ~~not permitted~~required to ~~reduce employment levels due~~file an annual update to ~~involuntary attrition associated~~the FERC-approved formula on or before May 15, and PECO is required to file on or before May 31, with the ~~merger integration process and have made other commitments regarding hiring and relocation of positions.~~

In July 2015, the OPC, Public Citizen, Inc., the Sierra Club and the Chesapeake Climate Action Network (CCAN) filed motions to stay the MDPSC order approving the merger. The Circuit Court judge issued an order denying the motions for stayresulting rates effective on August 12, 2015. On January 8, 2016, the Circuit Court judge affirmed the MDPSC’s order approving the merger and denied the petitions for judicial review filed by the OPC, the Sierra Club, CCAN and Public Citizen, Inc. On January 19, 2016, the OPC filed a notice of appeal to the Maryland Court of Special Appeals, and on January 21, the Sierra Club and CCAN filed notices of appeal. On January 27, 2017, the Maryland Court of Special Appeals affirmed the Circuit Court's judgment that the MDPSC did not err in approving the merger. The OPC and Sierra Club filed petitions seeking further review in the Court of Appeals of Maryland, which is the highest court in Maryland. On June ~~21, 2017, the Court of Appeals granted discretionary review~~1 of the ~~January 27, 2017 decision by~~same year. The annual update for ComEd is based on prior year actual costs and current year projected capital additions (initial year revenue requirement). The update for ComEd also reconciles any differences between the Maryland Court of Special Appeals. The Maryland Court of Appeals will review the OPC argument that the MDPSC did not properly consider the acquisition premium paid to PHI shareholders under Maryland’s merger approval standard and the Sierra Club’s argument that the merger would harm the renewable and distributed generation markets. The two lower courts examining these issues rejected these arguments, which Exelon believes are without merit. All briefs have been filed and oral arguments were presented to the court on October 10, 2017.

~~Between March 25, 2016 and April 22, 2016, various parties filed motions with the DCPSC to reconsider its March 23, 2016 order approving the merger. On~~revenue requirement in effect beginning June 17, 2016, the DCPSC denied all motions. In August 2016, the District of Columbia Office of People’s Counsel, the District of Columbia Government, and Public Citizen jointly with DC Sun each filed petitions for judicial review1 of the ~~DCPSC’s March 23, 2016 order with the District of Columbia Court of Appeals. On July 20, 2017, the Court issued an opinion rejecting all of appellants’ arguments~~prior year and ~~affirming the Commission’s decision approving the merger.~~

~~Table of Contents~~

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

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

~~Accounting~~actual costs incurred for ~~the Merger Transaction~~

that year (annual reconciliation). The ~~total purchase price consideration of approximately $7.1 billion~~annual update for ~~the PHI Merger consisted of cash paid to PHI shareholders, cash paid~~PECO is based on prior year actual costs and current year projected capital additions, accumulated depreciation, and accumulated deferred income taxes. The annual update for ~~PHI preferred securities and cash paid for PHI stock-based compensation equity awards as follows:~~

(In millions of dollars, except per share data) Total Consideration
Cash paid to PHI shareholders at $27.25 per share (254 million shares outstanding at March 23, 2016) $ 6,933
Cash paid for PHI preferred stock 180
Cash paid for PHI stock-based compensation equity awards^(a)
29
Total purchase price $ 7,142

~~_________~~

~~(a)~~

PHI’s unvested time-based restricted stock units and performance-based restricted stock units issued prior to April 29, 2014 were immediately vested and paid in cash upon the close of the merger. PHI’s remaining unvested time-based restricted stock units as of the close of the merger were cancelled. There were no remaining unvested performance-based restricted stock units as of the close of the merger.

PHI shareholders received $27.25 of cash in exchange for each share of PHI common stock outstanding as of the effective date of the merger. In connection with the Merger Agreement, Exelon entered into a Subscription Agreement under which it purchased $180 million of a new class of nonvoting, nonconvertible and nontransferable preferred securities of PHI prior to December 31, 2015. On March 23, 2016, the preferred securities were cancelled for no consideration to Exelon, and accordingly, the $180 million cash consideration previously paid to acquire the preferred securities was treated as purchase price consideration.

The preliminary valuations performed in the first quarter of 2016 were updated in the second, third, and fourth quarters of 2016. There were no adjustments to the purchase price allocation in the first quarter of 2017 and the purchase price allocation is now final.

Exelon applied push-down accounting to PHI, and accordingly, the PHI assets acquired and liabilities assumed were recorded at their estimated fair values on Exelon’s and PHI's Consolidated Balance Sheets as follows:

Purchase Price Allocation^(a)

Current assets $ 1,441
Property, plant and equipment 11,088
Regulatory assets 5,015
Other assets 248
Goodwill 4,005
Total assets $ 21,797

Current liabilities $ 2,752
Unamortized energy contracts 1,515
Regulatory liabilities 297
Long-term debt, including current maturities 5,636
Deferred income taxes 3,447
Pension and OPEB obligations 821
Other liabilities 187
Total liabilities $ 14,655
Total purchase price $ 7,142

~~_________~~


~~(a)~~	Amounts shown reflect the final purchase price allocation and the correction of a reporting error identified and corrected in the second quarter of 2016. The error had resulted in a gross up of certain assets and liabilities related to legacy PHI intercompany and income tax receivable and payable balances.

~~Table of Contents~~

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

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

On its successor financial statements, PHI has recorded, beginning March 24, 2016, Membership interest equity of $7.2 billion, which is greater than the total $7.1 billion purchase price, reflecting the impact of a $59 million deferred tax liability recorded only at Exelon Corporate to reflect unitary state income tax consequences of the merger.

The excess of the purchase price over the estimated fair value of the assets acquired and the liabilities assumed totaled $4.0 billion, which was recognized as goodwill by PHI and Exelon at the acquisition date, reflecting the value associated with enhancing Exelon's regulated utility portfolio of businesses, including the ability to leverage experience and best practices across the utilities and the opportunities for synergies. For purposes of future required impairment assessments, the goodwill has been assigned to PHI's reportable unitsBGE, Pepco, DPL, and ACE ~~in the amounts of $1.7 billion, $1.1 billion and $1.2 billion, respectively. None of this goodwill~~ is ~~expected to be tax deductible.~~

Immediately following closing of the merger, $235 million of net assets included in the table above associated with PHI's unregulated business interests were distributed by PHI to Exelon. Exelon contributed $163 million of such net assets to Generation.

~~The fair values of PHI's assets and liabilities were determined~~ based on significant estimates and assumptions that are judgmental in nature, including projected future cash flows (including timing), discount rates reflecting risk inherent in the future cash flows, future market prices and impacts of utility rate regulation. There were also judgments made to determine the expected useful lives assigned to each class of assets acquired.

Through its wholly owned rate regulated utility subsidiaries, most of PHI’s assets and liabilities are subject to cost-of-service rate regulation. Under such regulation, rates charged to customers are established by a regulator to provide for recovery ofprior year actual costs and ~~a fair return on invested~~current year projected capital ~~or rate base, generally measured at historical cost. In applying the acquisition method of accounting,~~additions, accumulated depreciation, depreciation and amortization expense, and accumulated deferred income taxes. The update for regulated assets and liabilities included in rate base or otherwise earning a return (primarily property, plant and equipment and regulatory assets earning a return), no fair value adjustments were recorded as historical cost is viewed as a reasonable proxy for fair value.

Fair value adjustments were applied to the historical cost bases of other assets and liabilities subject to rate regulation but not earning a return (including debt instruments and pension and OPEB obligations). In these instances, a corresponding offsetting regulatory asset or liability was also established, as the underlying utility asset and liability amounts are recoverable from or refundable to customers at historical cost (and not at fair value) through the rate setting process. Similar treatment was applied for fair value adjustments to record intangible assets and liabilities, such as for electricity and gas energy supply contracts as further described below. Regulatory assets and liabilities established to offset fair value adjustments are amortized in amounts and over time frames consistent with the realization or settlement of the fair value adjustments, with no impact on reported net income. See Note 5 - Regulatory Matters for additional information regarding the fair value of regulatory assets and liabilities established by Exelon and PHI.

Fair value adjustments were recorded at Exelon and PHI for the difference between the contract price and the market price of electricity and gas energy supply contracts of PHI’s wholly owned rate regulated utility subsidiaries. These adjustments are intangible assets and liabilities classified as unamortized energy contracts on Exelon’s and PHI’s Consolidated Balance Sheets as of September 30, 2017. The difference between the contract price and the market price at the acquisition date of the Merger was recognized for each contract as either an intangible asset or liability. In total, Exelon and PHI recorded a net $1.5 billion liability reflecting out-of-the-money contracts. The valuation of the acquired intangible assets and liabilities was estimated by applying either the market approach or the income approach depending on the nature of the underlying contract. The market approach was utilized when prices and other relevant information generated by market transactions involving comparable transactions were available. Otherwise the income approach, which is based upon discounted projected future cash flows associated with the underlying contracts, was utilized. In certain instances, the valuations were based upon certain unobservable inputs, which are considered Level 3 inputs, pursuant to applicable accounting guidance. Key estimates and inputs include forecasted power prices and the discount rate. The unamortized energy contract fair value adjustment amounts and the corresponding offsetting regulatory asset and liability amounts are amortized through Purchase power and fuel expense or Operating revenues, as applicable, over the life of the applicable contract in relation to the present value of the underlying cash flows as of the merger date.

As mentioned, under cost-of-service rate regulation, rates charged to customers are established by a regulator to provide for recovery of costs and a fair return on invested capital, or rate base, generally measured at historical cost. Historical cost information therefore is the most relevant presentation for the financial statements of PHI’s rate regulated utility subsidiary registrants, Pepco, DPL and ACE. As such, Exelon and PHI did not push-down the application of acquisition accounting to PHI's utility registrants, and therefore the financial statements ofPECO, BGE, Pepco, DPL, and ACE ~~do not reflect~~also reconciles any differences between the ~~revaluation of any assets~~actual costs and ~~liabilities.~~

~~Table of Contents~~

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

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

~~The current impact of PHI, including its unregulated businesses, on Exelon's Consolidated Statements of Operations and Comprehensive Income includes:~~

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Operating revenues $ 1,347
$ 1,437
$ 3,679
$ 2,656
Net income (loss) 176
169
382
(92 )
actual revenues for the calendar year (annual reconciliation).

For 2023, the ~~three and nine months ended September 30, 2017 and 2016, the Registrants have recognized costs to achieve the PHI acquisition as follows:~~

Three Months Ended
September 30, Nine Months Ended
September 30,
Acquisition, Integration and Financing Costs^(a)
2017 2016 2017 2016
Exelon $ (8 ) $ 20
$ 10
$ 123
Generation 5
9
18
29
ComEd^(b)
—
—
1
(6 )
PECO 1
1
3
3
BGE^(c)
1
1
3
(3 )
Pepco^(d)
(8 ) 3
(6 ) 26
DPL^(e)
1
2
(6 ) 18
ACE^(f)
(8 ) 2
(6 ) 17

Successor Predecessor
Acquisition, Integration and Financing Costs^(a)
Three Months Ended September 30, 2017 Three Months Ended September 30, 2016 Nine Months Ended September 30, 2017 March 24, 2016 to September 30, 2016 January 1, 2016 to March 23, 2016
PHI^(g)
$ (15 ) $ 7
$ (17 ) $ 63
$ 29

~~_________~~


~~(a)~~	The costs incurred are classified primarily within Operating and maintenance expense in the Registrants’ respective Consolidated Statements of Operations and Comprehensive Income, with the exception of the financing costs, which are included within Interest expense. Costs do not include merger commitments discussed above.


~~(b)~~	For the nine months ended September 30, 2016, includes the reversal of previously incurred acquisition, integration and financing costs of $8 million, incurred at ComEd that have been deferred and recorded as a regulatory asset for anticipated recovery. See Note 5—Regulatory Matters for more information.


~~(c)~~	For the nine months ended September 30, 2016, includes the reversal of previously incurred acquisition, integration and financing costs of $6 million incurred at BGE that have been deferred and recorded as a regulatory asset for anticipated recovery. See Note 5—Regulatory Matters for more information.

~~(d)~~

For the three and nine months ended September 30, 2017, includes the reversal of previously incurred acquisition, integration and financing costs of $8 million incurred at Pepco that have been deferred and recorded as a regulatory asset for anticipated recovery. For the nine months ended September 30, 2016, includes the reversal of previously incurred acquisition, integration and financing costs of $10 million incurred at Pepco that have been deferred and recorded as a regulatory asset for anticipated recovery. See Note 5—Regulatory Matters for more information.

~~(e)~~

For the nine months ended September 30, 2017, includes the reversal of previously incurred acquisition, integration and financing costs of $8 million incurred at DPL that have been deferred and recorded as a regulatory asset for anticipated recovery. For the nine months ended September 30, 2016, includes the reversal of previously incurred acquisition, integration and financing costs of $3 million incurred at DPL that have been deferred and recorded as a regulatory asset for anticipated recovery. See Note 5—Regulatory Matters for more information.


~~(f)~~	For the three and nine months ended September 30, 2017, includes the reversal of previously incurred acquisition, integration and financing costs of $8 million incurred at ACE that have been deferred and recorded as a regulatory asset for anticipated recovery. See Note 5—Regulatory Matters for more information.

~~(g)~~

For the three and nine months ended September 30, 2017, includes the reversal of previously incurred acquisition, integration and financing costs of $16 million and $24 million, respectively, incurred at PHI that have been deferred and recorded as a regulatory asset for anticipated recovery. For the Successor period March 24, 2016 to September 30, 2016, includes the reversal of previously incurred acquisition, integration and financing costs of $13 million incurred at PHI that have been deferred and recorded as a regulatory asset for anticipated recovery. See Note 5—Regulatory Matters for more information.

~~Table of Contents~~

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

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

~~Pro-forma Impact of the Merger~~

~~The~~ following unaudited pro-forma financial information reflects the consolidated results of operations of Exelon as if the merger with PHI had taken place on January 1, 2015. The unaudited pro-forma information was calculated after applying Exelon’s accounting policies and adjusting PHI’s results to reflect purchase accounting adjustments.

The unaudited pro-forma financial information has been presented for illustrative purposes only and is not necessarily indicative of results of operations that would have been achieved had the merger events taken place on the dates indicated, or the future consolidated results of operations of the combined company.

Three Months Ended
September 30, Nine Months Ended
September 30,
Year Ended
December 31,

2016^(a)

2016^(a)

2016^(b)
Total operating revenues $ 9,002
$ 24,468
$ 32,342
Net income attributable to common shareholders 501
1,346
1,562

Basic earnings per share $ 0.54
$ 1.46
$ 1.69
Diluted earnings per share 0.54
1.45
1.69

~~_________~~


~~(a)~~	The amounts above include adjustments for non-recurring costs directly related to the merger of $20 million and $660 million for the three and nine months ended September 30, 2016, respectively, and intercompany revenue of $171 million for the nine months ended September 30, 2016.


~~(b)~~	~~The amounts above include adjustments for non-recurring costs directly related to the merger of $680 million and intercompany revenue of $171 million for the year ended December 31, 2016.~~

~~Asset Divestitures (Exelon, Generation, PHI, Pepco and DPL)~~

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 is an indirect wholly owned subsidiary of Exelon and Generation. Each of the aforementioned facilities are held through a wholly owned direct subsidiary of EGTP. EGTP also owns two equity method investments in shared facility companies. EGTP, its direct parent and its wholly owned subsidiaries secured a nonrecourse senior secured term loan facility, a revolving loan facility and certain commodity and interest rate swaps.

On May 2, 2017, 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, the proceeds from which will first be used to pay the administrative costs of the sale, the normal and ordinary costs of operating the plants and repayment of the secured debt of EGTP, including the revolving credit facility. See Note 11 - Debt and Credit Agreements for details regarding the nonrecourse debt associated with EGTP. As a result, as of September 30, 2017, certain EGTP assets and liabilitiesincreases/(decreases) were ~~classified as held for sale at their respective fair values less costs to sell and~~ included in the ~~other current assets~~Utility Registrants' electric transmission formula rate updates:


Registrant(a)	Initial Revenue Requirement Increase		Annual Reconciliation Increase (Decrease)		Total Revenue Requirement Increase			Allowed Return on Rate Base(b)		Allowed ROE(c)
ComEd	$	20	$	63	$	83		8.09	%	11.50	%
PECO	24		23		47			7.41	%	10.35	%
BGE	19		(12)		4		(d)	7.34	%	10.50	%
Pepco	37		(5)		32			7.57	%	10.50	%
DPL	32		(3)		29			7.08	%	10.50	%
ACE	41		(12)		29			7.08	%	10.50	%

__________

(a)All rates are effective June 1, 2023 - May 31, 2024, subject to review by interested parties pursuant to review protocols of each Utility Registrants' tariffs.

(b)Represents the weighted average debt and ~~other current liabilities balances~~equity return on ~~Exelon's~~transmission rate bases. For ComEd and ~~Generation's Consolidated Balance Sheets. See Note 6 - Impairment~~PECO, the common equity component of ~~Long-Lived Assets~~the ratio used to calculate the weighted average debt and equity return on the transmission formula rate base is currently capped at 55% and 55.75%, respectively.

(c)The rate of return on common equity for ~~further information.~~

~~In July 2016, DPL completed the sale~~each Utility Registrant includes a 50-basis-point incentive adder for being a member of a 9~~acre land parcel located on South Madison Street~~RTO.

(d)The increase in ~~Wilmington, DE, resulting in~~BGE's transmission revenue requirement includes a ~~pre-tax gain~~$3 million reduction related to a FERC-approved dedicated facilities charge to recover the costs of ~~approximately $4 million. Due~~providing transmission service to ~~the fair value adjustments recorded at Exelon and PHI as part of purchase accounting, no gain was recorded in the Exelon and PHI Consolidated Statements of Operations and Comprehensive Income.~~ specifically designated load by BGE.

On June 16, 2016, Generation initiated the sales process of its Upstream business by executing a forbearance agreement with the lenders of the nonrecourse debt. See Note 11 - Debt and Credit Agreements for more information. In December 2016, Generation sold substantially all of the Upstream assets, see Note 4 - Mergers, Acquisitions and Dispositions of the Combined Notes to the Consolidated Financial Statements in the Exelon 2016 Form 10-K for further information.

On May 2, 2016, Pepco completed the sale of the New York Avenue land parcel, located in Washington D.C., resulting in a pre-tax gain of approximately $8 million at Pepco. Due to the fair value adjustments recorded at Exelon and PHI as part of purchase accounting, no gain was recorded in the Exelon and PHI Consolidated Statements of Operations and Comprehensive Income.

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

~~On April 21, 2016, Generation completed the sale of the retired New Boston generating site, located in Boston, Massachusetts, resulting in a pre-tax gain of approximately $32 million.~~

5.Other State Regulatory Matters ~~(All Registrants)~~

Except for the matters noted below, the disclosures set forth in Note 3 - Regulatory Matters of the Exelon 2016 Form 10-K reflect, in all material respects, the current status of regulatory and legislative proceedings of the Registrants. The following is an update to that discussion.

Illinois Regulatory Matters

CEJA (Exelon and ComEd). On September 15, 2021, the Governor of Illinois signed into law CEJA. CEJA includes, among other features, (1) procurement of CMCs from qualifying nuclear-powered generating facilities, (2) a requirement to file a general rate case or a new four-year MRP no later than January 20, 2023 to establish rates effective after ComEd’s existing performance-based distribution formula rate sunsets, (3) an extension of and certain adjustments to ComEd’s energy efficiency MWh savings goals, (4) revisions to the Illinois RPS

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Note 3 — Regulatory Matters

requirements, including expanded charges for the procurement of RECs from wind and solar generation, (5) a requirement to accelerate amortization of ComEd’s unprotected excess deferred income taxes (EDIT) that ComEd was previously directed by the ICC to amortize using the average rate assumption method which equates to approximately 39.5 years, and (6) requirements that ComEd and the ICC initiate and conduct various regulatory proceedings on subjects including ethics, spending, grid investments, and performance metrics. Regulatory or legal challenges regarding the validity or implementation of CEJA are possible and Exelon and ComEd cannot reasonably predict the outcome of any such challenges.

ComEd Electric Distribution Rates

ComEd filed, and received approval for, its last performance-based electric distribution formula rate update filing under EIMA in 2022; those rates are in effect throughout 2023.

On February 3, 2022, the ICC approved a tariff that establishes the process under which ComEd will reconcile its 2022 and 2023 rate year revenue requirements with actual costs. Those reconciliation amounts will be determined using the same process as were used for prior reconciliations under the performance-based electric distribution formula rate. Using that process, for the rate years 2022 and 2023 ComEd will ultimately collect revenues from customers reflecting each year’s actual recoverable costs, year-end rate base, and a weighted average debt and equity return on distribution rate base, with the ROE component based on the annual average of the monthly yields of the 30-year U.S. Treasury bonds plus 580 basis points. In April 2023, ComEd filed its first petition with the ICC to reconcile its 2022 actual costs with the approved revenue requirement that was in effect in 2022; the final order is expected by December 2023, for rates beginning January 2024. The rate year 2023 reconciliation will be filed in 2024.

Beginning in 2024, ComEd will recover from retail customers, subject to certain exceptions, the costs it incurs to provide electric delivery services either through its electric distribution rate or other recovery mechanisms authorized by CEJA. On January 17, 2023, ComEd filed a petition with the ICC seeking approval of a MRP for 2024-2027. The MRP supports a multi-year grid plan (Grid Plan), also filed on January 17, covering planned investments on the electric distribution system within ComEd’s service area through 2027. Costs incurred during each year of the MRP are subject to ICC review and the plan’s revenue requirement for each year will be reconciled with the actual costs that the ICC determines are prudently and reasonably incurred for that year. The reconciliation is subject to adjustment for certain costs, including a limitation on recovery of costs that are more than 105% of certain costs in the previously approved MRP revenue requirement, absent a modification of the rate plan itself. Thus, for example, the rate adjustments necessary to reconcile 2024 revenues to ComEd’s actual 2024 costs incurred would take effect in January 2026 after the ICC’s review during 2025. On May 22, 2023, direct testimony was filed by ICC staff and more than a dozen intervenors and intervenor groups. The testimonies addressed a wide variety of topics, including rate of return on equity, capital structure, grid planning, various distribution grid and information technology investments, and affordability and customer service. ComEd filed rebuttal testimony in June, which provided, among other things, defense of ComEd’s planned 2024-2027 capital investment and proposed cost of equity. ComEd also made voluntary adjustments and, per the ICC’s final beneficial electrification order requiring ComEd to recover beneficial electrification costs through the MRP, increased its total revenue requirement request from $1.472 billion to $1.545 billion. On July 27, 2023, ICC staff and intervenors filed rebuttal testimony, which showed little to no movement on the key issues, including ROE and large capital projects. On August 14, 2023, ComEd filed surrebuttal testimony. On August 22, 2023, evidentiary hearings were held, during which testimony and other evidence was admitted and the evidentiary phase of the hearing process was closed. ComEd filed its reply brief on September 27, 2023, to adjust its total requested revenue requirement increase to $1.487 billion. On October 23, 2023 the administrative law judges (ALJs) issued a proposed order in ComEd's MRP proceeding recommending a $317 million reduction to ComEd's requested revenue requirement increase of $1.487 billion. Significant differences between the ALJ’s proposed order and ComEd’s final position relate to the proposed return on equity and the disallowance of any return on ComEd’s pension asset. The ALJs proposed order is not final, and briefs on exception will be filed in November 2023. The Commission may also hear oral arguments prior to making its final decision. The ICC must issue its decision on both the MRP and Grid Plan by mid-December 2023, for rates to begin with the January 2024 billing cycle.

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Note 3 — Regulatory Matters

In January 2022, ComEd filed a request with the ICC proposing performance metrics that would be used in determining ROE incentives and penalties in the event ComEd filed a MRP in January 2023. On September 27, 2022, the ICC issued a final order approving seven performance metrics that provide symmetrical performance adjustments of 32 total basis points to ComEd’s rate of return on common equity based on the extent to which ComEd achieves the annual performance goals. On November 10, 2022, the ICC granted ComEd's application for rehearing, in part. On April 5, 2023, the ICC issued its final order on rehearing for the performance and tracking metrics proceeding, in which the ICC declined to adopt ComEd’s proposed modifications to the reliability and peak load reduction performance metrics. Efforts are underway to implement the performance metrics, which take effect on January 1, 2024. ComEd will make its initial filing in 2025 to assess performance achieved under the metrics in 2024, and to determine any ROE adjustment, which would take effect in 2026.

Carbon Mitigation Credit

CEJA establishes decarbonization requirements for Illinois as well as programs to support the retention and development of emissions-free sources of electricity. ComEd is required to purchase CMCs from participating nuclear-powered generating facilities between June 1, 2022 and May 31, 2027. The price to be paid for each CMC was established through a competitive bidding process that included consumer-protection measures that capped the maximum acceptable bid amount and a formula that reduces CMC prices by an energy price index, the base residual auction capacity price in the ComEd zone of PJM, and the monetized value of any federal tax credit or other subsidy if applicable. The consumer protection measures contained in CEJA will result in net payments to ComEd ratepayers if the energy index, the capacity price and applicable federal tax credits or subsidy exceed the CMC contract price. In the June 2022 billing period, ComEd began issuing credits to its retail customers under its new CMC rider. A regulatory asset is recorded for the difference between customer credits issued and the credit to be received from the participating nuclear-powered generating facilities. The balance as of September 30, 2023 is $862 million.

Under CEJA, the costs of procuring CMCs, including carrying costs, are recovered through a rider, the Rider Carbon-Free Resource Adjustment (Rider CFRA). As originally approved by the ICC, Rider CFRA provides for an annual reconciliation and true-up to actual costs incurred or credits received by ComEd to purchase CMCs, with any difference to be credited to or collected from ComEd’s retail customers in subsequent periods. The difference between the net payments to (or receivables from) ComEd ratepayers and the credits received by ComEd to purchase CMCs is recorded to Purchased Power expense with an offset to the regulatory asset (or regulatory liability). On December 21, 2022, ComEd filed an amendment to Rider CFRA proposing that it recover costs or provide credits faster than the tariff allows, implement monthly reconciliations, and allow ComEd to adjust Rider CFRA rates based not only on anticipated differences but also past payments or credits, and implement monthly reconciliations beginning the June 2023 delivery period. The ICC approved the proposal on January 19, 2023.In addition, on March 24, 2023, ComEd submitted revisions to Rider CFRA which clarified the methodology for calculating interest to be included in the annual reconciliation associated with the June 2022 through May 2023 delivery year. The ICC approved the proposal on April 20, 2023.

Beneficial Electrification Plan

On March 23, 2023, the ICC issued its final order approving the beneficial electrification plan for ComEd. The ICC rejected ComEd’s request to treat a large portion of beneficial electrification costs as a regulatory asset and ordered ComEd to seek cost recovery through the multi-year rate plan filing for 2024 and 2025, and the final formula rate reconciliation docket for 2023, rather than through a separate charge. The order also authorized an overall annual budget of $77 million per year for the three year plan period (2023 through 2025), with flexibility to roll forward unused funds to future years within the same plan period. On April 18, 2023, ComEd filed an application for rehearing in the beneficial electrification plan docket. The Chicago Transit Authority and City of Chicago, jointly, and the Office of the Illinois Attorney General (ILAG) also filed applications for rehearing. On April 27, 2023, ICC staff filed a motion for clarification, seeking clarification from the ICC on the precise budget described in the final order. On May 8, 2023, the ICC denied all applications for rehearing, and entered an amendatory order regarding the annual beneficial electrification plan budgets. ComEd has been directed to use good faith efforts to spend $77 million annually. ComEd subsequently filed its compliance filing in May 2023, detailing project related spending, clarifying the procedure that will be used to seek stakeholder feedback related to beneficial electrification pilot programs, and including the timeline for tariff changes required to implement the programs. ComEd and the ILAG both filed appeals of the ICC’s interim order that addressed the permissible scope of utility beneficial electrification programs outside of transportation and the rate impact cap. The ILAG also filed an appeal seeking reversal of portions of the ICC’s final decision. The final order partly mooted

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Note 3 — Regulatory Matters

ComEd’s appeal of the interim order and ComEd has decided not to pursue the other issues. As such, ComEd recently moved to voluntarily dismiss its appeal and the appellate court granted that request. The ILAG consolidated their appeals. Any ruling on the appeals, even a negative ruling removing programs from the BE Plan or lowering the overall budget of the BE Plan, will only impact forward-looking costs.

Energy Efficiency Formula Rate (Exelon and ComEd). ~~On April 13, 2017,~~ ComEd filed its annual ~~distribution~~energy efficiency formula rate update with the ICC ~~pursuant to EIMA.~~on May 26, 2023. The filing establishes the revenue requirement used to set the rates that will take effect in January ~~2018~~2024 after the ~~ICC’s~~ICC's review and ~~approval, which is due by December 2017.~~approval. The requested revenue requirement ~~requested~~update is based on ~~2016~~a reconciliation of the 2022 actual costs plus projected ~~2017 capital additions as well as an annual reconciliation of the~~2024 expenditures.


Initial Revenue Requirement Increase		Annual Reconciliation Increase		Total Revenue Requirement Increase		Requested Return on Rate Base(a)		Requested ROE
$	87	$	31	$	118	6.48	%	8.91	%

__________

(a)The requested revenue requirement ~~in effect in 2016 to the actual costs incurred that year. ComEd's 2017 filing request includes a total~~ increase to the revenue requirement of $96 million, reflecting an increase of $78 million for the initial revenue requirement for 2017 and an increase of $18 million related to the annual reconciliation for 2016. The revenue requirement for 2017 provides for a weighted average debt and equity return on ~~distribution~~the energy efficiency regulatory asset and rate base of ~~6.47%~~6.48% inclusive of an allowed ROE of ~~8.40%~~8.91%, reflecting the monthly average ~~rate on~~yields for 30-year treasury ~~notes~~bonds plus 580 basis points. ~~The annual~~For the 2022 reconciliation ~~for 2016 provided~~year, the requested revenue requirement provides for a weighted average debt and equity return on ~~distribution~~the energy efficiency regulatory asset and rate base of ~~6.45%~~7.48% inclusive of an allowed ROE of ~~8.34%~~10.91%, ~~reflecting~~which includes an upward performance adjustment that increased the ~~average rate on 30-year treasury notes plus 580 basis points less a~~ROE. The performance metrics penalty of 6 basis points. See table below for ComEd's regulatory assets associated with its distribution formula rate. For additional information on ComEd's distribution formula rate filings see Note 3 — Regulatory Matters ofadjustment can either increase or decrease the ~~Exelon 2016 Form 10-K.~~

On December 6, 2016, the ICC issued a final order approving the 2016 distribution formula rate, which included a total increase to the revenue requirement of $127 million, reflecting an increase of $134 million for the initial revenue requirement for 2016 and a decrease of $7 million related to the annual reconciliation for 2015. On December 20, 2016, the ICC granted ComEd's and other parties' joint application for rehearing on the impact that changing ComEd’s OSHA recordable rate for 2014 and 2015 had on the revenue requirement approved in this order. On March 22, 2017, the ICC issued an order approving ComEd's proposal to reduce the 2016 revenue requirement by $18 million, which was reflected in customer rates beginning in April 2017.

~~Illinois Future Energy Jobs Act (Exelon, Generation and ComEd)~~

~~Background~~

~~Zero Emission Standard~~

FEJA includes a ZES that provides compensation through the procurement of ZECs targeted at preserving the environmental attributes of zero-emissions nuclear-powered generating facilities that meet specific eligibility criteria.

On September 11, 2017, the ICC approved the IPA's ZES Procurement Plan filed with the ICC on July 31, 2017. Bidders interested in participating in the procurement process had 14 days following the ICC's approval of the plan to submit the required eligibility information and become qualified bidders. Generation’s Clinton and Quad Cities nuclear plants timely submitted the required eligibility information to the ICC and responded to follow up questions. Winning bidders will contract directly with Illinois utilities, including ComEd, for 10-year terms extending through May 31, 2027. The ZEC price will beROE based upon the ~~current social cost~~achievement of carbon as determined by the Federal government and is 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 will be 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

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- May 31, 2018, the ZEC annual cost cap, is 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 will be paid in subsequent years if the payments do not exceed the prescribed annual cost cap for that year.

On October 27, 2017, the IPA released the schedule for the ZEC procurement event indicating that contracts with zero emission facilities will be fully executed on January 30, 2018. Winning bidders will be entitled to compensation for the sale of ZECs retroactive to the June 1, 2017 effective date of FEJA. To the extent Generation is selected as a winning bidder, revenue retroactive to the effective date of FEJA would be recognized in the period the contracts are executed. Upon the execution of the contracts, ComEd will record an associated obligation and expense for the procurement of ZEC's.

ComEd will recover all costs associated with purchasing ZECs through a new rate rider that provides for an annual reconciliation and true-up to actual costs incurred by ComEd to purchase ZECs, with any difference to be credited to or collected from ComEd’s retail customers in subsequent periods with interest. ComEd began billing its retail customers under its new ZEC rate rider on June 1, 2017 and recorded a regulatory liability of $71 million as of September 30, 2017 for revenues recorded in advance of incurring expenses.

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. One lawsuit was filed by customers of ComEd, led by the Village of Old Mill Creek, and the other was brought by the EPSA and three other electric suppliers. Both lawsuits argue that the Illinois ZEC program will distort PJM's FERC-approved energy and capacity market auction system of setting wholesale prices, and seek a permanent injunction preventing the implementation of the program. Exelon intervened and filed motions to dismiss in both lawsuits. In addition, on March 31, 2017, plaintiffs in both lawsuits filed motions for preliminary injunction with the court; the court stayed briefing on the motions for preliminary injunction until the resolution of the motions to dismiss.On July 14, 2017, the district court granted the motions to dismiss. On July 17, 2017, the plaintiffs appealed the decision to the Seventh Circuit. Plaintiffs-Appellants initial brief was filed on August 28, 2017 and the state’s and Exelon’s briefs were filed on October 27, 2017. Reply briefs are due on December 12, 2017. Exelon cannot predict the outcome of these lawsuits. It is possible that resolution of these matters could have a material, unfavorable impact on Exelon’s and Generation’s results of operations, financial positions and cash flows.

See Note 7 - Early Nuclear Plant Retirements for additional information regarding the economic challenges facing Generation’s Clinton and Quad Cities nuclear plants and the expected benefits of the ZES.

~~ComEd Electric Distribution Rates~~

FEJA extends the sunset date for ComEd’s performance-based electric distribution formula rate from 2019 to the end of 2022, allows ComEd to revise the electric distribution formula rate to eliminate the ROE collar, and allows ComEd to implement a decoupling tariff if the electric distribution formula rate is terminated at any time. ComEd will revise its electric distribution formula rate to eliminate the ROE collar beginning with the reconciliation filed in 2018 for the 2017 calendar year. Elimination of the ROE collar effectively offsets the favorable or unfavorable impacts to ComEd's electric distribution formula rate revenues associated with variations in delivery volumes associated with above or below normal weather, numbers of customers or usage per customer. ComEd began reflecting the impacts of this change in its electric distribution services costs regulatory asset in first quarter 2017. As of September 30, 2017, ComEd recorded an increase to its electric distribution services costs regulatory asset of approximately $21 million for this change.

FEJA requires ComEd to make non-recoverable contributions to low income energy assistance programs of $10 million per year for 5 years as long as the electric distribution formula rate remains in effect. With the exception of these contributions, ComEd will recover from customers, subject to certain caps explained below, the costs it incurs pursuant to FEJA either through its electric distribution formula rate or other recovery mechanisms.

~~Energy Efficiency~~

Prior to FEJA, Illinois law required ComEd to implement cost-effective energy efficiency measures and, for a 10-year period ending May 31, 2018, cost-effective demand response measures to reduce peak demand by 0.1% over the prior year for eligible retail customers.

Beginning January 1, 2018, FEJA provides for new cumulative annual energy efficiency MWh savings goals for ComEd, which are designed to achieve 21.5% of cumulative persisting annual MWh savings by 2030, as compared

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to the deemed baseline of 88 million MWhs of electric power and energy sales. FEJA deems the cumulative persisting annual MWh savings to be 6.6% from 2012 through the end of 2017. ComEd expects to spend approximately $250 million to $400 million annually from 2017 through 2030 to achieve these energy efficiency MWh savings goals. In addition, FEJA extends the peak demand reduction requirement from 2018 to 2026. Because the new requirements apply beginning in 2018, FEJA extends the existing energy efficiency plans, which were due to end on May 31, 2017, through December 31, 2017. FEJA also exempts customers with demands over 10 MW from energy efficiency plans and requirements beginning June 1, 2017. On September 11, 2017, the ICC approved ComEd's 2018 - 2021 energy efficiency plan with minor modifications filed by ComEd with the ICC on June 30, 2017.

FEJA allows ComEd to cancel its existing energy efficiency rate rider and replace it with an energy efficiency formula rate, and to defer energy efficiency costs (except for any voltage optimization costs which will be recovered through the electric distribution formula rate) as a separate regulatory asset that will be 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 will earn 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 will be required to file an update to its energy efficiency formula rate on or before June 1 each year, with resulting rates effective in January of the following year. The annual update will be 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. The update will also include a reconciliation of any differences between the revenue requirement in effect for the prior year and the revenue requirement based on actual prior year costs and actual year-end energy efficiency regulatory asset balances less any related deferred income taxes. ComEd records a regulatory asset or liability and corresponding increase or decrease to Operating revenues for any differences between the revenue requirement in effect and ComEd’s best estimate of the revenue requirement expected to be approved by the ICC for that year’s reconciliation.

ComEd cancelled its existing energy efficiency rate rider effective June 2, 2017. On August 1, 2017, ComEd filed with the ICC a reconciliation of revenues and costs incurred through the cancellation date. On August 30, 2017, the ICC approved ComEd's request, filed on August 1, 2017, to issue an $80 million credit on retail customers' bills in October 2017 for the majority of the over-recoveries with any final adjustment applicable to the over-recoveries to be billed or credited in the future. As of September 30, 2017, ComEd’s over-recoveries associated with its former energy efficiency rate rider were $33 million.

~~Initial Energy Efficiency Formula Rate Filing~~

On August 15, 2017, the ICC approved ComEd's new initial energy efficiency formula rate filed with the ICC on June 9, 2017 pursuant to FEJA. The filing establishes the formula under which energy efficiency rates will be calculated going forward and the revenue requirement used to set the initial rates for the period October 1, 2017 through December 31, 2017. The initial revenue requirement is based on projected costs and projected PJM capacity revenues for the period from June 1, 2017 through December 31, 2017, and projected year-end 2017 energy efficiency regulatory asset balances (less any related deferred income taxes). ComEd requested an initial decrease in revenue requirement of $7 million reflecting higher projected PJM capacity revenues compared to projected energy efficiency costs and provides for a weighted average debt and equity return of 6.47% inclusive of an allowed ROE of 8.40%, reflecting the average rate on 30-year treasury notes plus 580 basis points. The annual reconciliation for 2017 will be included in ComEd’s 2018 energy efficiency formula rate filing and reflected in customer rates beginning January 2019. The approved energy efficiency formula rate also provides for revenue decoupling to effectively offset the favorable or unfavorable impacts to ComEd's energy efficiency formula rate revenues associated with variations in delivery volumes associated with above or below normal weather, numbers of customers or usage per customer.

As of September 30, 2017, Exelon and ComEd recorded a regulatory asset of $78 million under the energy efficiency formula, reflecting $83 million of deferred energy efficiency costs partially offset by $5 million of over recoveries for the initial energy efficiency formula rate reconciliation.

~~2017 Energy Efficiency Formula Rate Filing~~

On September 11, 2017, the ICC approved ComEd's annual energy efficiency formula rate filed with the ICC on June 30, 2017 pursuant to FEJA. The filing establishes the revenue requirement used to set rates that will take effect

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in January 2018. The revenue requirement for 2018 is based on projected 2018 energy efficiency costs and PJM capacity revenues, and year-end 2018 energy efficiency regulatory asset balances (less any related deferred income taxes). In its 2017 filing ComEd requested a total increase to the revenue requirement of $12 million and provides for a weighted average debt and equity return of 6.47% inclusive of an allowed ROE of 8.40%, reflecting the average rate on 30-year treasury notes plus 580 basis points. The annual reconciliation for 2018 will be included in ComEd’s 2019 energy efficiency formula rate filing, and reflected in customer rates beginning January 2020.

~~Renewable Portfolio Standard~~

Existing Illinois law requires ComEd to purchase each year an increasing percentage of renewable energy resources for the customers for which it supplies electricity. This obligation is satisfied through the procurement of RECs. FEJA revises the Illinois RPS to require ComEd to procure RECs for all retail customers by June 2019, regardless of the customers’ electricity supplier, and provides support for low-income rooftop and community solar programs, which will be funded by the existing Renewable Energy Resources Fund and ongoing RPS collections. FEJA also requires ComEd to use RPS collections to fund utility job training and workforce development programs in the amounts of $10 million in each of the years 2017, 2021, and 2025. ComEd recorded a $10 million and $20 million current and noncurrent liability, respectively, as of September 30, 2017 associated with this obligation. ComEd will recover all costs associated with purchasing RECs and funding utility job training and workforce development programs through a new RPS rate rider that provides for a reconciliation and true-up to actual costs, with any difference between revenues and expenses to be credited to or collected from ComEd’s retail customers in subsequent periods with interest. The first reconciliation and true-up for RECs will occur in 2021 and cover revenues and costs for the four year period beginning June 1, 2017 through May 31, 2021. Subsequently, the RPS rate rider will provide for an annual reconciliation and true-up. ComEd began billing its retail customers under its new RPS rate rider on June 1, 2017 and recorded a related regulatory liability of $7 million as of September 30, 2017. ComEd also recorded a regulatory liability of $38 million for alternative compliance payments received from RES to purchase RECs on behalf of the RES in the future.

~~As of September 30, 2017, ComEd had received $45 million~~ of over-recovered RPS costs and alternative compliance payments from RES, which are deposited into a separate interest bearing bank account pursuant to FEJA and are classified as Restricted cash on Exelon's and ComEd's Balance Sheets.

~~Customer Rate Increase Limitations~~

FEJA includes provisions intended to limit the average impact on ComEd customer rates for recovery of costs incurred under FEJA as follows: (1) for a typical ComEd residential customer, the average impact must be less than $0.25 cents per month, (2) for nonresidential customers with a peak demand less than 10 MW, the average annual impact must be less than 1.3% of the average amount paid per kWh for electric service by Illinois commercial retail customers during 2015, and (3) for nonresidential customers with a peak demand greater than 10 MW, the average annual impact must be less than 1.3% of the average amount paid per kWh for electric service by Illinois industrial retail customers during 2015.

~~On June 30, 2017, ComEd submitted a 10-year projection to the ICC of customer rate impacts for residential customers and nonresidential customers with a peak demand less than 10 MW~~. Such projections indicate that customer rate impacts will not exceed the limitations set by FEJA discussed below. Thereafter, beginning in 2018, ComEd must submit a report to the ICC for residential customers and nonresidential customers with a peak demand less than 10 MW by February 15th and June 30th of each year, respectively. For nonresidential customers with a peak demand greater than 10 MW, ComEd must submit a report to the ICC by May 1 of each year if a rate reduction will be necessary in the following year. For residential customers, the reports will include the actual costs incurred under FEJA during the preceding year and a rolling 10-year customer rate impact projection. The reports for nonresidential customers with a peak demand less than 10 MW will also include the actual costs incurred under FEJA during the preceding year, as well as the average annual rate increase from January 1, 2017 through the end of the preceding year and the average annual rate increase projected for the remainder of the 10-year period.

If the projected residential customer or nonresidential customer with a peak demand less than 10 MW rate increase exceeds the limitations during the first four years, ComEd is required to decrease costs associated with FEJA investments, including reductions to ZEC contract quantities. If the projected residential customer or nonresidential customer with a peak demand less than 10 MW rate increase exceeds the limitations during the last six years, ComEd is required to demonstrate how it will reduce FEJA investments to ensure compliance. If the actual residential customer or nonresidential customer with a peak demand less than 10 MW rate increase exceeds the limitations for any one year, ComEd is required to submit a corrective action plan to decrease future year costs to reduce customer rates to

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ensure future compliance. If the actual residential customer or nonresidential customer rate exceeds the limitations for two consecutive years, ComEd can offer to credit customers for amounts billed in excess of the limitations or ComEd can terminate FEJA investments. If ComEd chooses to terminate FEJA investments, the ICC shall order termination of ZEC contracts and further initiate proceedings to reduce energy efficiency savings ~~goals and terminate support for low-income rooftop and community solar programs~~. ~~ComEd is allowed to fully recover all costs incurred as of and up to the date of the programs’ termination.~~goals.

For the energy efficiency formula, ComEd records a regulatory asset or liability and corresponding increase or decrease to Operating revenues for any differences between the revenue requirement in effect and ComEd’s best estimate of the revenue requirement expected to be approved by the ICC for that year’s reconciliation. For the other rate riders established under FEJA, ComEd records a regulatory asset or liability for any differences between revenues and incurred expenses.

~~Renewable Energy Resources (Exelon and ComEd).~~ In accordance with legislation in effect on December 31, 2016, the IPA's Procurement Plans include the procurement of cost-effective renewable energy resources in amounts that equal or exceed a minimum target percentage of the total electricity that each electric utility supplies to its eligible retail customers. The June 1, 2016 target renewable energy resources obligation for the utilities was at least 11.5%. This obligation increases by at least 1.5% each year thereafter to an ultimate target of at least 25% by June 1, 2025. All goals are subject to rate impact criteria set forth by Illinois legislation. As of September 30, 2017, ComEd had purchased renewable energy resources or equivalents, such as RECs, in accordance with the IPA Procurement Plan. ComEd currently retires all RECs upon transfer and acceptance. ComEd is permitted to recover procurement costs of RECs from retail customers without mark-up through rates.

In accordance with FEJA that took effect on June 1, 2017, beginning with the plan or plans to be implemented in the 2017 delivery year, the IPA shall develop a long term renewable resources procurement plan (LT Plan). The RPS target percentages for the overall service territory have not changed through June 1, 2025 although FEJA extended the 25% RPS target to delivery years after 2025. Currently, each RES and each utility is responsible for the renewable resource obligation of the customers it supplies power for. Over time, this will change and the utility will procure renewable resources based on the retail load of substantially all customers in its service territory. For the delivery year beginning June 1, 2017, the LT Plan shall include cost effective renewable energy resources procured by the utility for the retail load the utility supplies and for 50% of the retail customer load supplied by Retail Electric Suppliers in the utility service territory on February 28, 2017. Utility procurement for RES supplied retail customer load will increase to 75% June 1, 2018 and to 100% beginning June 1, 2019.

~~Pennsylvania Regulatory Matters~~

~~Pennsylvania Procurement Proceedings (Exelon and PECO).~~ ~~Through PECO’s PAPUC approved DSP Programs, PECO procures electric supply for its default electric customers through PAPUC approved competitive procurements.~~

On March 17, 2016, PECO filed its fourth DSP Program with the PAPUC proposing a 24-month term from June 1, 2017 through May 31, 2019, in compliance with electric generation procurement guidelines set forth in Act 129. On December 8, 2016, the PAPUC approved the fourth DSP Program for the modified 48-month term and deferred CAP Shopping to another proceeding. Office of Consumer Advocate and Low Income Advocates subsequently filed a Petition for Reconsideration and Clarification related to CAP Shopping. On March 16, 2017, the PAPUC granted reconsideration and consolidated the proceeding with the DSP II docket, which includes the pending CAP Shopping plan that would allow low-income CAP customers to purchase their generation supply from EGSs. PAPUC referred the consolidated proceedings to the Office of Administrative Law Judge for hearing and decision.

~~Pennsylvania Act 11 of 2012 (Exelon and PECO).~~ In February 2012, Act 11 was signed into law, which provided the PAPUC authority to approve the implementation of a distribution system improvement charge (DSIC) in rates designed to recover capital project costs incurred to repair, improve or replace utilities’ aging electric and natural gas distribution systems in Pennsylvania. Prior to recovering costs pursuant to a DSIC, the PAPUC's implementation order requires a utility to have a Long Term Infrastructure Improvement Plan (LTIIP) approved by the Commission, which outlines how the utility is planning to increase its investment for repairing, improving or replacing aging infrastructure. The PAPUC approved PECO’s petition for its proposed electric DSIC and LTIIP on October 22, 2015 for spending of $275 million over a 5 year period through 2020. The PAPUC approved PECO's petition for its proposed modified gas LTIIP on June 14, 2017 for spending of $762 million over a 10 year period through 2022.

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

~~Maryland Regulatory Matters~~

~~2017 Maryland Electric Distribution Rates (Exelon, PHI and Pepco).~~ On March 24, 2017, Pepco filed an application with the MDPSC to increase its annual electric distribution base rates by $69 million, which was updated to $67 million on August 24, 2017, reflecting a requested ROE of 10.1%. The application included a request for an income tax adjustment to reflect full normalization of removal costs associated with pre-1981 property, which accounted for $18 million of the requested increase. On October 20, 2017, the MDPSC approved an increase in Pepco electric distribution rates of $34 million, reflecting a ROE of 9.5%. On October 27, 2017, the MDPSC issued an errata order revising the approved increase in Pepco electric distribution rates to $32 million. The errata order corrected a number of computational errors in the original order but did not alter any of the findings. The new rates became effective for services rendered on or after October 20, 2017. In its decision, the MDPSC denied Pepco’s request regarding the income tax adjustment without prejudice to Pepco filing another similar proposal with additional information. Requests for rehearing are due November 20, 2017.

~~2017 Maryland Electric Distribution Rates (Exelon, PHI and DPL).~~ On July 14, 2017, DPL filed an application with the MDPSC to increase its annual electric distribution base rates by $27 million, which was updated to $22 million on September 28, 2017, reflecting a requested ROE of 10.1%. DPL expects a decision in the matter in the first quarter of 2018, but cannot predict how much of the requested increase the MDPSC will approve.

~~2016 Maryland Electric Distribution Rates (Exelon, PHI and DPL).~~ On February 15, 2017, the MDPSC approved an increase in DPL electric distribution rates of $38 million reflecting a ROE of 9.6%. The new rates became effective for services rendered on or after February 15, 2017. The MDPSC also denied DPL’s request to continue its Grid Resiliency Program, through which DPL proposed to invest $5 million a year for two years to improve priority feeders and install single-phase reclosing fuse technology. The final order did not result in the recognition of any incremental regulatory assets or liabilities.

~~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 all of its SOS-related costs. The Administrative Charge is now comprised of five components: CWC, uncollectibles, incremental costs, return, and an administrative adjustment, which is an adder to the utility’s SOS rate to act as a proxy for retail suppliers’ costs. The Commission 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. The Commission ruled that the level of the administrative adjustment will be determined in BGE’s next rate case. On December 16, 2016, MDPSC Staff requested clarification concerning the amount of return on the SOS awarded to BGE and on December 19, 2016, the residential consumer advocate sought rehearing of the return awarded. On January 24, 2017, the MDPSC issued an order denying the MDPSC Staff request for clarification and the residential consumer advocate request for rehearing. On February 22, 2017, the residential consumer advocate filed an appeal of the MDPSC's orders with the Circuit Court for Baltimore City. The residential consumer advocate filed its Memorandum on Appeal on June 5, 2017 and subsequent Reply Memoranda were filed by BGE and the MDPSC on July 7, 2017 and July 12, 2017, respectively. On August 7, 2017, following oral argument by the parties, a decision was issued from the Circuit Court affirming the decision of the MDPSC. On September 5, 2017, the residential consumer advocate filed an appeal of the Circuit Court's decision to the Maryland Court of Special Appeals. BGE cannot predict the outcome of this appeal.

~~Smart Meter and Smart Grid Investments (Exelon and BGE).~~ In August 2010, the MDPSC approved a comprehensive smart grid initiative for BGE that included the planned installation of 2 million residential and commercial electric and natural gas smart meters at an expected total cost of $480 million of which $200 million was funded by SGIG. The MDPSC’s approval ordered BGE to defer the associated incremental costs, depreciation and amortization, and an appropriate return, in a regulatory asset until such time as a cost-effective advanced metering system is implemented. As of September 30, 2017 and December 31, 2016, the balance of BGE's regulatory asset was $219 million and $230 million, respectively, representing incremental program deployment costs. The current quarter balance of $219 million consists of three major components, including $133 million of unamortized incremental deployment costs of the AMI program, $54 million of unamortized costs of the non-AMI meters replaced under the program, and $32 million related to post-test year incremental program deployment costs incurred prior to approval became effective June 2016. The balance as of September 30, 2017 reflects the impact of the cost disallowances and adjustments in BGE's 2015 electric and natural gas distribution rate case. The incremental deployment costs for the AMI program and the non-AMI meter components of the regulatory asset are being recovered through rates and amortized to expense

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

over a 10 year period, while the post-test year incremental program deployment costs have not yet been approved for recovery by the MDPSC. A return on the regulatory asset is currently included in rates, except for the $54 million portion representing the unamortized cost of the retired non-AMI meters and a $32 million portion related to post-test year incremental program deployment costs.

As a combined result of the MDPSC orders in BGE's 2015 electric and natural gas distribution rate case, BGE recorded a $52 million charge in June 2016 to Operating and maintenance expense in Exelon’s and BGE’s Consolidated Statements of Operations and Comprehensive Income reducing certain regulatory assets and other long-lived assets and reclassified $56 million of non-AMI plant costs from Property, plant and equipment, net to Regulatory assets on Exelon's and BGE's Consolidated Balance Sheets. For further information, see Note 3 - Regulatory Matters of the Exelon 2016 Form 10-K.

~~Delaware Regulatory Matters~~

~~2017 Electric and Natural Gas Distribution Rates (Exelon, PHI and DPL).~~ On August 17, 2017, DPL filed applications with the DPSC to increase its annual electric and natural gas distribution base rates by $24 million, which was updated to $31 million on October 18, 2017, and $13 million, respectively, reflecting a requested ROE of 10.1%. DPL expects a decision in the electric proceeding and the gas proceeding in the third quarter of 2018, but cannot predict how much of the requested rate increases the DPSC will approve. While the DPSC is not required to issue a decision on the application within a specified period of time, Delaware law allows DPL to put into effect $2.5 million of the rate increase two months after filing the application and the entire requested rate increase seven months after filing, subject to a cap and a refund obligation based on the final DPSC order. On October 24, 2017, the Staff of the DPSC and the Public Advocate filed a joint motion to dismiss DPL's electric distribution base rate application without prejudice to refiling, arguing that the amount of the requested increase to $31 million required additional time to review and additional public notice. The DPSC is expected to decide at its meeting on November 9, 2017. DPL cannot predict the outcome of this matter.

~~2016 Electric and Natural Gas Distribution Rates (Exelon, PHI and DPL).~~ On May 17, 2016, DPL filed applications with the DPSC to increase its annual electric and natural gas distribution base rates by $63 million, which was updated to $60 million on March 8, 2017, and $22 million, respectively, reflecting a requested ROE of 10.6%. Delaware law allowed DPL to put into effect $2.5 million of each of the rate increases effective July 16, 2016. On December 17, 2016, the DPSC approved an additional $30 million in electric distribution rates and an additional $10 million in natural gas distribution rates effective December 17, 2016, subject to refund based on the final DPSC orders.

On March 8, 2017, DPL entered into a settlement agreement with the Division of the Public Advocate, Delaware Electric Users Group and the DPSC Staff in its electric distribution rate proceeding, which provides for an increase in DPL annual electric distribution base rates of $31.5 million reflecting a ROE of 9.7% compared to the $32 million increase previously put into effect. On May 23, 2017, the DPSC issued an order approving the settlement agreement, with the new rates effective June 1, 2017. Pursuant to the settlement agreement, no refund of the interim rates put into effect on July 16, 2016 and December 17, 2016 (as discussed above) is required.

On April 6, 2017, DPL entered into a settlement agreement with the Division of the Public Advocate and the DPSC Staff in its natural gas distribution rate proceeding, which provides for an increase in DPL annual natural gas distribution base rates of $4.9 million reflecting a ROE of 9.7%. The settlement agreement also provides that DPL will refund amounts collected under the temporary rates effective July 16, 2016 and December 17, 2016 (as discussed above) in excess of the $4.9 million, and that the new rates will be effective within thirty days of DPSC approval of the settlement agreement. On June 6, 2017, the DPSC issued an order approving the settlement agreement, with the new rates effective July 1, 2017. Pursuant to the settlement agreement, a rate refund plus interest of approximately $5 million was issued to customers beginning in August 2017 for which a regulatory liability has been recorded as of September 30, 2017. This is a one-time refund and was included on customer bills from mid-August through mid-September.

~~District of Columbia Regulatory Matters~~

~~2016 Electric Distribution Rates (Exelon, PHI and Pepco).~~ On June 30, 2016, Pepco filed an application with the DCPSC to increase its annual electric distribution base rates by $86 million, which was updated to $77 million on February 1, 2017, reflecting a requested ROE of 10.6%.

On July 25, 2017, the DCPSC approved an increase in Pepco electric distribution base rates of $37 million reflecting a ROE of 9.5%. The new rates became effective for services rendered on or after August 15, 2017. In its

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

decision, the DCPSC ordered that the $26 million customer rate credit created as a result of the Exelon and PHI merger will be provided primarily to residential customers and some small commercial customers to offset the impact of this increase until that amount has been exhausted, which is expected to take approximately two years. Additionally, the Commission is holding approximately $6 million to $7 million of the customer rate credit for use toward a possible new class of customers for certain senior citizens and disabled persons. The DCPSC also held that Pepco's bill stabilization adjustment, which decouples distribution revenues from utility customers from the amount of electricity delivered, will continue to be in place and that no refund of previously collected funds is required. Several parties filed requests that the DCPSC reconsider the order on various issues, and on October 6, 2017, the Commission issued an order denying each of the requests.

~~District of Columbia Power Line Undergrounding Initiative (Exelon, PHI and Pepco).~~ The District of Columbia government enacted on an emergency basis (effective May 17, 2017) and thereafter on a permanent basis (effective July 11, 2017) legislation to amend the Electric Company Infrastructure Improvement Financing Act of 2014 (as amended) (the Infrastructure Improvement Financing Act) to authorize the District of Columbia Power Line Undergrounding (DC PLUG) initiative, a projected six year, $500 million project to place underground some of the District of Columbia’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.

The $250 million of project costs funded by Pepco will be recovered through a volumetric surcharge on the electric bill of substantially all of Pepco's customers in the District of Columbia. Pepco will earn a return on these project costs.

The $250 million of project costs funded by the District of Columbia will come from two sources. Project costs of $187.5 million will be funded through a charge assessed on Pepco by the District of Columbia; Pepco will recover this charge from customers through a volumetric distribution rider. The remaining costs up to $62.5 million are to be funded by the existing capital projects program of the District Department of Transportation (DDOT). Ownership and responsibility for the operation and maintenance of all the assets funded by the District of Columbia will be transferred to Pepco for a nominal amount upon completion. Pepco will not recover or earn a return on the cost of the assets transferred to it by the District of Columbia.

In accordance with the Infrastructure Improvement Financing Act, Pepco filed an application for approval of the first two-year portion of the DC PLUG initiative (the First Biennial Plan) on July 3, 2017. After the initial application, Pepco will be required to make two updated applications, one every two years until the project is completed. Pepco anticipates that the DCPSC will issue an order approving the First Biennial Plan in early November 2017. Upon the issuance of a DCPSC order approving the First Biennial Plan, Pepco will become obligated to pay $187.5 million to the District of Columbia over the six year project term, at which time it will record an obligation and offsetting regulatory asset.

New Jersey Regulatory Matters

~~New Jersey Consolidated Tax Adjustment~~Termination of Energy Procurement Provisions of PPAs (Exelon, PHI, and ACE).~~The Consolidated Tax Adjustment (CTA) is a New Jersey ratemaking policy that requires utilities that are part of a consolidated tax group to share~~On December 22, 2021, ACE filed with ~~customers the tax benefits that came from losses at unregulated affiliates through a reduction in rate base. In 2013,~~ the NJBPU ~~opened~~ a ~~generic proceeding~~petition to ~~review~~terminate the ~~policy. In 2014,~~provisions in the PPAs to purchase electricity from two coal-powered generation facilities located in the state of New Jersey. The petition was approved by the NJBPU ~~issued a decision which retained the CTA, but in a highly modified format that significantly reduced the impact~~on March 23, 2022. Upon closing of the ~~CTA~~transaction on March 31, 2022, ACE recognized a liability of $203 million for the contract termination fee, which is to ~~ACE. On~~be paid by the end of 2024, and recognized a corresponding regulatory asset of $203 million.

As of September ~~18, 2017,~~30, 2023, the ~~Appellate Division~~$71 million liability for the contract termination fee consists of $61 million and $10 million included in Other current liabilities and Other deferred credits and other liabilities, respectively, in Exelon's Consolidated Balance Sheet. The current and noncurrent liabilities are included in PPA termination obligation and Other deferred credits and other liabilities, respectively, in PHI's and ACE's Consolidated Balance Sheets. For the nine months ended September 30, 2023 and 2022, ACE has respectively paid $65 million and $45 million of the ~~Superior Court~~liability, which is recorded in Changes in Other assets and liabilities in Exelon's, PHI's, and ACE's Consolidated Statements of ~~New Jersey reversed~~Cash Flows.

ACE Infrastructure Investment Program “Powering the NJBPU’s decision in adopting the revised CTA policy and held that NJBPU’s actions related to the CTA constituted a rulemaking that should have been undertaken pursuant to the requirements of the Administrative Procedures Act. The Court did not address the merits of the CTA methodology itself. No party filed an appeal of the Court’s decision, and the NJBPU is expected to conduct further proceedings. If the NJBPU were to apply the CTA in its unmodified form, it could have a material prospective impact to ACE through a reduction in rate base in future rate cases.

~~2017 Electric Distribution Rates~~Future” Filing (Exelon, PHI, and ACE).On ~~March 30, 2017,~~October 31, 2022, ACE filed ~~an application~~ with the NJBPU a second IIP, called “Powering the Future”, proposing to ~~increase~~seek recovery through a new component of ACE’s rider mechanism, totaling $379 million, over the four-year period of July 1, 2023, to June 30, 2027. The new IIP will allow ACE to invest in projects that are designed to enhance the reliability, resiliency, and safety of the service ACE provides to its annual electric distribution rates by $70 million (before New Jersey sales and use tax), which was updated to $73 million on July 14, 2017, reflecting a requested ROE of 10.1%. The application also requests approval of a rate surcharge mechanism called the “System Renewal Recovery Charge,” which would permit more timely recovery of certain costs associated with reliability and system renewal-related capital investments.

customers. On ~~September 8, 2017,~~June 15, 2023, ACE entered into a settlement agreement with other parties, which allows for a recovery totaling $93 million of reliability related capital investments from July 1, 2023, through June 30, 2027. ACE will have the option of seeking approval from the NJBPU ~~staff,~~to extend the ~~New Jersey Division~~end date of ~~Rate Counsel~~the IIP beyond June 30, 2027, if ACE determines an extension is necessary. On June 29, 2023, the NJBPU adopted the settlement agreement and ~~Wal-Mart Stores, Inc. in its electric distribution rate proceeding, which provides for~~issued an ~~increase~~

order approving the program.

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

Note 3 — Regulatory Matters

in ACE annual electric distribution base rates of $43 million (before New Jersey sales and use tax) reflecting a ROE of 9.6%. In addition, pursuant to the settlement agreement, ACE agreed to withdraw its request for approval of a System Renewal Recovery Charge without prejudice to its right to refile. On September 22, 2017, the NJBPU issued an order approving the settlement agreement, with the new rates effective on October 1, 2017.

~~2016 Electric Distribution Rates (Exelon, PHI and ACE).~~ On August 24, 2016, the NJBPU issued an order approving a stipulation of settlement among ACE, the New Jersey Division of Rate Counsel, NJBPU Staff and Unimin Corporation, which, among other things, provided that a determination on ACE's grid resiliency program, PowerAhead, would be separated into a phase II of the rate proceeding and decided at a later date. PowerAhead includes capital investments to enhance the resiliency of the system through improvements focused on improving the distribution system's ability to withstand major storm events. A stipulation of settlement with respect to the PowerAhead program (the PowerAhead Stipulation) was approved by the NJBPU on May 31, 2017. As adopted, the PowerAhead program includes an approved investment level of $79 million to be recovered through the cost recovery mechanism described in the PowerAhead Stipulation. The NJBPU order adopting the PowerAhead Stipulation was effective on June 10, 2017.

~~Update and Reconciliation of Certain Under-Recovered Balances (Exelon, PHI and ACE).~~ On February 1, 2017, ACE submitted its 2017 annual petition with the NJBPU seeking to reconcile and update (i) charges related to the recovery of above-market costs associated with ACE’s long-term power purchase contracts with the non-utility generators and (ii) costs related to surcharges for the New Jersey Societal Benefit Program (a statewide public interest program that is intended to benefit low income customers and address other public policy goals) and ACE’s uncollectible accounts. As filed, the net impact of adjusting the charges as proposed would have been an overall annual rate decrease of approximately $29 million (revised to approximately $32 million in April 2017, based upon an update for actuals through March 2017), including New Jersey sales and use tax. On May 31, 2017, the NJBPU approved a stipulation of settlement entered into by the parties providing for an overall annual rate decrease of approximately $32 million, effective June 1, 2017. The rate decrease was placed into effect provisionally, subject to a review by NJBPU and the Division of Rate Counsel of the final underlying costs for reasonableness and prudence. This rate decrease will have no effect on ACE’s operating income, since these revenues provide for recovery of deferred costs under an approved deferral mechanism. The matter is pending at the NJBPU.

~~New York~~Other Federal Regulatory Matters

~~New York Clean Energy Standard~~FERC Audit (Exelon and ~~Generation)~~ComEd). On August 1, 2016, the New York Public Service Commission (NYPSC) issued an order establishing the New York CES, a component of which is the 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. The New York State Energy Research and Development Authority (NYSERDA) will centrally procure the ZECs from eligible plants through a 12-year contract, to be administered in six two-year tranches, extending from April 1, 2017 through March 31, 2029. ZEC payments will be made to the eligible resources based upon the number of MWh produced,Utility Registrants are subject to ~~specified caps~~periodic audits by FERC. FERC’s Division of Audits and ~~minimum performance requirements.~~Accounting initiated a nonpublic audit of ComEd in April 2021 evaluating ComEd’s compliance with (1) approved terms, rates, and conditions of its federally regulated service; (2) accounting requirements of the Uniform System of Accounts; (3) reporting requirements of the FERC Form 1; and (4) the requirements for record retention. The ~~price~~audit period extends back to ~~be paid for~~January 1, 2017. During the ~~ZECs~~first quarter of 2023, ComEd was provided with information from FERC about several potential findings, including ComEd's methodology regarding the allocation of certain overhead costs to capital under ~~each tranche will be administratively determined using a formula based~~FERC regulations. 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 increase in underlying energy~~preliminary findings and capacity prices. The ZEC price for the first tranche has been set at $17.48 per MWh of production. Following the first tranche, the price will be updated bi-annually. Each Load Serving Entity (LSE) shall be required to purchase an amount of ZECs equivalent to its load ratio share of the total electric energy in the New York Control Area. Cost recovery from ratepayers shall be incorporated into the commodity charges on customer bills.

The NYPSC initially identified three plants eligible for the ZEC program: the FitzPatrick, Ginna, and Nine Mile Point nuclear facilities. As issued, the order also provided that the duration of the program beyond the first tranche was conditional upon a buyer purchasing the FitzPatrick facility and taking title prior to September 1, 2018. On November 18, 2016, the required contracts with NYSERDA were executed for Ginna and Nine Mile Point, in addition to Entergy’s execution of the required contract for the FitzPatrick facility. On March 31, 2017, Generation closed on the acquisition of FitzPatrick. Generation is currently recognizing revenue for the sale of New York ZECs in the month following generation when the ZECs are transferred to NYSERDA. For the three and nine months ended September 30, 2017, Generation has recognized $118 million and $191 million of ZEC revenue.

Several parties filed with the NYPSC requests for rehearing or reconsideration of the New York CES. Generation and CENG also filed a request for clarification, or in the alternative limited rehearing, that the condition limiting the duration of the program beyond the first tranche be limited to the eligibility of the FitzPatrick plant only and have no

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bearing on Ginna or Nine Mile Point’s eligibility for the full 12-year duration. On December 15, 2016, the NYPSC approved Generation’s and CENG's petition to clarify this condition and denied all petitions for rehearing of the New York CES. Parties had until mid-April to appeal to New York State court the denials of the requests for rehearing. A Petition seeking to invalidate the ZEC program was filed in New York State court by certain environmental groups and other parties on November 30, 2016, and amended on January 13, 2017, arguing that the NYPSC did not have authority to establish the program and that it violated certain technical provisions of the State Administrative Procedures Act (SAPA) when adopting the ZEC program. On February 15, 2017, Generation and CENG filed a motion to dismiss the state court action. The NYPSC also filed a motion to dismiss the state court action. On March 24, 2017, the plaintiffs filed a memorandum of law opposing the motions to dismiss, and Generation and CENG filed a reply brief on April 28, 2017. Oral argument was held on June 19, 2017. The motions to dismiss are pending.

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. On December 9, 2016, Generation and CENG filed a motion to intervene in the case and to dismiss the lawsuit. The State also filed a motion to dismiss. Oral argument was held on March 29, 2017. On July 25, 2017, the court granted both motions to dismiss. On August 24, 2017, plaintiffs appealed the decision to the Second Circuit. ~~Plaintiffs-Appellants’ initial brief was filed on October 13, 2017. The state’s and Exelon’s briefs are due on November 17, 2017. Reply briefs are due on December 1, 2017.~~

Other legal challenges remain possible, the outcomes of which remain uncertain. See Note 7 - Early Nuclear Plant Retirements for additional information relative to Ginna and Nine Mile Point. See Note 4 - Mergers, Acquisitions and Dispositions for additional information on Generation's acquisition of FitzPatrick.

~~Ginna Nuclear Power Plant Reliability Support Services Agreement (Exelon and Generation).~~ In November 2014, in response to a petition filed by Ginna Nuclear Power Plant (Ginna) regarding the possible retirement of Ginna, the NYPSC directed Ginna and Rochester Gas & Electric Company (RG&E) to negotiate a Reliability Support Services Agreement (RSSA) to support the continued operation of Ginna to maintain the reliability of the RG&E transmission grid for a specified period of time. During 2015 and 2016, Ginna and RG&E made filings with the NYPSC and FERC for their approval of the proposed RSSA. Although the RSSA was still subject to regulatory approvals, on April 1, 2015, Ginna began delivering the power and capacity from the Ginna plant into the ISO-NY consistent with the technical provisions of the RSSA.

~~On March 22, 2016, Ginna submitted a compliance filing~~discussions with FERC ~~with revisions~~staff, ComEd determined that a loss was probable and recorded a regulatory liability to the RSSA requested by FERC. On April 8, 2016, FERC accepted the 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 adjustmentreflect its best estimate of approximately $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. As stated previously, on November 18, 2016 the required contract with NYSERDA was executed by Generation and CENG for Ginna. Upon the expiry of the RSSA on March 31, 2017, Ginna was required to make refund payments of $20 million to RG&E related to capital expenditures. Ginna paid RG&E the $20 million in June 2017. Additionally, the provisions of the RSSA provided for a one-time payment of $12 million to be paid from RG&E to Ginna at the end of the contract. This $12 million was recognized in revenuethat loss as of March 31, ~~2017. RG&E paid the $12 million~~2023.

On July 27, 2023, FERC issued a final audit report which included, among other things, findings and recommendations related to Ginna in May 2017. 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 7-Early Nuclear Plant Retirements for further informationComEd's methodology regarding the ~~impacts~~allocation of certain overhead costs to capitalized construction costs under FERC regulations. On August 28, 2023, ComEd filed a ~~decision~~formal notice of the issues it will contest. The final outcome and resolution of any contested audit issues as well as a reasonable estimate of potential future losses cannot be accurately estimated at this stage; however, the final resolution of these matters could result in recognition of future losses, above the amounts currently accrued, that could be material to ~~early retire one or more nuclear plants.~~the Exelon and ComEd financial statements.

Regulatory Assets and Liabilities

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~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

~~(Dollars in millions, except per share data,~~The Utility Registrants' regulatory assets and liabilities have not changed materially since December 31, 2022, unless ~~otherwise noted)~~

~~Federal Regulatory Matters~~

~~Transmission Formula Rate (Exelon, ComEd, BGE, Pepco, DPL and ACE).~~ ~~The following total increases/(decreases) were included in ComEd’s, BGE’s, Pepco's, DPL's and ACE's 2017 annual electric transmission formula rate filings:~~

2017
Annual Transmission Filings^(a)
ComEd BGE Pepco DPL ACE
Initial revenue requirement
increase
$ 44
$ 31
$ 5
$ 6
$ 20
Annual reconciliation (decrease) increase (33 ) 3
15
8
22
Dedicated facilities decrease^(b)
—
(8 ) —
—
—
Total revenue requirement increase $ 11
$ 26
$ 20
$ 14
$ 42

Allowed return on rate base^(c)
8.43 % 7.47 % 7.92 % 7.16 % 8.02 %
Allowed ROE^(d)
11.50 % 10.50 % 10.50 % 10.50 % 10.50 %

~~_________~~


~~(a)~~	~~All rates are effective June 2017, subject to review by the FERC and other parties, which is due by fourth quarter 2017.~~


~~(b)~~	~~BGE's transmission revenues include a FERC approved dedicated facilities charge 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% 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 regional transmission organization.

~~For additional information regarding transmission formula rate filings see~~noted below. See Note 3 — Regulatory Mattersof the ~~Exelon 2016 Form 10-K.~~

~~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 would be updated annually to ensure that under this rate customers pay the actual costs of providing transmission services. The formula rate filing includes a requested increase of $22 million to PECO’s annual transmission revenues and a requested rate of return on common equity of 11%, inclusive of a 50 basis point adder for being a member of a regional transmission organization. PECO requested that the new transmission rate be effective as of July 2017. 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. PECO cannot predict the final outcome of the settlement or hearing proceedings, or the transmission formula FERC may approve.

~~PJM Transmission Rate Design and Operating Agreements (Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE).~~ PJM Transmission Rate Design specifies the rates for transmission service charged to customers within PJM. Currently, ComEd, PECO, BGE, Pepco, DPL and ACE incur costs based on the existing rate design, which charges customers based on the cost of the existing transmission facilities within their load zone and the cost of new transmission facilities based on those who benefit from those facilities. In April 2007, FERC issued an order concluding that PJM’s current rate design for existing facilities is just and reasonable and should not be changed. In the same order, FERC held that the costs of new facilities 500 kV and above should be socialized across the entire PJM footprint and that the costs of new facilities less than 500 kV should be allocated to the customers of the new facilities who caused the need for those facilities. A number of parties appealed to the U.S. Court of Appeals for the Seventh Circuit for review of the decision.

In August 2009, the court issued its decision affirming the FERC’s order with regard to the existing facilities, but remanded to FERC the issue of the cost allocation associated with the new facilities 500 kV and above (Cost Allocation Issue) for further consideration by the FERC. On remand, FERC reaffirmed its earlier decision to socialize the costs of new facilities 500 kV and above. A number of parties filed appeals of these orders. In June 2014, the court again remanded the Cost Allocation Issue to FERC. On December 18, 2014, FERC issued an order setting an evidentiary hearing and settlement proceeding regarding the Cost Allocation Issue. ~~On June 15, 2016, a number of parties, including~~

~~Table of Contents~~

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

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

Exelon and the Utility Registrants, filed a proposed Settlement with FERC. If the Settlement is approved, 50% of the costs of the 500 kV and above facilities approved by the PJM Board on or before February 1, 2013 will be socialized across PJM and 50% will be allocated according to a formula that calculates the flows on the transmission facilities. Each state that is a party in this proceeding either signed, or did not oppose, the settlement. The Settlement is opposed by a number of merchant transmission owners and New York load-serving entities. The Settlement includes provisions for monthly credits or charges that are expected to be mostly refunded or recovered through customer rates over a 10-year period based on negotiated numbers for charges prior to January 1, 2016.

Exelon expects that the Settlement will not have a material impact on the results of operations, cash flows and financial position of Generation, ComEd, PECO, BGE, Pepco, DPL or ACE. The Settlement is subject to approval by ~~FERC.~~

~~DOE Notice of Proposed Rulemaking (Exelon and Generation).~~ On August 23, 2017, the DOE 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 baseload 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. The DOE issued the NOPR under an infrequently-used section of the DOE Organization Act under which the FERC has exclusive jurisdiction to consider and take any final action related to NOPRs proposed by the DOE. The DOE NOPR recommended that the FERC take comments for 45 days after publication in the Federal Register and issue a final order 60 days after such publication. On October 2, 2017, the FERC issued a notice inviting comments regarding the DOE NOPR within 21 days and established a new docket wherein the FERC will consider the matter. On October 23, 2017, Exelon filed comments with the FERC, supporting the goals of the NOPR and urging the agency to take swift action to protect customers from power supply interruptions and ensure resiliency in a way that appropriately balances the value and cost to customers. Exelon cannot predict the final outcome of the proceeding or its potential impact, if any, on Exelon or Generation.

~~Complaints at FERC Seeking to Mitigate Illinois and New York Programs Providing ZECs (Exelon and Generation).~~ PJM and NYISO capacity markets include a Minimum Offer Price Rule (MOPR) that is intended to preclude buyers from exercising buyer market power. If a resource is subjected to a MOPR, its offer is adjusted to remove the revenues it receives through a federal, state or other government-provided financial support program - resulting in a higher offer that may not clear the capacity market. Currently, the MOPRs in PJM and NYISO apply only to certain new resources. Exelon has generally opposed policies that require subsidies or give preferential treatment to generation providers or technologies that do not provide superior reliability or environmental benefits, or that would threaten the reliability and value of the integrated electricity grid. Thus, Exelon has supported a MOPR as a means of minimizing the detrimental impact certain subsidized resources could have on capacity markets (such as the New Jersey (LCAPP) and Maryland (CfD) programs). However, in Exelon’s view, MOPRs should not be applied to resources that receive compensation for providing superior reliability or environmental benefits.

On January 9, 2017, the Electric Power Supply Association (EPSA) filed two requests with FERC: one seeking to amend a prior complaint against PJM and another seeking expedited action on a pending NYISO compliance filing in an existing proceeding. Both filings allege that the relevant MOPR should be expanded to also apply to existing resources receiving ZEC compensation under the New York CES and Illinois ZES programs. The EPSA parties have filed motions to expedite both proceedings. Exelon has filed protests at FERC in response to each filing, arguing generally that ZEC payments provide compensation for an environmental attribute that is distinct from the energy and capacity sold in the FERC-jurisdictional markets, and therefore, are no different than other renewable support programs like the PTC and RPS that have generally not been subject to a MOPR. However, if successful, for Generation's facilities in NYISO and PJM expected to receive ZEC compensation (Quad Cities, Ginna, Nine Mile Point and FitzPatrick), an expanded MOPR could require exclusion of ZEC compensation when bidding into future capacity auctions such that these facilities would have an increased risk of not clearing in those auctions and thus no longer receiving capacity revenues during the respective ZEC programs. Any such mitigation of these generating resources could have a material effect on Exelon’s and Generation’s future cash flows and results of operations. On August 30, 2017, EPSA filed motions to lodge the district court decisions dismissing the complaints and urging FERC to act expeditiously on its requests to expand the MOPR. On September 14, 2017, Exelon filed a response in each docket noting that it does not oppose the motions to lodge but arguing that the requests to expedite a decision on the requests to expand the MOPR have no merit. The timing of FERC’s decision with respect to both proceedings is currently unknown and the outcome of these matters is currently uncertain.

~~Table of Contents~~

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

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

~~Operating License Renewals (Exelon and Generation).~~ On August 29, 2012, Generation submitted a hydroelectric license application to FERC for a 46-year 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 with Maryland Department of the Environment (MDE) for Conowingo, Generation continues to work with MDE and other stakeholders to resolve water quality licensing issues, including: (1) water quality, (2) fish habitat, and (3) sediment. In addition, Generation continues to work with MDE and other Federal and Maryland state agencies to conduct and fund an additional sediment and nutrient monitoring study.

On April 21, 2016, Exelon and Interior executed a Settlement Agreement resolving all fish passage issues between the parties. The financial impact of the Settlement Agreement is estimated to be $3 million to $7 million per year, on average, over the 46-year life of the new license, including both capital and operating costs. The actual timing and amount of these costs are not currently fixed and may vary significantly from year to year throughout the life of the new license. Resolution of the remaining issues relating to Conowingo involving various stakeholders may have a material effect on Exelon’s and Generation’s results of operations and financial position through an increase in capital expenditures and operating costs. As of September 30, 2017, $30 million of direct costs associated with Conowingo licensing efforts have been capitalized. See Note 3 - Regulatory Matters of the Exelon 20162022 Form 10-K for ~~additional information on Generation's operating license renewal efforts.~~

~~Regulatory Assets and Liabilities (Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE)~~

Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE each prepare their consolidated financial statements in accordance with the authoritative guidance for accounting for certain types of regulation. Under this guidance, 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.

As a result of applying the acquisition method of accounting and pushing it down to the consolidated financial statements of PHI, certain regulatory assets and liabilities were established at Exelon and PHI to offset the impacts of fair valuing the acquired assets and liabilities assumed which are subject to regulatory recovery. In total, Exelon and PHI recorded a net $2.4 billion regulatory asset reflecting adjustments recorded as a result of the acquisition method of accounting. See Note 4 — Mergers, Acquisitions and Dispositions for additional information.

~~Table of Contents~~

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

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

~~The following tables provide information about the regulatory assets and liabilities of Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE as of September 30, 2017 and December 31, 2016. For~~ additional information on the specific regulatory assets and liabilities.

ComEd. Regulatory assets increased $733 million primarily due to increases of $392 million in the Electric distribution formula rate annual reconciliations regulatory asset, $171 million in the Energy efficiency costs, and $97 million in the ZEC regulatory asset.

PECO. Regulatory assets increased $150 million primarily due to an increase of $118 million in the Deferred income taxes regulatory asset. Regulatory liabilities ~~refer~~increased $6 million primarily due to ~~Note 3 —~~ increases of $49 million in the Electric energy and natural gas costs regulatory liability, offset by a decrease of $31 million in the Decommissioning the regulatory agreement units regulatory liability.

BGE. Regulatory ~~Matters~~assets increased $114 million primarily due to an increase of $38 million and $35 million in the Removal costs and Under-recovered revenue decoupling regulatory assets, respectively.

Pepco. Regulatory assets decreased $63 million primarily due to a decrease of $35 million in the Electric energy and natural gas costs regulatory asset. Regulatory liabilities decreased $43 million primarily due to a decrease of $52 million in the Deferred income taxes regulatory liability.

DPL. Regulatory assets decreased $17 million primarily due to a decrease of $26 million in the Electric energy and natural gas costs regulatory asset. Regulatory liabilities decreased $1 million primarily due to a decrease of $23 million in the Deferred income taxes regulatory liability, partially offset by an increase of $13 million in the Electric energy and natural gas costs regulatory liability.

ACE. Regulatory assets decreased $21 million primarily due to a decrease of $65 million in the Electric energy and natural gas costs regulatory asset as a result of the ~~Exelon 2016 Form 10-K.~~

Successor
September 30, 2017 Exelon ComEd PECO BGE PHI Pepco DPL ACE
Regulatory assets
Pension and other postretirement benefits^(a)
$ 4,020
$ —
$ —
$ —
$ —
$ —
$ —
$ —
Deferred income taxes^(b)
2,423
347
1,678
100
298
195
45
58
AMI programs 660
159
40
219
242
163
79
—
Under-recovered distribution service costs^(c)
256
256
—
—
—
—
—
—
Energy efficiency costs 78
78
—
—
—
—
—
—
Debt costs 120
38
1
12
75
16
8
5
Fair value of long-term debt 773
—
—
—
632
—
—
—
Fair value of PHI's unamortized energy contracts 830
—
—
—
830
—
—
—
Severance 2
—
—
2
—
—
—
—
Asset retirement obligations 108
73
22
13
—
—
—
—
MGP remediation costs 300
277
23
—
—
—
—
—
Under-recovered uncollectible accounts 70
60
—
—
10
—
—
10
Renewable energy 277
277
—
—
—
—
—
—
Energy and transmission programs ^{(d)(e)(f)(g)(h)(i)}
65
3
—
26
36
6
9
21
Deferred storm costs 31
—
—
—
31
9
5
17
Electric generation-related regulatory asset 3
—
—
3
—
—
—
—
Energy efficiency and demand response programs 599
—
1
284
314
233
81
—
Merger integration costs^(j)(k)(l)(m)
47
—
—
7
40
20
11
9
Under-recovered revenue decoupling⁽ⁿ⁾
72
—
—
34
38
33
5
—
COPCO acquisition adjustment 6
—
—
—
6
—
6
—
Workers compensation and long-term disability cost 33
—
—
—
33
33
—
—
Vacation accrual 38
—
14
—
24
—
14
10
Securitized stranded costs 93
—
—
—
93
—
—
93
CAP arrearage 9
—
9
—
—
—
—
—
Removal costs
518
—
—
—
518
144
98
277
Other 71
6
21
5
40
28
8
4
Total regulatory assets 11,502
1,574
1,809
705
3,260
880
369
504
Less: current portion 1,264
187
36
208
568
181
69
87
Total noncurrent regulatory assets $ 10,238
$ 1,387
$ 1,773
$ 497
$ 2,692
$ 699
$ 300
$ 417

Successor
September 30, 2017 Exelon ComEd PECO BGE PHI Pepco DPL ACE
Regulatory liabilities
Other postretirement benefits $ 41
$ —
$ —
$ —
$ —
$ —
$ —
$ —
Nuclear decommissioning 2,971
2,438
533
—
—
—
—
—
Removal costs 1,588
1,337
—
119
132
22
110
—
Deferred rent 37
—
—
—
37
—
—
—
Energy efficiency and demand response programs 62
33
29
—
—
—
—
—
DLC program costs 8
—
8
—
—
—
—
—
Electric distribution tax repairs 50
—
50
—
—
—
—
—
Gas distribution tax repairs 14
—
14
—
—
—
—
—
Energy and transmission programs ^{(d)(e)(f)(g)(h)(i)}
139
54
68
—
17
3
9
5
Renewable portfolio standards costs 46
46
—
—
—
—
—
—
Zero emission credit costs 71
71
—
—
—
—
—
—
Other 75
5
17
28
25
1
9
13
Total regulatory liabilities 5,102
3,984
719
147
211
26
128
18
Less: current portion 553
249
159
63
65
5
42
18
Total noncurrent regulatory liabilities $ 4,549
$ 3,735
$ 560
$ 84
$ 146
$ 21
$ 86
$ —

~~Table~~PPA termination. Regulatory liabilities decreased $29 million primarily due to a decrease of ~~Contents~~

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

~~(Dollars~~$9 million in ~~millions, except per share data, unless otherwise noted)~~

Successor
December 31, 2016 Exelon ComEd PECO BGE PHI Pepco DPL ACE
Regulatory assets
Pension and other postretirement benefits ^(a)
$ 4,162
$ —
$ —
$ —
$ —
$ —
$ —
$ —
Deferred income taxes ^(b)
2,016
75
1,583
98
260
171
38
51
AMI programs 701
164
49
230
258
174
84
—
Under-recovered distribution service costs ^(c)
188
188
—
—
—
—
—
—
Debt costs 124
42
1
7
81
17
9
6
Fair value of long-term debt 812
—
—
—
671
—
—
—
Fair value of PHI's unamortized energy contracts 1,085
—
—
—
1,085
—
—
—
Severance 5
—
—
5
—
—
—
—
Asset retirement obligations 111
76
23
12
—
—
—
—
MGP remediation costs 305
278
26
1
—
—
—
—
Under-recovered uncollectible accounts 56
56
—
—
—
—
—
—
Renewable energy 260
258
—
—
2
—
—
2
Energy and transmission programs ^{(d)(e)(f)(g)(h)(i)}
89
23
—
38
28
6
5
17
Deferred storm costs 36
—
—
1
35
12
5
18
Electric generation-related regulatory asset 10
—
—
10
—
—
—
—
Rate stabilization deferral 7
—
—
7
—
—
—
—
Energy efficiency and demand response programs 621
—
1
285
335
250
85
—
Merger integration costs^(j)(k)(l)(m)
25
—
—
10
15
11
4
—
Under-recovered revenue decoupling⁽ⁿ⁾
27
—
—
3
24
21
3
—
COPCO acquisition adjustment 8
—
—
—
8
—
8
—
Workers compensation and long-term disability costs 34
—
—
—
34
34
—
—
Vacation accrual 31
—
7
—
24
—
14
10
Securitized stranded costs 138
—
—
—
138
—
—
138
CAP arrearage 11
—
11
—
—
—
—
—
Removal costs 477
—
—
—
477
134
88
255
Other 49
7
9
5
29
22
5
4
Total regulatory assets 11,388
1,167
1,710
712
3,504
852
348
501
Less: current portion 1,342
190
29
208
653
162
59
96
Total noncurrent regulatory assets $ 10,046
$ 977
$ 1,681
$ 504
$ 2,851
$ 690
$ 289
$ 405

Successor
December 31, 2016 Exelon ComEd PECO BGE PHI Pepco DPL ACE
Regulatory liabilities
Other postretirement benefits $ 47
$ —
$ —
$ —
$ —
$ —
$ —
$ —
Nuclear decommissioning 2,607
2,169
438
—
—
—
—
—
Removal costs 1,601
1,324
—
141
136
18
118
—
Deferred rent 39
—
—
—
39
—
—
—
Energy efficiency and demand response programs 185
141
41
—
3
3
—
—
DLC program costs 8
—
8
—
—
—
—
—
Electric distribution tax repairs 76
—
76
—
—
—
—
—
Gas distribution tax repairs 20
—
20
—
—
—
—
—
Energy and transmission programs ^{(d)(e)(f)(g)(h)(i)}
134
60
56
—
18
8
5
5
Other 72
4
5
19
41
2
17
20
Total regulatory liabilities 4,789
3,698
644
160
237
31
140
25
Less: current portion 602
329
127
50
79
11
43
25
Total noncurrent regulatory liabilities $ 4,187
$ 3,369
$ 517
$ 110
$ 158
$ 20
$ 97
$ —

~~_________~~

~~(a)~~

As of September 30, 2017 and December 31, 2016, the pension and other postretirement benefits regulatory asset at Exelon includes regulatory assets of $969 million and $995 million, respectively, as a result of the PHI Merger related to unrecognized costs that are probable of regulatory recovery. The regulatory assets are amortized over periods from 3 to 15 years, depending on the underlying component. Pepco, DPL and ACE are currently recovering these costs through base rates. Pepco, DPL and ACE are not earning a return on the recovery of these costs in base rates.

~~(b)~~

As of September 30, 2017, includes transmission-related income tax regulatory assets that require FERC approval separate from the transmission formula rate of $73 million, $42 million, $34 million, $23 million and $21 million for ComEd, BGE, Pepco, DPL and ACE, respectively. As of December 31, 2016, includes transmission-related regulatory assets that require FERC approval separate from the transmission formula rate of $22 million, $38 million, $31 million, $20 million and $19 million for ComEd, BGE, Pepco, DPL and ACE, respectively. On December 13, 2016, BGE filed with FERC to begin recovering these existing and any similar future regulatory assets through its transmission formula rate. On May 9, 2017, FERC accepted BGE’s filing

~~Table of Contents~~

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

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

both the Stranded costs regulatory liability and made effective BGE’s proposed modifications to its transmission formula rate, subject to refund and further Commission order. ComEd, Pepco, DPL, and ACE are expected to make similar filings with FERC and other parties in subsequent periods.Over-recovered revenue decoupling regulatory liability.

~~(c)~~

As of September 30, 2017, ComEd’s regulatory asset of $256 million was comprised of $200 million for the 2015 - 2017 annual reconciliations and $56 million related to significant one-time events including $11 million of deferred storm costs, $7 million of Constellation and PHI merger and integration related costs, $6 million of emerald ash borer costs, and $32 million of smart meter related costs. As of December 31, 2016, ComEd’s regulatory asset of $188 million was comprised of $134 million for the 2015 and 2016 annual reconciliations and $54 million related to significant one-time events, including $20 million of deferred storm costs and $11 million of Constellation and PHI merger and integration related costs, and $23 million of smart meter related costs. See Note 4— Mergers, Acquisitions and Dispositions of the Exelon 2016 Form 10-K for further information.

~~(d)~~

As of September 30, 2017, ComEd’s regulatory liability of $54 million included $22 million related to over-recovered energy costs and $32 million associated with revenues received for renewable energy requirements. As of December 31, 2016, ComEd’s regulatory asset of $23 million included $15 million associated with transmission costs recoverable through its FERC approved formula rate and $8 million of Constellation merger and integration costs to be recovered upon FERC approval. As of December 31, 2016, ComEd’s regulatory liability of $60 million included $30 million related to over-recovered energy costs and $30 million associated with revenues received for renewable energy requirements.

~~(e)~~

As of September 30, 2017, PECO's regulatory liability of $68 million included $34 million related to over-recovered costs under the DSP program, $21 million related to the over-recovered natural gas costs under the PGC and $13 million related to over-recovered non-bypassable transmission service charges. As of December 31, 2016, PECO's regulatory liability of $56 million included $34 million related to over-recovered costs under the DSP program, $10 million related to over-recovered non-bypassable transmission service charges, $8 million related to the over-recovered natural gas costs under the PGC and $4 million related to the over-recovered electric transmission costs.

~~(f)~~

As of September 30, 2017, BGE's regulatory asset of $26 million included $5 million related to under-recovered electric energy costs, $14 million related to under-recovered natural gas costs, $3 million of costs associated with transmission costs recoverable through its FERC approved formula rate and $4 million of abandonment costs to be recovered upon FERC approval. As of December 31, 2016, BGE’s regulatory asset of $38 million included $4 million of costs associated with transmission costs recoverable through its FERC approved formula rate, $28 million related to under-recovered electric energy costs, $3 million of abandonment costs to be recovered upon FERC approval, and $3 million of under-recovered natural gas costs.

~~(g)~~

As of September 30, 2017, Pepco's regulatory asset of $6 million included $3 million of transmission costs recoverable through its FERC approved formula rate and $3 million of under-recovered electric energy costs. As of September 30, 2017, Pepco's regulatory liability of $3 million related to over-recovered electric energy costs. As of December 31, 2016, Pepco's regulatory asset of $6 million related to under-recovered electric energy costs. As of December 31, 2016, Pepco's regulatory liability of $8 million included $5 million of over-recovered transmission costs and $3 million of over-recovered electric energy costs.

~~(h)~~

As of September 30, 2017, DPL's regulatory asset of $9 million included $4 million of transmission costs recoverable through its FERC approved formula rate and $5 million related to under-recovered electric energy costs. As of September 30, 2017, DPL's regulatory liability of $9 million related to over-recovered electric energy costs. As of December 31, 2016, DPL's regulatory asset of $5 million included $1 million of transmission costs recoverable through its FERC approved formula rate and $4 million of under-recovered electric energy costs. As of December 31, 2016, DPL's regulatory liability of $5 million included $2 million of over-recovered electric energy costs and $3 million of over-recovered transmission costs.

~~(i)~~

As of September 30, 2017, ACE's regulatory asset of $21 million included $11 million of transmission costs recoverable through its FERC approved formula rate and $10 million of under-recovered electric energy costs. As of September 30, 2017, ACE's regulatory liability of $5 million related to over-recovered electric energy costs. As of December 31, 2016, ACE's regulatory asset of $17 million included $6 million of transmission costs recoverable through its FERC approved formula rate and $11 million of under-recovered electric energy costs. As of December 31, 2016, ACE's regulatory liability of $5 million included $4 million of over-recovered transmission costs and $1 million of over-recovered electric energy costs.


~~(j)~~	As of September 30, 2017 and December 31, 2016, BGE's regulatory asset of $7 million and $10 million, respectively, included $5 million and $6 million, respectively, of previously incurred PHI acquisition costs as authorized by the June 2016 rate case order.

~~(k)~~

As of September 30, 2017, Pepco’s regulatory asset of $20 million represents previously incurred PHI acquisition costs, including $11 million authorized for recovery in Maryland and $9 million expected to be recovered in the District of Columbia service territory. As of December 31, 2016, Pepco's regulatory asset of $11 million represents previously incurred PHI acquisition costs authorized for recovery in Maryland.

~~(l)~~

As of September 30, 2017, DPL’s regulatory asset of $11 million represents previously incurred PHI acquisition costs, including $4 million authorized for recovery in Maryland, $5 million authorized for recovery in Delaware electric rates, and $2 million expected to be recovered in electric and gas rates in the Delaware service territory. As of December 31, 2016, DPL's regulatory asset of $4 million represents previously incurred PHI acquisition costs expected to be recovered in the Maryland service territory.


~~(m)~~	~~As of September 30, 2017, ACE’s regulatory asset of $9 million represents previously incurred PHI acquisition costs expected to be recovered in the New Jersey service territory.~~

~~(n)~~

Represents the electric and natural gas distribution costs recoverable from customers under BGE’s decoupling mechanism. As of September 30, 2017, BGE had a regulatory asset of $24 million related to under-recovered electric revenue decoupling and $10 million related to under-recovered natural gas revenue decoupling. As of December 31, 2016, BGE had a regulatory asset of $2 million related to under-recovered natural gas revenue decoupling and $1 million related to under-recovered electric revenue decoupling.

Capitalized Ratemaking Amounts Not Recognized ~~(Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE)~~

The following table ~~illustrates our~~presents authorized amounts capitalized for ratemaking purposes related to earnings on ~~shareholders’~~shareholders' investment that are not recognized for financial reporting purposes ~~on our~~in the Registrants' Consolidated Balance Sheets. These amounts will be recognized as revenues in ~~our~~the related Consolidated Statements of Operations and Comprehensive Income in the periods they are billable to ~~our~~the Utility Registrants' customers. PECO had no related amounts at September 30, 2023 and December 31, 2022.

Exelon
ComEd^(a)
PECO
BGE^(b)
PHI
Pepco^(c)

DPL^(c)
ACE
September 30, 2017 $ 71
$ 7
$ —
$ 54
$ 10
$ 6
$ 4
$ —

Exelon
ComEd^(a)
PECO
BGE^(b)
PHI
Pepco^(c)

DPL^(c)
ACE
December 31, 2016 $ 72
$ 5
$ —
$ 57
$ 10
$ 6
$ 4
$ —

~~_________~~


~~(a)~~	~~Reflects ComEd's unrecognized equity returns earned for ratemaking purposes on its under-recovered distribution services costs 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.

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 3 — Regulatory Matters

~~Purchase~~


	Exelon		ComEd(a)		BGE(b)		PHI		Pepco(c)		DPL(c)		ACE(b)
September 30, 2023	$	81	$	25	$	21	$	35	$	27	$	1	$	7

December 31, 2022	57		8		28		21		18		2		1

__________

(a)Reflects ComEd's unrecognized equity returns earned for ratemaking purposes on its energy efficiency and electric distribution formula rate regulatory assets.

(b)BGE's and ACE's authorized amounts capitalized for ratemaking purposes primarily relate to earnings on shareholder's investment on their respective AMI programs.

(c)Pepco's and DPL's authorized amounts capitalized for ratemaking purposes relate to earnings on shareholder's investment on their respective AMI Programs and Energy Efficiency and Demand Response Programs, and for Pepco District of ~~Receivables Programs (Exelon, ComEd, PECO, BGE,~~Columbia revenue decoupling program. The earnings on energy efficiency are on Pepco District of Columbia and DPL Delaware programs only.

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. The primary sources of revenue include regulated electric and gas tariff sales, distribution, and transmission services.

See Note 4 — Revenue from Contracts with Customers of the 2022 Form 10-K for additional information regarding the primary sources of revenue for the Registrants.

Contract Liabilities

The Registrants record contract liabilities when consideration is received or due prior to the satisfaction of the performance obligations. The Registrants record contract liabilities in Other current liabilities and Other noncurrent deferred credits and other liabilities in their Consolidated Balance Sheets.

For PHI, Pepco, DPL, and ~~ACE)~~ACE these contract liabilities primarily relate to upfront consideration received in the third quarter of 2020 for a collaborative arrangement with an unrelated owner and manager of communication infrastructure. The revenue attributable to this arrangement will be recognized as operating revenue over the 35 years under the collaborative arrangement.

The following table provides a rollforward of the contract liabilities reflected in Exelon's, PHI's, Pepco's, DPL's, and ACE's Consolidated Balance Sheets for the three and nine months ended September 30, 2023 and 2022. At September 30, 2023 and December 31, 2022, ComEd's, PECO's, and BGE's contract liabilities were immaterial.



	Exelon(a)		PHI(a)		Pepco(a)		DPL		ACE(a)
Balance at December 31, 2022	$	101	$	101	$	81	$	10	$	10
Revenues recognized	(1)		(1)		(1)		—		—
Balance at March 31, 2023	100		100		80		10		10
Revenues recognized	(2)		(2)		(2)		—		—
Balance at June 30, 2023	$	98	$	98	$	78	$	10	$	10
Revenues recognized	(2)		(2)		(1)		—		(1)
Balance as of September 30, 2023	$	96	$	96	$	77	$	10	$	9

	Exelon(a)		PHI(a)		Pepco(a)		DPL(a)		ACE(a)
Balance at December 31, 2021	$	109	$	109	$	87	$	11	$	11
Revenues recognized	(2)		(2)		(2)		—		—
Balance at March 31, 2022	107		107		85		11		11
Revenues recognized	(2)		(2)		(1)		—		(1)
Balance at June 30, 2022	$	105	$	105	$	84	$	11	$	10
Revenues recognized	(2)		(2)		(1)		(1)		—
Balance as of September 30, 2022	$	103	$	103	$	83	$	10	$	10

__________

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 4 — Revenue from Contracts with Customers

(a)Revenues recognized in the three and nine months ended September 30, 2023 and 2022, were included in the contract liabilities at December 31, 2022 and 2021, respectively.

Transaction Price Allocated to Remaining Performance Obligations

The following table shows the amounts of future revenues expected to be recorded in each year for performance obligations that are unsatisfied or partially unsatisfied as of September 30, 2023. This disclosure only includes contracts for which the total consideration is fixed and determinable at contract inception. The average contract term varies by customer type and commodity but ranges from one month to several years.

This disclosure excludes 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.


Year	Exelon		PHI		Pepco		DPL		ACE
2023	$	2	$	2	$	2	$	—	$	1
2024	6		6		5		—		—
2025	5		5		5		—		—
2026	5		5		5		—		—
2027 and thereafter	78		78		60		10		8
Total	$	96	$	96	$	77	$	10	$	9

Revenue Disaggregation

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 5 — Segment Information for the presentation of the Registrants' revenue disaggregation.

5. Segment Information (All Registrants)

Operating segments for each of the Registrants are determined based on information used by the CODMs in deciding how to evaluate performance and allocate resources at each of the Registrants.

Exelon has six reportable segments, which include 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 the segments based on net income.

An analysis and reconciliation of the Registrants’ reportable segment information to the respective information in the consolidated financial statements for the three and nine months ended September 30, 2023 and 2022 is as follows:

Three Months Ended September 30, 2023 and 2022

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 5 — Segment Information



	ComEd		PECO		BGE		PHI		Other(a)		Intersegment Eliminations		Exelon
Operating revenues(b):
2023
Electric revenues	$	2,268	$	970	$	836	$	1,747	$	—	$	(28)	$	5,793
Natural gas revenues	—		67		96		24		—		—		187
Shared service and other revenues	—		—		—		2		445		(447)		—
Total operating revenues	$	2,268	$	1,037	$	932	$	1,773	$	445	$	(475)	$	5,980
2022
Electric revenues	$	1,378	$	941	$	757	$	1,557	$	—	$	(12)	$	4,621
Natural gas revenues	—		73		113		38		—		—		224
Shared service and other revenues	—		—		—		3		381		(384)		—
Total operating revenues	$	1,378	$	1,014	$	870	$	1,598	$	381	$	(396)	$	4,845
Intersegment revenues(c):
2023	$	9	$	2	$	2	$	2	$	443	$	(458)	$	—
2022	6		3		3		3		378		(393)		—
Depreciation and amortization:
2023	$	357	$	100	$	161	$	257	$	15	$	—	$	890
2022	333		92		148		238		14		—		825
Operating expenses:
2023	$	1,738	$	847	$	835	$	1,440	$	475	$	(478)	$	4,857
2022	913		798		810		1,254		439		(380)		3,834
Interest expense, net:
2023	$	119	$	52	$	47	$	80	$	139	$	—	$	437
2022	104		45		39		72		105		—		365
Income (loss) from continuing operations before income taxes:
2023	$	427	$	149	$	56	$	281	$	(130)	$	(16)	$	767
2022	375		179		26		291		(103)		—		768
Income Taxes:
2023	$	94	$	3	$	11	$	49	$	(90)	$	—	$	67
2022	84		44		(7)		2		(31)		—		92
Net income (loss) from continuing operations:
2023	$	333	$	146	$	45	$	232	$	(41)	$	(15)	$	700
2022	291		135		33		289		(71)		(1)		676
Capital Expenditures:
2023	$	664	$	361	$	330	$	488	$	12	$	—	$	1,855
2022	593		333		340		398		8		—		1,672

__________

(a)Other primarily includes Exelon’s corporate operations, shared service entities, and other financing and investment activities.

(b)Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in Taxes other than income taxes in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 15 — Supplemental Financial Information for additional information on total utility taxes.

(c)See Note 16 — Related Party Transactions for additional information on intersegment revenues.

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 5 — Segment Information

PHI:



	Pepco		DPL		ACE		Other(a)		Intersegment Eliminations		PHI
Operating revenues(b):
2023
Electric revenues	$	822	$	426	$	502	$	—	$	(3)	$	1,747
Natural gas revenues	—		24		—		—		—		24
Shared service and other revenues	—		—		—		103		(101)		2
Total operating revenues	$	822	$	450	$	502	$	103	$	(104)	$	1,773
2022
Electric revenues	$	724	$	374	$	462	$	—	$	(3)	$	1,557
Natural gas revenues	—		38		—		—		—		38
Shared service and other revenues	—		—		—		94		(91)		3
Total operating revenues	$	724	$	412	$	462	$	94	$	(94)	$	1,598
Intersegment revenues(c):
2023	$	1	$	2	$	—	$	103	$	(104)	$	2
2022	2		1		—		94		(94)		3
Depreciation and amortization:
2023	$	112	$	62	$	77	$	6	$	—	$	257
2022	99		59		74		6		—		238
Operating expenses:
2023	$	658	$	386	$	394	$	105	$	(103)	$	1,440
2022	555		345		353		96		(95)		1,254
Interest expense, net:
2023	$	41	$	18	$	19	$	3	$	(1)	$	80
2022	37		16		17		1		1		72
Income (loss) before income taxes:
2023	$	141	$	51	$	94	$	(4)	$	(1)	$	281
2022	146		54		95		(4)		—		291
Income Taxes:
2023	$	21	$	8	$	23	$	(3)	$	—	$	49
2022	1		2		1		(2)		—		2
Net income (loss):
2023	$	120	$	43	$	71	$	(2)	$	—	$	232
2022	145		52		94		(2)		—		289
Capital Expenditures:
2023	$	227	$	158	$	101	$	2	$	—	$	488
2022	193		100		105		—		—		398

_________

(a)Other primarily includes PHI’s corporate operations, shared service entities, and other financing and investment activities.

(c)Includes intersegment revenues with ComEd, BGE, and PECO, which are eliminated at Exelon.

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 5 — Segment Information

Electric and Gas Revenue by Customer Class (Utility Registrants):

The following tables disaggregate the Registrants' revenues 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 the Utility Registrants, the disaggregation of revenues reflects the two primary utility services of electric sales and natural gas sales (where applicable), with further disaggregation of these tariff sales provided by major customer groups. Exelon’s disaggregated revenues are consistent with the Utility Registrants, but exclude any intercompany revenues.



	Three Months Ended September 30, 2023
Revenues from contracts with customers	ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Electric revenues
Residential	$	1,047	$	654	$	512	$	959	$	405	$	255	$	299
Small commercial & industrial	540		148		86		199		54		70		75
Large commercial & industrial	263		67		144		386		303		32		51
Public authorities & electric railroads	11		7		7		16		9		3		4
Other(a)	265		80		104		201		67		67		68
Total electric revenues(b)	$	2,126	$	956	$	853	$	1,761	$	838	$	427	$	497
Natural gas revenues
Residential	$	—	$	43	$	57	$	12	$	—	$	12	$	—
Small commercial & industrial	—		16		10		7		—		7		—
Large commercial & industrial	—		—		25		1		—		1		—
Transportation	—		7		—		3		—		3		—
Other(c)	—		1		4		1		—		1		—
Total natural gas revenues(d)	$	—	$	67	$	96	$	24	$	—	$	24	$	—
Total revenues from contracts with customers	$	2,126	$	1,023	$	949	$	1,785	$	838	$	451	$	497
Other revenues
Revenues from alternative revenue programs	$	135	$	11	$	(22)	$	(15)	$	(18)	$	(2)	$	5
Other electric revenues(e)	7		3		4		3		2		1		—
Other natural gas revenues(e)	—		—		1		—		—		—		—

Total other revenues	$	142	$	14	$	(17)	$	(12)	$	(16)	$	(1)	$	5
Total revenues for reportable segments	$	2,268	$	1,037	$	932	$	1,773	$	822	$	450	$	502

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 5 — Segment Information



	Three Months Ended September 30, 2022
Revenues from contracts with customers	ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Electric revenues
Residential	$	935	$	620	$	406	$	808	$	318	$	207	$	283
Small commercial & industrial	217		149		88		179		44		65		70
Large commercial & industrial	(117)		93		158		401		303		43		55
Public authorities & electric railroads	3		8		7		16		9		4		3
Other(a)	246		71		101		166		57		55		54
Total electric revenues(b)	$	1,284	$	941	$	760	$	1,570	$	731	$	374	$	465
Natural gas revenues
Residential	$	—	$	46	$	70	$	10	$	—	$	10	$	—
Small commercial & industrial	—		20		13		6		—		6		—
Large commercial & industrial	—		—		28		3		—		3		—
Transportation	—		5		—		3		—		3		—
Other(c)	—		2		2		16		—		16		—
Total natural gas revenues(d)	$	—	$	73	$	113	$	38	$	—	$	38	$	—
Total revenues from contracts with customers	$	1,284	$	1,014	$	873	$	1,608	$	731	$	412	$	465
Other revenues
Revenues from alternative revenue programs	$	88	$	(5)	$	(8)	$	(11)	$	(8)	$	—	$	(3)
Other electric revenues(e)	6		5		4		1		1		—		—
Other natural gas revenues(e)	—		—		1		—		—		—		—

Total other revenues	$	94	$	—	$	(3)	$	(10)	$	(7)	$	—	$	(3)
Total revenues for reportable segments	$	1,378	$	1,014	$	870	$	1,598	$	724	$	412	$	462

__________

(a)Includes revenues from transmission revenue from PJM, wholesale electric revenue and mutual assistance revenue.

(b)Includes operating revenues from affiliates in 2023 and 2022 respectively of:

•$9 million, $6 million at ComEd

•$2 million, $3 million at PECO

•$1 million, $2 million at BGE

•$2 million, $3 million at PHI

•$1 million, $2 million at Pepco

•$2 million, $1 million at DPL

•less than $1 million, less than $1 million at ACE

(c)Includes revenues from off-system natural gas sales.

(d)Includes operating revenues from affiliates in 2023 and 2022 of:

•less than $1 million at PECO

•$1 million at BGE

(e)Includes late payment charge revenues.

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 5 — Segment Information

Nine Months Ended September 30, 2023 and 2022


	ComEd		PECO		BGE		PHI		Other(a)		Intersegment Eliminations		Exelon
Operating revenues(b):
2023
Electric revenues	$	5,836	$	2,484	$	2,322	$	4,459	$	—	$	(45)	$	15,056
Natural gas revenues	—		493		664		150		—		(3)		1,304
Shared service and other revenues	—		—		—		6		1,316		(1,322)		—
Total operating revenues	$	5,836	$	2,977	$	2,986	$	4,615	$	1,316	$	(1,370)	$	16,360
2022
Electric revenues	$	4,536	$	2,390	$	2,122	$	4,058	$	—	$	(24)	$	13,082
Natural gas revenues	—		487		688		157		—		(2)		1,330
Shared service and other revenues	—		—		—		8		1,342		(1,350)		—
Total operating revenues	$	4,536	$	2,877	$	2,810	$	4,223	$	1,342	$	(1,376)	$	14,412

Intersegment revenues(c):
2023	$	14	$	6	$	6	$	7	$	1,310	$	(1,343)	$	—
2022	14		5		13		9		1,342		(1,377)		6
Depreciation and amortization:
2023	$	1,045	$	297	$	487	$	741	$	46	$	—	$	2,616
2022	982		277		470		697		46		—		2,472
Operating expenses:
2023	$	4,472	$	2,436	$	2,503	$	3,864	$	1,521	$	(1,367)	$	13,429
2022	3,357		2,230		2,446		3,535		1,524		(1,288)		11,804
Interest expense, net:
2023	$	357	$	149	$	135	$	238	$	402	$	(4)	$	1,277
2022	308		129		110		216		300		—		1,063
Income (loss) from continuing operations before income taxes:
2023	$	1,057	$	418	$	362	$	593	$	(424)	$	(21)	$	1,985
2022	909		541		270		528		(228)		(42)		1,978
Income taxes:
2023	$	235	$	8	$	76	$	103	$	(149)	$	1	$	274
2022	203		67		3		10		82		(9)		356
Net income (loss) from continuing operations:
2023	$	822	$	410	$	286	$	490	$	(275)	$	(22)	$	1,711
2022	706		474		267		518		(310)		(33)		1,622
Capital expenditures:
2023	$	1,926	$	1,068	$	986	$	1,510	$	50	$	—	$	5,540
2022	1,801		991		918		1,174		68		—		4,952
Total assets:
September 30, 2023	$	42,042	$	15,259	$	13,649	$	26,656	$	5,825	$	(4,172)	$	99,259
December 31, 2022	39,661		14,502		13,350		26,082		6,014		(4,260)		95,349

__________

(a)Other primarily includes Exelon’s corporate operations, shared service entities, and other financing and investment activities.

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 5 — Segment Information

(c)See Note 16 — Related Party Transactions for additional information on intersegment revenues.

PHI:


	Pepco		DPL		ACE		Other(a)		Intersegment Eliminations		PHI
Operating revenues(b):
2023
Electric revenues	$	2,174	$	1,123	$	1,172	$	1	$	(11)	$	4,459
Natural gas revenues	—		150		—		—		—		150
Shared service and other revenues	—		—		—		309		(303)		6
Total operating revenues	$	2,174	$	1,273	$	1,172	$	310	$	(314)	$	4,615
2022
Electric revenues	$	1,919	$	1,019	$	1,120	$	—	$	—	$	4,058
Natural gas revenues	—		157		—		—		—		157
Shared service and other revenues	—		—		—		298		(290)		8
Total operating revenues	$	1,919	$	1,176	$	1,120	$	298	$	(290)	$	4,223
Intersegment revenues(c):
2023	$	5	$	5	$	1	$	309	$	(313)	$	7
2022	4		5		2		288		(290)		9
Depreciation and amortization:
2023	$	329	$	182	$	212	$	18	$	—	$	741
2022	312		172		192		21		—		697
Operating expenses:
2023	$	1,810	$	1,079	$	971	$	318	$	(314)	$	3,864
2022	1,588		999		947		291		(290)		3,535
Interest expense, net:
2023	$	122	$	53	$	52	$	9	$	2	$	238
2022	111		48		49		7		1		216
Income (loss) before income taxes:
2023	$	292	$	153	$	162	$	(14)	$	—	$	593
2022	259		138		133		(2)		—		528
Income taxes:
2023	$	43	$	25	$	40	$	(5)	$	—	$	103
2022	(2)		8		2		2		—		10
Net income (loss):
2023	$	249	$	128	$	122	$	(9)	$	—	$	490
2022	261		130		131		(4)		—		518
Capital expenditures:
2023	$	710	$	416	$	376	$	8	$	—	$	1,510
2022	595		294		284		1		—		1,174
Total assets:
September 30, 2023	$	11,061	$	5,870	$	5,155	$	4,644	$	(74)	$	26,656
December 31, 2022	10,657		5,802		4,979		4,677		(33)		26,082

__________

(a)Other primarily includes PHI’s corporate operations, shared service entities, and other financing and investment activities.

(c)Includes intersegment revenues with ComEd, BGE, and PECO, which are eliminated at Exelon.

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 5 — Segment Information

Electric and Gas Revenue by Customer Class (Utility Registrants):



	Nine Months Ended September 30, 2023
Revenues from contracts with customers	ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Electric revenues
Residential	$	2,744	$	1,617	$	1,308	$	2,181	$	954	$	626	$	601
Small commercial & industrial	1,363		415		253		503		134		189		180
Large commercial & industrial	553		196		412		1,099		838		98		163
Public authorities & electric railroads	33		23		22		49		25		11		13
Other(a)	716		219		303		563		187		186		194
Total electric revenues(b)	$	5,409	$	2,470	$	2,298	$	4,395	$	2,138	$	1,110	$	1,151
Natural gas revenues
Residential	$	—	$	335	$	406	$	88	$	—	$	88	$	—
Small commercial & industrial	—		123		66		40		—		40		—
Large commercial & industrial	—		1		124		3		—		3		—
Transportation	—		20		—		11		—		11		—
Other(c)	—		12		28		8		—		8		—
Total natural gas revenues(d)	$	—	$	491	$	624	$	150	$	—	$	150	$	—
Total revenues from contracts with customers	$	5,409	$	2,961	$	2,922	$	4,545	$	2,138	$	1,260	$	1,151
Other revenues
Revenues from alternative revenue programs	$	405	$	1	$	47	$	59	$	28	$	10	$	21
Other electric revenues(e)	22		13		12		11		8		3		—
Other natural gas revenues(e)	—		2		5		—		—		—		—

Total other revenues	$	427	$	16	$	64	$	70	$	36	$	13	$	21
Total revenues for reportable segments	$	5,836	$	2,977	$	2,986	$	4,615	$	2,174	$	1,273	$	1,172

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 5 — Segment Information



	Nine Months Ended September 30, 2022
Revenues from contracts with customers	ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Electric revenues
Residential	$	2,610	$	1,538	$	1,158	$	2,007	$	826	$	570	$	611
Small commercial & industrial	953		386		239		461		117		173		171
Large commercial & industrial	48		229		418		1,056		806		99		151
Public authorities & electric railroads	22		23		20		47		25		11		11
Other(a)	718		202		297		524		157		168		190
Total electric revenues(b)	$	4,351	$	2,378	$	2,132	$	4,095	$	1,931	$	1,021	$	1,134
Natural gas revenues
Residential	$	—	$	335	$	448	$	77	$	—	$	77	$	—
Small commercial & industrial	—		125		77		35		—		35		—
Large commercial & industrial	—		—		128		9		—		9		—
Transportation	—		19		—		11		—		11		—
Other(c)	—		7		50		25		—		25		—
Total natural gas revenues(d)	$	—	$	486	$	703	$	157	$	—	$	157	$	—
Total revenues from contracts with customers	$	4,351	$	2,864	$	2,835	$	4,252	$	1,931	$	1,178	$	1,134
Other revenues
Revenues from alternative revenue programs	$	163	$	1	$	(40)	$	(33)	$	(15)	$	(3)	$	(14)
Other electric revenues(e)	22		11		11		4		3		1		—
Other natural gas revenues(e)	—		1		4		—		—		—		—

Total other revenues	$	185	$	13	$	(25)	$	(29)	$	(12)	$	(2)	$	(14)
Total revenues for reportable segments	$	4,536	$	2,877	$	2,810	$	4,223	$	1,919	$	1,176	$	1,120

__________

(a)Includes revenues from transmission revenue from PJM, wholesale electric revenue and mutual assistance revenue.

(b)Includes operating revenues from affiliates in 2023 and 2022 respectively of:

•$14 million, $14 million at ComEd

•$5 million, $5 million at PECO

•$4 million, $5 million at BGE

•$7 million, $9 million at PHI

•$5 million, $4 million at Pepco

•$5 million, $5 million at DPL

•$1 million, $2 million at ACE

(c)Includes revenues from off-system natural gas sales.

(d)Includes operating revenues from affiliates in 2023 and 2022 respectively of:

•$1 million, $1 million at PECO

•$2 million, $7 million at BGE

(e)Includes late payment charge revenues.

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 6 — Accounts Receivable

6. Accounts Receivable (All Registrants)

Allowance for Credit Losses on Accounts Receivable

The following tables present the rollforward of Allowance for Credit Losses on Customer Accounts Receivable.


	Three Months Ended September 30, 2023
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance at June 30, 2023	$	323	$	67	$	101	$	50	$	105	$	50	$	21	$	34
Plus: Current period provision for expected credit losses(a)	72		24		13		9		26		11		6		9
Less: Write-offs, net of recoveries(b)	54		15		19		7		13		5		4		4
Balance at September 30, 2023	$	341	$	76	$	95	$	52	$	118	$	56	$	23	$	39

	Three Months Ended September 30, 2022
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance at June 30, 2022	$	354	$	81	$	107	$	57	$	109	$	42	$	22	$	45
Plus: Current period provision for expected credit losses	38		10		12		2		14		6		1		7
Less: Write-offs, net of recoveries	51		17		16		5		12		4		3		5
Balance at September 30, 2022	$	341	$	74	$	103	$	54	$	111	$	44	$	20	$	47

	Nine Months Ended September 30, 2023
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance at December 31, 2022	$	327	$	59	$	105	$	54	$	109	$	47	$	21	$	41
Plus: Current period provision for expected credit losses(c)(d)	144		45		32		23		44		24		10		10
Less: Write-offs, net(e)(f)(g)of recoveries(b)	130		28		42		25		35		15		8		12
Balance at September 30, 2023	$	341	$	76	$	95	$	52	$	118	$	56	$	23	$	39

	Nine Months Ended September 30, 2022
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance at December 31, 2021	$	320	$	73	$	105	$	38	$	104	$	37	$	18	$	49
Plus: Current period provision for expected credit losses	141		31		33		30		47		23		8		16
Less: Write-offs, net of recoveries	120		30		35		14		40		16		6		18
Balance at September 30, 2022	$	341	$	74	$	103	$	54	$	111	$	44	$	20	$	47

__________

(a)For ComEd, BGE, PHI, Pepco, DPL and ACE, the change in current period provision for expected credit losses is primarily a result of increased receivable balances.

(b)Recoveries were not material to the Registrants.

(c)For ComEd and DPL, the change in current period provision for expected credit losses is primarily a result of increased receivable balances.

(d)For BGE and ACE, the change in current period provision for expected credit losses is primarily a result of changes in customer risk profile.

(e)For PECO and BGE, the change in write-offs is primarily a result of increased disconnection activities.

(f)For DPL, the change in write-offs is primarily attributable to unfavorable customer payment behavior.

(g)For ACE, the change in write-offs is primarily attributable to the termination of the moratorium in New Jersey, which beginning in March 2020, prevented customer disconnections for non-payment. Disconnection activities resumed in January 2022, driving the change in write-offs of aging accounts receivable for the nine months ended September 20, 2023.

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 6 — Accounts Receivable

The following tables present the rollforward of Allowance for Credit Losses on Other Accounts Receivable.


	Three Months Ended September 30, 2023
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance at June 30, 2023	$	87	$	18	$	8	$	8	$	53	$	31	$	9	$	13
Plus: Current period provision (benefit) for expected credit losses	6		3		2		3		(2)		(2)		—		—
Less: Write-offs, net of recoveries(a)	5		1		2		2		—		—		—		—
Balance at September 30, 2023	$	88	$	20	$	8	$	9	$	51	$	29	$	9	$	13

	Three Months Ended September 30, 2022
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance at June 30, 2022	$	81	$	18	$	10	$	11	$	42	$	20	$	8	$	14
Plus: Current period provision (benefit) for expected credit losses	8		2		2		2		2		2		(1)		1
Less: Write-offs, net of recoveries	5		2		1		1		1		—		—		1
Balance at September 30, 2022	$	84	$	18	$	11	$	12	$	43	$	22	$	7	$	14

	Nine Months Ended September 30, 2023
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance at December 31, 2022	$	82	$	17	$	9	$	10	$	46	$	25	$	7	$	14
Plus: Current period provision for expected credit losses	21		6		3		5		7		4		2		1
Less: Write-offs, net of recoveries(a)	15		3		4		6		2		—		—		2
Balance at September 30, 2023	$	88	$	20	$	8	$	9	$	51	$	29	$	9	$	13

	Nine Months Ended September 30, 2022
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance at December 31, 2021	$	72	$	17	$	7	$	9	$	39	$	16	$	8	$	15
Plus: Current period provision (benefit) for expected credit losses	24		5		6		6		7		6		(1)		2
Less: Write-offs, net of recoveries	12		4		2		3		3		—		—		3
Balance at September 30, 2022	$	84	$	18	$	11	$	12	$	43	$	22	$	7	$	14

__________

(a)Recoveries were not material to the Registrants.

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 6 — Accounts Receivable

Unbilled Customer Revenue

The following table provides additional information about unbilled customer revenues recorded in the Registrants' Consolidated Balance Sheets at September 30, 2023 and December 31, 2022.


	Unbilled customer revenues(a)
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
September 30, 2023	$	740	$	279	$	135	$	118	$	208	$	100	$	44	$	64
December 31, 2022	912		223		219		247		223		103		74		46

__________

(a)Unbilled customer revenues are classified in Customer accounts receivable, net in the Registrants' Consolidated Balance Sheets.

Other Purchases of Customer and Other Accounts Receivables

The Utility Registrants are required, under separate legislation and regulations in Illinois, Pennsylvania, Maryland, District of Columbia, Delaware, and New Jersey, to purchase certain receivables from alternative retail electric and, as applicable, natural gas suppliers that participate in the utilities' consolidated billing. ComEd, BGE, Pepco and DPL purchase receivables at a discount to recover primarily uncollectible accounts expense from the suppliers. PECO is required to purchase receivables at face value and is permitted to recover uncollectible accounts expense, including those from Third Party Suppliers, from customers through distribution rates. ACE purchases receivables at face value. ACE recovers all uncollectible accounts expense, including those from Third Party Suppliers, through the Societal Benefits Charge (SBC) rider, which includes uncollectible accounts expense as a component. The SBC is filed annually with the NJBPU. Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE do not record unbilled commodity receivables under the POR programs. Purchased billed receivables are classified in Other accounts receivable, net on Exelon’s, ComEd’s, PECO’s, BGE’s, PHI's, Pepco's, DPL's and ACE's Consolidated Balance Sheets. The following ~~tables provide information about~~table presents the total receivables purchased.


	Total receivables purchased
	Exelon			ComEd		PECO		BGE			PHI		Pepco		DPL		ACE
Nine months ended September 30, 2023	$	3,124		$	726	$	843	$	628		$	927	$	600	$	174	$	153
Nine months ended September 30, 2022	3,088		(a)	753		832		607		(a)	896		559		168		169

__________

(a)Includes $4 million of receivables purchased ~~receivables of those companies as of~~from Generation prior to the separation on February 1, 2022 for the nine months ended September 30, ~~2017 and December 31, 2016.~~2022.

Successor
As of September 30, 2017 Exelon ComEd PECO BGE PHI Pepco DPL ACE
Purchased receivables $ 312
$ 89
$ 68
$ 55
$ 100
$ 66
$ 10
$ 24
Allowance for uncollectible accounts^(a)
(33 ) (13 ) (5 ) (4 ) (11 ) (6 ) (1 ) (4 )
Purchased receivables, net $ 279
$ 76
$ 63
$ 51
$ 89
$ 60
$ 9
$ 20

Successor
As of December 31, 2016 Exelon ComEd PECO BGE PHI Pepco DPL ACE
Purchased receivables $ 313
$ 87
$ 72
$ 59
$ 95
$ 63
$ 10
$ 22
Allowance for uncollectible accounts^(a)
(37 ) (14 ) (6 ) (4 ) (13 ) (7 ) (2 ) (4 )
Purchased receivables, net $ 276
$ 73
$ 66
$ 55
$ 82
$ 56
$ 8
$ 18

~~_________~~


~~(a)~~	For ComEd, BGE, Pepco and DPL, reflects the incremental allowance for uncollectible accounts recorded, which is in addition to the purchase discount. For ComEd, the incremental uncollectible accounts expense is recovered through its Purchase of Receivables with Consolidated Billing tariff.

~~6. Impairment of Long-Lived Assets (Exelon and Generation)~~

~~Long-Lived Assets (Exelon and Generation)~~

Generation evaluates long-lived assets for recoverability whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. EGTP’s operating cash flows have been negatively impacted by certain market conditions and the seasonality of its cash flows. On May 2, 2017, EGTP entered into a consent agreement with its lenders to initiate an orderly sales process to sell the assets of its wholly owned subsidiaries, the proceeds from which will first be used to pay the administrative costs of the sale, the normal and ordinary costs of operating the plants and repayment of the secured debt of EGTP. As a result, as of June 30, 2017, and September 30, 2017, certain of EGTP’s assets and liabilities were classified as held for sale at their respective fair values less costs to sell and included in the other current assets and other current liabilities balances on Exelon’s and Generation’s Consolidated Balance Sheets. As of June 30, 2017, the fair value analysis was based on an income approach using significant unobservable inputs (Level 3) including revenue and generation forecasts, projected capital and maintenance expenditures and discount rates. As a result of this analysis, in the second quarter 2017, Exelon and Generation recorded a pre-tax impairment charge of $418 million within Operating and maintenance expense on their Consolidated Statements of Operations and Comprehensive Income. In the third quarter 2017, Exelon and Generation recorded an additional pre-tax impairment charge of $40 million within Operating and maintenance expense on their Consolidated Statements of Operations and Comprehensive Income to reflect an indicated decline in fair value based on new information obtained in the quarter through the orderly sales process. See Note 4 - Mergers, Acquisitions and Dispositions and Note 11 - Debt and Credit Agreements, for further information.

During the first quarter of 2016, significant changes in Generation’s intended use of the Upstream oil and gas assets, developments with nonrecourse debt held by its upstream subsidiary CEU Holdings, LLC (as described in Note

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 7 — Income Taxes

~~14 - Debt and Credit Agreements of~~7. Income Taxes (All Registrants)

Rate Reconciliation

The effective income tax rate from continuing operations varies from the Exelon 2016 Form 10-K) and continued declines in both production volumes and commodity prices suggested that the carrying value may be impaired. Generation concluded that the estimated undiscounted future cash flows and fair value of its Upstream properties were less than their carrying values. As a result, a pre-tax impairment charge of $119 million was recorded in March 2016 within Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. On June 16, 2016, Generation initiated the sales process of its Upstream business by executing a forbearance agreement with the lenders of the nonrecourse debt. An additional pre-tax impairment charge of $15 million was recorded in September 2016 within Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive IncomeU.S. federal statutory rate principally due to ~~further declines in fair value. In December 2016, Generation sold substantially all~~the following:


	Three Months Ended September 30, 2023(a)
	Exelon		ComEd		PECO(b)		BGE		PHI		Pepco		DPL		ACE
U.S. Federal statutory rate	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%
Increase (decrease) due to:
State income taxes, net of federal income tax benefit(c)	(2.7)		7.8		(1.2)		6.6		6.2		5.5		6.1		7.0
Plant basis differences	(4.4)		(0.4)		(15.6)		(0.2)		(1.5)		(2.4)		(0.9)		(0.5)
Excess deferred tax amortization	(6.4)		(5.3)		(2.4)		(5.4)		(8.0)		(9.2)		(10.0)		(3.1)
Amortization of investment tax credit, including deferred taxes on basis difference	(0.1)		(0.1)		—		(0.1)		(0.1)		—		(0.1)		(0.1)
Tax credits	(0.5)		(1.2)		—		(2.0)		(0.5)		(0.6)		(0.4)		(0.3)
Other	1.8		0.2		0.2		(0.3)		0.3		0.6		—		0.5
Effective income tax rate	8.7	%	22.0	%	2.0	%	19.6	%	17.4	%	14.9	%	15.7	%	24.5	%


	Three Months Ended September 30, 2022(a)
	Exelon		ComEd		PECO(d)		BGE(d)		PHI(d)		Pepco(d)		DPL(d)		ACE(d)
U.S. Federal statutory rate	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%	21.0	%
Increase (decrease) due to:
State income taxes, net of federal income tax benefit	9.0		8.0		20.7		6.8		1.4		(2.7)		6.5		7.0
Plant basis differences	(5.3)		(0.4)		(14.2)		(2.6)		(1.7)		(2.3)		(0.8)		(1.0)
Excess deferred tax amortization	(11.6)		(5.6)		(3.2)		(47.3)		(19.3)		(14.6)		(21.7)		(25.5)
Amortization of investment tax credit, including deferred taxes on basis difference	(0.1)		(0.1)		—		(0.2)		(0.1)		—		(0.2)		(0.2)
Tax credits	(0.6)		(0.4)		—		(1.9)		(0.9)		(0.8)		(1.3)		(0.7)
Other	(0.4)		(0.1)		0.3		(2.7)		0.3		0.1		0.2		0.5
Effective income tax rate	12.0	%	22.4	%	24.6	%	(26.9)	%	0.7	%	0.7	%	3.7	%	1.1	%

__________

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

(b)For PECO, the lower effective tax rate is primarily related to plant basis differences attributable to tax repair deductions.

(c)For Exelon, the lower state income taxes, net of ~~the Upstream Assets. See Note 4 - Mergers, Acquisitions and Dispositions of the Exelon 2016 Form 10-K for further information.~~

~~In the second quarter of 2016, updates~~federal income tax expense, is primarily due to the ~~Company's~~ long-term ~~view~~marginal state income tax rate change of ~~energy and capacity prices suggested that~~$54 million.

(d)For PECO, the ~~carrying value~~higher effective tax rate is related to a one-time state income expense, net of ~~a group~~federal income tax benefit, of ~~merchant wind assets, located in West Texas, may be impaired. Upon review,~~$38 million attributable to the estimated undiscounted future cash flows and fair value of the group were less than their carrying value. The fair value analysis was based on the income approach using significant unobservable inputs (Level 3) including revenue and generation forecasts, projected capital and maintenance expenditures and discount rates. As a result of the fair value analysis, long-lived assets held and used with a carrying amount of approximately $60 million were written down to their fair value of $24 million and a pre-tax impairment charge of $36 million was recorded during the second quarter in Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

~~Also~~change in the ~~second quarter of 2016, updates~~Pennsylvania corporate income tax rate partially offset by plant basis differences attributable to tax repair deductions. For BGE, PHI, Pepco, DPL, and ACE, the lower effective tax rate is primarily related to the ~~Company's long-term view, as described above, in conjunction with the previous decision~~acceleration of certain income tax benefits due to ~~early retire the Clinton~~distribution and Quad Cities nuclear facilities in Illinois suggested that the carrying value of our Midwest asset group may be impaired. Generation completed a comprehensive review of the estimated undiscounted future cash flows of the Midwest asset group and no impairment charge was required.transmission rate case settlements.

~~Like-Kind Exchange Transaction (Exelon)~~

In June 2000, UII, LLC (formerly Unicom Investments, Inc.) (UII), a wholly owned subsidiary of Exelon Corporation, entered into transactions pursuant to which UII invested in coal-fired generating station leases (Headleases) with the Municipal Electric Authority of Georgia (MEAG). The generating stations were leased back to MEAG as part of the transactions (Leases).

On March 31, 2016, UII and MEAG finalized an agreement to terminate the MEAG Headleases, the MEAG Leases, and other related agreements prior to their expiration dates. As a result of the lease termination, UII received an early termination payment of $360 million from MEAG and wrote-off the $356 million net investment in the MEAG Headleases and the Leases. The transaction resulted in a pre-tax gain of $4 million which is reflected in Operating and maintenance expense in Exelon's Consolidated Statements of Operations and Comprehensive Income. See Note 12—Income Taxes for additional information.

~~7. Early Nuclear Plant Retirements (Exelon and Generation)~~

Exelon and Generation continue to evaluate the current and expected economic value of each of Generation’s nuclear plants. Factors that will continue to affect the economic value of Generation’s nuclear plants include, but are not limited to: market power prices, results of capacity auctions, potential legislative and regulatory solutions to ensure nuclear plants are fairly compensated for their carbon-free emissions, 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 nuclear plant, and the resulting financial statement impacts, may be affected by a number of factors, 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 decommissioning trust fund requirements, 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, where applicable, and just prior to its next scheduled nuclear refueling outage.

In 2015 and 2016, Generation identified the Clinton, Quad Cities, Ginna, Nine Mile Point, and Three Mile Island (TMI) nuclear plants as having the greatest risk of early retirement based on economic valuation and other factors. PSEG has also recently made public similar financial challenges facing its New Jersey nuclear plants including Salem,

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 7 — Income Taxes


	Nine Months Ended September 30, 2023(a)
	Exelon	ComEd	PECO(b)	BGE	PHI	Pepco	DPL	ACE
U.S. Federal statutory rate	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%
Increase (decrease) due to:
State income taxes, net of federal income tax benefit(c)	2.8	7.8	(1.3)	6.5	6.1	5.5	6.2	6.9
Plant basis differences	(4.3)	(0.4)	(15.5)	(0.5)	(1.6)	(2.5)	(1.0)	(0.5)
Excess deferred tax amortization	(6.6)	(5.5)	(2.4)	(5.4)	(7.7)	(9.2)	(9.4)	(2.6)
Amortization of investment tax credit, including deferred taxes on basis difference	(0.1)	(0.1)	—	(0.1)	(0.1)	—	(0.1)	(0.1)
Tax credits	(0.5)	(0.7)	—	(0.7)	(0.6)	(0.7)	(0.4)	(0.3)
Other	1.5	0.1	0.1	0.2	0.3	0.6	—	0.3
Effective income tax rate	13.8%	22.2%	1.9%	21.0%	17.4%	14.7%	16.3%	24.7%


	Nine Months Ended September 30, 2022(a)
	Exelon	ComEd	PECO(d)	BGE(d)	PHI(d)	Pepco(d)	DPL(d)	ACE(d)
U.S. Federal statutory rate	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%
Increase (decrease) due to:
State income taxes, net of federal income tax benefit(e)	9.5	7.9	6.6	2.8	2.0	(3.2)	6.5	6.9
Plant basis differences	(4.2)	(0.5)	(12.2)	(1.1)	(1.7)	(2.4)	(0.7)	(1.1)
Excess deferred tax amortization	(11.3)	(5.7)	(3.2)	(20.7)	(18.8)	(15.4)	(20.4)	(24.7)
Amortization of investment tax credit, including deferred taxes on basis difference	(0.1)	(0.1)	—	(0.1)	(0.1)	—	(0.2)	(0.2)
Tax credits(f)	0.3	(0.3)	—	(0.7)	(0.7)	(0.6)	(0.7)	(0.6)
Other(g)	2.8	—	0.2	(0.1)	0.2	(0.2)	0.3	0.2
Effective income tax rate	18.0%	22.3%	12.4%	1.1%	1.9%	(0.8)%	5.8%	1.5%

__________

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

(b)For PECO, the lower effective tax rate is primarily related to plant basis differences attributable to tax repair deductions.

(c)For Exelon, the lower state income taxes, net of ~~which Generation owns~~federal income tax expense, is primarily due to the long-term marginal state income tax rate change of $54 million.

(d)For PECO, the lower effective tax rate is primarily related to plant basis differences attributable to tax repair deductions partially offset by higher state income taxes, net of federal income tax benefit, related to a ~~42.59% ownership interest. As previously disclosed, Exelon and Generation have committed~~one-time expense of $38 million attributable to ~~cease operation of~~ the ~~Oyster Creek nuclear plant by the end of 2019.~~

~~The TMI nuclear plant did not clear~~change in the ~~May 2017 PJM capacity auction for~~Pennsylvania corporate income tax rate. For BGE, PHI, Pepco, DPL and ACE, the ~~2020-2021 planning year~~lower effective tax rate is primarily related to the acceleration of certain income tax benefits due to distribution and ~~will not receive capacity revenue for that period,~~transmission rate case settlements.

(e)For Exelon, the ~~third consecutive year that TMI failed~~higher state income taxes, net of federal income tax benefit, is primarily due to ~~clear~~ the ~~PJM base residual capacity auction. The plant is currently committed to operate through May 2019.~~

~~Based on these capacity auction results, prolonged periods~~long-term marginal state income tax rate change of ~~low wholesale power prices,~~approximately $67 million and the absence of federal or state policies that place a value on nuclear energy for its ability to produce electricity without air pollution, Exelon announced that Generation will permanently cease generation operations at TMI on or about September 30, 2019. The current NRC license for TMI expires in 2034. Generation is proceeding with the market and regulatory notifications that must be made to shut down the plant, including filingrecognition of a ~~deactivation notice~~valuation allowance of approximately $40 million against the net deferred tax asset position for certain standalone state filing jurisdictions, partially offset by a one-time impact associated with ~~PJM on May 30, 2017~~a state tax benefit of $43 million and ~~notification~~indemnification adjustments pursuant to the ~~NRC on June 20, 2017. PJM has subsequently notified Generation that it has not identified any reliability issues and has approved the deactivation~~Tax Matters Agreement of ~~TMI as proposed.~~

~~In 2017,~~$4 million as a result of the ~~plant retirement decision~~separation. For PECO, the higher state income taxes, net of ~~TMI, Exelon and Generation recognized~~federal income tax benefit, related to a one-time ~~charges in Operating and maintenance~~ expense of ~~$76~~$38 million attributable to the change in the Pennsylvania corporate income tax rate.

(f)For Exelon, reflects the income tax expense related to ~~materials~~the write-off of federal tax credits subject to recapture of approximately $15 million as a result of the separation.

(g)For Exelon, primarily reflects the nondeductible transaction costs of approximately $19 million arising as part of the separation and ~~supplies inventory reserve~~indemnification adjustments employee-related costs and construction work-in-progress (CWIP) impairments, among other items. In addition to these one-time charges, there will be ongoing annual incremental non-cash charges to earnings stemming from shortening the expected economic useful life of TMI primarily related to accelerated depreciation of plant assets (including any ARC), accelerated amortization of nuclear fuel, and additional ARO accretion expense associated with the changes in decommissioning timing and cost assumptions. During the three and nine months ended September 30, 2017, both Exelon’s and Generation’s results include an incremental $112 million and $149 million, respectively, of pre-tax expense for these items. Please refer to Note 13 — Nuclear Decommissioning for additional detail on changespursuant to the ~~nuclear decommissioning ARO balances resulting from the early retirement~~Tax Matters Agreement of ~~TMI.~~$40 million.

Income statement expense (pre-tax) Q3 2017 YTD 2017
Depreciation and amortization
Accelerated depreciation^(a)
$ 106
$ 141
Accelerated nuclear fuel amortization 6
8
Total $ 112
$ 149

~~_________~~


~~(a)~~	~~Reflects incremental accelerated depreciation of plant assets, including any ARC.~~

Based on insufficient capacity auction results and the lack of progress on Illinois energy legislation, on June 2, 2016, Generation announced a decision to shut down the Clinton and Quad Cities nuclear plants on June 1, 2017 and June 1, 2018, respectively. With the passage of the Illinois ZES on December 7, 2016, and subject to prevailing over any related administrative or legal challenges, Generation reversed this decision and revised the expected economic useful lives for both facilities; 2027 for Clinton and 2032 for Quad Cities. Refer to Note 5 - Regulatory Matters for additional discussion on the Illinois ZES.

Exelon's and Generation's 2016 results included a net incremental $714 million of total pre-tax expense associated with the initial early retirement decision for Clinton and Quad Cities, as summarized in the table below.

Income statement expense (pre-tax) Q2 2016 Q3 2016 Q4 2016 YTD 2016
Depreciation and amortization
Accelerated depreciation^(a)
$ 115
$ 344
$ 253
$ 712
Accelerated Nuclear Fuel amortization 9
28
23
60
Operating and maintenance
One time charges^(b)
141
5
(120 ) 26
ARO accretion, net of contractual offset^(c)
—
2
—
2
Contractual offset for ARC depreciation^(c)
(14 ) (41 ) (31 ) (86 )
Total $ 251
$ 338
$ 125
$ 714

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 7 — Income Taxes

~~_________~~Unrecognized Tax Benefits


~~(a)~~	~~Reflects incremental accelerated depreciation of plant assets, including any ARC, for the period June 2, 2016, through December 6, 2016.~~


~~(b)~~	~~Primarily includes materials and supplies inventory reserve adjustments, employee related costs and CWIP impairments.~~

~~(c)~~

For Quad Cities based on the regulatory agreement with the Illinois Commerce Commission, decommissioning-related activities are offset within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. The offset results in an equal adjustment to the noncurrent payables to ComEd at Generation and an adjustment to the regulatory liabilities at ComEd. Likewise, ComEd has recorded an equal noncurrent affiliate receivable from Generation and corresponding regulatory liability.

~~In New York,~~Exelon, PHI and ACE have the ~~Ginna, Nine Mile Point,~~following unrecognized tax benefits at September 30, 2023 and ~~Generation’s recently acquired FitzPatrick nuclear plant also faced significant economic challenges~~December 31, 2022. ComEd's, PECO's, BGE's, Pepco's, and ~~risk~~DPL's amounts are not material.


	Exelon(a)		PHI		ACE
September 30, 2023	$	138	$	56	$	16
December 31, 2022	148		59		17

__________

(a)At September 30, 2023 and December 31, 2022, Exelon reflected a receivable of ~~retirement before~~$50 million in Other deferred debits and other assets in the ~~end~~Consolidated Balance Sheet for Constellation’s share of ~~each unit’s respective operating license period (2029~~unrecognized tax benefits for Ginna and Nine Mile Point Unit 1, 2046 for Nine Mile Point Unit 2, and 2034 for FitzPatrick). On August 1, 2016, the NYPSC issued an order adopting the New York CES that, subject to prevailing over any administrative or legal challenges, would allow Ginna, Nine Mile Point, and FitzPatrick to continue to operate at least through the life of the program (March 31, 2029). The assumed useful life for depreciation purposes for each facility is through the end of their current operating licenses. Ginna most recently operated under an RSSA which expired March 31, 2017 and has filed the required notice with the NYPSC of its intent to continue operating beyond the expiry of the RSSA. Refer to Note 4 - Mergers, Acquisitions and Dispositions for additional information on Generation’s acquisition of FitzPatrick and Note 5 - Regulatory Matters for additional discussion on the Ginna RSSA and the New York CES.

Assuming the successful implementation of the Illinois ZES and the New York CES and the continued effectiveness of these programs, Generation and CENG, through its ownership of Ginna and Nine Mile Point, no longer consider Clinton, Quad Cities, Ginna or Nine Mile Point to be at heightened risk for early retirement. However,periods prior to the ~~extent either~~separation.

Reasonably possible the ~~Illinois ZES~~total amount of unrecognized tax benefits could significantly increase or decrease within 12 months after the New York CES programs do not operate as expected over their full terms, each of these plants (and now including the newly acquired FitzPatrick) could again be at heightened risk for early retirement, which could have a material impact on Exelon’s and Generation’s future results of operations, cash flows and financial position.reporting date.

~~8. Intangible Assets (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 and paid the District of Columbia $25 million. The specific sponsorship rights were to be determined over time through future negotiations. As of September 30, ~~2017, PHI~~2023, ACE has ~~recorded~~$14 million of unrecognized state tax benefits that could significantly decrease within the ~~sponsorship agreement as a finite-lived intangible asset~~12 months after the reporting date based on the outcome of pending court cases involving other taxpayers. The unrecognized tax benefit, if recognized, may be included in future base rates and that portion would have no impact to the effective tax rate.

Other Tax Matters

Tax Matters Agreement (Exelon)

In connection with ~~a $25 million carrying amount. Because no specific sponsorship agreements have yet been~~the separation, Exelon entered into a TMA with Constellation. The TMA governs the ~~District~~respective rights, responsibilities, and obligations between Exelon and Constellation after the separation with respect to tax liabilities, refunds and attributes for open tax years that Constellation was part of ~~Columbia, amortization~~Exelon’s consolidated group for U.S. federal, state, and local tax purposes.

Indemnification for Taxes. As a former subsidiary of Exelon, Constellation has joint and several liability with Exelon to the ~~finite-lived intangible asset has yet~~IRS and certain state jurisdictions relating to ~~commence. In~~ the ~~third quarter~~taxable periods prior to the separation. The TMA specifies that Constellation is liable for their share of ~~2017, PHI continued discussions~~taxes required to be paid by Exelon with respect to taxable periods prior to the ~~District of Columbia regarding~~separation to the ~~nature and timing of available sponsorship opportunities, and based on these ongoing discussions, will continue to evaluate any potential impact on~~extent Constellation would have been responsible for such taxes under the ~~valuation of the sponsorship intangible asset.~~

~~9. Fair Value of Financial Assets and Liabilities (All Registrants)~~

~~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) asexisting Exelon tax sharing agreement. As of September 30, ~~2017~~2023, Exelon recorded a payable of $15 million in Other current liabilities that is due to Constellation.

Tax Refunds. The TMA specifies that Constellation is entitled to their share of any future tax refunds claimed by Exelon with respect to taxable periods prior to the separation to the extent that Constellation would have received such tax refunds under the existing Exelon tax sharing agreement.

Tax Attributes. At the date of separation certain tax attributes, primarily pre-closing tax credit carryforwards, that were generated by Constellation were required by law to be allocated to Exelon. The TMA provides that Exelon will reimburse Constellation when those allocated tax credit carryforwards are utilized. As of September 30, 2023, Exelon recorded a payable of $22 million and ~~December 31, 2016:~~$509 million in Other current liabilities and Other deferred credits and other liabilities, respectively, in the Consolidated Balance Sheet for tax attribute carryforwards that are expected to be utilized and reimbursed to Constellation.

~~Exelon~~Corporate Alternative Minimum Tax (All Registrants)

On August 16, 2022, the IRA was signed into law and implements a new corporate alternative minimum tax (CAMT) that imposes a 15.0% tax on modified GAAP net income. Corporations are entitled to a tax credit (minimum tax credit) to the extent the CAMT liability exceeds the regular tax liability. This amount can be carried forward indefinitely and used in future years when regular tax exceeds the CAMT.

September 30, 2017

Carrying
Amount
Fair Value
Level 1 Level 2 Level 3 Total
Short-term liabilities $ 710
$ —
$ 710
$ —
$ 710
Long-term debt (including amounts due within one year)^(a)
34,865
—
34,686
1,949
36,635
Long-term debt to financing trusts^(b)
389
—
—
423
423
SNF obligation 1,142
—
857
—
857

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 7 — Income Taxes

Beginning in 2023, based on the existing statue, Exelon and each of the Utility Registrants will be subject to and will report the CAMT on a separate Registrant basis in the Consolidated Statements of Operations and Comprehensive Income and the Consolidated Balance Sheets. The deferred tax asset related to the minimum tax credit carryforward will be realized to the extent Exelon’s consolidated deferred tax liabilities exceed the minimum tax credit carryforward. Exelon’s deferred tax liabilities are expected to exceed the minimum tax credit carryforward for the foreseeable future and thus no valuation allowance is required. Exelon is continuing to assess the financial statement impacts of the IRA and will update estimates based on future guidance issued by the U.S. Treasury.

Long-Term Marginal State Income Tax Rate (Exelon)

In the third quarter of 2023, Exelon updated its marginal state income tax rates for changes in state apportionment. The changes in marginal rates in the third quarter of 2023 resulted in a decrease of $54 million to the deferred tax liability at Exelon, and a corresponding adjustment to income tax expense, net of federal taxes.

Allocation of Tax Benefits (All Registrants)

The Utility Registrants are party to an agreement with 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 Utility Registrants. That allocation is treated as a contribution to capital from Exelon to the party receiving the benefit.

The following table presents the allocation of tax benefits from Exelon under the Tax Sharing Agreement, for the three and nine months ended September 30, 2023, and 2022.


	ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
September 30, 2023	$	13	$	19	$	—	$	10	$	4	$	—	$	2
September 30, 2022	$	1	$	47	$	—	$	28	23		$	3	2

8. Retirement Benefits (All Registrants)

Defined Benefit Pension and OPEB

The majority of the 2023 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 5.53%. The majority of the 2023 OPEB cost is calculated using an expected long-term rate of return on plan assets of 6.50% for funded plans and a discount rate of 5.51%.

During the first quarter of 2023, Exelon received an updated valuation of its pension and OPEB to reflect actual census data as of January 1, 2023. This valuation resulted in an increase to the pension obligation of $27 million and an increase to the OPEB obligation of $2 million. Additionally, AOCI increased by $10 million (after-tax) and regulatory assets and liabilities increased by $18 million and $1 million, respectively.

A portion of the net periodic benefit cost for all plans is capitalized within the Consolidated Balance Sheets. The following table presents the components of Exelon's net periodic benefit costs, prior to capitalization, for the three and nine months ended September 30, 2023 and 2022.

December 31, 2016

Carrying
Amount
Fair Value
Level 1 Level 2 Level 3 Total
Short-term liabilities $ 1,267
$ —
$ 1,267
$ —
$ 1,267
Long-term debt (including amounts due within one year)^(a)
34,005
1,113
31,741
1,959
34,813
Long-term debt to financing trusts^(b)
641
—
—
667
667
SNF obligation 1,024
—
732
—
732

~~Generation~~

September 30, 2017

Carrying
Amount
Fair Value
Level 1 Level 2 Level 3 Total
Short-term liabilities $ 92
$ —
$ 92
$ —
$ 92
Long-term debt (including amounts due within one year)^(a)
9,528
—
7,915
1,652
9,567
SNF obligation 1,142
—
857
—
857

December 31, 2016

Carrying
Amount
Fair Value
Level 1 Level 2 Level 3 Total
Short-term liabilities $ 699
$ —
$ 699
$ —
$ 699
Long-term debt (including amounts due within one year)^(a)
9,241
—
7,482
1,670
9,152
SNF obligation 1,024
—
732
—
732

~~ComEd~~

September 30, 2017

Carrying
Amount
Fair Value
Level 1 Level 2 Level 3 Total
Long-term debt (including amounts due within one year)^(a)
$ 7,600
$ —
$ 8,353
$ —
$ 8,353
Long-term debt to financing trusts^(b)
205
—
—
226
226

December 31, 2016

Carrying
Amount
Fair Value
Level 1 Level 2 Level 3 Total
Long-term debt (including amounts due within one year)^(a)
$ 7,033
$ —
$ 7,585
$ —
$ 7,585
Long-term debt to financing trusts^(b)
205
—
—
215
215

~~PECO~~

September 30, 2017

Carrying
Amount
Fair Value
Level 1 Level 2 Level 3 Total
Long-term debt (including amounts due within one year)^(a)
$ 2,902
$ —
$ 3,181
$ —
$ 3,181
Long-term debt to financing trusts 184
—
—
197
197

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 8 — Retirement Benefits


	Pension Benefits				OPEB
	Three Months Ended September 30,				Three Months Ended September 30,
	2023		2022		2023		2022
Components of net periodic benefit cost
Service cost	$	39	$	58	$	6	$	10
Interest cost	145		110		25		19
Expected return on assets	(189)		(205)		(21)		(25)
Amortization of:
Prior service cost (credit)	1		1		(2)		(5)
Actuarial loss	41		73		—		4

Settlement charges	18		—		—		—
Net periodic benefit cost	$	55	$	37	$	8	$	3

	Pension Benefits				OPEB
	Nine Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Components of net periodic benefit cost
Service cost	$	116	$	177	$	18	$	30
Interest cost	434		330		76		57
Expected return on assets	(566)		(619)		(63)		(75)
Amortization of:
Prior service cost (credit)	2		3		(7)		(15)
Actuarial loss (gain)	125		222		(1)		12

Settlement charges	18		—		—		—
Net periodic benefit cost	$	129	$	113	$	23	$	9

The amounts below represent the Registrants' allocated pension and OPEB costs. 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 Utility Registrants, which apply multi-employer accounting, the service cost and non-service cost components are included in Operating and maintenance expense and Property, plant, and equipment, net in their consolidated financial statements.

December 31, 2016

Carrying
Amount
Fair Value
Level 1 Level 2 Level 3 Total
Long-term debt (including amounts due within one year)^(a)
$ 2,580
$ —
$ 2,794
$ —
$ 2,794
Long-term debt to financing trusts 184
—
—
192
192

~~BGE~~

September 30, 2017

Carrying
Amount
Fair Value
Level 1 Level 2 Level 3 Total
Long-term debt (including amounts due within one year)^(a)
$ 2,577
$ —
$ 2,817
$ —
$ 2,817

December 31, 2016

Carrying
Amount
Fair Value
Level 1 Level 2 Level 3 Total
Short-term liabilities $ 45
$ —
$ 45
$ —
$ 45
Long-term debt (including amounts due within one year)^(a)
2,322
—
2,467
—
2,467
Long-term debt to financing trusts^(b)
252
—
—
260
260

~~PHI (Successor)~~

September 30, 2017
Carrying Amount Fair Value
Level 1 Level 2 Level 3 Total
Short-term liabilities $ 118
$ —
$ 118
$ —
$ 118
Long-term debt (including amounts due within one year)^(a)
5,930
—
5,729
297
6,026

December 31, 2016
Carrying Amount Fair Value
Level 1 Level 2 Level 3 Total
Short-term liabilities $ 522
$ —
$ 522
$ —
$ 522
Long-term debt (including amounts due within one year)^(a)
5,898
—
5,520
289
5,809

~~Pepco~~

September 30, 2017
Carrying Amount Fair Value
Level 1 Level 2 Level 3 Total
Long-term debt (including amounts due within one year)^(a)
$ 2,546
$ —
$ 3,087
$ 9
$ 3,096

December 31, 2016
Carrying Amount Fair Value
Level 1 Level 2 Level 3 Total
Short-term liabilities $ 23
$ —
$ 23
$ —
$ 23
Long-term debt (including amounts due within one year)^(a)
2,349
—
2,788
8
2,796

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

~~DPL~~

Note 8 — Retirement Benefits

September 30, 2017
Carrying Amount Fair Value
Level 1 Level 2 Level 3 Total
Short-term liabilities $ 54
$ —
$ 54
$ —
$ 54
Long-term debt (including amounts due within one year)^(a)
1,326
—
1,407
—
1,407


	Three Months Ended September 30,				Nine Months Ended September 30,
Pension and OPEB Costs (Benefit)	2023		2022		2023		2022
Exelon	$	63	$	40	$	152	$	122
ComEd	6		15		19		45
PECO	(3)		(2)		(10)		(6)
BGE	14		11		42		33
PHI	25		13		74		39
Pepco	9		2		26		6
DPL	4		1		13		3
ACE	3		3		10		9

Defined Contribution Savings Plan

December 31, 2016
Carrying Amount Fair Value
Level 1 Level 2 Level 3 Total
Long-term debt (including amounts due within one year)^(a)
$ 1,340
$ —
$ 1,383
$ —
$ 1,383

~~ACE~~

September 30, 2017
Carrying Amount Fair Value
Level 1 Level 2 Level 3 Total
Short-term liabilities $ 65
$ —
$ 65
$ —
$ 65
Long-term debt (including amounts due within one year)^(a)
1,130
—
969
288
1,257

December 31, 2016
Carrying Amount Fair Value
Level 1 Level 2 Level 3 Total
Long-term debt (including amounts due within one year)^(a)
$ 1,155
$ —
$ 1,007
$ 280
$ 1,287

~~_________~~

~~(a)~~

~~Includes unamortized debt issuance costs which are not fair valued of $196 million, $51 million, $53 million, $17 million, $17 million, $6 million~~, $32 million, $11 million, and $5 million for Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, as of September 30, 2017. Includes unamortized debt issuance costs which are not fair valued of $200 million, $64 million, $46 million, $15 million, $15 million, $2 million, $30 million, $11 million, and $6 million for Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, as of December 31, 2016.


~~(b)~~	Includes unamortized debt issuance costs which are not fair valued of $1 million and $1 million for Exelon and ComEd, respectively, as of September 30, 2017. Includes unamortized debt issuance costs which are not fair valued of $7 million, $1 million, and $6 million for Exelon, ComEd and BGE, respectively, as of December 31, 2016.

~~Short-Term Liabilities.~~ The ~~short-term liabilities included~~Registrants participate in ~~the tables above are comprised of dividends payable (included in other current liabilities) (Level 1) and short-term borrowings (Level 2).~~a 401(k) defined contribution savings plan that is sponsored by Exelon. The ~~Registrants’ carrying amounts~~plan is qualified under applicable sections of the ~~short-term liabilities are representative~~IRC and allows employees to contribute a portion of ~~fair value because of the short-term nature of these instruments.~~

~~Long-Term Debt.~~ The fair value amounts of Exelon’s taxable debt securities (Level 2) and private placement taxable debt securities (Level 3) are determined by a valuation model that is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. In order to incorporate the credit risk of the Registrants into the discount rates, Exelon obtains pricing (i.e., U.S. Treasury rate plus credit spread) based on trades of existing Exelon debt securities as well as debt securities of other issuers in the utility sector with similar credit ratings in both the primary and secondary market, across the Registrants’ debt maturity spectrum. The credit spreads of various tenors obtained from this information are added to the appropriate benchmark U.S. Treasury rates in order to determine the current market yields for the various tenors. 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 their pre-tax and/or note. Due to low trading volume of private placement debt, qualitative factors such as market conditions, low volume of investors and investor demand, this debt is classified as Level 3. The fair value of Exelon's equity units (Level 1) are valued based on publicly traded securities issued by Exelon.

The fair value of Generation’s and Pepco's non-government-backed fixed rate nonrecourse debt (Level 3) 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

~~100~~

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~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

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

cash flows or off-taker credit, and other circumstances related to the project (e.g., political and regulatory environment). The fair value of Generation’s government-backed fixed rate project financing debt (Level 3) is largely based on a discounted cash flow methodology that is similar to the taxable debt securities methodology described above. 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 Treasury rate as well as a current market curve derived from government-backed securities. Variable rate financing debt resets on a monthly or quarterly basis and the carrying value approximates fair value (Level 2). When trading data is available on variable rate financing debt, the fair value is based on market and quoted prices for its own and other nonrecourse debt with similar risk profiles (Level 2). Generation, Pepco, DPL and ACE also have tax-exempt debt (Level 2). Due to low trading volume in this market, qualitative factors, such as market conditions, investor demand, and circumstances related to the issuer (e.g., conduit issuer political and regulatory environment), may be incorporated into the credit spreads that are used to obtain the fair value as described above. Variable rate tax-exempt debt (Level 2) resets on a regular basis and the carrying value approximates fair value.

~~SNF Obligation~~. The carrying amount of Generation’s SNF obligation (Level 2) is derived from a contract with the DOE to provide for disposal of SNF from Generation’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 Treasury rate. The compounded obligation amount is discounted back to present value using Generation’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. The carrying amount also includes $112 million as of September 30, 2017 for the one-time fee obligation associated with closing of the FitzPatrick acquisition on March 31, 2017. The fair value was determined using a similar methodology, however the New York Power Authority's (NYPA) discount rate is used in place of Generation's given the contractual right to reimbursement from NYPA for the obligation; see Note 4 - Mergers, Acquisitions and Dispositions for additional information on Generation's acquisition of FitzPatrick.

~~Long-Term Debt to Financing Trusts~~. Exelon’s long-term debt to financing trusts is valued based on publicly traded securities issued by the financing trusts. Due to low trading volume of these securities, qualitative factors, such as market conditions, investor demand, and circumstances related to each issue, this debt is classified as Level 3.

~~Recurring Fair Value Measurements~~

~~Exelon records the fair value of assets and liabilities~~after-tax income in accordance with the hierarchy established by the authoritative guidance for fair value measurements. 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~~specified guidelines. All Registrants ~~have the ability to liquidate as~~match a percentage of the ~~reporting date.~~

~~Level 2 — inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data.~~

~~Level 3 — unobservable inputs, such as internally developed pricing models or third-party valuations for the asset or liability due~~employee contributions up to ~~little or no market activity for the asset or liability.~~

Transfers in and out of levels are recognized as of the end of the reporting period when the transfer occurred. Given derivatives categorized within Level 1 are valued using exchange-based quoted prices within observable periods, transfers between Level 2 and Level 1 were not material. Additionally, there were no material transfers between Level 1 and Level 2 during the nine months ended September 30, 2017 for cash equivalents, nuclear decommissioning trust fund investments, pledged assets for Zion Station decommissioning, Rabbi trust investments, and deferred compensation obligations. For derivative contracts, transfers into Level 2 from Level 3 generally occur when the contract tenor becomes more observable and due to changes in market liquidity or assumptions for certain ~~commodity contracts.~~

~~101~~

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~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

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

~~Generation and Exelon~~

In accordance with the applicable guidance on fair value measurement, certain investments that are measured at fair value using the NAV per share as a practical expedient are no longer classified within the fair value hierarchy and are included under "Not subject to leveling" in the table below.

limits. The following ~~tables present assets~~table presents the employer contributions and ~~liabilities measured and recorded at fair value on Exelon's and Generation’s Consolidated Balance Sheets on a recurring basis and their level within~~employer matching contributions to the ~~fair value hierarchy as of September 30, 2017 and December 31, 2016:~~

Generation Exelon
As of September 30, 2017 Level 1 Level 2 Level 3 Not subject to leveling Total Level 1 Level 2 Level 3 Not subject to leveling Total
Assets
Cash equivalents^(a)
$ 80
$ —
$ —
$ —
$ 80
$ 944
$ —
$ —
$ —
$ 944
NDT fund investments

Cash equivalents^(b)
149
86
—
—
235
149
86
—
—
235
Equities 3,935
840
—

2,088
6,863
3,935
840
—

2,088
6,863
Fixed income
Corporate debt —
1,651
255
—
1,906
—
1,651
255
—
1,906
U.S. Treasury and agencies 1,951
28
—
—
1,979
1,951
28
—
—
1,979
Foreign governments —
70
—
—
70
—
70
—
—
70
State and municipal debt —
246
—
—
246
—
246
—
—
246
Other^(c)
—
46
—
509
555
—
46
—
509
555
Fixed income subtotal 1,951

2,041

255
509

4,756

1,951

2,041

255
509

4,756
Middle market lending —
—
416
87
503
—
—
416
87
503
Private equity —
—
—
212
212
—
—
—
212
212
Real estate —
—
—
449
449
—
—
—
449
449
NDT fund investments subtotal^(d)
6,035

2,967

671
3,345

13,018

6,035

2,967

671
3,345

13,018
Pledged assets for Zion Station decommissioning
Cash equivalents 15
—
—
—
15
15
—
—
—
15

~~102~~

~~Table of Contents~~

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

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

Generation Exelon
As of September 30, 2017 Level 1 Level 2 Level 3 Not subject to leveling Total Level 1 Level 2 Level 3 Not subject to leveling Total
Middle market lending —
—
17
25
42
—
—
17
25
42
Pledged assets for Zion Station
decommissioning subtotal^(e)
15

—

17
25

57

15

—

17
25

57
Rabbi trust investments

Cash equivalents 5
—
—
—
5
77
—
—
—
77
Mutual funds 22
—
—
—
22
56
—
—
—
56
Fixed income —
—
—
—
—
—
13
—
—
13
Life insurance contracts —
21
—
—
21
—
68
21
—
89
Rabbi trust investments subtotal 27

21

—
—

48

133

81

21
—

235
Commodity derivative assets
Economic hedges 487
2,076
1,628
—
4,191
487
2,076
1,628
—
4,191
Proprietary trading 2
41
42
—
85
2
41
42
—
85
Effect of netting and allocation of collateral^{(f) (g)}
(501 ) (1,828 ) (837 ) —
(3,166 ) (501 ) (1,828 ) (837 ) —
(3,166 )
Commodity derivative assets subtotal (12 )
289

833
—

1,110

(12 )
289

833
—

1,110
Interest rate and foreign currency derivative assets
Derivatives designated as hedging instruments —
—
—
—
—
—
10
—
—
10
Economic hedges 3
13
—
—
16
3
13
—
—
16
Effect of netting and allocation of collateral (3 ) (8 ) —
—
(11 ) (3 ) (8 ) —
—
(11 )
Interest rate and foreign currency derivative assets subtotal —

5

—
—

5

—

15

—
—

15
Other investments —
—
43
—
43
—
—
43
—
43
Total assets 6,145

3,282

1,564

3,370

14,361

7,115

3,352

1,585

3,370

15,422
Liabilities
Commodity derivative liabilities
Economic hedges (559 ) (2,062 ) (1,189 ) —
(3,810 ) (559 ) (2,062 ) (1,466 ) —
(4,087 )
Proprietary trading (3 ) (43 ) (27 ) —
(73 ) (3 ) (43 ) (27 ) —
(73 )
Effect of netting and allocation of collateral^{(f) (g)}
560
2,043
978
—
3,581
560
2,043
978
—
3,581
Commodity derivative liabilities subtotal (2 ) (62 ) (238 ) —
(302 ) (2 ) (62 ) (515 ) —
(579 )
Interest rate and foreign currency derivative liabilities
Economic hedges (2 ) (17 ) —
—
(19 ) (2 ) (17 ) —
—
(19 )
Effect of netting and allocation of collateral 2
8
—
—
10
2
8
—
—
10
Interest rate and foreign currency derivative liabilities subtotal —

(9 )
—
—

(9 )
—

(9 )
—
—

(9 )
Deferred compensation obligation —
(35 ) —
—
(35 ) —
(137 ) —
—
(137 )
Total liabilities (2 )
(106 )
(238 ) —

(346 )
(2 )
(208 )
(515 ) —

(725 )
Total net assets $ 6,143

$ 3,176

$ 1,326
$ 3,370

$ 14,015

$ 7,113

$ 3,144

$ 1,070
$ 3,370

$ 14,697

~~103~~

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~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

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

Generation Exelon
As of December 31, 2016 Level 1 Level 2 Level 3 Not subject to leveling Total Level 1
Level 2
Level 3 Not subject to leveling
Total
Assets
Cash equivalents^(a)
$ 39
$ —
$ —
$ —
$ 39
$ 373
$ —
$ —
$ —
$ 373
NDT fund investments

Cash equivalents^(b)
110
19
—
—
129
110
19
—
—
129
Equities 3,551

452

—

2,011

6,014

3,551

452

—

2,011

6,014
Fixed income
Corporate debt —
1,554
250
—
1,804
—
1,554
250
—
1,804
U.S. Treasury and agencies 1,291
29
—
—
1,320
1,291
29
—
—
1,320
Foreign governments —
37
—
—
37
—
37
—
—
37
State and municipal debt —
264
—
—
264
—
264
—
—
264
Other^(c)
—
59
—
493
552
—
59
—
493
552
Fixed income subtotal 1,291

1,943

250
493

3,977

1,291

1,943

250
493

3,977
Middle market lending —
—
427
71
498
—
—
427
71
498
Private equity —
—
—
148
148
—
—
—
148
148
Real estate —
—
—
326
326
—
—
—
326
326
NDT fund investments subtotal^(d)
4,952

2,414

677
3,049

11,092

4,952

2,414

677
3,049
11,092
Pledged assets for Zion Station decommissioning
Cash equivalents 11
—
—
—
11
11
—
—
—
11
Equities —
2
—
—
2
—
2
—
—
2
Fixed Income - U.S. Treasury and agencies 16
1
—
—
17
16
1
—
—
17
Middle market lending —
—
19
64
83
—
—
19
64
83
Pledged assets for Zion Station decommissioning subtotal^(e)
27

3

19
64

113

27

3

19
64

113
Rabbi trust investments
Cash equivalents 2
—
—
—
2
74
—
—
—
74
Mutual funds 19
—
—
—
19
50
—
—
—
50
Fixed income —
—
—
—
—
—
16
—
—
16
Life insurance contracts —
18
—
—
18
—
64
20
—
84
Rabbi trust investments subtotal 21

18

—
—

39

124

80

20
—

224
Commodity derivative assets
Economic hedges 1,356
2,505
1,229
—
5,090
1,358
2,505
1,229
—
5,092
Proprietary trading 3
50
23
—
76
3
50
23
—
76
Effect of netting and allocation of collateral^{(f) (g)}
(1,162 ) (2,142 ) (481 ) —
(3,785 ) (1,164 ) (2,142 ) (481 ) —
(3,787 )
Commodity derivative assets subtotal 197

413

771
—

1,381

197

413

771
—

1,381
Interest rate and foreign currency derivative assets

Derivatives designated as hedging instruments —
—
—
—
—
—
16
—
—
16
Economic hedges —
28
—
—
28
—
28
—
—
28
Proprietary trading 3
2
—
—
5
3
2
—
—
5
Effect of netting and allocation of collateral (2 ) (19 ) —
—
(21 ) (2 ) (19 ) —
—
(21 )
Interest rate and foreign currency derivative assets subtotal 1

11

—
—

12

1

27

—
—

28
Other investments —
—
42
—
42
—
—
42
—
42
Total assets 5,237

2,859

1,509
3,113

12,718

5,674

2,937

1,529
3,113

13,253

~~104~~

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~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

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

Generation Exelon
As of December 31, 2016 Level 1 Level 2 Level 3 Not subject to leveling Total Level 1
Level 2
Level 3 Not subject to leveling
Total
Liabilities

Commodity derivative liabilities
Economic hedges (1,267 ) (2,378 ) (794 ) —
(4,439 ) (1,267 ) (2,378 ) (1,052 ) —
(4,697 )
Proprietary trading (3 ) (50 ) (26 ) —
(79 ) (3 ) (50 ) (26 ) —
(79 )
Effect of netting and allocation of collateral^{(f) (g)}
1,233
2,339
542
—
4,114
1,233
2,339
542
—
4,114
Commodity derivative liabilities subtotal (37 )
(89 )
(278 ) —

(404 )
(37 )
(89 )
(536 ) —

(662 )
Interest rate and foreign currency derivative liabilities
Derivatives designated as hedging instruments —
(10 ) —
—
(10 ) —
(10 ) —
—
(10 )
Economic hedges —
(21 ) —
—
(21 ) —
(21 ) —
—
(21 )
Proprietary trading (4 ) —
—
—
(4 ) (4 ) —
—
—
(4 )
Effect of netting and allocation of collateral 4
19
—
—
23
4
19
—
—
23
Interest rate and foreign currency derivative liabilities subtotal —

(12 )
—
—

(12 )
—

(12 )
—
—

(12 )
Deferred compensation obligation —
(34 ) —
—
(34 ) —
(136 ) —
—
(136 )
Total liabilities (37 )
(135 )
(278 ) —

(450 )
(37 )
(237 )
(536 ) —

(810 )
Total net assets $ 5,200

$ 2,724

$ 1,231
$ 3,113

$ 12,268

$ 5,637

$ 2,700

$ 993
$ 3,113

$ 12,443

~~_________~~

~~(a)~~

Generation excludes cash of $282 million and $252 million at September 30, 2017 and December 31, 2016 and restricted cash of $184 million and $157 million at September 30, 2017 and December 31, 2016. Exelon excludes cash of $382 million and $360 million at September 30, 2017 and December 31, 2016 and restricted cash of $219 million and $180 million at September 30, 2017 and December 31, 2016 and includes long-term restricted cash of $22 million and $25 million at September 30, 2017 and December 31, 2016, which is reported in other deferred debits on the balance sheet.


~~(b)~~	Includes $75 million and $29 million of cash received from outstanding repurchase agreements at September 30, 2017 and December 31, 2016, respectively, and is offset by an obligation to repay upon settlement of the agreement as discussed in (d) below.

~~(c)~~

Includes derivative instruments of less than $1 million and $(2) million, which have a total notional amount of $885 million and $933 million at September 30, 2017 and December 31, 2016, respectively. The notional principal amountssavings plan 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 $52 million and $31 million at September 30, 2017 and December 31, 2016, 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)~~	Excludes net assets of less than $1 million at September 30, 2017 and December 31, 2016. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases.

~~(f)~~

Collateral posted/(received) from counterparties totaled $59 million, $215 million and $141 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of September 30, 2017. Collateral posted/(received) from counterparties, net of collateral paid to counterparties, totaled $71 million, $197 million and $61 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2016.


~~(g)~~	Of the collateral posted/(received), $27 million represents variation margin on the exchanges as of September 30, 2017. Of the collateral posted/(received), $(158) million represents variation margin on the exchanges as of December 31, 2016.

~~105~~

~~Table of Contents~~

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

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

~~ComEd, PECO and BGE~~

The following tables present assets and liabilities measured and recorded at fair value on ComEd's, PECO's and BGE's Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of September 30, 2017 and December 31, 2016:

ComEd PECO BGE
As of September 30, 2017 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets
Cash equivalents^(a)
$ 273
$ —
$ —
$ 273
$ 314
$ —
$ —
$ 314
$ 18
$ —
$ —
$ 18
Rabbi trust investments

Mutual funds —
—
—
—
7
—
—
7
5
—
—
5
Life insurance contracts —
—
—
—
—
10
—
10
—
—
—
—
Rabbi trust investments subtotal —

—

—

—

7

10

—

17

5

—

—

5
Total assets 273

—

—

273

321

10

—

331

23

—

—

23
Liabilities

Deferred compensation obligation —
(7 ) —
(7 ) —
(10 ) —
(10 ) —
(4 ) —
(4 )
Mark-to-market derivative liabilities^(b)
—
—
(277 ) (277 ) —
—
—
—
—
—
—
—
Total liabilities —
(7 ) (277 ) (284 ) —
(10 ) —
(10 ) —
(4 ) —
(4 )
Total net assets (liabilities) $ 273
$ (7 ) $ (277 ) $ (11 ) $ 321
$ —
$ —
$ 321
$ 23
$ (4 ) $ —
$ 19

ComEd PECO BGE
As of December 31, 2016 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets
Cash equivalents^(a)
$ 20
$ —
$ —
$ 20
$ 45
$ —
$ —
$ 45
$ 36
$ —
$ —
$ 36
Rabbi trust investments

Mutual funds —
—
—
—
7
—
—
7
4
—
—
4
Life insurance contracts —
—
—
—
—
10
—
10
—
—
—
—
Rabbi trust investments subtotal —

—

—

—

7

10

—

17

4

—

—

4
Total assets 20

—

—

20

52

10

—

62

40

—

—

40
Liabilities

Deferred compensation obligation —
(8 ) —
(8 ) —
(11 ) —
(11 ) —
(4 ) —
(4 )
Mark-to-market derivative liabilities^(b)
—
—
(258 ) (258 ) —
—
—
—
—
—
—
—
Total liabilities —
(8 ) (258 ) (266 ) —
(11 ) —
(11 ) —
(4 ) —
(4 )
Total net assets (liabilities) $ 20
$ (8 ) $ (258 ) $ (246 ) $ 52
$ (1 ) $ —
$ 51
$ 40
$ (4 ) $ —
$ 36

~~_________~~

~~(a)~~

ComEd excludes cash of $36 million at September 30, 2017 and December 31, 2016 and restricted cash of $2 million at December 31, 2016. PECO excludes cash of $20 million and $22 million at September 30, 2017 and December 31, 2016. BGE excludes cash of $11 million and $13 million at September 30, 2017 and December 31, 2016 and restricted cash of $1 million at September 30, 2017 and includes long-term restricted cash of $2 million at December 31, 2016, which is reported in other deferred debits on the balance sheet.


~~(b)~~	The Level 3 balance consists of the current and noncurrent liability of $20 million and $257 million, respectively, at September 30, 2017, and $19 million and $239 million, respectively, at December 31, 2016, related to floating-to-fixed energy swap contracts with unaffiliated suppliers.

~~106~~

~~Table of Contents~~

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

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

~~PHI, Pepco, DPL and ACE~~

The following tables present assets and liabilities measured and recorded at fair value on PHI's, Pepco's, DPL's and ACE's Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of September 30, 2017 and December 31, 2016:

Successor
As of September 30, 2017 As of December 31, 2016
PHI Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets
Cash equivalents^(a)
$ 184
$ —
$ —
$ 184
$ 217
$ —
$ —
$ 217
Mark-to-market derivative assets^(b)
—
—
—
—
2
—
—
2
Effect of netting and allocation of collateral —
—
—
—
(2 ) —
—
(2 )
Mark-to-market derivative assets subtotal —
—
—
—
—
—
—
—
Rabbi trust investments

Cash equivalents 72
—
—
72
73
—
—
73
Fixed income —
13
—
13
—
16
—
16
Life insurance contracts —
23
21
44
—
22
20
42
Rabbi trust investments subtotal 72

36

21

129

73

38

20

131
Total assets 256

36

21

313
290

38

20

348
Liabilities

Deferred compensation obligation —
(24 ) —
(24 ) —
(28 ) —
(28 )
Total liabilities —

(24 )
—

(24 )
—

(28 )
—

(28 )
Total net assets $ 256

$ 12

$ 21

$ 289
$ 290

$ 10

$ 20

$ 320

Pepco DPL ACE
As of September 30, 2017 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets

Cash equivalents^(a)
$ 144
$ —
$ —
$ 144
$ —
$ —
$ —
$ —
$ 31
$ —
$ —
$ 31
Rabbi trust investments

Cash equivalents 43
—
—
43
—
—
—
—
—
—
—
—
Fixed income —
13
—
13
—
—
—
—
—
—
—
—
Life insurance contracts —
23
21
44
—
—
—
—
—
—
—
—
Rabbi trust investments subtotal 43

36

21

100

—

—

—

—

—

—

—

—
Total assets 187

36

21

244

—

—

—

—

31

—

—

31
Liabilities

Deferred compensation obligation —
(4 ) —
(4 ) —
(1 ) —
(1 ) —
—
—
—
Total liabilities —

(4 )
—

(4 )
—

(1 )
—

(1 )
—

—

—

—
Total net assets (liabilities) $ 187
$ 32
$ 21
$ 240
$ —
$ (1 ) $ —
$ (1 ) $ 31
$ —
$ —
$ 31

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~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

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

Pepco DPL ACE
As of December 31, 2016 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets

Cash equivalents^(a)
$ 33
$ —
$ —
$ 33
$ 42
$ —
$ —
$ 42
$ 130
$ —
$ —
$ 130
Mark-to-market derivative assets^(b)
—
—
—
—
2
—
—
2
—
—
—
—
Effect of netting and allocation of collateral —
—
—
—
(2 ) —
—
(2 ) —
—
—
—
Mark-to-market derivative assets subtotal —
—
—
—
—
—
—
—
—
—
—
—
Rabbi trust investments
Cash equivalents 43
—
—
43
—
—
—
—
—
—
—
—
Fixed income —
16
—
16
—
—
—
—
—
—
—
—
Life insurance contracts —
22
19
41
—
—
—
—
—
—
—
—
Rabbi trust investments subtotal 43

38

19

100

—

—

—

—

—

—

—

—
Total assets 76

38

19

133

42

—

—

42

130

—

—

130
Liabilities
Deferred compensation obligation —
(5 ) —
(5 ) —
(1 ) —
(1 ) —
—
—
—
Total liabilities —
(5 ) —
(5 ) —
(1 ) —
(1 ) —
—
—
—
Total net assets (liabilities) $ 76
$ 33
$ 19

$ 128
$ 42
$ (1 ) $ —
$ 41
$ 130
$ —
$ —
$ 130

~~_________~~

~~(a)~~

PHI excludes cash of $18 million and $19 million at September 30, 2017 and December 31, 2016 and includes long-term restricted cash of $22 million and $23 million at September 30, 2017 and December 31, 2016 which is reported in other deferred debits on the balance sheet. Pepco excludes cash of $7 million and $9 million at September 30, 2017 and December 31, 2016. DPL excludes cash of $3 million and $4 million at September 30, 2017 and December 31, 2016. ACE excludes cash of $5 million and $3 million at September 30, 2017 and December 31, 2016 and includes long-term restricted cash of $22 million and $23 million at September 30, 2017 and December 31, 2016 which is reported in other deferred debits on the balance sheet.


~~(b)~~	~~Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC.~~

~~The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during~~ the three and nine months ended September 30, ~~2017~~2023 and ~~2016:~~2022.


	Three Months Ended September 30,				Nine Months Ended September 30,
Savings Plan Employer Contributions	2023		2022		2023		2022
Exelon	$	27	$	23	$	74	$	66
ComEd	12		11		31		29
PECO	3		3		10		9
BGE	3		2		8		7
PHI	5		4		13		11
Pepco	1		1		3		3
DPL	1		1		3		3
ACE	1		1		2		2

Successor
Generation ComEd PHI Exelon
Three Months Ended September 30, 2017
NDT Fund
Investments

Pledged Assets
for Zion Station
Decommissioning

Mark-to-Market
Derivatives

Other
Investments
Total Generation
Mark-to-Market
Derivatives
Life Insurance Contracts Eliminated in Consolidation Total
Balance as of June 30, 2017 $ 683
$ 21
$ 589
$ 41
$ 1,334
$ (256 ) $ 20
$ —
$ 1,098
Total realized / unrealized gains (losses)

Included in net income —
—
(82 )
^(a)
1
(81 ) —
1
—
(80 )
Included in payable for Zion Station decommissioning —
(4 ) —
—
(4 ) —
—
—
(4 )
Included in regulatory assets —
—
—
—
—
(21 )
^(b)
—
—
(21 )
Change in collateral —
—
11
—
11
—
—
—
11
Purchases, sales, issuances and settlements

Purchases 19
—
57
1
77
—
—
—
77
Settlements (31 ) —
10
^(c)
—
(21 ) —
—
—
(21 )
Transfers out of Level 3 —
—
10
—
10
—
—
—
10
Balance at September 30, 2017 $ 671
$ 17
$ 595
$ 43
$ 1,326
$ (277 ) $ 21
$ —
$ 1,070
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2017 $ —
$ —
$ 24
$ 1
$ 25
$ —
$ 1
$ —
$ 26

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~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

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

Successor
Generation ComEd PHI Exelon
Nine Months Ended September 30, 2017
NDT Fund
Investments

Pledged Assets
for Zion Station
Decommissioning

Mark-to-Market
Derivatives

Other
Investments
Total Generation
Mark-to-Market
Derivatives
Life Insurance Contracts Eliminated in Consolidation �� Total
Balance as of December 31, 2016 $ 677
$ 19
$ 493
$ 42
$ 1,231
$ (258 ) $ 20
$ —
$ 993
Total realized / unrealized gains (losses)

Included in net income 4
—
(110 )
^(a)
2
(104 ) —
2
—
(102 )
Included in noncurrent payables to affiliates 13
—
—
—
13
—
—
(13 ) —
Included in payable for Zion Station decommissioning —
(3 ) —
—
(3 ) —
—
—
(3 )
Included in regulatory assets —
—
—
—
—
(19 )
^(b)
—
13
(6 )
Change in collateral —
—
81
—
81
—
—
—
81
Purchases, sales, issuances and settlements

Purchases 54
1
146
4
205
—
—
—
205
Sales —
—
(15 ) —
(15 ) —
—
—
(15 )
Issuances —
—
—
—
—
—
(1 ) —
(1 )
Settlements (77 ) —
(8 )
^(c)
—
(85 ) —
—
—
(85 )
Transfers into Level 3 —
—
(9 ) —
(9 ) —
—
—
(9 )
Transfers out of Level 3 —
—
17
(5 ) 12
—
—
—
12
Balance as of September 30, 2017 $ 671
$ 17

$ 595
$ 43
$ 1,326
$ (277 ) $ 21
$ —
$ 1,070
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2017 $ 2
$ —
$ 161
$ 2
$ 165
$ —
$ 2
$ —
$ 167

~~_________~~


~~(a)~~	~~Includes a reduction for the reclassification of $96 million and $279 million of realized gains due to the settlement of derivative contracts for the three and nine months ended September 30, 2017.~~

~~(b)~~

Includes $24 million of decreases in fair value and an increase for realized losses due to settlements of $3 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended September 30, 2017. Includes $32 million of decreases in fair value and an increase for realized losses due to settlements of $13 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the nine months ended September 30, 2017.


~~(c)~~	~~Exelon includes the settlement value for any open contracts that were net settled prior to their scheduled maturity within this line item.~~

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~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

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

Successor
Generation ComEd PHI Exelon
Three Months Ended September 30, 2016
NDT Fund
Investments

Pledged Assets
for Zion Station
Decommissioning

Mark-to-Market
Derivatives

Other
Investments
Total Generation
Mark-to-Market
Derivatives
Life Insurance Contracts Eliminated in Consolidation Total
Balance as of June 30, 2016 $ 715
$ 25
$ 609
$ 37
$ 1,386
$ (221 ) $ 20
$ —
$ 1,185
Total realized / unrealized gains (losses)

Included in net income (4 ) —
95
^(a)
1
92
—
1
—
93
Included in noncurrent payables to affiliates 6
—
—
—
6
—
—
(6 ) —
Included in payable for Zion Station decommissioning —
(1 ) —
—
(1 ) —
—
—
(1 )
Included in regulatory assets —
—
—
—
—
(23 )
^(b)
—
6
(17 )
Change in collateral —
—
31
—
31
—
—
—
31
Purchases, sales, issuances and settlements

Purchases 4
—
207
^(c)
3
214
—
—
—
214
Sales —
(5 ) (2 ) —
(7 ) —
—
—
(7 )
Issuances —
—
—
—
—
—
—
—
—
Settlements (28 ) —
—
—
(28 ) —
—
—
(28 )
Transfers into Level 3 —
—
(1 ) 1
—
—
—
—
—
Transfers out of Level 3 —
—
(4 ) —
(4 ) —
—
—
(4 )
Balance as of September 30, 2016 $ 693

$ 19

$ 935

$ 42

$ 1,689

$ (244 )
$ 21
$ —

$ 1,466
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2016 $ 3
$ —
$ 285
$ —
$ 288
$ —
$ —
$ —
$ 288

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~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

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

Successor
Generation ComEd
PHI^(d)
Exelon
Nine Months Ended September 30, 2016
NDT Fund
Investments

Pledged Assets
for Zion Station
Decommissioning

Mark-to-Market
Derivatives

Other
Investments
Total Generation
Mark-to-Market
Derivatives
Life Insurance Contracts Eliminated in Consolidation Total
Balance as of December 31, 2015 $ 670
$ 22
$ 1,051
$ 33
$ 1,776
$ (247 ) $ —
$ —
$ 1,529
Included due to merger —
—
—
—
—
—
20
—
20
Total realized / unrealized gains (losses)

Included in net income 2
—
(339 )
^(a)
1
(336 ) —
2
—
(334 )
Included in noncurrent payables to affiliates 18
—
—
—
18
—
—
(18 ) —
Included in payable for Zion Station decommissioning —
1
—
—
1
—
—
—
1
Included in regulatory assets —
—
—
—
—
3
^(b)
—
18
21
Change in collateral —
—
(51 ) —
(51 ) —
—
—
(51 )
Purchases, sales, issuances and settlements

Purchases 123
1
289
^(c)
7
420
—
—
—
420
Sales (1 ) (5 ) (5 ) —
(11 ) —
—
—
(11 )
Issuances —
—
—
—
—
—
(1 ) —
(1 )
Settlements (119 ) —
—
—
(119 ) —
—
—
(119 )
Transfers into Level 3 —
—
1
1
2
—
—
—
2
Transfers out of Level 3 —
—
(11 ) —
(11 ) —
—
—
(11 )
Balance as of September 30, 2016 $ 693
$ 19
$ 935
$ 42
$ 1,689

$ (244 ) $ 21
$ —
$ 1,466
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2016 $ 7
$ —
$ 240
$ —
$ 247
$ —
$ 1
$ —
$ 248

~~_________~~


~~(a)~~	Includes a reduction for the reclassification of $190 million and $579 million of realized gains due to the settlement of derivative contracts recorded in results of operations for the three and nine months ended September 30, 2016.

~~(b)~~

Includes $25 million of decreases in fair value and an increase for realized losses due to settlements of $2 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended September 30, 2016. Includes $10 million of decreases in fair value and an increase for realized losses due to settlements of $13 million for the nine months ended September 30, 2016.


~~(c)~~	~~Includes $168 million of fair value from contracts acquired as a result of portfolio acquisitions.~~


~~(d)~~	Successor period represents activity from March 24, 2016 through September 30, 2016. See tables below for PHI's predecessor periods, as well as activity for Pepco for the three and nine months ended September 30, 2017 and 2016.

Predecessor
January 1, 2016 to March 23, 2016
PHI Preferred Stock Life Insurance Contracts
Beginning Balance $ 18
$ 19
Total realized / unrealized gains (losses)
Included in net income (18 ) 1
Ending Balance
$ —
$ 20
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities for the period $ —
$ 1

~~111~~

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~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

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

Life Insurance Contracts
Three Months Ended
September 30, Nine Months Ended
September 30,
Pepco 2017 2016 2017 2016
Beginning balance $ 20
$ 20
$ 20
$ 19
Total realized / unrealized gains (losses)
Included in net income 1
1
2
3
Purchases, sales, issuances and settlements
Issuances —
—
(1 ) (1 )
Ending balance $ 21

$ 21
$ 21

$ 21
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities for the period $ 1
$ —
$ 2
$ 2

The following tables present the income statement classification of the total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis during the three and nine months ended September 30, 2017 and 2016:

Successor
Generation PHI Exelon
Operating
Revenues Purchased
Power and
Fuel
Other, net^(a)

Other, net^(a)
Operating
Revenues Purchased
Power and
Fuel
Other, net^(a)
Total gains (losses) included in net income for the three months ended September 30, 2017 $ (3 ) $ (69 ) $ 1
$ 1
$ (3 ) $ (69 ) $ 2
Total gains (losses) included in net income for the nine months ended September 30, 2017 34
(152 ) 6
2
34
(152 ) 8
Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended September 30, 2017 47
(23 ) 1
1
47
(23 ) 2
Change in the unrealized gains (losses) relating to assets and liabilities held for the nine months ended September 30, 2017 222
(61 ) 4
2
222
(61 ) 6

Successor
Generation PHI Exelon

Operating
Revenues

Purchased
Power and
Fuel

Other, net^(a)

Other, net^(a)

Operating
Revenues

Purchased
Power and
Fuel

Other, net^(a)
Total gains (losses) included in net income for the three months ended September 30, 2016 $ 180
$ (85 ) $ (4 ) $ 1
$ 180
$ (85 ) $ (3 )
Total gains (losses) included in net income for the nine months ended September 30, 2016 (232 ) (107 ) 2
2
(232 ) (107 ) 4
Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended September 30, 2016 323
(38 ) 3
—
323
(38 ) 3
Change in the unrealized gains (losses) relating to assets and liabilities held for the nine months ended September 30, 2016 303
(63 ) 7
1
303
(63 ) 8

~~112~~

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~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

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

Predecessor
PHI Pepco
January 1, 2016 to March 23, 2016 Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016

Other, net^(a)

Other, net^(a)

Total gains (losses) included in net income $ (17 ) $ 1
$ 1
$ 2
$ 3
Change in the unrealized gains (losses) relating to assets and liabilities held 1
1
—
2
2

~~_________~~


~~(a)~~	Other, net activity consists of realized and unrealized gains (losses) included in income for the NDT funds held by Generation, accrued interest on a convertible promissory note at Generation and the life insurance contracts held by PHI and Pepco.

~~Valuation Techniques Used to Determine Fair Value~~

~~The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the tables above.~~

~~Cash Equivalents (Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE).~~ The Registrants’ cash equivalents include investments with original maturities of three months or less when purchased. The cash equivalents shown in the fair value tables are comprised of investments in mutual and money market funds. The fair values of the shares of these funds are based on observable market prices and, therefore, have been categorized in Level 1 in the fair value hierarchy.

~~Preferred Stock Derivative (PHI).~~ In connection with entering into the PHI Merger Agreement, PHI entered into a Subscription Agreement with Exelon dated April 29, 2014, pursuant to which PHI issued to Exelon shares of Preferred stock. The Preferred stock contained embedded features requiring separate accounting consideration to reflect the potential value to PHI that any issued and outstanding Preferred stock could be called and redeemed at a nominal par value upon a termination of the merger agreement under certain circumstances due to the failure to obtain required regulatory approvals. The embedded call and redemption features on the shares of the Preferred stock in the event of such a termination were separately accounted for as derivatives. These Preferred stock derivatives were valued quarterly using quantitative and qualitative factors, including management’s assessment of the likelihood of a Regulatory Termination and therefore, were categorized in Level 3 in the fair value hierarchy. As a result of the PHI Merger, the PHI Preferred stock derivative was reduced to zero as of March 23, 2016. The write-off was charged to Other, net on the PHI Consolidated Statement of Operations and Comprehensive Income.

~~Nuclear Decommissioning Trust Fund Investments and Pledged Assets for Zion Station Decommissioning (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. 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.

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 Generation is able to independently corroborate. The fair values of equity securities held directly by the trust funds which are based on quoted prices in active markets are categorized in 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. Equity securities held individually are primarily traded on the New York Stock Exchange and NASDAQ-Global Select Market, which contain only actively traded securities due to the volume trading requirements imposed by these exchanges.

For fixed income securities, multiple prices from pricing services are obtained 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

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

price source is considered to be preferable. Generation has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, Generation selectively corroborates the fair values of securities by comparison to other market-based price sources. U.S. Treasury securities are categorized as Level 1 because they trade in a highly liquid and transparent market. The fair values of fixed income securities, excluding U.S. Treasury 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 fair values of private placement fixed income securities, which are included in Corporate debt, are determined using a third party valuation that contains significant unobservable inputs and are categorized in Level 3.

Equity and fixed income commingled funds and mutual funds are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives such as holding short-term fixed income securities or tracking the performance of certain equity indices by purchasing equity securities to replicate the capitalization and characteristics of the indices. 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 commingled funds and mutual funds, which are not publicly quoted, the funds are valued using NAV as a practical expedient for fair value, which is primarily derived from the quoted prices in active markets on the underlying securities, and are not classified within the fair value hierarchy. These investments typically can be redeemed monthly with 30 or less days of notice and without further restrictions.

Derivative instruments consisting primarily of futures and interest rate 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.

Middle market lending are investments in loans or managed funds which lend to private companies. Generation elected the fair value option for its investments in certain limited partnerships that invest in middle market lending managed funds. The fair value of these loans is determined using a combination of valuation models including cost models, market models and income models. Investments in loans are categorized as Level 3 because the fair value of these securities is based largely on inputs that are unobservable and utilize complex valuation models. Managed funds are valued using NAV or its equivalent as a practical expedient, and therefore, are not classified within the fair value hierarchy. Investments in middle market lending typically cannot be redeemed until maturity of the term loan.

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

~~As of September 30, 2017, Generation has outstanding commitments to invest in fixed income, middle market lending, private equity and real estate investments of approximately $75 million~~, ~~$285 million,$240 million, and$95 million, respectively. These commitments will be funded by Generation’s existing nuclear decommissioning trust funds.~~

~~Concentrations of Credit Risk~~. Generation evaluated its NDT portfolios for the existence of significant concentrations of credit risk as of September 30, 2017. 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 September 30, 2017, there were no significant concentrations (generally defined as greater than 10 percent) of risk in Generation's NDT assets.

~~See Note 13 — Nuclear Decommissioning for further discussion on the NDT 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

~~114~~

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

life insurance policies. The mutual funds are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives, which are consistent with Exelon’s overall investment strategy. 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 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.

~~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.

Exelon may utilize fixed-to-floating interest rate swaps, which are typically designated as fair value hedges, as a means to achieve its targeted level of variable-rate debt as a percent of total debt. In addition, the Registrants may utilize interest rate derivatives to lock in interest rate levels in anticipation of future financings. These interest rate derivatives are typically designated as cash flow hedges. Exelon determines the current fair value by calculating the net present value of expected payments and receipts under the swap agreement, based on and discounted by the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk and other market parameters. As these inputs are based on observable data and valuations of similar instruments, the interest rate swaps are categorized in Level 2 in the fair value hierarchy. See Note 10 - Derivative Financial Instruments for further discussion on mark-to-market derivatives.

~~Deferred Compensation Obligations (Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE).~~ 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.

~~Additional Information Regarding Level 3 Fair Value Measurements (Exelon, Generation, ComEd, PHI, Pepco, DPL and ACE)~~

~~Mark-to-Market Derivatives (Exelon, Generation and ComEd).~~ 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

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

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. 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. 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.

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 $2.93 and $0.41 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 10 —Derivative Financial Instruments for more 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.

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

~~The table below discloses the significant inputs to the forward curve used to value these positions.~~

Type of trade Fair Value at September 30, 2017
Valuation
Technique

Unobservable
Input
Range
Mark-to-market derivatives — Economic Hedges (Exelon and Generation)^(a)(b)
$ 439
Discounted
Cash Flow Forward power
price $7 - $124

Forward gas
price $1.84 - $9.43

Option Model Volatility
percentage 9% - 114%

Mark-to-market derivatives — Proprietary trading (Exelon and Generation)^(a)(b)
$ 15
Discounted
Cash Flow Forward power
price $12 - $69

Mark-to-market derivatives (Exelon and ComEd) $ (277 ) Discounted
Cash Flow
Forward heat
rate^(c)
9x - 10x
Marketability
reserve 3% - 8%
Renewable
factor 88% - 125%

~~_________~~


~~(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 $141 million as of September 30, 2017.~~


~~(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.

Type of trade Fair Value at December 31, 2016
Valuation
Technique

Unobservable
Input
Range
Mark-to-market derivatives — Economic Hedges (Exelon and Generation)^(a)(b)
$ 435
Discounted
Cash Flow Forward power price $11 - $130

Forward gas price $1.72 - $9.20

Option Model Volatility percentage 8% - 173%

Mark-to-market derivatives — Proprietary trading (Exelon and Generation)^(a)(b)
$ (3 ) Discounted
Cash Flow Forward power price $19 - $79

Mark-to-market derivatives (Exelon and ComEd) $ (258 ) Discounted Cash Flow
Forward heat
rate^(c)
8x - 9x
Marketability reserve 3% - 8%
Renewable factor 89% - 121%

~~_________~~


~~(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 $61 million as of December 31, 2016.~~


~~(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 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

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

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.

~~Nuclear Decommissioning Trust Fund Investments and Pledged Assets for Zion StationDecommissioning (Exelon and Generation).~~ For middle market lending and certain corporate debt securities investments, the fair value is determined using a combination of valuation models including cost models, market models and income models. The valuation estimates are based on discounting the forecasted cash flows, market-based comparable data, credit and liquidity factors, as well as other factors that may impact value. Significant judgment is required in the application of discounts or premiums applied for factors such as size, marketability, credit risk and relative performance.

Because Generation relies on third-party fund managers to develop the quantitative unobservable 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 Generation. This includes information regarding the sensitivity of the fair values to changes in the unobservable inputs. Generation gains an understanding of the fund managers’ inputs and assumptions used in preparing the valuations. Generation performed procedures to assess the reasonableness of the valuations.

~~Rabbi Trust Investments - Life insurance contracts (Exelon, PHI, Pepco, DPL and ACE).~~ ~~For~~life insurance policies categorized as Level 3, 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. Exelon gains an understanding of the types of inputs and assumptions used in preparing the valuations and performs procedures to assess the reasonableness of the valuations.

~~10.~~9. Derivative Financial 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.

~~Commodity Price Risk (All Registrants)~~

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. 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 energy-related products. The Registrants ~~believe these instruments, which are classified as either economic hedges~~do not execute derivatives for speculative or ~~non-derivatives, mitigate exposure to fluctuations in commodity prices.~~proprietary trading purposes.

~~Derivative accounting~~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 ~~each period.~~immediately. Other accounting treatments are available through special election and designation, provided they meet specific, restrictive criteria both at the time of designation and on an ongoing basis. These alternative permissible accounting treatments include ~~normal purchase normal sale (NPNS),~~NPNS, cash flow ~~hedge,~~hedges, and fair value ~~hedge. For Generation, all~~hedges. At ComEd, derivative economic hedges related to commodities are recorded at fair value ~~through earnings for the consolidated company, referred to as~~and offset by a corresponding regulatory asset or liability. At Exelon, derivative economic hedges ~~in the following tables. The Registrants have applied the NPNS scope exception~~related to ~~certain derivative contracts for the forward sale of generation, power procurement agreements,~~interest rates are recorded at fair value and ~~natural gas supply agreements. Generation has also entered into bilateral long-term contractual obligations for sales of energy~~offsets are recorded to load-serving entities, including electric utilities, municipalities, electric cooperatives, and retail load aggregators, as well as contractual obligations to deliver energy to market participants who primarily focusElectric operating revenues or Interest expense based on the ~~resale~~activity the transaction is economically hedging. For all NPNS derivative instruments, accounts receivable or accounts payable are recorded when derivatives settle and revenue or expense is recognized in earnings as the underlying physical commodity is sold or consumed. At Exelon, derivative hedges that qualify and are designated as cash flow hedges are recorded at fair value and offsets are recorded to AOCI.

ComEd’s use of ~~energy products for delivery. These non-derivative contracts are accounted for primarily under the accrual method of accounting. Additionally, Generation~~cash collateral is ~~exposed to~~generally unrestricted unless ComEd is 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 meets 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.

~~Economic Hedging.~~ The Registrants are exposed to commodity price risk primarily relating to changes in the market price of electricity, fossil fuels, and other commodities associated with price movements resulting from changes

qualifications.

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Note 9 — Derivative Financial Instruments

~~in supply and demand, fuel costs, market liquidity, weather conditions, governmental regulatory and environmental~~Commodity Price Risk

The Registrants employ established policies and ~~other factors. Within Exelon, Generation has~~procedures to manage their risks associated with market fluctuations in commodity prices by entering into physical and financial derivative contracts, which are either determined to be non-derivative or classified as economic hedges. The Utility Registrants procure electric and natural gas supply through a competitive procurement process approved by each of the ~~most~~respective state utility commissions. The Utility Registrants’ hedging programs are intended to reduce exposure to ~~commodity price risk. As such, Generation uses a variety of derivative~~energy and ~~non-derivative instruments to manage the commodity price risk of its electric generation facilities, including power and gas sales, fuel and energy purchases,~~ natural gas ~~transportation~~price volatility and pipeline capacity agreements, and other energy-related products marketed and purchased. In order to manage these risks, Generation may enter into fixed-price derivative or non-derivative contracts to hedgehave no direct earnings impact as the ~~variability in future cash flows~~costs are fully recovered from ~~forecasted sales of energy and gas and purchases of fuel and energy.~~customers through regulatory-approved recovery mechanisms. The ~~objectives for entering into such hedges include fixing the price for~~following table provides a portion of anticipated future electricity sales at a level that provides an acceptable return on electric generation operations, fixing the price of a portion of anticipated fuel purchases for the operation of power plants, and fixing the price for a portion of anticipated energy purchases to supply load-serving customers. The portion of forecasted transactions hedged may vary based upon management’s policies and hedging objectives, the market, weather conditions, operational and other factors. 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.

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 September 30, 2017, the percentage of expected generation hedged is 98%-101%, 79%-82%, and 45%-48% for 2017, 2018, and 2019, 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 generating facilities 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, BGE, Pepco, DPL, and ACE to serve their retail load.

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. Delivery under the contracts began in June 2012. These contracts are designed to lock in a portionsummary of the ~~long-term~~Utility Registrants’ primary derivative hedging instruments, listed by commodity ~~price risk resulting from the renewable energy resource procurement requirements in the Illinois Settlement Legislation. ComEd has not elected hedge~~and accounting for these derivative financial instruments. ComEd records the fair value of the swap contracts on its balance sheet. Because ComEd receives full cost recovery for energy procurement and related costs from retail customers, the change in fair value each period is recorded by ComEd as a regulatory asset or liability. treatment.


Registrant	Commodity	Accounting Treatment	Hedging Instrument
ComEd	Electricity	NPNS	Fixed price contracts based on all requirements in the IPA procurement plans.
	Electricity	Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability(a)	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 MWhs per year.
PECO	Electricity	NPNS	Fixed price contracts for default supply requirements through full requirements contracts.
	Gas	NPNS	Fixed price contracts to cover about 10% of planned natural gas purchases in support of projected firm sales.
BGE	Electricity	NPNS	Fixed price contracts for all SOS requirements through full requirements contracts.
	Gas	NPNS	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.
Pepco	Electricity	NPNS	Fixed price contracts for all SOS requirements through full requirements contracts.
DPL	Electricity	NPNS	Fixed price contracts for all SOS requirements through full requirements contracts.
	Gas	NPNS	Fixed and index priced contracts through full requirements contracts.
	Gas	Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability(b)	Exchange traded future contracts for up to 50% of estimated monthly purchase requirements each month, including purchases for storage injections.
ACE	Electricity	NPNS	Fixed price contracts for all BGS requirements through full requirements contracts.

__________

(a)See Note 3 — Regulatory Matters of the ~~Exelon 2016~~2022 Form 10-K for additional information.

PECO has contracts to procure electric supply that were executed through the competitive procurement process outlined in its PAPUC-approved DSP Programs, which are further discussed in Note 5 — Regulatory Matters. Based on Pennsylvania legislation and the DSP Programs permitting PECO to recover its electric supply procurement costs from retail customers with no mark-up, PECO’s price risk related to electric supply procurement is limited. PECO locked in fixed prices for a significant portion of its commodity price risk through full requirements contracts. PECO has certain full requirements contracts that are considered derivatives and qualify for the NPNS scope exception under current derivative authoritative guidance.

PECO’s natural gas procurement policy is designed to achieve a reasonable balance of long-term and short-term gas purchases under different pricing approaches in order to achieve system supply reliability at the least cost. PECO’s reliability strategy is two-fold. First, PECO must assure that there is sufficient transportation capacity to satisfy delivery requirements. Second, PECO must ensure that a firm source of supply exists to utilize the capacity resources. All of PECO’s natural gas supply and asset management agreements that are derivatives either qualify for the NPNS scope exception and have been designated as such, or have no mark-to-market balances because the derivatives are index priced. Additionally, in accordance with the 2016 PAPUC PGC settlement and to reduce the exposure of PECO and its customers to natural gas price volatility, PECO has continued its program to purchase natural gas for both winter and summer supplies using a layered approach of locking-in prices ahead of each season with long-term gas purchase agreements (those with primary terms of at least twelve months). Under the terms of the 2016 PGC settlement, PECO is required to lock in (i.e., economically hedge) the price of a minimum volume of its long-term gas commodity purchases. PECO’s gas-hedging program is designed to cover about 20% of planned natural gas purchases in support of projected firm sales. (b)The ~~hedging program for natural gas procurement has no direct impact on PECO’s financial position or results of operations as natural gas costs are fully recovered from customers under the PGC.~~

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

BGE has contracts to procure SOS electric supply that are executed through a competitive procurement process approved by the MDPSC. The SOS rates charged recover BGE's wholesale power supply costs and include an administrative fee. BGE’s price risk related to electric supply procurement is limited. BGE locks in fixed prices for all of its SOS requirements through full requirements contracts. Certain of BGE’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other BGE full requirements contracts are not derivatives.

BGE provides natural gas to its customers under a MBR mechanism approved by the MDPSC. Under this mechanism, BGE’s actual cost of gas is compared to a market index (a measure of the market price of gas in a given period). The difference between BGE’s actual cost and the market index is shared equally between shareholders and customers. BGE must also secure fixed price contracts for at least 10%, but not more than 20%, of forecasted system supply requirements for flowing (i.e., non-storage) gas for the November through March period. These fixed-price contracts are not subject to sharing under the MBR mechanism. BGE also ensures it has sufficient pipeline transportation capacity to meet customer requirements. All of BGE’s natural gas supply and asset management agreements qualify for the NPNS scope exception and result in physical delivery.

Pepco has contracts to procure SOS electric supply that are executed through a competitive procurement process approved by the MDPSC and DCPSC. The SOS rates charged recover Pepco's wholesale power supply costs and include an administrative fee. The administrative fee includes an incremental cost component and a shareholder return component for residential and commercial rate classes. Pepco’s price risk related to electric supply procurement is limited. Pepco locks in fixed prices for all of its SOS requirements through full requirements contracts. Certain of Pepco’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other Pepco full requirements contracts are not derivatives.

DPL has contracts to procure SOS electric supply that are executed through a competitive procurement process approved by the MDPSC and the DPSC. The SOS rates charged recover DPL's wholesale power supply costs. In Delaware, DPL is also entitled to recover a Reasonable Allowance for Retail Margin (RARM). The RARM includes a fixed annual margin of approximately $2.75 million, plus an incremental cost component and a cash working capital allowance. In Maryland, DPL charges an administrative fee intended to allow it to recover its administrative costs. DPL locks in fixed prices for all of its SOS requirements through full requirements contracts. DPL’s price risk related to electric supply procurement is limited. Certain of DPL’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other DPL full requirements contracts are not derivatives.

DPL provides natural gas to its customers under an Annual GCR mechanism approved by the DPSC. Under this mechanism, DPL’s Annual GCR Filing establishes a future GCR for firm bundled sales customers by using a forecast of demand and commodity costs. The actual costs are trued up versus the forecast on a monthly basis and any shortfall or excess is carried forward as a recovery balance in the next GCR filing. The demand portion of the GCR is based upon DPL’s firm transportation and storage contracts. DPL has firm deliverability of swing and seasonal storage; a liquefied natural gas facility and firm transportation capacity to meet customer demand and provide a reserve margin. The commodity portion of the GCR includes a commission approved hedging program which is intended to reduce gas commodity price volatility while limiting the firm natural gas customers’ exposure to adverse changes in the market price of natural gas. The hedge program requires that DPL hedge, on a non-discretionary basis, an amount equal to fifty percent (50%) of estimated purchase requirements for each month, including estimated monthly purchases for storage injections. The fifty percent (50%) hedge monthly target is achieved by hedging 1/12th of the 50% target each month beginning 12-months prior to the month in which the physical gas is to be purchased. Currently, DPL uses only exchange traded futures for its gas hedging program, which are considered derivatives, however, it retains the capability to employ other physical and financial hedges if needed. DPL has not elected hedge accounting for these derivative financial instruments. Because of the DPSC-approved fuel adjustment clause for DPL's derivatives, the change in fair value of the ~~derivatives each period, in addition to all premiums paid and other transaction costs incurred as part of the Gas Hedging Program, are fully recoverable and are recorded by~~ DPL as regulatory assets or liabilities. DPL’s physical gas purchases are currently all daily, monthly or intra-month transactions. From time to time, DPL will enter into seasonal purchase or sale arrangements, however, there are none currently in the portfolio. Certain of DPL's full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other DPL full requirements contracts areeconomic hedge is not ~~derivatives.~~

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

any profit or incur any loss on the supply component of the BGS it supplies to customers. ACE’s price risk related to electric supply procurement is limited. ACE locks in fixed prices for all of its BGS requirements through full requirements contracts. Certain of ACE’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other ACE full requirements contracts are not derivatives.

~~Proprietary Trading.~~ Generation also enters into certain energy-related derivatives for proprietary trading purposes. Proprietary trading includes all contracts entered into with the intent of benefiting from shifts or changes in market prices as opposed to those entered into with the intent of hedging or managing risk. Proprietary trading activities are subject to limits established by Exelon’s RMC. The proprietary trading activities, which included settled physical sales volumes of 2,601 GWhs and 6,763 GWhs for the three and nine months endedmaterial at September 30, ~~2017, respectively,~~2023 and ~~1,506 GWhs~~December 31, 2022.

The fair value of derivative economic hedges is presented in Other current assets and ~~4,015 GWhs~~current and ~~for the three~~noncurrent Mark-to-market derivative liabilities in Exelon's and nine months September 30, 2016, respectively, are a complement to Generation’s energy marketing portfolio but represent a small portion of Generation’s revenue from energy marketing activities. ComEd, PECO, BGE, PHI, Pepco, DPL and ACE do not enter into derivatives for proprietary trading purposes.ComEd's Consolidated Balance Sheets.

Interest Rate and ~~Foreign Exchange~~Other Risk ~~(All Registrants)~~(Exelon)

~~The Registrants use~~Exelon Corporate uses a combination of fixed-rate and variable-rate debt to manage interest rate exposure. ~~The Registrants utilize fixed-to-floating interest rate swaps, which are typically designated as fair value hedges, as a means to manage their interest rate exposure. In addition, the Registrants~~Exelon Corporate may utilize interest rate derivatives to lock in rate levels in anticipation of future financings, which are typically designated as cash flow hedges. ~~These strategies are employed~~In addition, Exelon Corporate may also utilize interest rate swaps to manage interest rate ~~risks. At September 30, 2017, Exelon had $800 million of notional amounts of fixed-to-floating hedges outstanding,~~exposure and ~~Exelon and Generation had $491 million of notional amounts of floating-to-fixed hedges outstanding. To~~ manage ~~foreign exchange rate exposure associated with international energy purchases~~potential fluctuations in ~~currencies other than U.S. dollars, Generation utilizes foreign currency derivatives,~~Electric operating revenues at the corporate level in consolidation, which are ~~typically designated~~directly correlated to yields on U.S. Treasury bonds under ComEd's distribution formula rate. These interest rate swaps are accounted for as economic hedges. ~~Below is a summary of the interest rate and foreign exchange hedge balances as of September 30, 2017:~~A hypothetical 50

Generation Exelon Corporate Exelon
Description
Derivatives
Designated
as Hedging
Instruments

Economic
Hedges

Proprietary
Trading(a)

Collateral
and
Netting(b)
Subtotal
Derivatives
Designated
as Hedging
Instruments
Total
Mark-to-market derivative assets (current assets) $ —
$ 15
$ —
$ (10 ) $ 5
$ —
$ 5
Mark-to-market derivative assets (noncurrent assets) —
1
—
(1 ) —
10
10
Total mark-to-market derivative assets —
16
—
(11 ) 5
10
15
Mark-to-market derivative liabilities (current liabilities) —
(17 ) —
9
(8 ) —
(8 )
Mark-to-market derivative liabilities (noncurrent liabilities) —
(2 ) —
1
(1 ) —
(1 )
Total mark-to-market derivative liabilities —
(19 ) —
10
(9 ) —
(9 )
Total mark-to-market derivative net assets (liabilities) $ —
$ (3 ) $ —
$ (1 ) $ (4 ) $ 10
$ 6

~~__________~~

~~(a)~~

Generation enters into interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions. The characterization of the interest rate derivative contracts between the proprietary trading activity in the above table is driven by the corresponding characterization of the underlying commodity position that gives rise to the interest rate exposure. Generation does not utilize proprietary trading interest rate derivatives with the objective of benefiting from shifts or changes in market interest rates.

~~(b)~~

Exelon and Generation net all available amounts allowed under the derivative accounting guidance on 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 counterparty exposures subject to a master netting or similar agreement, such as accrued interest, transactions that do not qualify as derivatives, letters of credit and other forms of non-cash collateral. These are not reflected in the table above.

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

Note 9 — Derivative Financial Instruments

~~The following table provides~~basis point change in the interest rates associated with Exelon's interest rate swaps as of September 30, 2023 would result in an immaterial impact to Exelon's Consolidated Net Income.

Below is a summary of the interest rate ~~and foreign exchange~~ hedge balances ~~recorded by the Registrants as of~~ at September 30, 2023 and December 31, ~~2016:~~2022.


	September 30, 2023
	Derivatives Designated as Hedging Instruments		Economic Hedges		Total
Other current assets	$	—	$	3	$	3
Other deferred debits (noncurrent assets)	41		—		41
Total derivative assets	41		3		44
Mark-to-market derivative liabilities (current liabilities)	—		(23)		(23)

Total mark-to-market derivative liabilities	—		(23)		(23)
Total mark-to-market derivative net assets (liabilities)	$	41	$	(20)	$	21

Generation Exelon Corporate Exelon
Description
Derivatives
Designated
as Hedging
Instruments

Economic
Hedges

Proprietary
Trading^(a)

Collateral
and
Netting^(b)
Subtotal
Derivatives
Designated
as Hedging
Instruments
Total
Mark-to-market derivative assets (current assets) $ —
$ 17
$ 4
$ (13 ) $ 8
$ —
$ 8
Mark-to-market derivative assets (noncurrent assets) —
11
1
(8 ) 4
16
20
Total mark-to-market derivative assets —
28
5
(21 ) 12
16
28
Mark-to-market derivative liabilities (current liabilities) (7 ) (13 ) (2 ) 14
(8 ) —
(8 )
Mark-to-market derivative liabilities (noncurrent liabilities) (3 ) (8 ) (2 ) 9
(4 ) —
(4 )
Total mark-to-market derivative liabilities (10 ) (21 ) (4 ) 23
(12 ) —
(12 )
Total mark-to-market derivative net assets (liabilities) $ (10 ) $ 7
$ 1
$ 2
$ —
$ 16
$ 16


	December 31, 2022
	Derivatives Designated as Hedging Instruments		Economic Hedges		Total

Other deferred debits (noncurrent assets)	$	6	$	5	$	11
Total derivative assets	6		5		11
Mark-to-market derivative liabilities (current liabilities)	—		(3)		(3)
Mark-to-market derivative liabilities (noncurrent liabilities)	(4)		—		(4)
Total mark-to-market derivative liabilities	(4)		(3)		(7)
Total mark-to-market derivative net assets	$	2	$	2	$	4

~~__________~~Cash Flow Hedges (Interest Rate Risk)

~~(a)~~

~~(b)~~

~~Fair Value Hedges~~. For derivative instruments that qualify and are designated ~~and qualify~~ as cash flow hedges, the changes in fair value ~~hedges,~~each period are initially recorded in AOCI and reclassified into earnings when the ~~gain or loss~~underlying transaction affects earnings. In January 2023, Exelon Corporate entered into $115 million notional of 5-year maturity floating-to-fixed swaps and $115 million notional of 10-year maturity floating-to-fixed swaps, for a total of $230 million designated as cash flow hedges. In February 2023, Exelon terminated the previously issued floating-to-fixed swaps with a total notional of $1.5 billion upon issuance of $2.5 billion of debt. See Note 10 – Debt and Credit Agreements for additional information on the ~~derivative as well as the offsetting loss or gain on the hedged item attributable~~debt issuance. Prior to the ~~hedged risk are recognized~~termination, the AOCI derivative gain was $7 million (net of tax). The settlements resulted in ~~current earnings.~~a cash receipt of $10 million, which is being amortized into Interest expense in Exelon's Consolidated Statement of Operations and Comprehensive Income over the 5-year and 10-year terms of the swaps.

Since the termination in February 2023, Exelon ~~includes~~has entered into additional floating-to-fixed swaps. The following table provides the ~~gain or loss on the hedged items and the offsetting loss or gain on the related interest rate swaps in interest expense as follows:~~

Three Months Ended September 30,

Income Statement
Location
2017 2016 2017 2016

Gain (loss) on Swaps Gain (loss) on Borrowings
Exelon Interest expense $ (2 ) $ (8 ) $ 6
$ 14


Nine Months Ended September 30,

Income Statement
Location
2017 2016 2017 2016

Gain (loss) on Swaps Gain (loss) on Borrowings
Exelon Interest expense $ (6 ) $ 15
$ 17
$ (3 )

Atnotional amounts outstanding held by Exelon at September 30, ~~2017, Exelon had total outstanding fixed-to-floating fair value hedges related to interest rate swaps of $800 million, with a derivative asset of $10 million. At~~2023 and December 31, ~~2016, Exelon had total outstanding fixed-to-floating fair value hedges~~2022.


	September 30, 2023		December 31, 2022
5-year maturity floating-to-fixed swaps	$	390	$	635
10-year maturity floating-to-fixed swaps	390		635
Total	$	780	$	1,270

The related ~~to interest rate swaps of $800 million, with a~~AOCI derivative ~~asset of $16 million. During~~gain for the three and nine months ended as of September 30, ~~2017 and 2016, the impact on the results of operations as a result of ineffectiveness from fair value hedges~~2023 was ~~a $4 million gain, a $11 million gain, a $6 million gain, and a $12 million gain, respectively.~~

~~Cash Flow Hedges. During the first and second quarter of 2016, Exelon entered into $600~~$22 million and ~~$100~~$31 million (net of floating-to-fixed forward starting interest rate swaps, respectively, to manage a portion of the interest rate exposure associated with an anticipated debt issuance. The swaps were designated as cash flow hedges. Exelon terminated the swaps during the second quarter of 2016 upon issuance of the debt. Exelon recognized a loss of $3 million related to the swapstax). See Note 14 – Changes in Accumulated Other Comprehensive Income (Loss) for additional information.

Economic Hedges (Interest Rate and ~~$3 million of AOCI will be amortized into~~ Other ~~net in Exelon's Consolidated Statement~~

Risk)

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

Note 9 — Derivative Financial Instruments

~~of Operations and Comprehensive Income over the term of the debt. See Note 11— Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.~~

~~During the first quarter of 2016,~~ Exelon entered into a $100 million floating-to-fixed forward starting interest rate swaps to manage a portion of the interest rate exposure associated with an anticipated debt issuance. The swap was designated as a cash flow hedge. Exelon terminated the swap during the first quarter of 2016 upon issuance of the debt. Exelon did not recognize a gain or loss as a result of the termination of the swap and an immaterial amount of AOCI will be amortized into Other, net in Exelon's Consolidated Statement of Operations and Comprehensive Income over the term of the debt.

During the first quarter of 2014, EGR, a subsidiary of Generation, entered into floating-to-fixed interest rate swaps to manage a portion of its interest rate exposure in connection with its long-term borrowings. The swaps were de-designated as cash flow hedges and, during the second quarter of 2017, upon termination of the debt, Generation terminated the swaps. The total notional amount of the swaps was $164 million. No gain or loss was recognized as a result of the termination of the swaps. See Note 11 — Debt and Credit Agreements for additional information.

During the three and nine months ended September 30, 2017 and 2016, the impact on the results of operations as a result of ineffectiveness from cash flow hedges in continuing designated hedge relationships was immaterial.

~~Economic Hedges~~. During the third quarter of 2014, EGTP, a subsidiary of Generation, entered into a floating-to-fixed interest rate swap to manage a portion of its interest rate exposure in connection with the long-term borrowing. See Note 14 —Debt and Credit Agreements of the Exelon 2016 Form 10-K for additional information regarding the financing. The swaps have a notional amount of $491 million as of September 30, 2017 and expire in 2019. The swap was designated as a cash flow hedge in the fourth quarter of 2014. During the first quarter of 2017, the swap was de-designated. At September 30, 2017, the subsidiary had a $6 million derivative liability related to the swap. During the three and nine months ended September 30, 2017, a gain of $2 million and a loss of $2 million related to the swap, respectively, were recorded to Interest expense.

During the third quarter of 2011, Sacramento PV Energy, a subsidiary of Generation entered into floating-to-fixed interest rate swaps to manage a portion of its interest rate exposure in connection with the long-term borrowings. See Note 14 — Debt and Credit Agreements of the Exelon 2016 Form 10-K for additional information regarding the financing. During the first quarter of 2016, upon the termination of debt, Generation terminated the swaps. The total notional amount of the swaps was $25 million. No gain or loss was recognized as a result of the termination of the swaps.

During the third quarter of 2012, Constellation Solar Horizons, a subsidiary of Generation, entered into a floating-to-fixed interest rate swap to manage a portion of its interest rate exposure in connection with the long-term borrowings. See Note 14 — Debt and Credit Agreements of the Exelon 2016 Form 10-K for additional information regarding the financing. During the first quarter of 2016, upon the termination of debt, Generation terminated the swap. The total notional amount of the swap was $24 million. No gain or loss was recognized as a result of the termination of the swap.

At September 30, 2017, Generation had immaterial notional amounts of interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions and $111 million in notional amounts of foreign currency exchange rate swaps that are marked-to-market to manage the exposure associated with international purchases of commodities in currencies other than U.S. dollars.

~~Fair Value Measurement and Accounting for the Offsetting of Amounts Related to Certain Contracts (Exelon, Generation, ComEd, PECO, BGE, PHI and DPL)~~

~~Fair value accounting guidance and disclosures about offsetting assets and liabilities requires the fair value of~~Corporate executes derivative instruments to be shown in the Notes to the 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 Sheet. 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. Generation’s use of cash collateral is generally unrestricted, unless Generation is downgraded below investment grade (i.e., to BB+ or Ba1). In the table below, 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 column. As of September 30, 2017 and December 31, 2016, $3

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~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

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

million and $8 million of cash collateral held, respectively, was not offset against derivative positions because such collateral was not associated with any energy-related derivatives, were associated with accrual positions, or as of the balance sheet date there were no positions to offset. Excluded from the tables below are economic hedges that qualify for the NPNS scope exception and other non-derivative contracts that are accounted for under the accrual method of accounting.

~~ComEd’s use of cash collateral is generally unrestricted unless ComEd is downgraded below investment grade (i.e., to BB+ or Ba1).~~

~~Cash collateral held by PECO and BGE must be deposited in a non affiliate major U.S. commercial bank or foreign bank with a U.S. branch office that meet certain qualifications.~~

In the table below, DPL's economic hedges 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 column.

~~The following table provides a summary of the derivative fair value balances recorded by the Registrants as of September 30, 2017:~~

Successor
Generation ComEd DPL PHI Exelon
Derivatives
Economic
Hedges

Proprietary
Trading

Collateral
and
Netting^{(a) (e)}

Subtotal^(b)

Economic
Hedges^(c)

Economic
Hedges^(d)

Collateral
and
Netting^(a)
Subtotal Subtotal
Total
Derivatives
Mark-to-market derivative assets (current assets) $ 2,608
$ 55
$ (1,969 ) $ 694
$ —
$ —
$ —
$ —
$ —
$ 694
Mark-to-market derivative assets (noncurrent assets) 1,583
30
(1,197 ) 416
—
—
—
—
—
416
Total mark-to-market derivative assets 4,191

85
(3,166 ) 1,110
—
—
—
—

—
1,110
Mark-to-market derivative liabilities (current liabilities) (2,334 ) (46 ) 2,230
(150 ) (20 ) —
—
—
—
(170 )
Mark-to-market derivative liabilities (noncurrent liabilities) (1,476 ) (27 ) 1,351
(152 ) (257 ) —
—
—
—
(409 )
Total mark-to-market derivative liabilities (3,810 ) (73 ) 3,581
(302 ) (277 ) —
—
—

—
(579 )
Total mark-to-market derivative net assets (liabilities) $ 381
$ 12
$ 415
$ 808
$ (277 ) $ —
$ —
$ —

$ —
$ 531

~~_________~~

~~(a)~~

Exelon, Generation, PHI and DPL net all available amounts allowed under the derivative accounting guidance on 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 are not reflected in the table above.


~~(b)~~	Current and noncurrent assets are shown net of collateral of $123 million and $61 million, respectively, and current and noncurrent liabilities are shown net of collateral of $138 million and $93 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $415 million at September 30, 2017.


~~(c)~~	~~Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.~~


~~(d)~~	~~Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC.~~


~~(e)~~	~~Of the collateral posted/(received), $27 million represents variation margin on the exchanges.~~

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~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

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

~~The following table provides a summary of the derivative fair value balances recorded by the Registrants as of December 31, 2016:~~

Successor
Generation ComEd DPL PHI Exelon
Description
Economic
Hedges

Proprietary
Trading

Collateral
and
Netting^{(a) (e)}

Subtotal^(b)

Economic
Hedges^(c)

Economic
Hedges^(d)

Collateral and
Netting^(a)
Subtotal Subtotal Total
Derivatives
Mark-to-market derivative assets (current assets) $ 3,623
$ 55
$ (2,769 ) $ 909
$ —
$ 2
$ (2 ) $ —
$ —
$ 909
Mark-to-market derivative assets (noncurrent assets) 1,467
21
(1,016 ) 472
—
—
—
—
—
472
Total mark-to-market derivative assets 5,090
76
(3,785 ) 1,381
—
2
(2 ) —
—
1,381
Mark-to-market derivative liabilities (current liabilities) (3,165 ) (54 ) 2,964
(255 ) (19 ) —
—
—
—
(274 )
Mark-to-market derivative liabilities (noncurrent liabilities) (1,274 ) (25 ) 1,150
(149 ) (239 ) —
—
—
—
(388 )
Total mark-to-market derivative liabilities (4,439 ) (79 ) 4,114
(404 ) (258 ) —
—
—
—
(662 )
Total mark-to-market derivative net assets (liabilities) $ 651
$ (3 ) $ 329
$ 977
$ (258 ) $ 2
$ (2 ) $ —
$ —
$ 719

~~_________~~

~~(a)~~

Exelon, Generation, PHI and DPL net all available amounts allowed under the derivative accounting guidance on 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, and letters of credit and other forms of non-cash collateral. These are not reflected in the table above.


~~(b)~~	Current and noncurrent assets are shown net of collateral of $100 million and $72 million, respectively, and current and noncurrent liabilities are shown net of collateral of $95 million and $62 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $329 million at December 31, 2016.


~~(c)~~	~~Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.~~


~~(d)~~	~~Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC.~~


~~(e)~~	~~Of the collateral posted/(received), $(158) million represents variation margin on the exchanges.~~

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~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

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

~~Cash Flow Hedges (Exelon and Generation).~~ The tables below provide the activity of OCI related to cash flow hedges for the nine months ended September 30, 2017 and 2016, containing information about the changes in the fair value of cash flow hedges and the reclassification from Accumulated OCI into results of operations. The amounts reclassified from OCI, when combined with the impacts of the hedged transactions, result in the ultimate recognition of net revenues or expenses at the contractual price.

Total Cash Flow Hedge OCI Activity, Net of Income Tax
Generation Exelon
Three Months Ended September 30, 2017
Income Statement
Location
Total Cash
Flow Hedges
Total Cash
Flow Hedges

Accumulated OCI derivative loss at June 30, 2017 $ (14 ) $ (12 )
Effective portion of changes in fair value 1
1

Reclassifications from AOCI to net income Interest Expense (1 )
^(a)
(1 )
^(a)
Accumulated OCI derivative loss at September 30, 2017 $ (14 ) $ (12 )

Total Cash Flow Hedge OCI Activity, Net of Income Tax
Generation Exelon
Nine Months Ended September 30, 2017
Income Statement
Location
Total Cash
Flow Hedges Total Cash
Flow Hedges
Accumulated OCI derivative loss at December 31, 2016 $ (19 ) $ (17 )
Effective portion of changes in fair value 2

2

Reclassifications from AOCI to net income Interest Expense 3
^(b)
3
^(b)
Accumulated OCI derivative loss at September 30, 2017 $ (14 ) $ (12 )

Total Cash Flow Hedge OCI Activity, Net of Income Tax
Generation Exelon
Three Months Ended September 30, 2016
Income Statement
Location
Total Cash
Flow Hedges
Total Cash
Flow Hedges

Accumulated OCI derivative loss at June 30, 2016 $ (25 ) $ (26 )
Effective portion of changes in fair value 1

3

Accumulated OCI derivative loss at September 30, 2016 $ (24 ) $ (23 )

Total Cash Flow Hedge OCI Activity, Net of Income Tax
Generation Exelon
Nine Months Ended September 30, 2016
Income Statement
Location
Total Cash
Flow Hedges
Total Cash
Flow Hedges

Accumulated OCI derivative loss at December 31, 2015 $ (21 ) $ (19 )
Effective portion of changes in fair value —

(1 )
Reclassifications from AOCI to net income Interest Expense (3 )
^(c)
(3 )
^(c)
Accumulated OCI derivative loss at September 30, 2016 $ (24 ) $ (23 )

~~_________~~


~~(a)~~	~~Amount is net of related income tax benefit of $1 million for the three months ended September 30, 2017.~~


~~(b)~~	~~Amount is net of related income tax expense of $2 million for the nine months ended September 30, 2017.~~


~~(c)~~	~~Amount is net of related income tax expense of $2 million for the nine months ended September 30, 2016.~~

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~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

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

~~Economic Hedges (Exelon and Generation).~~ ~~These instruments represent hedges that economically~~ mitigate exposure to fluctuations in ~~commodity prices and include financial options, futures, swaps, physical forward sales and purchases,~~interest rates but for which the fair value or cash flow hedge elections were not made. ~~Additionally, Generation~~For derivatives intended to serve as economic hedges, fair value is recorded on the balance sheet and changes in fair value each period are recognized in earnings or as a regulatory asset or liability, if regulatory requirements are met, each period.

Exelon Corporate enters into floating-to-fixed interest rate ~~derivative contracts and foreign exchange currency~~cap swaps ~~("treasury")~~ to manage a portion of interest rate exposure in connection with existing borrowings. In the ~~exposure related to~~fourth quarter of 2022, Exelon Corporate entered into $1 billion notional of 18-month maturity floating-to-fixed interest rate cap swaps and $850 million notional of 6-month maturity floating-to-fixed interest rate cap swaps, for a total of $1.85 billion notional of floating-to-fixed interest rate cap swaps as of December 31, 2022. The 6-month maturity floating-to-fixed interest rate cap swaps of $850 million notional matured in March 2023. Exelon receives payments on the interest rate ~~component~~cap when the floating rate exceeds the fixed rate. Settlements received are immaterial as of ~~commodity positions~~September 30, 2023.

Additionally, to manage potential fluctuations in Electric operating revenues related to ComEd's distribution formula rate, Exelon Corporate enters into 30-year constant maturity treasury interest rate (Corporate 30-year treasury) swaps.

The following table provides the notional amounts outstanding held by Exelon at September 30, 2023 and ~~international purchases of commodities in currencies other than U.S. Dollars.~~ December 31, 2022.


Hedging Instrument	September 30, 2023		December 31, 2022
Interest rate cap swaps	$	1,000	$	1,850
Constant maturity treasury interest rate swaps	4,875		500
Total	$	5,875	$	2,350

For the three and nine months ended September 30, ~~2017 and 2016,~~2023, Exelon Corporate recognized the following net pre-tax mark-to-market ~~gains~~ (losses) ~~of certain purchase and sale contracts were reported~~which are also recognized in ~~Operating revenues or Purchased power and fuel expense, or Interest expense at Exelon and Generation in the Consolidated Statements of Operations and Comprehensive Income and are included in “Net~~Net fair value changes related to ~~derivatives”~~derivatives in ~~Exelon’s and Generation’s~~Exelon's Consolidated Statements of Cash Flows. In the tables below, “Change in fair value” represents the change in fair value of the derivative contracts held at the reporting date. The “Reclassification to realized” generally represents the recognized change in fair value that was reclassified from unrealized to realized when the transaction to which the derivative relates occurs.

Generation Exelon
Three Months Ended September 30, 2017
Operating
Revenues

Purchased
Power
and Fuel
Total Total
Change in fair value of commodity positions $ 132
$ 45
$ 177
$ 177
Reclassification to realized at settlement of commodity positions (77 ) (24 ) (101 ) (101 )
Net commodity mark-to-market gains (losses) 55
21
76
76
Change in fair value of treasury positions (3 ) —
(3 ) (3 )
Reclassification to realized at settlement of treasury positions —
—
—
—
Net treasury mark-to-market gains (losses) (3 ) —
(3 ) (3 )
Net mark-to-market gains (losses) $ 52
$ 21
$ 73
$ 73

Generation Exelon
Nine Months Ended September 30, 2017
Operating
Revenues

Purchased
Power
and Fuel
Total Total
Change in fair value of commodity positions $ 123
$ (153 ) $ (30 ) $ (30 )
Reclassification to realized of commodity positions (164 ) 39
(125 ) (125 )
Net commodity mark-to-market gains (losses) (41 ) (114 ) (155 ) (155 )
Change in fair value of treasury positions (4 ) —
(4 ) (4 )
Reclassification to realized of treasury positions (2 ) —
(2 ) (2 )
Net treasury mark-to-market gains (losses) (6 ) —
(6 ) (6 )
Net mark-to-market gains (losses) $ (47 ) $ (114 ) $ (161 ) $ (161 )

Generation Exelon
Three Months Ended September 30, 2016
Operating
Revenues

Purchased
Power
and Fuel
Total Total
Change in fair value of commodity positions $ 280
$ (73 ) $ 207
$ 207
Reclassification to realized at settlement of commodity positions (92 ) (26 ) (118 ) (118 )
Net commodity mark-to-market gains (losses) 188
(99 ) 89
89
Change in fair value of treasury positions 1
—
1
1
Reclassification to realized at settlement of treasury positions (2 ) —
(2 ) (2 )
Net treasury mark-to-market gains (losses) (1 ) —
(1 ) (1 )
Net mark-to-market gains (losses) $ 187
$ (99 ) $ 88
$ 88

~~127~~

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~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

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

Generation Exelon
Nine Months Ended September 30, 2016
Operating
Revenues

Purchased
Power
and Fuel
Total Total
Change in fair value of commodity positions $ 127
$ 36
$ 163
$ 163
Reclassification to realized of commodity positions (484 ) 217
(267 ) (267 )
Net commodity mark-to-market gains (losses) (357 ) 253
(104 ) (104 )
Change in fair value of treasury positions (3 ) —
(3 ) (3 )
Reclassification to realized of treasury positions (6 ) —
(6 ) (6 )
Net treasury mark-to-market gains (losses) (9 ) —
(9 ) (9 )
Net mark-to-market gains (losses) $ (366 ) $ 253
$ (113 ) $ (113 )

~~Proprietary Trading Activities (Exelon and Generation).~~ ~~For~~Exelon had no swaps for the three and nine months ended September 30, 2017 and 2016, Exelon and Generation recognized the following net unrealized mark-to-market gains (losses), net realized mark-to-market gains (losses) and total net mark-to-market gains (losses) before income taxes relating to mark-to-market activity on commodity derivative instruments entered into for proprietary trading purposes and interest rate and foreign exchange derivative contracts to hedge risk associated with the interest rate and foreign exchange components of underlying commodity positions. 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 “Net fair value changes related to derivatives” in Exelon’s and Generation’s Consolidated Statements of Cash Flows. In the tables below, “Change in fair value” represents the change in fair value of the derivative contracts held at the reporting date. The “Reclassification to realized” represents the recognized change in fair value that was reclassified to realized due to settlement of the derivative during the period.2022.

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Change in fair value of commodity positions $ 11
$ 4
$ 17
$ 18
Reclassification to realized of commodity positions (6 ) (6 ) (13 ) (17 )
Net commodity mark-to-market gains (losses) 5
(2 ) 4
1
Change in fair value of treasury positions (1 ) —
(2 ) (2 )
Reclassification to realized of treasury positions 1
1
1
2
Net treasury mark-to-market gains (losses) —
1
(1 ) —
Total net mark-to-market gains (losses) $ 5
$ (1 ) $ 3
$ 1


	Three Months Ended September 30, 2023		Nine Months Ended September 30, 2023
Income Statement Location	(Loss) Gain		(Loss) Gain
Electric operating revenues	$	(16)	$	(21)
Interest expense	—		1
Total	$	(16)	$	(20)

Credit Risk ~~(All Registrants)~~

The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties ~~that enter into~~on executed derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date. ~~For energy-related derivative instruments, Generation enters into enabling agreements~~The Utility Registrants have contracts to procure electric and natural gas supply 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 existprovide suppliers with a ~~counterparty that allow for cross product netting. In addition to payment netting language in~~certain amount of unsecured credit. If the ~~enabling agreement, Generation’s~~exposure on the supply contract exceeds the amount of unsecured credit, ~~department establishes credit limits, margining thresholds and collateral requirements for each counterparty, which are defined in~~ the derivative contracts. Counterparty credit limits are based on an internal credit review process that considers a variety of factors, including the results of a scoring model, leverage, liquidity, profitability, credit ratings by credit rating agencies and risk management capabilities. To the extent that a counterparty’s margining thresholds are exceeded, the counterparty issuppliers may be required to post ~~collateral with Generation as specified in each enabling agreement. Generation’s credit department monitors current and forward~~collateral. The net credit exposure is mitigated primarily by the ability to recover procurement costs through customer rates. The amount of cash collateral received from external counterparties decreased as of September 30, 2023 due to decreasing energy prices. The following table reflects the Registrants' cash collateral held from external counterparties, which is recorded in Other current liabilities on their respective Consolidated Balance Sheets, at September 30, 2023 and ~~their affiliates, both on an individual and an aggregate basis.~~

December 31, 2022:

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 9 — Derivative Financial Instruments

~~The following tables provide information on Generation’s credit exposure for all derivative instruments, NPNS and applicable payables and receivables, net of~~


	September 30, 2023		December 31, 2022
Exelon	$	112	$	297
ComEd	105		77
PECO(a)	—		—
BGE	1		23
PHI	6		197
Pepco(b)	—		26
DPL	1		121
ACE	5		50

__________

(a)PECO had less than one million in cash collateral ~~and instruments that are subject to master netting agreements, as of~~held with external parties at September 30, ~~2017. The tables further delineate that exposure by credit rating of the counterparties~~2023 and ~~provide guidance on the concentration of credit risk to individual counterparties. The figures~~December 31, 2022.

(b)Pepco had less than one million 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. Additionally, the figures in the tables below exclude exposurescash collateral held with ~~affiliates, including net receivables with ComEd, PECO, BGE, Pepco, DPL and ACE of $18 million, $22 million~~, ~~$22 million, $34 million, $12 million, and $7 million as of~~external parties at September 30, ~~2017, respectively.~~2023.

Rating as of September 30, 2017 Total Exposure Before Credit Collateral
Credit Collateral^(a)
Net Exposure Number of Counterparties Greater than 10% of Net Exposure Net Exposure of Counterparties Greater than 10% of Net Exposure
Investment grade $ 828
$ 9
$ 819
1
$ 278
Non-investment grade 44
4
40

No external ratings
Internally rated — investment grade 316
—
316

Internally rated — non-investment grade 100
18
82

Total $ 1,288
$ 31
$ 1,257
1
$ 278

Net Credit Exposure by Type of Counterparty As of
September 30, 2017
Financial institutions $ 48
Investor-owned utilities, marketers, power producers 538
Energy cooperatives and municipalities 525
Other 146
Total $ 1,257

~~_________~~


~~(a)~~	As of September 30, 2017, credit collateral held from counterparties where Generation had credit exposure included $19 million of cash and $12 million of letters of credit. The credit collateral does not include non-liquid collateral.

~~ComEd’s power procurement contracts provide suppliers with a certain amount of unsecured credit.~~ The credit position is based on daily, updated forward market prices compared to the benchmark prices. The benchmark prices are the forward prices of energy projected through the contract term and are set at the point of supplier bid submittals. If the forward market price of energy exceeds the benchmark price on a given day, the suppliers are required to post collateral for the secured credit portion after adjusting for any unpaid deliveries and unsecured credit allowed under the contract. The unsecured credit used by the suppliers represents ComEd’s net credit exposure. As of September 30, 2017, ComEd’s net credit exposure to suppliers was less than $1 million.

ComEd is permitted to recover its costs of procuring energy through the Illinois Settlement Legislation. ComEd’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 3 — Regulatory Matters of the Exelon 2016 Form 10-K for additional information.

~~PECO’s supplier master agreements that govern the terms of its~~Utility Registrants’ electric supply procurement contracts which define a supplier’s performance assurance requirements, allow a supplier to meet its credit requirements with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s lowest credit rating from the major credit rating agencies and the supplier’s tangible net worth. The credit position is based on the initial market price, which is the forward price of energy on the day a transaction is executed, compared to the current forward price curve for energy. To the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to post collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. The unsecured credit used by the suppliers represents PECO’s net credit exposure. As of September 30, 2017, PECO had no material net credit exposure to suppliers.

PECO is permitted to recover its costs of procuring electric supply through its PAPUC-approved DSP Program. PECO’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 5 — Regulatory Matters for additional information.

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

PECO’s natural gas procurement plan is reviewed and approved annually on a prospective basis by the PAPUC. PECO’s counterparty credit risk under its natural gas supply and asset management agreements is mitigated by its ability to recover its natural gas costs through the PGC, which allows PECO to adjust rates quarterly to reflect realized natural gas prices. PECO doesdo not obtain collateral from suppliers under its natural gas supply and asset management agreements. As of September 30, 2017, PECO had no material credit exposure under its natural gas supply and asset management agreements with investment grade suppliers.

BGE is permitted to recover its costs of procuring energy through the MDPSC-approved procurement tariffs. BGE’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 3 — Regulatory Matters of the Exelon 2016 Form 10-K for additional information.

BGE’s full requirement wholesale electric power agreements that govern the terms of its electric supply procurement contracts, which define a supplier’s performance assurance requirements, allow a supplier, or its guarantor, to meet its credit requirements with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s lowest credit rating from the major credit rating agencies and the supplier’s tangible net worth, subject to an unsecured credit cap. The credit position is based on the initial market price, which is the forward price of energy on the day a transaction is executed, compared to the current forward price curve for energy. To the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to post collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. The unsecured credit used by the suppliers represents BGE’s net credit exposure. The seller’s credit exposure is calculated each business day. As of September 30, 2017, BGE had no net credit exposure to suppliers.

BGE’s regulated gas business is exposed to market-price risk. This market-price risk is mitigated by BGE’s recovery of its costs to procure natural gas through a gas cost adjustment clause approved by the MDPSC. BGE does make off-system sales after BGE has satisfied its customers’ demands, which are not covered by the gas cost adjustment clause. At September 30, 2017, BGE had credit exposure of less than $1 million related to off-system sales which is mitigated by parental guarantees, letters of credit or right to offset clauses within other contracts with those third-party suppliers.

Pepco’s, DPL's and ACE's power procurement contracts provide suppliers with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s lowest credit rating from the major credit rating agencies and the supplier’s tangible net worth. The credit position is based on the initial market price, which is the forward price of energy on the day a transaction is executed, compared to the current forward price curve for energy. To the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to post collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. The unsecured credit used by the suppliers represents Pepco’s, DPL's and ACE's net credit exposure. As of September 30, 2017, Pepco’s, DPL's and ACE's net credit exposures to suppliers were immaterial.

Pepco is permitted to recover its costs of procuring energy through the MDPSC-approved and DCPSC-approved procurement tariffs. DPL is permitted to recover its costs of procuring energy through the MDPSC-approved and DPSC-approved procurement tariffs. ACE is permitted to recover its costs of procuring energy through the NJBPU-approved procurement tariffs. Pepco’s, DPL's and ACE's counterparty credit risks are mitigated by their ability to recover realized energy costs through customer rates. See Note 3 — Regulatory Matters of the Exelon 2016 Form 10-K for additional information.

DPL’s natural gas procurement plan is reviewed and approved annually on a prospective basis by the DPSC. DPL’s counterparty credit risk under its natural gas supply and asset management agreements is mitigated by its ability to recover its natural gas costs through the GCR, which allows DPL to adjust rates annually to reflect realized natural gas prices. To the extent that the fair value of the transactions in a net loss position exceeds the unsecured credit threshold, then collateral is required to be posted in an amount equal to the amount by which the unsecured credit threshold is exceeded. Exchange-traded contracts are required to be fully collateralized without regard to the credit rating of the holder. As of September 30, 2017, DPL had no credit exposure under its natural gas supply and asset management agreements with investment grade suppliers.

~~Collateral and Contingent-Related Features (All Registrants)~~

As part of the normal course of business, Generation routinely enters into physical or financially settled contracts for the purchase and sale of electric capacity, energy, fuels, emissions allowances and other energy-related products. Certain of Generation’s derivative instruments contain provisions that would require ~~Generation~~them to post collateral. ~~Generation~~

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

~~also enters into commodity transactions on exchanges (i.e., NYMEX, ICE). The exchanges act as the counterparty to each trade. Transactions on the exchanges must adhere to comprehensive collateral~~PECO’s, BGE’s, 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 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:

Credit-Risk Related Contingent Feature September 30, 2017 December 31, 2016
Gross fair value of derivative contracts containing this feature^(a)
$ (916 ) $ (960 )
Offsetting fair value of in-the-money contracts under master netting arrangements^(b)
638
627
Net fair value of derivative contracts containing this feature^(c)
$ (278 ) $ (333 )

~~_________~~


~~(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.

Generation had cash collateral posted of $460 million and letters of credit posted of $255 million and cash collateral held of $49 million and letters of credit held of $29 million as of September 30, 2017 for external counterparties with derivative positions. Generation had cash collateral posted of $347 million and letters of credit posted of $284 million and cash collateral held of $24 million and letters of credit held of $28 million at December 31, 2016 for external counterparties with derivative positions. In the event of a credit downgrade below investment grade (i.e., to BB+ by S&P or Ba1 by Moody’s), Generation would have been required to post additional collateral of $1.8 billion and $1.9 billion as of September 30, 2017 and December 31, 2016, respectively. These amounts represent the potential additional collateral required after giving consideration to offsetting derivative and non-derivative positions under master netting agreements.

Generation’s and Exelon’s interest rate swaps contain provisions that, in the event of a merger, if Generation’s debt ratings were to materially weaken, it would be in violation of these provisions, resulting in the ability of the counterparty to terminate the agreement prior to maturity. Collateralization would not be required under any circumstance. Termination of the agreement could result in a settlement payment by Exelon or the counterparty on any interest rate swap in a net liability position. The settlement amount would be equal to the fair value of the swap on the termination date. As of September 30, 2017, Generation's swaps were in a liability position with a fair value of $4 million and Exelon's swaps were in an asset position, with a fair value of $6 million.

~~See Note 26 — Segment Information of the Exelon 2016 Form 10-K for further information regarding the letters of credit supporting the cash collateral.~~

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. Under the terms of ComEd’s standard block energy contracts, collateral postings are one-sided from suppliers, including Generation, should exposures between market prices and benchmark prices exceed established unsecured credit limits outlined in the contracts. As of September 30, 2017, ComEd held approximately $10 million in

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~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

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

collateral from suppliers in association with energy procurement contracts. Under the terms of ComEd's annual renewable energy contracts, collateral postings are required to cover a fixed value for RECs only. In addition, under the terms of ComEd’s long-term renewable energy contracts, collateral postings are required from suppliers for both RECs and energy. The REC portion is a fixed value and the energy portion is one-sided from suppliers should the forward market prices exceed contract prices. As of September 30, 2017, ComEd held approximately $21 million in the form of cash and letters of credit as margin for both the annual and long-term REC obligations. If ComEd lost its investment grade credit rating as of September 30, 2017, it would have been required to post approximately $3 million of collateral to its counterparties. See Note 3 — Regulatory Matters of the Exelon 2016 Form 10-K for additional information.

~~PECO’s~~DPL’s natural gas procurement contracts contain provisions that could require PECO, BGE, and DPL to post ~~collateral. This~~ collateral ~~may be posted~~ in the form of cash or credit support, which vary by contract and counterparty, with thresholds contingent upon PECO’s, BGE's, and DPL’s credit ~~rating from the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty.~~rating. As of September 30, ~~2017,~~2023, PECO, ~~was~~BGE, and DPL were not required to post collateral for any of these agreements. If PECO, BGE, or DPL lost ~~its~~their investment grade credit rating as of September 30, ~~2017, PECO~~2023, they could have been required to post ~~approximately~~collateral to their counterparties of $20 million, ~~of collateral to its counterparties.~~

~~PECO’s supplier master agreements that govern the terms of its DSP Program contracts do not contain provisions that would require PECO to post collateral.~~

~~BGE’s full requirements wholesale power agreements that govern the terms of its electric supply procurement contracts do not contain provisions that would require BGE to post collateral.~~

BGE’s natural gas procurement contracts contain provisions that could require BGE to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon BGE’s credit rating from the major credit rating agencies. The collateral$30 million, and credit support requirements vary by contract and by counterparty. As of September 30, 2017, BGE was not required to post collateral for any of these agreements. If BGE lost its investment grade credit rating as of September 30, 2017, BGE could have been required to post approximately $28 million of collateral to its counterparties.

~~Pepco’s full requirements wholesale power agreements that govern the terms of its electric supply procurement contracts do not contain provisions that would require Pepco to post collateral.~~

~~DPL’s full requirements wholesale power agreements that govern the terms of its electric supply procurement contracts do not contain provisions that would require DPL to post collateral.~~

DPL's natural gas procurement contracts contain provisions that could require DPL to post collateral. To the extent that the fair value of the natural gas derivative transaction in a net loss position exceeds the unsecured credit threshold, then collateral is required to be posted in an amount equal to the amount by which the unsecured credit threshold is exceeded. The DPL obligations are standalone, without the guaranty of PHI. If DPL lost its investment grade credit rating as of September 30, 2017, DPL could have been required to post an additional amount of approximately $9 million, ~~of collateral to its natural gas counterparties.~~respectively.

~~ACE’s full requirements wholesale power agreements that govern the terms of its electric supply procurement contracts do not contain provisions that would require ACE to post collateral.~~

~~11.~~10. Debt and Credit Agreements (All Registrants)

Short-Term Borrowings

Exelon ~~Pepco, DPL and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and short-term notes.~~Corporate, ComEd, and BGE meet their short-term liquidity requirements primarily through the issuance of commercial paper. ~~Generation and~~ PECO ~~meet their~~meets its 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 ~~requirement~~requirements primarily through the issuance of short-term notes and borrowings from the Exelon intercompany money pool.

~~132~~

~~Table~~ The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of ~~Contents~~letters of credit.

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

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

Commercial Paper

The ~~Registrants~~following table reflects the Registrants' commercial paper programs supported by the revolving credit agreements at September 30, 2023 and December 31, 2022.


	Outstanding Commercial Paper at				Average Interest Rate on Commercial Paper Borrowings at
Commercial Paper Issuer	September 30, 2023		December 31, 2022		September 30, 2023		December 31, 2022
Exelon(a)	$	820	$	1,938	5.44	%	4.77	%
ComEd	277		427		5.42	%	4.71	%
PECO	—		239		—	%	4.71	%
BGE	59		409		5.43	%	4.81	%
PHI(b)	173		414		5.47	%	4.78	%

Pepco	—		299		—	%	4.79	%
DPL	—		115		—	%	4.76	%
ACE	173		—		5.47	%	—	%

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 10 — Debt and Credit Agreements

__________

(a)Exelon Corporate had ~~the following amounts of~~$311 million and $449 million in outstanding commercial paper borrowings ~~outstanding as of~~at September 30, ~~2017~~2023 and December 31, ~~2016:~~2022, respectively.

(b)Represents the consolidated amounts of Pepco, DPL, and ACE.

Commercial Paper Borrowings September 30, 2017 December 31, 2016
Exelon $ 118
$ 688
Generation —
620
BGE —
45
PHI 118
23
Pepco —
23
DPL 54
—
ACE 65
—
Revolving Credit Agreements

Exelon Corporate and the Utility Registrants each have a 5-year revolving credit facility. The following table reflects the credit agreements:


Borrower	Aggregate Bank Commitment		Interest Rate
Exelon Corporate	$	900	SOFR plus 1.275	%
ComEd	1,000		SOFR plus 1.000	%
PECO	600		SOFR plus 0.900	%
BGE	600		SOFR plus 0.900	%
Pepco	300		SOFR plus 1.075	%
DPL	300		SOFR plus 1.000	%
ACE	300		SOFR plus 1.075	%

Exelon Corporate and the Utility Registrants had no outstanding amounts on the revolving credit facilities as of September 30, 2023.

The Utility Registrants have credit facility agreements, arranged at minority and community banks, which are solely utilized to issue letters of credit. The facility agreements have aggregate commitments of $40 million, $40 million, $15 million, $15 million, $15 million, and $15 million, at ComEd, PECO, BGE, Pepco, DPL, and ACE, respectively. These facilities expire on October 4, 2024.

See Note 16 — Debt and Credit Agreements of the 2022 Form 10-K for additional information on the Registrants' credit facilities.

Short-Term Loan Agreements

On ~~January 13, 2016, PHI~~March 23, 2017, Exelon Corporate entered into a ~~$500 million~~ term loan agreement ~~which~~for $500 million. The loan agreement was ~~amended~~renewed in the first quarter of 2023 and was bifurcated into two tranches of $300 million on March ~~28, 2016.~~14, 2023 and $200 million on March 24, 2023. The ~~net proceeds of the loan were used to repay PHI's outstanding commercial paper,~~agreements will expire on March 14, 2024 and ~~for general corporate purposes.~~March 22, 2024, respectively. Pursuant to the loan ~~agreement, as amended,~~agreements, loans made thereunder bear interest at a variable rate equal to ~~LIBOR~~SOFR plus 1%, and all indebtedness thereunder is unsecured. On March 23, 2017, the aggregate principal amount of all loans, together with any accrued but unpaid interest due under the loan agreement was fully repaid and the loan terminated. On March 23, 2017, Exelon Corporate entered into a similar type term loan for $500 million which expires on March 22, 2018. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 1%0.90% and all indebtedness thereunder is unsecured. The loan agreement is reflected in ~~Exelon’s~~Exelon's Consolidated Balance ~~Sheet~~Sheets within ~~Short-Term~~Short-term borrowings.

~~Credit Agreements~~

On ~~January 9, 2017, the credit~~October 4, 2022, ComEd entered into a 364-day term loan agreement for ~~Generation's $75~~$150 million ~~bilateral credit facility~~with a variable rate equal to SOFR plus 0.75% and an expiration date of October 3, 2023. The proceeds from this loan were used to repay outstanding commercial paper obligations. The balance of the loan was ~~amended and restated to increase~~repaid on January 13, 2023 in conjunction with the ~~facility size to $100~~$400 million and ~~extend~~$575 million First Mortgage Bond agreements that were entered into on January 3, 2023. Refer to the ~~maturity to January 2019. This facility will solely be used by Generation to issue letters~~Issuance of ~~credit.~~Long-Term Debt table below for further information.

On May ~~26, 2016, Exelon Corporate, Generation,~~9, 2023, ComEd ~~PECO and BGE~~ entered into ~~amendments~~a 364-day term loan agreement for $400 million with a variable rate equal 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, DPLSOFR plus 1.00% 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~~expiration date of ~~the facility~~May 7, 2024. The proceeds from this loan were used 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~~repay outstanding commercial paper obligations and (iv) converted its financial covenant from a debt to capitalization leverage ratio to an interest coverage ratio. On May 26, 2017, each of the Registrants' respective syndicated revolving credit facilities had their maturity dates extended to May 26, 2022.

for general corporate purposes. The loan agreement is reflected in Exelon's and ComEd's Consolidated Balance Sheets within Short-term borrowings.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 10 — Debt and Credit Agreements

Long-Term Debt

Issuance of Long-Term Debt

During the nine months ended September 30, ~~2017,~~2023, the following long-term debt was issued:

Company

Type

Interest Rate

Maturity

Amount

Use of Proceeds

Exelon

Notes

5.15%

March 15, 2028

$1,000

Repay existing indebtedness and for general corporate purposes.

Exelon

Notes

5.30%

March 15, 2033

850

Repay existing indebtedness and for general corporate purposes.

Exelon

Notes

5.60%

March 15, 2053

650

Repay existing indebtedness and for general corporate purposes.

ComEd

First Mortgage Bonds, Series 134

4.90%

February 1, 2033

400

Repay outstanding commercial paper obligations and to fund other general corporate purposes.

ComEd

First Mortgage Bonds Series 135

5.30%

February 1, 2053

575

Repay outstanding commercial paper obligations and to fund other general corporate purposes.

PECO

First and Refunding Mortgage Bonds

4.90%

June 15, 2033

575

Refinance existing indebtedness, refinance outstanding commercial paper obligations, and for general corporate purposes.

BGE

Notes

5.40%

June 1, 2053

700

Repay outstanding commercial paper obligations, repay existing indebtedness, and for general corporate purposes.

Pepco

First Mortgage Bonds

5.30%

March 15, 2033

Repay existing indebtedness and for general corporate purposes.

Pepco

First Mortgage Bonds

5.40%

March 15, 2038

Repay existing indebtedness and for general corporate purposes.

Pepco

First Mortgage Bonds

5.57%

March 15, 2053

125

Repay existing indebtedness and for general corporate purposes.

Pepco

First Mortgage Bonds

5.35%

September 13, 2033

100

Repay existing indebtedness and for general corporate purposes.

DPL(a)

First Mortgage Bonds

5.30%

March 15, 2033

Repay existing indebtedness and for general corporate purposes.

DPL

First Mortgage Bonds

5.57%

March 15, 2053

Repay existing indebtedness and for general corporate purposes.

ACE

First Mortgage Bonds

5.57%

March 15, 2053

Repay existing indebtedness and for general corporate purposes.

Company Type Interest Rate Maturity Amount Use of Proceeds
Exelon
Junior Subordinated Notes^(a)
3.50 % June 1, 2022 $ 1,150
Refinance Exelon's Junior Subordinated Notes issued in June 2014.
Generation Albany Green Energy Project Financing LIBOR + 1.25%
November 17, 2017 $ 14
Albany Green Energy biomass generation development.
Generation Energy Efficiency Project Financing 3.90 % February 1, 2018 $ 17
Funding to install energy conservation measures for the Naval Station Great Lakes project.
Generation Energy Efficiency Project Financing 2.61 % September 30, 2018 $ 10
Funding to install energy conservation measures for the Pensacola project.
Generation Energy Efficiency Project Financing 3.53 % April 1, 2019 $ 8
Funding to install energy conservation measures for the State Department project.
Generation Energy Efficiency Project Financing 3.72 % May 1, 2018 $ 4
Funding to install energy conservation measures for the Smithsonian Zoo project.
Generation Senior Notes 2.95 % January 15, 2020 $ 250
Repay outstanding commercial paper obligations and for general corporate purposes.
Generation Senior Notes 3.40 % March 15, 2022 $ 500
Repay outstanding commercial paper obligations and for general corporate purposes.
Generation ExGen Texas Power Nonrecourse Debt LIBOR + 4.75%
September 18, 2021 $ 6
Funding for general corporate purposes.
ComEd First Mortgage Bonds, Series 122 2.95 % August 15, 2027 $ 350
Refinance maturing first mortgage bonds, to repay a portion of ComEd’s outstanding commercial paper obligations and for general corporate purposes.
ComEd First Mortgage Bonds, Series 123 3.75 % August 15, 2047 $ 650
Refinance maturing first mortgage bonds, to repay a portion of ComEd’s outstanding commercial paper obligations and for general corporate purposes.
PECO First and Refunding Mortgage Bonds 3.70 % September 15, 2047 $ 325
General corporate purposes.
BGE Notes 3.75 % August 15, 2047 $ 300
Redeem $250 million in principal amount of the 6.20% Deferrable Interest Subordinated Debentures due October 15, 2043 issued by BGE's affiliate BGE Capital Trust II, repay commercial paper obligations and for general corporate purposes.
Pepco Energy Efficiency Project Financing 3.30 % December 15, 2017 $ 2
Funding to install energy conservation measures for the DOE Germantown project.
Pepco First Mortgage Bonds 4.15 % March 15, 2043 $ 200
Funding to repay outstanding commercial paper and for general corporate purposes.
__________

~~_________~~


~~(a)~~	~~See the Junior Subordinated Notes discussion below for further information.~~

~~EGTP Nonrecourse Debt~~(a)On March 15, 2023, DPL entered into a purchase agreement of First Mortgage Bonds of $340 million, $75 million, and $110 million at 5.45%, 5.55% and 5.72% due on November 8, 2033, November 8, 2038, and November 8, 2053, respectively. The closing date of the issuance is expected to occur in November 2023.

In September 2014, EGTP, an indirect subsidiary of Exelon and Generation, issued $675 million aggregate principal amount of a nonrecourse senior secured term loan. The net proceeds were distributed to Generation for general business purposes. The loan is scheduled to mature on September 18, 2021. The term loan bears interest at a variable rate equal to LIBOR plus 4.75%, subject to a 1% LIBOR floor with interest payable quarterly. Debt Covenants

As of September 30,

2023, the Registrants are in compliance with debt covenants.

~~134~~

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 11 — Fair Value of Financial Assets and Liabilities

~~2017, $660 million was outstanding. As part~~11. Fair Value of Financial Assets and Liabilities (All Registrants)

Exelon measures and classifies 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 ~~agreement, a revolving credit facility was established~~reporting date.

•Level 2 — inputs other than quoted prices included within Level 1 that are directly observable for the ~~amount of $20 million available~~asset or liability or indirectly observable through ~~and scheduled~~corroboration with observable market data.

•Level 3 — unobservable inputs, such as internally developed pricing models or third-party valuations for the asset or liability due to ~~mature on September 18, 2019. In addition~~little or no market activity for the asset or liability.

Exelon’s valuation techniques used to measure the ~~financing, EGTP entered into various interest rate swaps with an initial notional amount of approximately $505 million at an interest rate of 2.34% to hedge a portion~~fair value of the ~~interest rate exposure in connection with this financing, as required by the debt covenants. See Note 10 — Derivative Financial Instruments for additional information regarding interest rate swaps.~~

~~On May 2, 2017, EGTP entered into a consent agreement with its lenders, which resulted~~assets and liabilities shown in the ~~outstanding~~tables below are in accordance with the policies discussed in Note 17 — Fair Value of Financial Assets and Liabilities of the 2022 Form 10-K.

Fair Value of Financial Liabilities Recorded at Amortized Cost

The following tables present the carrying amounts and fair values of the Registrants’ short-term liabilities, long-term debt, ~~balance being classified as Long-term~~and trust preferred securities (long-term debt ~~due within one year on Exelon's and Generation's Consolidated Balance Sheets. See Note 4 - Mergers, Acquisitions and Dispositions and Note 6 - Impairment of Long-Lived Assets for more information.~~

~~Junior Subordinated Notes~~

~~In June 2014, Exelon issued $1.15 billion of~~to financing trusts or junior subordinated notes in the form of 23 million equity units at a stated amount of $50.00 per unit. Each equity unit represented an undivided beneficial ownership interest in Exelon’s $1.15 billion of 2.50% junior subordinated notes due in 2024 (“2024 notes”) and a forward equity purchase contract. As contemplated in the June 2014 equity unit structure, in April 2017, Exelon completed the remarketing of the 2024 notes into $1.15 billion of 3.497% junior subordinated notes due in 2022 (“Remarketing”). Exelon conducted the Remarketing on behalf of the holders of equity units and did not directly receive any proceeds therefrom. Instead, the former holders of the 2024 notes used debt remarketing proceeds towards settling the forward equity purchase contract with Exelon on June 1, 2017. Exelon issued approximately 33 million shares of common stock from treasury stock and received $1.15 billion upon settlement of the forward equity purchase contract. When reissuing treasury stock Exelon uses the average price paid to repurchase shares to calculate a gain or loss on issuance and records gains or losses directly to retained earnings. A loss on reissuance of treasury shares of $1.05 billion was recorded to retained earningsdebentures) as of September 30, ~~2017. See Note 17 - Earnings Per Share~~2023 and ~~Equity for further information on~~December 31, 2022. The Registrants have no financial liabilities measured using the ~~issuance of common stock.~~NAV practical expedient.

~~Albany Green Energy Project~~

During the third quarter of 2017, upon completion of AGE, Generation retired $228 million of its LIBOR + 1.25% outstanding debt balance, which included $6 million of accumulated interest. Pursuant to the financing terms entered into by AGE in the second quarter of 2015, the entire financing balance plus accumulated interest was due upon substantial completion, but no later than November 17, 2017. See Note 3 - Variable Interest Entities for more details regarding AGE.

~~BGE Redemption of Trust Preferred Securities~~

~~On August 28, 2017, BGE redeemed all~~The carrying amounts of the ~~outstanding shares~~Registrants’ short-term liabilities as presented in their Consolidated Balance Sheets are representative of ~~BGE Capital Trust II 6.20% Preferred Securities (“Securities”), pursuant to the optional redemption provisions~~their fair value (Level 2) because of the ~~Indenture under~~short-term nature of these instruments.


	September 30, 2023										December 31, 2022
	Carrying Amount		Fair Value								Carrying Amount		Fair Value
			Level 1		Level 2		Level 3		Total				Level 1		Level 2		Level 3		Total
Long-Term Debt, including amounts due within one year(a)
Exelon	$	41,085	$	—	$	31,584	$	2,675	$	34,259	$	37,074	$	—	$	29,902	$	2,327	$	32,229
ComEd	11,484		—		9,343		—		9,343		10,518		—		9,006		—		9,006
PECO	5,133		—		4,110		—		4,110		4,612		—		3,864		50		3,914
BGE	4,601		—		3,735		—		3,735		4,207		—		3,613		—		3,613
PHI	8,637		—		4,352		2,675		7,027		8,120		—		4,507		2,277		6,784
Pepco	4,095		—		2,129		1,473		3,602		3,751		—		2,229		1,205		3,434
DPL	2,060		—		1,126		543		1,669		1,938		—		1,164		458		1,622
ACE	1,833		—		893		659		1,552		1,757		—		909		614		1,523
Long-Term Debt to Financing Trusts
Exelon	$	390	$	—	$	—	$	384	$	384	$	390	$	—	$	—	$	384	$	384
ComEd	205		—		—		206		206		205		—		—		204		204
PECO	184		—		—		179		179		184		—		—		180		180

__________

(a)Includes unamortized debt issuance costs, unamortized debt discount and premium, net, purchase accounting fair value adjustments, and finance lease liabilities which are not fair valued. Refer to Note 16 — Debt and Credit Agreements of the ~~Securities were issued. The redemption price per share was $25.19, which equaled~~2022 Form 10-K for unamortized debt issuance costs, unamortized debt discount and premium, net, and purchase accounting fair value adjustments and Note 10 — Leases of the stated value per share plus accrued and unpaid dividends to, but excluding, the redemption date. No dividends on the Securities redeemed were accrued on or after the redemption date, nor did any interest accrue on amounts held to pay the redemption price.2022 Form 10-K for finance lease liabilities.

~~135~~

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 11 — Fair Value of Financial Assets and Liabilities

~~12. Income Taxes (All Registrants)~~Recurring Fair Value Measurements

The ~~effective income tax rate from continuing operations varies from~~following tables present assets and liabilities measured and recorded at fair value in the ~~U.S. Federal statutory rate principally due to~~Registrants' Consolidated Balance Sheets on a recurring basis and their level within the ~~following:~~fair value hierarchy at September 30, 2023 and December 31, 2022. The Registrants have no financial assets or liabilities measured using the NAV practical expedient:

Exelon


	At September 30, 2023						At December 31, 2022
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Cash equivalents(a)	$	649	$	—	$	—	$	649	$	664	$	—	$	—	$	664
Rabbi trust investments
Cash equivalents	66		—		—		66		62		—		—		62
Mutual funds	53		—		—		53		49		—		—		49
Fixed income	—		7		—		7		—		7		—		7
Life insurance contracts	—		60		42		102		—		58		40		98
Rabbi trust investments subtotal	119		67		42		228		111		65		40		216

Interest rate derivative assets
Derivatives designated as hedging instruments	—		41		—		41		—		6		—		6
Economic hedges	—		3		—		3		—		5		—		5
Interest rate derivative assets subtotal	—		44		—		44		—		11		—		11
Total assets	768		111		42		921		775		76		40		891
Liabilities
Commodity derivative liabilities	—		—		(134)		(134)		—		—		(84)		(84)
Interest rate derivative liabilities
Derivatives designated as hedging instruments	—		—		—		—		—		(4)		—		(4)
Economic hedges	—		(23)		—		(23)		—		(3)		—		(3)
Interest rate derivative liabilities subtotal	—		(23)		—		(23)		—		(7)		—		(7)
Deferred compensation obligation	—		(69)		—		(69)		—		(75)		—		(75)
Total liabilities	—		(92)		(134)		(226)		—		(82)		(84)		(166)
Total net assets (liabilities)	$	768	$	19	$	(92)	$	695	$	775	$	(6)	$	(44)	$	725

__________

(a)Exelon excludes cash of $188 million and $345 million at September 30, 2023 and December 31, 2022, respectively, and restricted cash of $110 million and $81 million at September 30, 2023 and December 31, 2022, respectively, and includes long-term restricted cash of $212 million and $117 million at September 30, 2023 and December 31, 2022, respectively, which is reported in Other deferred debits and other assets in the Consolidated Balance Sheets.

Three Months Ended September 30, 2017
Successor
Exelon
Generation
ComEd
PECO
BGE PHI Pepco DPL ACE
U.S. Federal statutory rate 35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit 2.2 5.6 6.6 (0.1) 5.3 5.1 2.2 5.3 5.6
Qualified nuclear decommissioning trust fund income 2.6 5.8 — — — — — — —
Amortization of investment tax credit, including deferred taxes on basis difference
(1.1) (2.2) (0.2) (0.1) (0.1) (0.2) (0.1) (0.2) (0.4)
Plant basis differences (2.6) — (0.3) (14.6) (0.8) (4.9) (6.7) (1.9) (3.4)
Production tax credits and other credits (2.2) (4.8) — — — — — — —
Noncontrolling interests 0.5 1.0 — — — — — — —
FitzPatrick bargain purchase gain (0.2) (0.4) — — — — — — —
Other (0.1) 0.3 (0.2) (0.2) (0.2) 0.2 — (0.2) 0.1
Effective income tax rate 34.1% 40.3% 40.9% 20.0% 39.2% 35.2% 30.4% 38.0% 36.9%

Three Months Ended September 30, 2016
Successor
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
U.S. Federal statutory rate 35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit 3.8 2.6 7.3 2.4 5.2 5.6 5.6 5.2 6.1
Qualified nuclear decommissioning trust fund income 4.0 7.8 — — — — — — —
Amortization of investment tax credit, including deferred taxes on basis difference (0.9) (1.6) (0.6) (0.1) (0.2) (0.1) — (0.2) (0.1)
Plant basis differences (3.0) — (1.9) (6.7) (0.5) (5.0) (6.7) (1.3) (4.6)
Production tax credits and other credits (2.9) (5.7) (0.1) — — — — — —
Noncontrolling interest 0.2 0.5 — — — — — — —
Statute of limitations expiration

(0.1) 0.3 — — — — — — —
Penalties 4.3 — 27.2 — — — — — —
Merger expenses

(0.6) — — — — (5.7) (2.3) (8.6) (2.9)
Other (0.8) (0.5) 0.1 0.1 (0.4) (0.7) (0.9) 0.1 (0.6)
Effective income tax rate 39.0% 38.4% 67.0% 30.7% 39.1% 29.1% 30.7% 30.2% 32.9%

~~136~~

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 11 — Fair Value of Financial Assets and Liabilities

ComEd, PECO, and BGE


	ComEd								PECO								BGE
At September 30, 2023	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Cash equivalents(a)	$	491	$	—	$	—	$	491	$	29	$	—	$	—	$	29	$	2	$	—	$	—	$	2
Rabbi trust investments

Mutual funds	—		—		—		—		9		—		—		9		9		—		—		9
Life insurance contracts	—		—		—		—		—		17		—		17		—		—		—		—
Rabbi trust investments subtotal	—		—		—		—		9		17		—		26		9		—		—		9

Total assets	491		—		—		491		38		17		—		55		11		—		—		11
Liabilities
Commodity derivative liabilities(b)	—		—		(134)		(134)		—		—		—		—		—		—		—		—
Deferred compensation obligation	—		(7)		—		(7)		—		(8)		—		(8)		—		(4)		—		(4)
Total liabilities	—		(7)		(134)		(141)		—		(8)		—		(8)		—		(4)		—		(4)
Total net assets (liabilities)	$	491	$	(7)	$	(134)	$	350	$	38	$	9	$	—	$	47	$	11	$	(4)	$	—	$	7


	ComEd								PECO								BGE
At December 31, 2022	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Cash equivalents(a)	$	392	$	—	$	—	$	392	$	10	$	—	$	—	$	10	$	23	$	—	$	—	$	23
Rabbi trust investments
Mutual funds	—		—		—		—		7		—		—		7		7		—		—		7
Life insurance contracts	—		—		—		—		—		15		—		15		—		—		—		—
Rabbi trust investments subtotal	—		—		—		—		7		15		—		22		7		—		—		7
Total assets	392		—		—		392		17		15		—		32		30		—		—		30
Liabilities
Commodity derivative liabilities(b)	—		—		(84)		(84)		—		—		—		—		—		—		—		—
Deferred compensation obligation	—		(8)		—		(8)		—		(7)		—		(7)		—		(4)		—		(4)
Total liabilities	—		(8)		(84)		(92)		—		(7)		—		(7)		—		(4)		—		(4)
Total net assets (liabilities)	$	392	$	(8)	$	(84)	$	300	$	17	$	8	$	—	$	25	$	30	$	(4)	$	—	$	26

__________

(a)ComEd excludes cash of $55 million and $42 million at September 30, 2023 and December 31, 2022, respectively, and restricted cash of $105 million and $77 million at September 30, 2023 and December 31, 2022, respectively. Additionally, ComEd includes long-term restricted cash of $212 million and $117 million at September 30, 2023 and December 31, 2022, respectively, which is reported in Other deferred debits and other assets in the Consolidated Balance Sheets. PECO excludes cash of $23 million and $58 million at September 30, 2023 and December 31, 2022, respectively. BGE excludes cash of $13 million and $43 million at September 30, 2023 and December 31, 2022, respectively, and restricted cash of $1 million and $1 million at September 30, 2023 and December 31, 2022, respectively.

(b)The Level 3 balance consists of the current and noncurrent liability of $21 million and $113 million, respectively, at September 30, 2023 and $5 million and $79 million, respectively, at December 31, 2022 related to floating-to-fixed energy swap contracts with unaffiliated suppliers.

Nine Months Ended September 30, 2017
Successor
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
U.S. Federal statutory rate 35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit 0.7 2.1 5.9 (0.1) 5.2 4.9 3.0 5.1 5.6
Qualified nuclear decommissioning trust fund income 4.0 14.0 — — — — — — —
Amortization of investment tax credit, including deferred taxes on basis difference (0.9) (2.7) (0.2) (0.1) (0.1) (0.2) (0.1) (0.2) (0.4)
Plant basis differences (3.4) — (0.3) (14.4) (0.8) (4.6) (6.3) (1.8) (3.4)
Production tax credits and other credits (1.8) (6.2) — — — — — — —
Noncontrolling interests 0.2 0.7 — — — — — — —
Merger expenses (5.4) (2.5) — — — (11.8) (8.0) (10.0) (23.0)
FitzPatrick bargain purchase gain (3.2) (11.2) — — — — — — —
Like-kind exchange^(a)
(1.7) — 1.7 — — — — — —
Other — (0.4) 0.2 — 0.2 — (0.3) 0.6 (0.3)
Effective income tax rate 23.5% 28.8% 42.3% 20.4% 39.5% 23.3% 23.3% 28.7% 13.5%

~~137~~

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 11 — Fair Value of Financial Assets and Liabilities

PHI, Pepco, DPL, and ACE


	At September 30, 2023								At December 31, 2022
PHI	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Cash equivalents(a)	$	83	$	—	$	—	$	83	$	205	$	—	$	—	$	205
Rabbi trust investments
Cash equivalents	63		—		—		63		59		—		—		59
Mutual funds	10		—		—		10		11		—		—		11
Fixed income	—		7		—		7		—		7		—		7
Life insurance contracts	—		21		40		61		—		22		39		61
Rabbi trust investments subtotal	73		28		40		141		70		29		39		138
Total assets	156		28		40		224		275		29		39		343
Liabilities
Deferred compensation obligation	—		(13)		—		(13)		—		(14)		—		(14)



Total liabilities	—		(13)		—		(13)		—		(14)		—		(14)
Total net assets	$	156	$	15	$	40	$	211	$	275	$	15	$	39	$	329


	Pepco								DPL								ACE
At September 30, 2023	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Cash equivalents(a)	$	22	$	—	$	—	$	22	$	1	$	—	$	—	$	1	$	1	$	—	$	—	$	1




Rabbi trust investments
Cash equivalents	62		—		—		62		—		—		—		—		—		—		—		—

Life insurance contracts	—		21		40		61		—		—		—		—		—		—		—		—
Rabbi trust investments subtotal	62		21		40		123		—		—		—		—		—		—		—		—
Total assets	84		21		40		145		1		—		—		1		1		—		—		1
Liabilities
Deferred compensation obligation	—		(1)		—		(1)		—		—		—		—		—		—		—		—



Total liabilities	—		(1)		—		(1)		—		—		—		—		—		—		—		—
Total net assets	$	84	$	20	$	40	$	144	$	1	$	—	$	—	$	1	$	1	$	—	$	—	$	1

Successor Predecessor
Nine Months Ended September 30, 2016 March 24, 2016 to September 30, 2016 January 1, 2016 to March 23, 2016
Exelon Generation ComEd PECO BGE Pepco
DPL^(b)

ACE^(b)

PHI^(b)
PHI
U.S. Federal statutory rate 35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit^(c)
2.5 2.6 5.4 1.3 4.8 23.0 310.5 5.5 4.4 11.9
Qualified nuclear decommissioning trust fund income 4.8 8.8 — — — — — — — —
Amortization of investment tax credit, including deferred taxes on basis difference (1.3) (2.0) (0.3) (0.1) (0.2) (0.2) (17.9) 0.5 0.5 (0.9)
Plant basis differences (4.5) — (0.6) (8.8) (3.3) (29.0) (98.6) 7.8 17.5 (13.5)
Production tax credits and other credits (4.1) (7.6) — — — — — — — —
Noncontrolling interest 0.5 0.9 — — — — — — — —
Statute of limitations expiration
(0.5) (1.7) — — — — — — — —
Penalties 2.3 — 5.6 — — — — — — —
Merger expenses
6.2 — — — — 36.7 635.9 (35.4) (49.8) 11.1
Other (1.8) (2.1) — (1.5) — (2.5) 35.1 0.4 1.4 3.6
Effective income tax rate 39.1% 33.9% 45.1% 25.9% 36.3% 63.0% 900.0%
13.8%
9.0% 47.2%

~~_________~~


~~(a)~~	~~See Like-Kind Exchange within the Other Income Tax Matters section below for further details.~~


~~(b)~~	DPL and ACE recognized a loss before income taxes for the nine months ended September 30, 2016, and PHI recognized a loss before income taxes for the period of March 24, 2016, through September 30, 2016. As a result, positive percentages represent an income tax benefit for the periods presented.


~~(c)~~	~~Includes a remeasurement of uncertain state income tax positions for Pepco and DPL.~~

~~Accounting for Uncertainty in Income Taxes~~

~~The Registrants have the following unrecognized tax benefits as of September 30, 2017 and December 31, 2016:~~

Successor
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
September 30, 2017 $ 738
$ 468
$ 2
$ —
$ 120
$ 120
$ 59
$ 21
$ 8

Successor
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
December 31, 2016 $ 916
$ 490
$ (12 ) $ —
$ 120
$ 172
$ 80
$ 37
$ 22

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 in 2012 and PHI in 2016. In the

~~138~~

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 11 — Fair Value of Financial Assets and Liabilities

~~first quarter 2017, as a part~~


	Pepco								DPL								ACE
At December 31, 2022	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Cash equivalents(a)	$	51	$	—	$	—	$	51	$	121	$	—	$	—	$	121	$	1	$	—	$	—	$	1
Rabbi trust investments
Cash equivalents	59		—		—		59		—		—		—		—		—		—		—		—


Life insurance contracts	—		22		38		60		—		—		—		—		—		—		—		—
Rabbi trust investments subtotal	59		22		38		119		—		—		—		—		—		—		—		—
Total assets	110		22		38		170		121		—		—		121		1		—		—		1
Liabilities
Deferred compensation obligation	—		(1)		—		(1)		—		—		—		—		—		—		—		—



Total liabilities	—		(1)		—		(1)		—		—		—		—		—		—		—		—
Total net assets	$	110	$	21	$	38	$	169	$	121	$	—	$	—	$	121	$	1	$	—	$	—	$	1

__________

(a)PHI excludes cash 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$60 million and ~~$22~~$165 million ~~respectively, as of~~at September 30, ~~2017, resulting in a benefit to Income taxes on Exelon’s, Generation’s, PHI’s, Pepco’s, DPL’s~~2023 and ~~ACE’s Consolidated Statements~~December 31, 2022, respectively, and restricted cash of ~~Operations~~$3 million and ~~Comprehensive Income and corresponding decreases in their effective tax rates.~~

Exelon reduced the liability related to the uncertain tax position associated with the like-kind exchange in the second quarter of 2017. Please see the Other Income Tax Matters section below for additional details related to the like-kind exchange adjustments made in the second quarter of 2017.

~~Reasonably possible the total amount of unrecognized tax benefits could significantly increase or decrease within 12 months after the reporting date~~

~~Like-Kind Exchange~~

~~As of~~$3 million at September 30, ~~2017, Exelon~~2023 and ~~ComEd have approximately $39~~December 31, 2022, respectively. Pepco excludes cash of $31 million and $2$45 million respectively, of unrecognized federal and state income tax benefits that could significantly decrease within the 12 months after the reporting date due to a final resolution of the like-kind exchange litigation described below. The recognition of these unrecognized tax benefits would decrease Exelon and ComEd's effective tax rate.

~~Settlement of Income Tax Positions~~

~~As of~~at September 30, ~~2017, Exelon, Generation, BGE, PHI, Pepco, DPL,~~2023 and ~~ACE have approximately $676 million, $469 million, $120 million, $88 million, $59 million, $21~~December 31, 2022, respectively, and restricted cash of $3 million and $8$3 million of 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, and the outcomes of pending court cases. Of the above unrecognized tax benefits, Exelon and Generation have $462 million that, if recognized, would decrease the effective tax rate. The unrecognized tax benefits related to BGE, DPL, ACE, and a portion of Pepco, if recognized, may be included in future regulated base rates and that portion would have no impact to the effective tax rate.

~~Other Income Tax Matters~~

~~Like-Kind Exchange (Exelon and ComEd)~~

Exelon, through its ComEd subsidiary, took a position on its 1999 income tax return to defer approximately $1.2 billion of tax gain on the sale of ComEd’s fossil generating assets. The gain was deferred by reinvesting a portion of the proceeds from the sale in qualifying replacement property under the like-kind exchange provisions of the IRC. The like-kind exchange replacement property purchased by Exelon included interests in three municipal-owned electric generation facilities which were properly leased back to the municipalities.

The IRS disagreed with this position and asserted that the entire gain of approximately $1.2 billion was taxable in 1999. Exelon was unable to reach agreement with the IRS regarding the dispute over the like-kind exchange position. The IRS asserted that the Exelon purchase and leaseback transaction was substantially similar to a leasing transaction, known as a SILO, which the IRS does not respect as the acquisition of an ownership interest in property. A SILO is a “listed transaction” that the IRS has identified as a potentially abusive tax shelter under guidance issued in 2005. Accordingly, the IRS asserted that the sale of the fossil plants followed by the purchase and leaseback of the municipal owned generation facilities did not qualify as a like-kind exchange and the gain on the sale is fully subject to tax. The IRS also asserted a penalty of approximately $90 million for a substantial understatement of tax.

Onat September 30, ~~2013, the IRS issued a notice~~2023 and December 31, 2022, respectively. DPL excludes cash of ~~deficiency to Exelon for the like-kind exchange position. Exelon filed a petition on~~$5 million and $31 million at September 30, 2023 and December ~~13, 2013 to initiate litigation in the United States Tax Court (Tax Court)~~31, 2022, respectively. ACE excludes cash of $13 million and ~~the trial took place in August of 2015. Exelon was not required to remit any part of the asserted tax or penalty in order to litigate the issue.~~$71 million at September 30, 2023 and December 31, 2022, respectively.

On September 19, 2016, the Tax Court rejected Exelon’s position in the case and ruled that Exelon was not entitled to defer gain on the transaction. In addition, contrary to Exelon’s evaluation that the penalty was unwarranted, the Tax Court ruled that Exelon is liable for the penalty and interest due on the asserted penalty. In June of 2017, the IRS finalized its computation of tax, penalties and interest owed by Exelon pursuant to the Tax Court’s decision. In September of 2017, Exelon appealed this decision to the U.S. Court of Appeals for the Seventh Circuit.

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

Note 11 — Fair Value of Financial Assets and Liabilities

InReconciliation of Level 3 Assets and Liabilities

The following tables present the ~~first quarter~~fair value reconciliation of ~~2013, Exelon concluded that it was no longer more likely than not that~~Level 3 assets and liabilities measured at fair value on a recurring basis during the ~~like-kind exchange position would be sustained~~three and recorded charges to earnings representing the amount of interest expense (after-tax) and incremental state income tax expense that would be payable in the event Exelon is unsuccessful in litigation. Exelon agreed to hold ComEd harmless from any unfavorable impacts on ComEd’s equity of the after-tax interest and penalty amounts.

Prior to the Tax Court’s decision, however, Exelon did not believe it was likely a penalty would be assessed based on applicable case law and the facts of the transaction. As a result, no charge had been recorded for the penalty or for after-tax interest on the penalty. While it has strong arguments on appeal with respect to both the merits and the penalty, Exelon has determined that, pursuant to accounting standards, it is no longer more likely than not to avoid ultimate imposition of the penalty. As a result, in the third quarter of 2016, Exelon and ComEd recorded a charge to earnings of approximately $106 million and $86 million, respectively, of penalty and approximately $94 million and $64 million, respectively, of after-tax interest. Exelon and ComEd recorded the penalty and pre-tax interest due on the asserted penalty to Other, net and Interest expense, net, respectively, on their Consolidated Statements of Operations. Consistent with Exelon’s agreement to continue to hold ComEd harmless from any unfavorable impact on its equity from the like-kind exchange position, ComEd recorded on its Consolidated Balance Sheets as ofnine months ended September 30, ~~2016, an additional $150 million receivable~~2023 and ~~non-cash equity contributions from Exelon.~~2022:

As a result of the IRS’s finalization of its computation in the second quarter 2017, Exelon recorded a benefit to earnings of approximately $26 million, consisting of an income tax benefit of $50 million and a reduction of penalties of $2 million, partially offset by after-tax interest expense of $26 million, while ComEd recorded a charge to earnings of approximately $23 million, consisting of income tax expense of $15 million and after-tax interest expense of $8 million.



	Exelon		ComEd			PHI and Pepco
Three Months Ended September 30, 2023	Total		Commodity Derivatives			Life Insurance Contracts
Balance at June 30, 2023	$	(91)	$	(133)		$	42
Total realized / unrealized gains (losses)
Included in net income(a)	—		—			(2)


Included in regulatory assets/liabilities	(1)		(1)		(b)	—








Balance at September 30, 2023	$	(92)	$	(134)	(c)	$	40
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities at September 30, 2023	$	—	$	—		$	(2)

In the second quarter of 2017, Exelon amended its agreement with ComEd to also hold ComEd harmless for the unfavorable impacts on its equity from the additional income tax amounts owed by ComEd as a result of the IRS’s finalization of its computation related to the like-kind exchange position. Accordingly, in the second quarter of 2017, ComEd recorded an additional receivable and non-cash equity contribution from Exelon for the total $23 million. As of June 30, 2017, ComEd had a total receivable from Exelon pursuant to the hold harmless agreement of $369 million, which was included in Current Receivables from Affiliates on ComEd’s Consolidated Balance Sheet.



	Exelon		ComEd			PHI and Pepco
Three Months Ended September 30, 2022	Total		Commodity Derivatives			Life Insurance Contracts
Balance at June 30, 2022	$	(50)	$	(88)		$	37
Total realized / unrealized gains (losses)
Included in net income(a)	1		—			1

Included in regulatory assets/liabilities	45		45		(b)	—








Balance at September 30, 2022	$	(4)	$	(43)	(c)	$	38
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities at September 30, 2022	$	1	$	—		$	1

Exelon expects to pay the tax, penalties and interest of approximately $1.3 billion related to the like-kind exchange, including $300 million attributable to ComEd, in the fourth quarter of 2017. While Exelon will receive a tax benefit of approximately $350 million associated with the deduction for the interest, Exelon currently has a net operating loss carryforward and thus does not expect to realize the cash benefit until 2018. After taking into account these interest deduction tax benefits, the total estimated net cash outflow for the like-kind exchange is approximately $950 million, of which approximately $300 million is attributable to ComEd after giving consideration to Exelon’s agreement to hold ComEd harmless from any unfavorable impacts on ComEd’s equity from the like-kind exchange position. Following a final appellate decision, which is expected in 2018, Exelon expects to receive approximately $60 million related to final interest computations.


	Exelon		ComEd			PHI and Pepco
Nine Months Ended September 30, 2023	Total		Commodity Derivatives			Life Insurance Contracts
Balance at December 31, 2022	$	(44)	$	(84)		$	40
Total realized / unrealized gains (losses)
Included in net income(a)	2		—			—


Included in regulatory assets/liabilities	(50)		(50)		(b)	—








Balance at September 30, 2023	$	(92)	$	(134)	(c)	$	40
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities at September 30, 2023	$	2	$	—		$	—

Of the above amounts payable, Exelon deposited with the IRS $1.25 billion in October of 2016. Any remaining amounts due to the IRS will be paid by Exelon in the fourth quarter of 2017. Exelon funded the $1.25 billion deposit with a combination of cash on hand and short-term borrowings. The deposit is reflected as a current asset and the related liabilities for the tax, penalty, and interest are included on Exelon’s balance sheet as current obligations. In the third quarter of 2017, the $300 million payable discussed above attributable to ComEd, net of ComEd’s receivable pursuant to the hold harmless agreement, was settled with Exelon. No recovery will be sought from ComEd customers for any interest, penalty, or additional income tax payment amounts resulting from the like-kind exchange tax position.

As previously disclosed, in the first quarter of 2014, Exelon entered into an agreement to terminate its investment in one of the three municipal-owned electric generation properties in exchange for a net early termination amount of $335 million. In the first quarter of 2016, Exelon terminated its interests in the remaining two municipal-owned electric generation properties in exchange for $360 million.

~~Long-Term Marginal State Income Tax Rate (Exelon, Generation, ComEd, PHI and Pepco)~~

Exelon, Generation and PHI periodically review events that may significantly impact how income is apportioned among the states and, therefore, the calculation of their respective deferred state income taxes. Events that may require Exelon, Generation and PHI to update their long-term state tax apportionment include significant changes in tax law


	Exelon		ComEd			PHI and Pepco
Nine Months Ended September 30, 2022	Total		Commodity Derivatives			Life Insurance Contracts
Balance at December 31, 2021	$	(182)	$	(219)		$	35
Total realized / unrealized gains (losses)
Included in net income(a)	3		—			3


Included in regulatory assets/liabilities	176		176		(b)	—







Transfers out of Level 3	(1)		—			—
Balance at September 30, 2022	$	(4)	$	(43)	(c)	$	38
The amount of total gains included in income attributed to the change in unrealized gain related to assets and liabilities at September 30, 2022	$	3	$	—		$	3

__________

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

Note 11 — Fair Value of Financial Assets and Liabilities

~~and/or significant operational changes. Exelon's, PHI's~~(a)Classified in Operating and Pepco's long-term marginal state income tax rate were revised in the first quarter of 2017 as a result of a statutory rate change in Washington, D.C. As a result, Exelon, PHI and Pepco recorded a one-time decrease to Deferred income tax liability of $28 million, $8 million, and $8 million, respectively, on their Consolidated Balance Sheets. Because income taxes are recovered through customer rates, Exelon, PHI and Pepco recorded a corresponding regulatory liability of $8 million, in the Consolidated Balance Sheets. In addition, Exelon recorded a decrease to Income taxmaintenance expense ~~of $20 million, net of federal taxes,~~ in the Consolidated Statements of Operations and Comprehensive ~~Income for the three months ended March 31, 2017.~~Income.

~~In the third quarter~~(b)Includes $5 million of 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 9.5% effective July 1, 2017. As a result of the rate changes,decreases in the third quarter of 2017, Exelon, Generation and ComEd recorded a one-time increase to Deferred income taxes of approximately $250 million, $20 million and $270 million, respectively, on their Consolidated Balance Sheets. Because income taxes are recovered through customer rates, each of Exelon and ComEd recorded a corresponding regulatory asset of $272 million. Further, Exelon recorded a decrease to Income tax expense of approximately $20 million and Generation recorded an increase to Income tax expense of approximately $20 million (each net of federal taxes) in their Consolidated Statements of Operations and Comprehensive Income for the three and nine months ended September 30, 2017. The Illinois statutory rate increase is not expected to have a material ongoing impact to Exelon’s, Generation’s or ComEd’s future results of operations.

~~13. Nuclear Decommissioning (Exelon and Generation)~~

~~Nuclear Decommissioning Asset Retirement Obligations~~

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.

~~The following table provides a rollforward of the nuclear decommissioning ARO reflected on Exelon’s and Generation’s Consolidated Balance Sheets from December 31, 2016 to September 30, 2017:~~

Nuclear decommissioning ARO at December 31, 2016^(a)
$ 8,734
Acquisition of FitzPatrick 444
Accretion expense 342
Net decrease due to changes in, and timing of, estimated cash flows (148 )
Costs incurred to decommission retired plants (6 )
Nuclear decommissioning ARO at September 30, 2017^(a)
$ 9,366

~~_________~~


~~(a)~~	Includes $12 million and $10 million for the current portion of the ARO at September 30, 2017 and December 31, 2016, respectively, which is included in Other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets.

During the nine months ended September 30, 2017, Generation’s nuclear ARO increased by approximately $632 million. The increase primarily reflects the net impacts of the acquisition of FitzPatrick, the announced early retirement of TMI, year-to-date accretion of the ARO liability due to the passage of time and ARO updates completed during 2017 to reflect changes in amounts and timing of estimated decommissioning cash flows.

~~In the first quarter of 2017, a preliminary estimate of $417 million was recorded for the~~ fair value of FitzPatrick’s ARO. In the third quarter of 2017, an adjustment was recorded to increase the FitzPatrick ARO valuation by $27 million to $444 million to reflect updated cost estimate inputs from a third-party engineering firm. For additional details on the acquisition of FitzPatrick, see Note 4 - Mergers, Acquisitions and Dispositions.

The net $148 million decrease due to changes in, and timing of, estimated cash flows was driven by multiple adjustments throughout the period, some with offsetting impacts. These adjustments include a $180 million decrease

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

for refinements in estimated fleet wide labor costs expected to be incurred for certain on-site personnel during decommissioning as well as decreases resulting from updates to the cost studies of Clinton and Quad Cities. These decreases were partially offset by a $138 million increase in TMI's ARO liability associated with the May 30, 2017 announcement to early retire the unit on September 30, 2019. The increase in the ARO liability for TMI incorporates the early shutdown date, increases the probabilities of longer term decommissioning scenarios, and reflects an increase in the estimated costs to decommission based on an updated decommissioning cost study. Refer to Note 7 - Early Nuclear Plant Retirements for additional information regarding the announced early retirement of TMI.

~~Nuclear Decommissioning Trust Fund Investments~~

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 (NDCA) with the PAPUC proposing an annual recovery from customers of approximately $4 million. This amount reflects a decrease from the current 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 will be effective January 1, 2018. See Note 16 - Asset Retirement Obligations of Exelon's 2016 Form 10-K, for information regarding the amount collected from PECO ratepayers for decommissioning costs.

Exelon and Generation had NDT fund investments totaling $12,966 million and $11,061 million at September 30, 2017 and December 31, 2016, respectively. The increase is primarily driven by improved market performance and the acquisition of FitzPatrick.

~~The following table provides unrealized gains on NDT funds for the three and nine months ended September 30, 2017 and 2016:~~

Exelon and Generation Exelon and Generation
Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Net unrealized gains on decommissioning trust funds — Regulatory Agreement Units^(a)
$ 44
$ 155
$ 253
$ 286
Net unrealized gains on decommissioning trust funds — Non-Regulatory Agreement Units^(b)(c)
111
116
347
216

~~_________~~


~~(a)~~	Net unrealized gains related to Generation’s NDT funds associated with Regulatory Agreement Units are included in Regulatory liabilities on Exelon’s Consolidated Balance Sheets and Noncurrent payables to affiliates on Generation’s Consolidated Balance Sheets.

~~(b)~~

Excludes $4 million and $5 million of net unrealized losses related to the Zion Station pledged assets for the three months ended September 30, 2017 and 2016 respectively. Excludes $5 million and $2 million of net unrealized losses related to the Zion Station pledged assets for the nine months ended September 30, 2017 and 2016, respectively. Net unrealized losses related to Zion Station pledged assets are included in Other current liabilities and Payable for Zion Station decommissioning on Exelon’s and Generation’s Consolidated Balance Sheets in 2017 and 2016, respectively.


~~(c)~~	Net unrealized gains related to Generation’s NDT funds with Non-Regulatory Agreement Units are included within Other, net in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

Interest and dividends on NDT fund investments are recognized when earned and are included in Other, net in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. Interest and dividends earned on the NDT fund investments for the Regulatory Agreement Units are eliminated within Other, net in Exelon’s and Generation’s Consolidated Statement of Operations and Comprehensive Income.

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

Refer to Note 3 — Regulatory Matters and Note 27 — Related Party Transactions of the Exelon 2016 Form 10-K for 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.

~~Zion Station Decommissioning~~

On September 1, 2010, Generation completed an Asset Sale Agreement (ASA) with EnergySolutions Inc. and its wholly owned subsidiaries, EnergySolutions, LLC (EnergySolutions) and ZionSolutions, under which ZionSolutions has assumed responsibility for completing certain decommissioning activities at Zion Station, which is located in Zion, Illinois and ceased operation in 1998. See Note 16 — Asset Retirement Obligations of the Exelon 2016 Form 10-K for information regarding the specific treatment of assets, including NDT funds, and decommissioning liabilities transferred in the transaction.

ZionSolutions is subject to certain restrictions on its ability to request reimbursements from the Zion Station NDT funds as defined within the ASA. Therefore, the transfer of the Zion Station assets did not qualify for asset sale accounting treatment and, as a result, the related NDT funds were reclassified to Pledged assets for Zion Station decommissioning within Generation’s and Exelon’s Consolidated Balance Sheets and will continue to be measured in the same manner as prior to the completion of the transaction. Additionally, the transferred ARO for decommissioning was replaced with a Payable for Zion Station decommissioning in Generation’s and Exelon’s Consolidated Balance Sheets. Changes in the value of the Zion Station NDT assets, net of applicable taxes, are recorded as a change in the payable to ZionSolutions. At no point will the payable to ZionSolutions exceed the project budget of the costs remaining to decommission Zion Station. Generation has retained its obligation for the SNF. 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 has a liability of approximately $112 million which is included within the nuclear decommissioning ARO at September 30, 2017. Generation also has retained 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. The following table provides the pledged assets and payables to ZionSolutions, and withdrawals by ZionSolutions at September 30, 2017 and December 31, 2016:

Exelon and Generation
September 30, 2017 December 31, 2016
Carrying value of Zion Station pledged assets $ 57
$ 113
Payable to Zion Solutions^(a)
53
104
Current portion of payable to Zion Solutions^(b)
53
90
Cumulative withdrawals by Zion Solutions to pay decommissioning costs^(c)
928
878

~~_________~~


~~(a)~~	Excludes a liability recorded within Exelon’s and Generation’s Consolidated Balance Sheets related to the tax obligation on the unrealized activity associated with the Zion Station NDT funds. The NDT funds will be utilized to satisfy the tax obligations as gains and losses are realized.


~~(b)~~	~~Included in Other current liabilities within Exelon’s and Generation’s Consolidated Balance Sheets.~~


~~(c)~~	~~Includes project expenses to decommission Zion Station and estimated tax payments on Zion Station NDT fund earnings.~~

~~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.

Generation filed its biennial decommissioning funding status report with the NRC on March 30, 2017 for all units except for Zion Station which is included in a separate report to the NRC submitted by ZionSolutions (see Zion Station Decommissioning above). The status report demonstrated adequate decommissioning funding assurance for all units except for Peach Bottom Unit 1. As a former PECO plant, financial assurance for decommissioning Peach Bottom Unit 1 is provided by the NDT fund in addition to collections from PECO ratepayers. As discussed under Nuclear Decommissioning Trust Fund Investments above, the amount collected from PECO ratepayers has been adjusted in the March 31, 2017 filing to the PAPUC which was approved on August 8, 2017 and will be effective January 1, 2018.

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

Generation will file its next decommissioning funding status report with the NRC by March 31, 2018 for shutdown reactors and reactors within five years of shutdown. This report will reflect the status of decommissioning funding assurance as of December 31, 2017 and will include the impact of the announced early retirement of TMI. A shortfall 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 at TMI, the associated level of costs, and the decommissioning trust fund investment performance going forward.

~~14. Retirement Benefits (All Registrants)~~

Exelon sponsors defined benefit pension plans and other postretirement benefit plans for essentially all employees. Effective March 23, 2016, Exelon became the sponsor of all of PHI's defined benefit pension and other postretirement benefit plans, and assumed PHI's benefit plan obligations and related assets. As a result, PHI's benefit plan net obligation and related regulatory assets were transferred to Exelon.

During the first quarter of 2017, in connection with the acquisition of Fitzpatrick, Exelon established a new qualified pension plan and a new OPEB plan, and recorded a provisional obligation for Fitzpatrick employees based on information available at the merger date of $38 million and $11 million, respectively. As permitted by business combinations accounting guidance, during the third quarter of 2017, Exelon updated those obligations based on a final valuation for Fitzpatrick employees as of the merger date of March 31, 2017. The updated obligations for pension and OPEB were $16 million and $17 million, respectively. Refer to Note 4 - Mergers, Acquisitions and Dispositions for additional discussion of the acquisition of FitzPatrick.

~~Defined Benefit Pension and Other Postretirement Benefits~~

During the first quarter of 2017, Exelon received an updated valuation of its pension and other postretirement benefit obligations to reflect actual census data as of January 1, 2017. This valuation resulted in an increase to the pension obligation of $92 million and an increase for realized gains due to ~~the other postretirement benefit obligation~~settlements of ~~$57 million. Additionally, accumulated other comprehensive loss increased by approximately $59~~$4 million ~~(after tax), regulatory assets increased by approximately $57 million and regulatory liabilities increased by approximately $4 million.~~

The majority of the 2017 pension benefit cost for Exelon-sponsored plans is calculated using an expected long-term rate of return on plan assets of 7.00% and a discount rate of 4.04%. The majority of the 2017 other postretirement benefit cost is calculated using an expected long-term rate of return on plan assets of 6.58% for funded plans and a discount rate of 4.04%.

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 three and nine months ended September 30, 2017 and 2016 and PHI's net periodic benefit costs, prior to capitalization, for the predecessor period of January 1, 2016 to March 23, 2016.

Pension Benefits
Three Months Ended September 30, Other Postretirement Benefits
Three Months Ended September 30,

2017^(a)

2016^(b)

2017^(a)

2016^(b)
Components of net periodic benefit cost:
Service cost $ 98
$ 92
$ 26
$ 27
Interest cost 211
215
45
47
Expected return on assets (300 ) (293 ) (39 ) (42 )
Amortization of:
Prior service (benefit) cost (1 ) 3
(47 ) (48 )
Actuarial loss 152
142
15
18
Settlement charges 1
—
—
—
Net periodic benefit cost $ 161
$ 159
$ —
$ 2

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~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

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

Pension Benefits
Nine Months Ended September 30, Other Postretirement Benefits
Nine Months Ended September 30,

2017^(a)

2016^(b)

2017^(a)

2016^(b)
Components of net periodic benefit cost:

Service cost $ 290
$ 262
$ 79
$ 80
Interest cost 632
616
136
138
Expected return on assets (898 ) (847 ) (121 ) (121 )
Amortization of:
Prior service cost (benefit) —
10
(140 ) (138 )
Actuarial loss 455
411
46
47
Settlement charges 3
—
—
—
Net periodic benefit cost $ 482

$ 452

$ —

$ 6

~~_________~~


~~(a)~~	~~FitzPatrick net benefit costs are included for the period after acquisition.~~


~~(b)~~	~~PHI net periodic benefit costs for the period prior to the merger are not included in the table above.~~

Predecessor
PHI
Pension Benefits Other Postretirement Benefits
January 1, 2016 to March 23, 2016 January 1, 2016 to March 23, 2016
Components of net periodic benefit cost:
Service cost $ 12
$ 1
Interest cost 26
6
Expected return on assets (30 ) (5 )
Amortization of:
Prior service cost (benefit) —
(3 )
Actuarial loss 14
2
Net periodic benefit cost $ 22
$ 1

The amounts below represent Exelon's, Generation's, ComEd's, PECO's, BGE's, PHI's, Pepco's, DPL's, ACE's, BSC's and PHISCO's allocated portion of the pension and postretirement benefit plan costs, which were included in Property, plant and equipment within the respective Consolidated Balance Sheets and Operating and maintenancePurchased power expense within the Consolidated Statement of Operations and Comprehensive Income during the three and nine months ended September 30, 2017 and 2016 and PHI's for the predecessor and successor periods of January 1, 2016 to March 23, 2016 and March 24, 2016 to September 30, 2016, respectively.

Three Months Ended September 30, Nine Months Ended September 30,
Pension and Other Postretirement Benefit Costs 2017 2016 2017 2016
Exelon $ 161
$ 161
$ 482
$ 458
Generation^(a)
57
54
170
163
ComEd 44
41
131
124
PECO 7
8
21
25
BGE 16
17
48
51
BSC^(b)
13
13
40
37
Pepco^(c)
6
8
19
24
DPL^(c)
3
4
10
13
ACE^(c)
3
4
10
11
PHISCO^(c)(d)
12
12
33
33

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

Successor Predecessor
Pension and Other Postretirement Benefit Costs Three Months Ended September 30, 2017 Three Months Ended September 30, 2016 Nine Months Ended September 30, 2017 March 24, 2016 to September 30, 2016 January 1, 2016 to March 23, 2016
PHI $ 24
$ 28
$ 72
$ 58
$ 23

~~_________~~


~~(a)~~	~~FitzPatrick net benefit costs are included for the period after acquisition.~~


~~(b)~~	These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO, BGE, PHI, Pepco, DPL or ACE amounts above.


~~(c)~~	Pepco's, DPL's, ACE's and PHISCO's pension and postretirement benefit costs for the nine months ended September 30, 2016 include $7 million, $4 million, $3 million and $9 million, respectively, of costs incurred prior to the closing of Exelon’s merger with PHI on March 23, 2016.


~~(d)~~	~~These amounts represent amounts billed to Pepco, DPL, and ACE through intercompany allocations. These amounts are not included in Pepco, DPL, or ACE amounts above.~~

~~Defined Contribution Savings Plans~~

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 the matching contributions to the savings plans during the three and nine months ended September 30, 2017 and 2016 and PHI's for the predecessor and successor periods of January 1, 2016 to March 23, 2016 and March 24, 2016 to September 30, 2016, respectively.

Three Months Ended September 30, Nine Months Ended September 30,
Savings Plan Matching Contributions 2017 2016 2017 2016
Exelon $ 34

$ 51

$ 97

$ 107
Generation 14
31
42
56
ComEd 9
10
24
23
PECO 3
3
7
7
BGE 3
2
7
5
BSC^(a)
2
2
7
9
Pepco^(b)
1
—
3
2
DPL^(b)
1
1
2
2
ACE —
—
1
1
PHISCO^(b)(c)
1
2
4
5

Successor Predecessor
Savings Plan Matching Contributions Three Months Ended September 30, 2017 Three Months Ended September 30, 2016 Nine Months Ended September 30, 2017 March 24, 2016 to September 30, 2016 January 1, 2016 to March 23, 2016
PHI $ 3
$ 3
$ 10
$ 7
$ 3

~~_________~~


~~(a)~~	These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO, BGE, PHI, Pepco, DPL or ACE amounts above.


~~(b)~~	Pepco's, DPL's and PHISCO's matching contributions for the nine months ended September 30, 2016 include $1 million, $1 million, and $1 million, respectively, of costs incurred prior to the closing of Exelon’s merger with PHI on March 23, 2016, which is not included in Exelon’s matching contributions for the nine months ended September 30, 2016.


~~(c)~~	~~These amounts represent amounts billed to Pepco, DPL, and ACE through intercompany allocations. These amounts are not included in Pepco, DPL, or ACE amounts above.~~

~~15. Severance (All Registrants)~~

The Registrants have an ongoing severance plan under which, in general, the longer an employee worked prior to termination the greater the amount of severance benefits. The Registrants record a liability and expense or regulatory asset for severance once terminations are probable of occurrence and the related severance benefits can be reasonably estimated. For severance benefits that are incremental to its ongoing severance plan (“one-time termination benefits”), the Registrants measure the obligation and record the expense at fair value at the communication date if there are no

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~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

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

~~future service requirements, or, if future service is required to receive the termination benefit, ratably over the required service period.~~

~~Ongoing Severance Plans~~

The Registrants provide severance and health and welfare benefits under Exelon’s ongoing severance benefit plans to terminated employees in the normal course of business. These benefits are accrued for when the benefits are considered probable and can be reasonably estimated.

~~For the three and nine months ended September 30, 2017 and 2016, Exelon, Generation, ComEd, PHI, Pepco, DPL, and ACE recorded the following severance costs~~ associated with ~~these ongoing severance benefits within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income.~~

Successor
Exelon
Generation^(a)

ComEd^(a)
PHI
Pepco^(a)

DPL^(a)

ACE^(a)
Three Months Ended
September 30, 2017 $ 1
$ —
$ —
$ 1
$ 1
$ —
$ —
September 30, 2016 8
7
—
1
—
—
—

Nine Months Ended
September 30, 2017 $ 10
$ 4
$ 2
$ 4
$ 2
$ 1
$ 1
September 30, 2016 12
10
1
1
—
—
—

~~_________~~

~~(a)~~

~~The amounts above~~floating-to-fixed energy swap contracts with unaffiliated suppliers for Generation include $2 million for amounts billed by BSC through intercompany allocations for the nine months ended September 30, 2017 and $1 million and $2 million for the three and nine months ended September 30, 2016, respectively. The amounts above for ComEd include $1 million for amounts billed by BSC through intercompany allocations for the three and nine months ended September 30, 2016. The amounts above for PHI include less than $1 million and $1 million billed by BSC through intercompany allocations for the three and nine months ended September 30, 2017, respectively, and $1 million for the three and nine months ended September 30, 2016. Amounts billed by PHISCO to Pepco were $1 million and $2 million for the three and nine months ended September 30, 2017, respectively. Amounts billed by PHISCO to DPL and ACE were $1 million, each, for the nine months ended September 30, 2017. Pepco, DPL and ACE did not have any ongoing severance plans for the three and nine months ended September 30, 2016.

~~Cost Management Program-Related Severance~~

In August 2015, Exelon announced a cost management program focused on cost savings at BSC and Generation, including the elimination of approximately 500 positions. These actions are in response to the continuing economic challenges confronting all parts of Exelon’s business and industry, necessitating continued focus on cost management through enhanced efficiency and productivity. Exelon expects that approximately 250 corporate support positions in BSC and approximately 250 positions located throughout Generation will be eliminated.

For the three and nine months ended September 30, 2017 and 2016, the Registrants recorded the following severance costs related to the cost management program within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income, pursuant to the authoritative guidance for ongoing severance plans:

Exelon Generation ComEd PECO BGE
Three Months Ended
September 30, 2017^(a)
$ 7
$ 7
$ —
$ —
$ —
September 30, 2016^(b)
1
1
—
—
—

Nine Months Ended
September 30, 2017^(a)
$ 6
$ 6
$ —
$ —
$ —
September 30, 2016^(b)
18
13
3
1
1

~~_________~~


~~(a)~~	~~Amounts billed by BSC through intercompany allocations for the nine months ended September 30, 2017 were immaterial.~~


~~(b)~~	The amounts above for Generation, ComEd, PECO and BGE include $7 million, $3 million, $1 million and $1 million, respectively, for amounts billed by BSC through intercompany allocations for the nine months ended September 30, 2016.

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~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

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

~~Early Plant Retirement-Related Severance (Exelon and Generation)~~

As a result of the Three Mile Island plant retirement decision, Exelon and Generation will incur certain employee-related costs, including severance benefit costs. Severance costs will be provided to management employees that are eligible under Exelon’s severance policy, to the extent that those employees are not redeployed to other locations. In June 2017, Exelon and Generation recognized severance costs of $17 million related to expected management employee severances resulting from the plant retirements within Operating and maintenance expense in their Consolidated Statements of Operation and Comprehensive Income. Approximately half of the employees at this location fall under a collective bargaining union agreement and are not eligible for severance benefits under an existing plan. The union and Exelon will negotiate terms of any severance benefits. If severance benefits are successfully negotiated, the amounts will be accrued as a one-time employee termination benefit once the established plan is communicated to employees. The final amount of the severance cost will ultimately depend on the specific employees severed. See Note 7 - Early Nuclear Plant Retirements for additional information regarding the announced early retirement of TMI.

~~Severance Costs Related to the PHI Merger~~

Upon closing the PHI Merger, Exelon recorded a severance accrual for the anticipated employee position reductions as a result of the post-merger integration. Cash payments under the plan began in May 2016 and will continue through 2020.

~~For the three and nine months ended September 30, 2017 and~~ the three months ended September 30, ~~2016,~~2023. Includes $51 million of increases in fair value and a decrease for realized gains due to settlements of $6 million recorded in Purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the ~~PHI Merger severance costs were immaterial. For the nine~~three months ended September 30, ~~2016, the Registrants~~2022. Includes $73 million of decreases in fair value and an increase for realized gains due to settlements of $23 million recorded ~~the following severance costs~~in Purchased power expense associated with the identified job reductions within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income, pursuant to the authoritative guidance for ongoing severance plans:

Successor
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Nine Months Ended September 30, 2016
Severance costs^(a)
$ 55
$ 9
$ 2
$ 1
$ 1
$ 42
$ 20
$ 12
$ 10

~~_________~~


~~(a)~~	The amounts above for Generation, ComEd, PECO, BGE, Pepco, DPL and ACE include $8 million, $2 million, $1 million, $1 million, $19 million, $11 million and $10 million, respectively, for amounts billed by BSC and/or PHISCO through intercompany allocations for the nine months ended September 30, 2016.

PHI, Pepco, DPL and ACE record regulatory assets for merger related integration costs which include a portion of the severance costs in the table above related to the PHI Merger. These regulatory assets are either currently being recovered in rates or are deemed probable of recovery in future rates. See Note 5 - Regulatory Matters for further information.

~~Severance Liability~~

Amounts included in the table below represent the severance liability recorded for the severance plans above for employees of each Registrant and exclude amounts included at Exelon and billed through intercompany allocations:

Successor
Severance Liability Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Balance at December 31, 2016 $ 88
$ 36
$ 3
$ —
$ —
$ 29
$ —
$ —
$ —
Severance charges^(a)
33
25
1
—
—
3
—
—
—
Payments (24 ) (7 ) (1 ) —
—
(11 ) —
—
—
Balance at September 30, 2017 $ 97
$ 54
$ 3
$ —
$ —
$ 21
$ —
$ —
$ —

~~_________~~


~~(a)~~	~~Includes salary continuance and health and welfare severance benefits.~~

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~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

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

~~16. Changes in Accumulated Other Comprehensive Income (Exelon, Generation, PECO and PHI)~~

~~The following tables present changes in accumulated other comprehensive income (loss) (AOCI) by component~~floating-to-fixed energy swap contracts with unaffiliated suppliers for the nine months ended September 30, ~~2017~~2023. Includes $179 million of increases in fair value and ~~2016:~~

Nine Months Ended September 30, 2017 Gains
and
(losses)
on Cash Flow Hedges
Unrealized
Gains and
(losses) on
Marketable
Securities

Pension and
Non-Pension
Postretirement
Benefit Plan
Items

Foreign
Currency
Items

AOCI of
Equity
Investments
Total
Exelon^(a)

Beginning balance $ (17 ) $ 4
$ (2,610 ) $ (30 ) $ (7 ) $ (2,660 )
OCI before reclassifications 2
2
(55 ) 7
7
(37 )
Amounts reclassified from AOCI^(b)
3
—
105
—
—
108
Net current-period OCI 5
2
50
7
7
71
Ending balance $ (12 ) $ 6
$ (2,560 ) $ (23 ) $ —
$ (2,589 )
Generation^(a)

Beginning balance $ (19 ) $ 2
$ —
$ (30 ) $ (7 ) $ (54 )
OCI before reclassifications 2
—
—
7
6
15
Amounts reclassified from AOCI^(b)
3
—
—
—
—
3
Net current-period OCI 5
—
—
7
6
18
Ending balance $ (14 ) $ 2
$ —
$ (23 ) $ (1 ) $ (36 )
PECO^(a)

Beginning balance $ —
$ 1
$ —
$ —
$ —
$ 1
OCI before reclassifications —
—
—
—
—
—
Amounts reclassified from AOCI^(b)
—
—
—
—
—
—
Net current-period OCI —
—
—
—
—
—
Ending balance $ —
$ 1
$ —
$ —
$ —
$ 1

~~149~~

~~Table~~a decrease for realized losses due to settlements of ~~Contents~~

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

~~(Dollars~~$3 million recorded in ~~millions, except per share data, unless otherwise noted)~~

Nine Months Ended September 30, 2016 Gains
and
(losses)
on Cash Flow Hedges
Unrealized
Gains and
(losses) on
Marketable
Securities

Pension and
Non-Pension
Postretirement
Benefit Plan
Items

Foreign
Currency
Items

AOCI of
Equity
Investments
Total
Exelon^(a)

Beginning balance $ (19 ) $ 3
$ (2,565 ) $ (40 ) $ (3 ) $ (2,624 )
OCI before reclassifications (9 ) —
(2 ) 3
(5 ) (13 )
Amounts reclassified from AOCI^(b)
5
—
104
5
—
114
Net current-period OCI (4 ) —
102
8
(5 ) 101
Ending balance $ (23 ) $ 3
$ (2,463 ) $ (32 ) $ (8 ) $ (2,523 )
Generation^(a)

Beginning balance $ (21 ) $ 1
$ —
$ (40 ) $ (3 ) $ (63 )
OCI before reclassifications (8 ) 1
—
3
1
(3 )
Amounts reclassified from AOCI^(b)
5
—
—
5
—
10
Net current-period OCI (3 ) 1
—
8
1
7
Ending balance $ (24 ) $ 2
$ —
$ (32 ) $ (2 ) $ (56 )
PECO^(a)

Beginning balance $ —
$ 1
$ —
$ —
$ —
$ 1
OCI before reclassifications —
—
—
—
—
—
Amounts reclassified from AOCI^(b)
—
—
—
—
—
—
Net current-period OCI —
—
—
—
—
—
Ending balance $ —
$ 1
$ —
$ —
$ —
$ 1
PHI Predecessor^(a)

Beginning balance January 1, 2016 $ (8 ) $ —
$ (28 ) $ —
$ —
$ (36 )
OCI before reclassifications —
—
—
—
—
—
Amounts reclassified from AOCI^(b)
—
—
1
—
—
1
Net current-period OCI —
—
1
—
—
1
Ending balance March 23, 2016^(c)
$ (8 ) $ —
$ (27 ) $ —
$ —
$ (35 )

~~_________~~


~~(a)~~	~~All amounts are net of tax and noncontrolling interest. Amounts in parenthesis represent a decrease in AOCI.~~


~~(b)~~	~~See next tables~~Purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for ~~details about these reclassifications.~~


~~(c)~~	~~As a result of~~ the ~~PHI Merger, the PHI predecessor balances at March 23, 2016 were reduced to zero on March 24, 2016 due to purchase accounting adjustments applied to PHI.~~

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

~~ComEd, PECO, BGE, Pepco, DPL and ACE did not have any reclassifications out of AOCI to Net income during the three and~~ nine months ended September 30, ~~2017~~2022.

(c)The balance consists of a current and ~~2016. The following tables present amounts reclassified out~~noncurrent liability of ~~AOCI to Net income for Exelon, Generation~~$21 million and ~~PHI during the three and nine months ended~~$113 million, respectively, at September 30, ~~2017~~2023. The balance consists of $24 million of current assets and ~~2016.~~

~~Three Months Ended~~current and noncurrent liability of none and $67 million, respectively at September 30, ~~2017~~2022.

Details about AOCI components
Items reclassified out of AOCI^(a)
Affected line item in the Statement of Operations and Comprehensive Income
Exelon Generation
Gains (losses) on cash flow hedges
Other cash flow hedges $ 2
$ 2
Interest expense
Total before tax 2
2

Tax benefit (1 ) (1 )
Net of tax $ 1
$ 1
Comprehensive income

Amortization of pension and other postretirement benefit plan items
Prior service costs^(b)
$ 23
$ —

Actuarial losses^(b)
(81 ) —

Total before tax (58 ) —

Tax benefit 23
—

Net of tax $ (35 ) $ —

Total Reclassifications for the period $ (34 ) $ 1
Comprehensive income

~~Nine Months Ended September 30, 2017~~

Details about AOCI components
Items reclassified out of AOCI^(a)
Affected line item in the Statement of Operations and Comprehensive Income

Exelon Generation
Gains and (losses) on cash flow hedges
Other cash flow hedges $ (5 ) $ (5 ) Interest expense
Total before tax (5 )
(5 )

Tax benefit 2
2

Net of tax $ (3 ) $ (3 ) Comprehensive income

Amortization of pension and other postretirement benefit plan items
Prior service costs^(b)
$ 69
$ —

Actuarial losses^(b)
(243 ) —

Total before tax (174 ) —

Tax benefit 69
—

Net of tax $ (105 ) $ —

Total Reclassifications $ (108 ) $ (3 ) Comprehensive income

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~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

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

~~Three Months Ended September 30, 2016~~

Details about AOCI components
Items reclassified out of AOCI^(a)
Affected line item in the Statement of Operations and Comprehensive Income

Exelon Generation
Gains and (losses) on cash flow hedges
Other cash flow hedges $ (3 ) $ (3 ) Interest expense
Total before tax (3 ) (3 )
Tax expense 1
1

Net of tax $ (2 ) $ (2 ) Comprehensive income

Amortization of pension and other postretirement benefit plan items
Prior service costs^(b)
$ 19
$ —

Actuarial losses^(b)
(76 ) —

Total before tax (57 ) —

Tax benefit 22
—

Net of tax $ (35 ) $ —

Gains and (losses) on foreign currency translation
Other $ (5 ) $ (5 ) Other Income and (deductions)
Total before tax (5 ) (5 )
Tax expense —
—

Net of tax $ (5 ) $ (5 ) Comprehensive income

Total Reclassifications for the period $ (42 ) $ (7 ) Comprehensive income

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~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

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

~~Nine Months Ended September 30, 2016~~

Details about AOCI components
Items reclassified out of AOCI^(a)
Affected line item in the Statement of Operations and Comprehensive Income
Predecessor
Exelon Generation PHI
Gains and (losses) on cash flow hedges
Other cash flow hedges $ (8 ) $ (8 ) $ —
Interest expense
Total before tax (8 )
(8 )
—

Tax benefit 3
3
—

Net of tax $ (5 ) $ (5 ) $ —
Comprehensive income

Amortization of pension and other postretirement benefit plan items
Prior service costs^(b)
$ 57
$ —
$ —

Actuarial losses^(b)
(227 ) —
(1 )
Total before tax (170 ) —
(1 )
Tax benefit 66
—
—

Net of tax $ (104 ) $ —
$ (1 )

Gains and (losses) on foreign currency translation
Other $ (5 ) $ (5 ) $ —
Other income and (deductions)
Total before tax (5 ) (5 ) —

Tax expense —
—
—

Net of tax $ (5 ) $ (5 ) $ —

Total Reclassifications $ (114 ) $ (10 ) $ (1 ) Comprehensive income

~~_________~~


~~(a)~~	~~Amounts in parenthesis represent a decrease in net income.~~


~~(b)~~	~~This AOCI component is included in the computation of net periodic pension and OPEB cost (see Note 14 — Retirement Benefits for additional details).~~

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~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

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

Commodity Derivatives (Exelon and ComEd)

The ~~following~~ table ~~presents income tax expense (benefit) allocated to each component of other comprehensive income (loss) during~~below discloses the ~~three and nine months ended September 30, 2017 and 2016:~~

Three Months Ended September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Exelon
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost $ 9
$ 7
$ 27
$ 22
Actuarial loss reclassified to periodic benefit cost (32 ) (29 ) (96 ) (88 )
Pension and non-pension postretirement benefit plans valuation adjustment —
1
2
1
Change in unrealized (loss)/gain on cash flow hedges —
(1 ) (3 ) 3
Change in unrealized (loss)/gain on equity investments 1
—
(2 ) 3
Change in unrealized (loss)/gain on marketable securities —
(1 ) (2 ) (1 )
Total $ (22 ) $ (23 ) $ (74 ) $ (60 )

Generation
Change in unrealized (loss)/gain on cash flow hedges $ —
$ (2 ) $ (3 ) $ 1
Change in unrealized (loss)/gain on equity investments —
—
(2 ) 3
Change in unrealized gain on marketable securities —
—
(1 ) —
Total $ —
$ (2 ) $ (6 ) $ 4



	~~Predecessor~~
~~PHI~~	~~January 1, 2016 to March 23, 2016~~
~~Pension and non-pension postretirement benefit plans:~~
~~Actuarial loss reclassified to periodic cost~~	$	—

~~17. Earnings Per Share and Equity (Exelon)~~

~~Earnings per Share~~

Diluted earnings per share is calculated by dividing Net income attributable to common shareholders by the weighted average number of shares of common stock outstanding, including shares to be issued upon exercise of stock options, performance share awards and restricted stock outstanding under Exelon’s LTIPs considered to be common stock equivalents. The following table sets forth the components of basic and diluted earnings per share and shows the effect of these stock options, performance share awards and restricted stock on the weighted average number of shares outstanding used in calculating diluted earnings per share:

Three Months Ended September 30,
Nine Months Ended September 30,
2017
2016
2017
2016
Exelon
Net income attributable to common shareholders $ 824
$ 490
$ 1,899
$ 930
Weighted average common shares outstanding — basic 962
925
941
924
Assumed exercise and/or distributions of stock-based awards 3
2
2
2
Weighted average common shares outstanding — diluted 965
927
943
926

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

The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was approximately 7 million and 9 million for the three and nine months ended September 30, 2017, respectively, and 11 million and 12 million for the three and nine months ended September 30, 2016, respectively. There were no equity units relatedsignificant unobservable inputs to the ~~PHI Merger not included in the calculation of diluted common shares outstanding due~~forward curve used to ~~their antidilutive effect for the three and nine months ended September 30, 2017. The number of equity units related~~value mark-to-market derivatives.


Type of trade	Fair Value at September 30, 2023		Fair Value at December 31, 2022		Valuation Technique	Unobservable Input	2023 Range & Arithmetic Average				2022 Range & Arithmetic Average
Commodity derivatives	$	(134)	$	(84)	Discounted Cash Flow	Forward power price(a)	$30.13	-	$72.72	$42.77	$34.78	-	$75.71	$48.44

________

(a)An increase to the ~~PHI Merger not included in~~forward power price would increase the calculation of diluted common shares outstanding due to their antidilutive effect was less than 1 million for the three and nine months ended September 30, 2016. Refer to Note 20 — Shareholders' Equity of the Exelon 2016 Form 10-K for further information regarding the equity units.fair value.

On June 1, 2017, Exelon settled the forward purchase contract, which was a component of the June 2014 equity units, through the issuance of approximately 33 million shares of Exelon common stock from treasury stock. The issuance of shares on June 1, 2017, triggered full dilution in the EPS calculation, which prior to settlement were included in the calculation of diluted EPS using the treasury stock method.

Prior to the June 2017 issuance Exelon had approximately 35 million shares of treasury stock with a cost of $2.3 billion. After issuance, Exelon has approximately 2 million shares of Treasury stock remaining, at a historical cost of $123 million. In 2008, Exelon management decided to defer indefinitely any share repurchases.

~~18.~~12. Commitments and Contingencies (All Registrants)

The following is an update to the current status of commitments and contingencies set forth in Note ~~24 of the Exelon 2016 Form 10-K . See Note 4 - Mergers, Acquisitions and Dispositions for further discussion on the PHI Merger commitments.~~

~~Commitments~~

~~Constellation Merger Commitments (Exelon and Generation)~~

In February 2012, the MDPSC issued an Order approving the Exelon and Constellation merger. As part of the MDPSC Order, Exelon agreed to provide a package of benefits to BGE customers, the City of Baltimore and the State of Maryland, resulting in an estimated direct investment in the State of Maryland of approximately $1 billion.

The direct investment includes the construction of a new 21-story headquarters building in Baltimore for Generation’s competitive energy business that was substantially complete in November 2016 and is now occupied by approximately 1,500 Exelon employees. Generation’s investment includes leasehold improvements that are not expected to exceed $110 million. In addition, Generation entered into a 20 year operating lease as the primary lessee of the building. Refer to Note 24 -18 — Commitments and Contingencies of the ~~Combined Notes to~~2022 Form 10-K.

Commitments

PHI Merger Commitments (Exelon, PHI, Pepco, DPL, and ACE). Approval of the ~~Consolidated Financial Statements~~PHI Merger in Delaware, New Jersey, Maryland, and the ~~Exelon 2016 Form 10-K for additional information regarding Generation’s future minimum lease payments.~~

~~The direct investment commitment also includes $450 million to $500 million relating to~~District of Columbia was conditioned upon Exelon and ~~Generation’s development or assistance in~~PHI agreeing to certain commitments. The following amounts represent total commitment costs that have been recorded since the ~~development of 285-300 MWs of new generation in Maryland, which is expected to be completed within a period of 10 years.~~ The MDPSC order contemplates various options for complying with the new generation development commitments, including building or acquiring generating assets, making subsidy or compliance payments, or in circumstances in which the generation build is delayed or certain specified provisions are elected, making liquidated damages payments. Exelon and Generation have incurred $457 million towards satisfying the commitment for new generation development in the state of Maryland, with approximately 220 MW of the new generation commencing with commercial operations toacquisition date and ~~an additional 10 MW commitment satisfied~~the total remaining obligations for Exelon, PHI, Pepco, DPL, and ACE at September 30, 2023:


Description	Exelon		PHI		Pepco		DPL		ACE
Total commitments	$	513	$	320	$	120	$	89	$	111
Remaining commitments(a)	42		39		34		3		2

__________

(a)Remaining commitments extend through ~~a liquidated damages payment made in the fourth quarter of 2016. Additionally, during the fourth quarter of 2016, given continued declines in projected energy~~2026 and capacity prices, Generation terminated rights to certain development projects originally intended to meet its remaining 55 MW commitment amount. The commitment will now most likely be satisfied via payment of liquidated damages or execution of a third party PPA, rather than by Generation constructing renewable generating assets. As a result, Exeloninclude escrow funds, charitable contributions, and ~~Generation recorded a pre-tax$50 million loss contingency in Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2016.~~rate credits.

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

~~Equity Investment~~Note 12 — Commitments ~~(Exelon~~ and ~~Generation)~~

As part of Generation's recent investments in technology development, Generation enters into equity purchase agreements that include commitments to invest additional equity through incremental payments to fund the anticipated needs of the planned operations of the associated companies. As of September 30, 2017, Generation’s estimated commitments relating to its equity purchase agreements, including the in-kind services contributions, is anticipated to be as follows:

Contingencies

Total
2017 (remainder of year) $ 12
2018 6
2019 3
Total $ 21

Commercial Commitments (All Registrants)

.The Registrants’ commercial commitments ~~as of~~at September 30, ~~2017,~~2023, representing commitments potentially triggered by future events were as follows:


			Expiration within
	Total		2023		2024		2025		2026		2027		2028 and beyond
Exelon
Letters of credit	$	20	$	9	$	11	$	—	$	—	$	—	$	—
Surety bonds(a)	207		85		122		—		—		—		—
Financing trust guarantees	378		—		—		—		—		—		378
Guaranteed lease residual values(b)	29		—		4		6		5		4		10
Total commercial commitments	$	634	$	94	$	137	$	6	$	5	$	4	$	388

ComEd
Letters of credit	$	12	$	6	$	6	$	—	$	—	$	—	$	—
Surety bonds(a)	46		5		41		—		—		—		—
Financing trust guarantees	200		—		—		—		—		—		200
Total commercial commitments	$	258	$	11	$	47	$	—	$	—	$	—	$	200

PECO
Letters of credit	$	1	$	—	$	1	$	—	$	—	$	—	$	—
Surety bonds(a)	2		—		2		—		—		—		—
Financing trust guarantees	178		—		—		—		—		—		178
Total commercial commitments	$	181	$	—	$	3	$	—	$	—	$	—	$	178

BGE
Letters of credit	$	4	$	2	$	2	$	—	$	—	$	—	$	—
Surety bonds(a)	3		1		2		—		—		—		—
Total commercial commitments	$	7	$	3	$	4	$	—	$	—	$	—	$	—

PHI

Surety bonds(a)	$	97	$	75	$	22	$	—	$	—	$	—	$	—
Guaranteed lease residual values(b)	29		—		4		6		5		4		10
Total commercial commitments	$	126	$	75	$	26	$	6	$	5	$	4	$	10

Pepco

Surety bonds(a)	$	85	$	71	$	14	$	—	$	—	$	—	$	—
Guaranteed lease residual values(b)	10		—		1		3		2		1		3
Total commercial commitments	$	95	$	71	$	15	$	3	$	2	$	1	$	3

DPL

Surety bonds(a)	$	7	$	2	$	5	$	—	$	—	$	—	$	—
Guaranteed lease residual values(b)	12		—		2		2		2		2		4
Total commercial commitments	$	19	$	2	$	7	$	2	$	2	$	2	$	4

ACE
Surety bonds(a)	$	5	$	2	$	3	$	—	$	—	$	—	$	—
Guaranteed lease residual values(b)	7		—		1		1		1		1		3
Total commercial commitments	$	12	$	2	$	4	$	1	$	1	$	1	$	3

__________

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

Successor
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Letters of credit (non-debt)^(a)
$ 1,276
$ 1,193
$ 14
$ 22
$ 2
$ 1
$ 1
$ —
$ —
Surety bonds^(b)
1,206
1,079
20
40
11
21
13
4
4
Financing trust guarantees 378
—
200
178
—
—
—
—
—
Guaranteed lease residual values^(c)
19
—
—
—
—
19
6
7
5
Total commercial commitments $ 2,879
$ 2,272
$ 234
$ 240
$ 13

$ 41
$ 20
$ 11
$ 9

~~_________~~


~~(a)~~	~~Letters of credit (non-debt) - Exelon and certain subsidiaries maintain non-debt letters of credit to provide credit support for certain transactions as requested by third parties.~~


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

~~(c)~~

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 maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $49 million, $14 million of which is a guarantee by Pepco, $19 million by DPL and $13 million by ACE. The minimum lease term associated with these assets ranges from 1 to 4 years. 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, including the CENG 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 also to limit the liability of nuclear reactor owners for such claims from any single incident. As of September 30, 2017, the current liability limit per incident is $13.4 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 September 10, 2013. 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 $13.0 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 $2.8 billion, including CENG's related liability, however any amounts payable under this secondary layer would be capped at $420 million per year.

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

Note 12 — Commitments and Contingencies

~~In addition,~~(b)Represents the ~~U.S. Congress could impose revenue-raising measures on the nuclear industry to pay public liability claims exceeding the $13.4 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 5 — Investment in Constellation Energy Nuclear Group, LLC of the Exelon 2016 Form 10-K 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 sitemaximum potential obligation in the event that the fair value of ~~an accident.~~certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The ~~property insurance maintained for each facility is currently provided through insurance policies purchased~~lease term associated with these assets ranges from ~~NEIL, an industry mutual insurance company~~1 to 9 years. The maximum potential obligation at the end of the minimum lease term would be $66 million guaranteed by Exelon and PHI, of which ~~Generation~~$22 million, $26 million, and $18 million is ~~a member.~~

~~Premiums paid to NEIL~~guaranteed by ~~its members are also subject to a potential assessment for adverse loss experience in~~Pepco, DPL, and ACE, respectively. Historically, payments under the ~~form~~guarantees have not been made and PHI believes the likelihood of ~~a retrospective premium obligation. NEIL has never assessed this retrospective premium since its formation in 1973, and Generation cannot predict~~payments being required under the ~~level of future assessments if any. The current maximum aggregate annual retrospective premium obligation for Generation~~guarantees is approximately $360 million. NEIL requires its members to maintain an investment grade credit rating or to ensure collectability of their annual retrospective premium obligation by providing a financial guarantee, letter of credit, deposit premium, or some other means of assurance.

NEIL provides “all risk” property damage, decontamination and premature decommissioning insurance for each station for losses resulting from damage to its nuclear plants, either due to accidents or acts of terrorism. If the decision is made to decommission the facility, a portion of the insurance proceeds will be allocated to a fund, which 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 condition, results of operations and liquidity.remote.

Environmental ~~Issues~~Remediation Matters

General (All Registrants)

~~General.~~. 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~~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 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 (All 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~~some sites, there are additional PRPs that may share responsibility for the ultimate remediation of each location.

•ComEd has ~~identified 42~~19 sites ~~19 of which the remediation has been completed and approved by the Illinois EPA or the U.S. EPA and 23~~ 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 ~~2022.~~2031.

•PECO has ~~identified 26~~6 sites ~~17 of which have been remediated in accordance with applicable PA DEP regulatory requirements. The remaining 9 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.~~2025.

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

•BGE has ~~identified 13 former gas manufacturing or purification~~4 sites that it currently ~~owns or owned at one time through a predecessor’s acquisition. Two of the gas manufacturing sites~~ require some level of remediation ~~and~~and/or ongoing ~~monitoring under~~activity. BGE expects the ~~direction~~majority of the ~~MDE. The required costs~~remediation at these ~~two~~ sites ~~are not considered material.~~In May 2017, BGE completed the additional work requested by MDE. All the sample testing produced results that were below the cleanup action level established by MDE and no further investigation is required. For more information, see the discussion of the Riverside site below.

to continue through at least 2025.

•DPL has ~~identified 3 sites, 2 of which remediation has been completed and approved by the MDE or the Delaware Department of Natural Resources and Environmental Control. The remaining~~1 site that is currently under study and the required cost at the site is not ~~considered~~expected to be material.

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. ~~ComEd and PECO have recorded regulatory assets for the recovery of these costs.~~ ~~See Note 5 — Regulatory Matters for additional information regarding the associated regulatory assets.~~ BGE is authorized to recover, and is currently recovering, environmental costs for the remediation of the former MGP facility sites from customers; however, while BGE does not have a rider for MGP clean-up costs, BGE has historically received recovery of actual clean-up costs in distribution rates. DPL has historically received recovery of actual clean-up costs in distribution rates.

As of September 30, 2017 and December 31, 2016, 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:

September 30, 2017
Total Environmental
Investigation and
Remediation Reserve

Portion of Total Related to
MGP Investigation and
Remediation
Exelon $ 429

$ 327
Generation 76
—
ComEd 294
293
PECO 33
32
BGE 3
2
PHI (Successor) 23

—
Pepco 21
—
DPL 1
—
ACE 1
—

December 31, 2016
Total Environmental
Investigation and
Remediation Reserve

Portion of Total Related to
MGP Investigation and
Remediation
Exelon $ 429

$ 325
Generation 72
—
ComEd 292
291
PECO 33
31
BGE 2
2
PHI (Successor) 30

1
Pepco 27
—
DPL 2
1
ACE 1
—

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

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

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 a PAPUC order, 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.

During the third quarter of ~~2017,~~2023, ComEd ~~PECO, BGE~~ and ~~PHI~~PECO completed an annual study of their future estimated MGP remediation requirements. The study resulted in a ~~$13 million and $2~~$25 million increase to the environmental ~~liabilities~~liability and related regulatory ~~assets~~asset for ~~ComEd~~ComEd. The increase was primarily due to increased costs resulting from inflation and ~~PECO, respectively, and no~~changes in remediation plans. The study did not result in a material change ~~at BGE and PHI.~~

The Registrants cannot reasonably estimate whether they will incur other significant liabilities for additional investigation and remediation costs at these or additional sites identified by the Registrants, environmental agencies or others, or whether such costs will be recoverable from third parties, including customers.

~~Water Quality~~

~~Benning Road Site NPDES Permit Limit Exceedances~~. Pepco holds an NPDES permit issued by EPA with a July 19, 2009 effective date, which authorizes discharges from the Benning Road service facility. The 2009 permit for the first time imposed numerical limits on the allowable concentration of certain metals in storm water discharged from the site into the Anacostia River. The permit contemplated that Pepco would meet these limits over time through the use of best management practices (BMPs). The BMPs were effective in reducing metal concentrations in storm water discharges, but were not sufficient to meet all of the numerical limits for all metals.

The 2009 permit remains in effect pending EPA’s action on the Pepco renewal application, including resolution of the stormwater compliance issues. On October 30, 2015, EPA filed a Clean Water Act civil enforcement action against Pepco in federal district court, and in March 2016 the court granted a motion by the Anacostia Riverkeeper to intervene in this case as a plaintiff along with EPA. Since 2009 Pepco has installed runoff mitigation measures and implemented new operating procedures to comply with regulations. In January 2017, the parties agreed to a settlement in the form of a Consent Decree whereby Pepco will pay a civil penalty in the amount of $1.6 million, continue the BMPs to manage stormwater, construct a new stormwater treatment system, and make certain other capital improvements to the stormwater management system. On May 19, 2017, the Consent Decree was entered with the Court and became final. The Civil Penalty assessed under the Consent Decree of $1.6 million was paid on June 5, 2017 and other requirements of the Decree are now being implemented.

~~Solid and Hazardous Waste~~

~~Cotter Corporation.~~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 Cotterenvironmental liability 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. On May 29, 2008, the EPA issued a Record of Decision approving the remediation option submitted by Cotter and the two other PRPs that required additional landfill cover. By letter dated January 11, 2010, the EPA requested that the PRPs perform a supplemental feasibility study for a remediation alternative that would involve complete excavation of the radiological contamination. On September 30, 2011, the PRPs submitted the supplemental feasibility study to the EPA for review. Since June 2012, the EPA has requested that the PRPs perform a series of additional analyses and groundwater and soil sampling as part of the supplemental feasibility study. This further analysis has focused on a partial excavation remedial option. The PRPs have provided a draft Remedial Investigation and Feasibility Study (RI/FS) report to the EPA for its review and comment. The final RI/FS will form the basis of EPA’s selection of a remedy from among the alternatives of a landfill cover, and partial or complete excavation. The EPA has advised the PRPs that the EPA announcement of the proposed remedy will take place in the first quarter of 2018. Thereafter, the EPA will select a final remedy and seek to enter into a Consent Decree with the PRPs to effectuate the remedy. Recent investigation has identified a number of other parties who may be PRPs and could be liable to contribute to the final remedy. Further investigation is on going.

The estimated cost of the landfill cover remedy (taking into account the current EPA technical requirements incorporated in the third quarter 2017) is approximately $110 million, including escalation, which will be allocated among all PRPs. Generation has accrued what it believes to be an adequate amount to cover its anticipated share of a landfill cover, which is included in the table above. ~~Generation believes that a partial excavation remedy is reasonably possible, and the partial excavation costs, inclusive of a landfill cover, could range from approximately $225 million to $650~~ million; such costs would likely be shared by the final group of identified PRPs. Generation believes the likelihood that the EPA would require a complete excavation remedy is remote. The cost of a partial or complete excavation could have a material, unfavorable impact on Generation’s and Exelon’s future results of operations and cash flows.

PECO.

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

~~During December 2015, the EPA took two actions related to the West Lake Landfill designed to abate what it termed as imminent~~Note 12 — Commitments and dangerous conditions at the landfill. The first involved installation by the PRPs of a non-combustible surface cover to protect against surface fires in areas where radiological materials are believed to have been disposed. Generation has accrued what it believes to be an adequate amount to cover its anticipated liability for this interim action. The second action involved EPA's public statement that it will require the PRPs to construct a barrier wall in an adjacent landfill to prevent a subsurface fire from spreading to those areas of the West Lake Landfill where radiological materials are believed to have been disposed. At this time, EPA has not provided sufficient details related to the basis for and the requirements and design of a barrier wall to enable Generation to determine the likelihood such a remedy will ultimately be implemented, assess the degree to which Generation may have liability as a potentially responsible party, or develop a reasonable estimate of the potential incremental costs. It is reasonably possible, however, that resolution of this matter could have a material, unfavorable impact on Generation's and Exelon's future results of operations and cash flows. Finally, one of the other PRPs, the landfill owner and operator of the adjacent landfill, has indicated that 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, Generation and Exelon do not possess sufficient information to assess this claim and are therefore unable to determine the impact on their future results of operations and cash flows.

On February 2, 2016, the U.S. Senate passed a bill to transfer remediation authority over the West Lake Landfill from the EPA to the U.S. Army Corps of Engineers, under the Formerly Utilized Sites Remedial Action Program (FUSRAP). The legislation was not passed in the U.S. House of Representatives, and would therefore require reintroduction in the Senate for consideration in the current session of Congress. Should such proposed legislation ultimately become law, it would be subject to annual funding appropriations in the U.S. Budget. Remediation under FUSRAP would not alter the liability of the PRPs, but would likely delay the determination of a final remedy and its implementation.

~~On A~~ugust 8, 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 the 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. The DOJ and the PRPs agreed to toll the statute of limitations until August 2018 so that settlement discussions could proceed. Based on Generation’s preliminary review, it appears probable that Generation has liability to Cotter under the indemnification agreement and has established an appropriate accrual for this liability, which is included in the table above.

Commencing in February 2012, a number of lawsuits have been filed in the U.S. District Court for the Eastern District of Missouri. Among the defendants were Exelon, Generation and ComEd, all of which were subsequently dismissed from the case, as well as Cotter, which remains a defendant. The suits allege that individuals living in the North St. Louis area developed some form of cancer or other serious illness due to Cotter's negligent or reckless conduct in processing, transporting, storing, handling and/or disposing of radioactive materials. Plaintiffs are asserting public liability claims under the Price-Anderson Act. Their state law claims for negligence, strict liability, emotional distress, and medical monitoring have been dismissed. The complaints do not contain specific damage claims. In the event of a finding of liability against Cotter, it is reasonably possible that Exelon would be financially responsible due to its indemnification responsibilities of Cotter described above. The court has dismissed a number of lawsuits, and is expected to dismiss additional lawsuits based on a recent ruling. Pre-trial motions and discovery are proceeding in the remaining cases and a pre-trial scheduling order has been filed with the court. At this stage of the litigation, Generation and ComEd cannot estimate a range of loss, if any.

68^th ~~Street Dump.~~ In 1999, the EPA proposed to add the 68th Street Dump in Baltimore, Maryland to the Superfund National Priorities List, and notified BGE and 19 others that they are PRPs at the site. In connection with BGE's 2000 corporate restructuring the responsibility for this liability was transferred to Constellation and as a result of the 2012 Exelon and CEG merger is now Generation's responsibility. In March 2004, the PRPs formed the 68th Street Coalition and entered into consent order negotiations with the U.S. EPA to investigate clean-up options for the site under the Superfund Alternative Sites Program. In May 2006, a settlement among the U.S. EPA and the PRPs

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

with respect to investigation of the site became effective. The settlement requires the PRPs, over the course of several years, to identify contamination at the site and recommend clean-up options. The PRPs submitted their investigation of the range of clean-up options in the first quarter of 2011. OnAt September 30, ~~2013, EPA issued~~2023 and December 31, 2022, the ~~Record of Decision identifying its preferred remedial alternative~~Registrants had accrued the following undiscounted amounts for ~~the site. The estimated cost for the alternative chosen by EPA is consistent with the PRPs estimated range of costs noted above. In July, 2017 the PRPs~~environmental liabilities in Accrued expenses, Other current liabilities, and ~~EPA finalized the terms of a Consent Decree which has been executed by the Parties~~Other deferred credits and ~~lodged with the U.S. District Court. After publication~~other liabilities in the Federal Register there will be a 30-day public comment period after which it is anticipated it will be approved by the Court without any significant change in the costs for cleanup, Generation has elected to be a non-performing cash-out party and following payment of the allocated cost for its share of the clean-up. Generation will have no remaining liability at the site, except for unknown conditions that could manifest themselves after the settlement. The cash-out payment is included in the table above and is immaterial to the Generation and Exelon financial statements.their respective Consolidated Balance Sheets:

~~Rossville Ash Site.~~ The Rossville Ash Site is a 32-acre property located in Rosedale, Baltimore County, Maryland, which was used for the placement of fly ash from 1983-2007. The property is owned by Constellation Power Source Generation, LLC (CPSG), a wholly owned subsidiary of Generation. In 2008, CPSG investigated and remediated the property by entering it into the Maryland Voluntary Cleanup Program (VCP) to address any historic environmental concerns and ready the site for appropriate future redevelopment. The site was accepted into the program in 2010 and is currently going through the process to remediate the site and receive closure from MDE. Exelon currently estimates the cost to close the site to be approximately $1 million which has been fully reserved and included in the table above as of September 30, 2017.


	September 30, 2023				December 31, 2022
	Total environmental investigation and remediation liabilities		Portion of total related to MGP investigation and remediation		Total environmental investigation and remediation liabilities		Portion of total related to MGP investigation and remediation
Exelon	$	434	$	345	$	409	$	355
ComEd	312		311		325		324
PECO	28		26		25		23
BGE	9		8		9		8
PHI	82		—		46		—
Pepco	80		—		44		—
DPL	1		—		1		—
ACE	1		—		1		—

~~Sauer Dump.~~ On May 30, 2012, BGE was notified by the U.S. EPA that it is considered a PRP at the Sauer Dump Superfund site in Dundalk, Maryland. The U.S. EPA offered BGE and three other PRPs the opportunity to conduct an environmental investigation and present cleanup recommendations at the site. In addition, the U.S. EPA is seeking recovery from the PRPs for past cleanup and investigation costs at the site. On March 11, 2013, BGE and three other PRPs signed an Administrative Settlement Agreement and Order on Consent with the U.S. EPA which requires the PRPs to conduct a remedial investigation and feasibility study at the site to determine what, if any, are the appropriate and recommended cleanup activities for the site. Although the ultimate outcome of this proceeding is uncertain based on the information complied to date, BGE has developed an estimate of the range of the probable liability; such costs would be shared by the 4 identified PRPs. BGE has accrued an appropriate reserve for its share of the estimated liabilities that is included it in the table above. ~~It is possible, however, that final resolution of this matter could have a material, unfavorable impact on BGE’s future results of operations and cash flows.~~

~~Riverside.~~ In 2013, the MDE, at the request of EPA, conducted a site inspection and limited environmental sampling of certain portions of the 170 acre Riverside property owned by BGE. The site consists of several different parcels with different current and historical uses. The sampling included soil and groundwater samples for a number of potential environmental contaminants. The sampling confirmed the existence of contaminants consistent with the known historical uses of the various portions of the site. In March 2014, the MDE requested that BGE conduct an investigation which included a site-wide investigation of soils, sediment, groundwater, and surface water to complement the MDE sampling. The field investigation was completed in January 2015, and a final report was provided to MDE in June 2015. In November 2015, MDE provided BGE with its comments and recommendations on the report which require BGE to conduct further investigation and sampling at the site to better delineate the nature and extent of historic contamination, including off-site sediment and soil sampling. MDE did not request any interim remediation at this time and in May 2017 BGE completed the additional work requested by MDE. All the offsite sample testing produced results that were below the cleanup action level established by MDE and no further investigation is required. MDE has provided BGE with the required clean-up levels for the on-site contamination and BGE is moving forward with the necessary remediation as directed by MDE. BGE has established what it believes is an appropriate reserve based upon the information available to date, and this amount is included in the table above. As the remediation proceeds, it is possible that additional reserves could be established, in amounts that could be material to BGE.

BGE is authorized to recover, and is currently recovering, environmental costs for the remediation of the former MGP facility sites from customers; however, while BGE does not have a rider for MGP clean-up costs, BGE has historically received recovery of actual clean-up costs in distribution rates. Additionally, legislation was passed during the 2017 Maryland General Assembly session that should further support BGE’s recovery of its clean-up costs.

Benning Road ~~Site.~~ Site (Exelon, 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, which is owned by Pepco, was formerly the location of aan electric generating facility owned by Pepco subsidiary, Pepco Energy Services ~~electric generating facility. That~~(PES), which became a part of Generation, following the 2016 merger between PHI and Exelon. This generating facility was deactivated

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in June ~~2012 and plant structure demolition was completed in July 2015.~~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~~Consent Decree entered into by Pepco and Pepco Energy Services (hereinafter "Pepco Entities") with the DOEE, which requires the Pepco ~~and Pepco Energy Services~~Entities to conduct a ~~Remediation~~Remedial Investigation ~~(RI)/~~and Feasibility Study ~~(FS)~~(RI/FS) for the Benning Road site and an approximately 10 to ~~15 acre~~15-acre portion of the adjacent Anacostia River. The purpose of this RI/FS ~~will form~~is to define the ~~basis for the remedial actions for~~nature and extent of contamination from the Benning Road site and ~~for the Anacostia River sediment associated with the site. The consent decree does not obligate Pepco or Pepco Energy Services~~ to pay for or perform any remediation work, but it is anticipated that DOEE will look to Pepco and Pepco Energy Services to assume responsibility for cleanup of any conditions in the river that are determined to be attributable to past activities at the Benning Road site. evaluate remedial alternatives.

Pursuant to ~~Exelon's March 23, 2016 acquisition of PHI,~~an internal agreement between the Pepco ~~Energy Services was transferred to Generation. On July 1, 2017,~~Entities, since 2013, Pepco ~~Energy Services was merged into Constellation New Energy, a subsidiary of Generation.~~

~~The initial RI field~~has performed the work ~~began in January 2013~~required by the Consent Decree and was completed in December 2014. In April 2015, Pepco and Pepco Energy Services submitted a draft RI Report to DOEE. After review, DOEE determined that additional field investigation and data analysis was required to complete the RI process (much of which was beyond the scope of the original DOEE-approved RI work plan). In the meantime, Pepco and Pepco Energy Services revised the draft RI Report to address DOEE’s comments and DOEE released the draft RI Report for public review in February 2016. Once the additional RI work has been ~~completed,~~reimbursed for that work by an agreed upon allocation of costs between the Pepco ~~and Generation will issue~~Entities. In September 2019, the Pepco Entities issued a draft “final” RI report ~~for review and comment by~~which DOEE ~~and the public.~~approved on February 3, 2020. The Pepco ~~and Generation will then proceed to develop an~~Entities are completing a FS to evaluate possible remedial alternatives for submission to DOEE. ~~The Court has established a~~In October 2022, DOEE approved dividing the work to complete the landside portion of the FS from the waterside portion to expedite the overall schedule for completion of the RIproject. It is currently anticipated that the landside FS will be complete and ~~FS, and approval~~approved by DOEE by the end of the first quarter of 2024 and the waterside FS will be complete and approved by DOEE by ~~June 2018.~~

~~Upon DOEE’s approval~~the end of the ~~final RI and~~fourth quarter of 2024. Following the completion of each FS, ~~Reports, Pepco and Generation will have satisfied their obligations under the consent decree. At that point,~~ DOEE will ~~prepare~~issue a Proposed Plan ~~regarding further response actions. After considering~~for public comment ~~on the Proposed Plan, DOEE will~~and then issue a Record of Decision (ROD) identifying ~~any further response~~the remedial actions determined to be ~~necessary.~~necessary for the area in question. On October 3, 2023, DOEE and Pepco entered into an addendum to the Benning Consent Decree pursuant to which Pepco has agreed to fund or perform the remedial actions to be selected by DOEE for the landslide and water areas. This addendum to the Benning Consent Decree has been lodged with the court.Following a 30-day public comment period, DOEE will request that the court approve this addendum to the Consent Decree, which will become effective upon the court’s approval.

As part of the separation between Exelon and Constellation in February 2022, the internal agreement between the Pepco Entities for completion and payment for the remaining Consent Decree work was memorialized in a formal agreement for post-separation activities. A second post-separation assumption agreement between Exelon and Constellation transferred any of the potential remaining remediation liability, if any, of PES/Generation to a non-utility subsidiary of Exelon which going forward will be responsible for those liabilities. Exelon, PHI, ~~Pepco~~ and ~~Generation~~Pepco have determined that a loss associated with this matter ~~for PHI, Pepco and Generation~~ is probable and have accrued an estimated liability, ~~for this issue has been accrued,~~ which is included in the table above. As the remedial investigation proceeds and potential remedies are identified, it is possible that additional accruals could be established in amounts that could be material to PHI and Pepco. The ultimate resolution of this matter is currently not expected to have any significant financial impact on Generation.

Anacostia River Tidal Reach (Exelon, PHI, and Pepco). Contemporaneous with the Benning Road site RI/FS being performed by the Pepco ~~and Generation,~~Entities, DOEE and ~~certain federal agencies~~NPS have been conducting a separate RI/FS focused on the entire tidal reach of the Anacostia River extending from just north of the ~~Maryland-D.C.~~Maryland-District of Columbia boundary

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Note 12 — Commitments and Contingencies

line to the confluence of the Anacostia and Potomac Rivers. ~~In March 2016, DOEE released a draft of the river-wide RI Report for public review and comment.~~ The river-wide RI incorporated the results of the river sampling performed by the Pepco ~~and Pepco Energy Services~~Entities 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.

On September 30, 2020, DOEE ~~asked Pepco, along with parties responsible~~released its Interim ROD for ~~other sites along~~the Anacostia River sediments. The Interim ROD reflects an adaptive management approach which will require several identified “hot spots” in the river to ~~participate in a “Consultative Working Group”~~be addressed first while continuing to ~~provide input into the process for future remedial actions addressing the entire tidal reach of~~conduct studies and to monitor the river to evaluate improvements and ~~to ensure proper coordination with the other river cleanup efforts currently~~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 ~~cleanup of~~ the ~~river segment adjacent to~~plan for the Benning Road site to proceed to conclusion.

On July 15, 2022, Pepco received a letter from the District of Columbia's Office of the Attorney General (D.C. OAG) on behalf of DOEE conveying a settlement offer to resolve all PRPs' liability to the District of Columbia (District) for their past costs and their anticipated future costs to complete the work for the Interim ROD. Pepco responded on July 27, 2022 to enter into settlement discussions. On October 3, 2023, Pepco and the District entered into another consent decree (the “Anacostia River Consent Decree”) pursuant to which Pepco agreed to pay $47 million to resolve its liability to the District for all past costs to perform the river-wide RI/FS and all future costs to complete the work required by the Interim ROD. This amount will be paid in four equal annual installments beginning a year after the effective date of the Anacostia River Consent Decree. The funds will be deposited into the DOEE’s Clean Land Fund for the District’s costs of the Interim ROD work. The Anacostia River Consent Decree caps Pepco’s liability for these costs and provides Pepco with the right to seek contribution from other potentially responsible parties. The Anacostia River Consent Decree has been filed with the U.S. District Court for the District of Columbia. Following a 30-day public comment period, the District will ask the court to approve the Anacostia River Consent Decree, which will become effective upon the court’s approval. Exelon, PHI, and Pepco have accrued a liability for Pepco’s payment obligations under the Anacostia Consent Decree and management's best estimate of its share of any other future Anacostia River response costs. Pepco has concluded that incremental exposure remains reasonably possible, but 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, CERCLA separately requires federal and state (here including Washington, D.C.) Natural Resource Trustees (federal or state agencies designated by the President or the relevant state, respectively, or Indian tribes) to conduct an assessment of any damages to natural resources within their jurisdiction as a result of the contamination that is being remediated. The Trustees can seek compensation from responsible parties for such damages, including restoration costs. During the second quarter of 2018, Pepco became aware that the Trustees are in the beginning stages of a NRD assessment, a 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 NRD process, Pepco cannot reasonably estimate the final range of loss potentially resulting from this process.

As noted in the Benning Road RI/FS. Pepco responded that it will participate in the Consultative Working Group but its participation is not an acceptance of any financial responsibility beyond the work that will be performed at the Benning Road site described above. DOEE has advised the Consultative Working Group that the federal and DOEE authorities are conducting phase 2 of a remedial investigation and that a feasibility study of potential remedies is expected to be completed in December 2017. A proposed remedy for the clean-up of sediments in this sectionSite disclosure above, as part of the ~~river is expected to be released for public comment~~separation of Exelon and Constellation in February 2018 and the DOEE has targeted June 2018 as the date for remedy selection. The Consultative Working Group and the other possible PRPs have provided input into the proposed clean-up process and schedule. At this time, it is not possible to predict the extent of Pepco’s participation in the river-wide RI/FS process, and Pepco cannot estimate the reasonably possible range of loss for response costs beyond those2022, an assumption agreement was executed transferring any potential future remediation liabilities associated with the Benning ~~RI/FS component~~Site remediation to a non-utility subsidiary of Exelon. Similarly, any potential future liability associated with the ARSP was also assumed by this entity.

Buzzard Point Site (Exelon, PHI, and Pepco). On December 8, 2022, Pepco received a letter from the D.C. OAG, alleging wholly past violations of the ~~river-wide initiative. It is possible, however, that resolution~~District's stormwater discharge and waste disposal requirements related to operations at the Buzzard Point facility, a 9-acre parcel of ~~this matter could~~waterfront property in Washington, D.C. occupied by an active substation and former steam plant building. The letter also alleged wholly past violations by Pepco of stormwater discharge requirements related to its district-wide system of underground vaults. On October 3, 2023, Pepco entered into a Consent Order with the District of Columbia to resolve the alleged violations without any admission of liability. The Consent Order requires Pepco to pay a civil penalty of $10 million. In addition, Pepco has agreed to assess the environmental conditions at its Buzzard Point facility and conduct any remedial actions deemed necessary as a result of the assessment, and also to assess potential environmental impacts associated with the operation of its underground vaults. The Consent Order has been filed with the District of Columbia Superior Court. Following a 30-day public comment period regarding the environmental assessment work required by the Consent Order, the District will ask the court to approve the Consent Order, which will be become effective upon the court’s approval. Exelon, PHI, and Pepco have ~~a material, unfavorable impact on Exelon's and Pepco’s future results of operations and cash flows.~~

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Note 12 — Commitments and Contingencies

~~Conectiv Energy Wholesale Power Generation Sites.~~ ~~In July 2010, PHI sold~~a liability for the wholesale power generation business of Conectiv Energy Holdings, Inc. and substantially all of its subsidiaries (Conectiv Energy) to Calpine Corporation (Calpine). Under New Jersey’s Industrial Site Recovery Act (ISRA), the transfer of ownership to Calpine triggered an obligation on the part of Conectiv Energy to remediate any environmental contamination at each of the nine Conectiv Energy generating facility sites located in New Jersey. Under the terms of the sale, Calpine assumed responsibility for performing the ISRA-required remediationpenalty payments and for the ~~payment of all related ISRA compliance~~projected costs ~~up to $10 million. Predecessor PHI was obligated to indemnify Calpine~~ for ~~any ISRA compliance remediation costs in excess of $10 million. According to PHI’s estimates,~~ the ~~costs of ISRA-required remediation activities at the 9 generating facility sites are in~~required environmental assessments and remediation. Pepco has concluded that incremental exposure is reasonably possible, but the range of ~~approximately $7 million to $18 million~~, ~~and predecessor PHI established an appropriate accrual for its share of~~loss cannot be reasonably estimated beyond the estimated clean-up costs. Pursuant to Exelon’s March 2016 acquisition of PHI, the Conectiv Energy legal entity was transferred to Generation and the accrual for Predecessor PHI's share of the estimated clean- up costs was also transferred to Generation and isamounts included in the table above as a liability of Generation. The responsibility to indemnify Calpine is shared by PHI and Generation. The ultimate resolution of this matter is currently not expected to have a material financial impact on PHI and Generation.above.

~~Rock Creek Mineral Oil Release.~~ In late August 2015, a Pepco underground transmission line in the District of Columbia suffered a breach, resulting in the release of non-toxic mineral oil surrounding the transmission line into the surrounding soil, and a small amount reached Rock Creek through a storm drain. Pepco notified regulatory authorities, and Pepco and its spill response contractors placed booms in Rock Creek, blocked the storm drain to prevent the release of mineral oil into the creek and commenced remediation of soil around the transmission line and the Rock Creek shoreline. Pepco estimates that approximately 6,100 gallons of mineral oil were released and that its remediation efforts recovered approximately 80% of the amount released. Pepco’s remediation efforts are ongoing under the direction of the DOEE, including the requirements of a February 29, 2016 compliance order which requires Pepco to prepare a full incident investigation report and prepare a removal action work plan to remove all impacted soils in the vicinity of the storm drain outfall, and in collaboration with the National Park Service, the Smithsonian Institution/National Zoo and EPA. Pepco’s investigation presently indicates that the damage to Pepco’s facilities occurred prior to the release of mineral oil when third-party excavators struck the Pepco underground transmission line while installing cable for another utility.

PHI and Pepco have reached a settlement with a third party who contributed to the loss. Exelon, PHI and Pepco do not believe that the balance of the remediation costs to resolve this matter will have a material adverse effect on their respective financial condition, results of operations or cash flows.

~~Brandywine Fly Ash Disposal Site.~~ In February 2013, Pepco received a letter from the MDE requesting that Pepco investigate the extent of waste on a Pepco right-of-way that traverses the Brandywine fly ash disposal site in Brandywine, Prince George’s County, Maryland, owned by NRG Energy, Inc. (as successor to GenOn MD Ash Management, LLC) (NRG). In July 2013, while reserving its rights and related defenses under a 2000 agreement covering the sale of this site, Pepco indicated its willingness to investigate the extent of, and propose an appropriate closure plan to address, ash on the right-of-way. Pepco submitted a schedule for development of a closure plan to MDE on September 30, 2013 and, by letter dated October 18, 2013, MDE approved the schedule.

Exelon, PHI and Pepco have determined that a loss associated with this matter is probable and have estimated that the costs for implementation of a closure plan and cap on the site are in the range of approximately $3 million to $6 million, for which an appropriate reserve has been established and is included in the table above. Exelon, PHI and Pepco believe that the costs incurred in this matter will be recoverable from NRG under the 2000 sale agreement.

Litigation and Regulatory Matters

~~Asbestos Personal Injury Claims~~DPA and Related Matters (Exelon ~~Generation,~~and ComEd). Exelon and ComEd ~~PECO~~received a grand jury subpoena in the second quarter of 2019 from the U.S. Attorney’s Office for the Northern District of Illinois (USAO) requiring production of information concerning their lobbying activities in the State of Illinois. On October 4, 2019, Exelon and ~~BGE)~~

ComEd received a second grand jury subpoena from the USAO requiring production of records of any communications with certain individuals and entities. On October 22, 2019, the SEC notified Exelon ~~Generation~~ and ~~PECO~~. ~~Generation maintains~~ComEd that it had also opened an investigation into their lobbying activities. On July 17, 2020, ComEd entered into a ~~reserve for claims~~Deferred Prosecution Agreement (DPA) with the USAO to resolve the USAO investigation. Under the DPA, the USAO filed a single charge alleging that ComEd improperly gave and offered to give jobs, vendor subcontracts, and payments associated with ~~asbestos-related personal injury actions~~those jobs and subcontracts for the benefit of the former Speaker of the Illinois House of Representatives and the Speaker’s associates, with the intent to influence the Speaker’s action regarding legislation affecting ComEd’s interests. The DPA provided that the USAO would defer any prosecution of such charge and any other criminal or civil case against ComEd in connection with the matters identified therein for a three-year period subject to certain ~~facilities~~obligations of ComEd, including payment to the U.S. Treasury of $200 million, which was paid in November 2020. Exelon was not made a party to the DPA, and therefore the investigation by the USAO into Exelon’s activities ended with no charges being brought against Exelon. The three-year term of the DPA ended on July 17, 2023, and on that ~~are currently owned~~same date the court granted the USAO’s motion to dismiss the pending charge against ComEd that had been deferred by ~~Generation or were previously owned~~the DPA.

On September 28, 2023, Exelon and ComEd reached a settlement with the SEC, concluding and resolving in its entirety the SEC investigation, which related to the conduct identified in the DPA that was entered into by ComEd in July 2020 and ~~PECO. The reserve is recorded on an undiscounted basis and excludes~~successfully exited in July 2023. Under the ~~estimated legal costs associated with handling these matters, which could be material.~~

~~At September 30, 2017 and December 31, 2016, Generation had reserved approximately $80~~terms of the settlement, Exelon has agreed to pay a civil penalty of $46.2 million and ~~$83 million, respectively,~~Exelon and ComEd have agreed to cease and desist from committing or causing any violations and any future violations of specified provisions of the federal securities laws and rules promulgated thereunder. Exelon recorded an accrual for the full amount of the penalty in ~~total for asbestos-related bodily injury claims. As~~the second quarter of ~~September 30, 2017, approximately $22 million~~2023, which was reflected in Operating and maintenance expense within Exelon's Consolidated Statements of ~~this amount~~Operations and Comprehensive Income and in Accrued expenses on the Consolidated Balance Sheets. Exelon paid the civil penalty in full on October 4, 2023.

Subsequent to Exelon announcing the receipt of the USAO subpoenas, various lawsuits were filed, and various demand letters were received related to ~~227 open claims presented to Generation, while~~ the ~~remaining $58 million~~subject of the ~~reserve~~subpoenas, the conduct described in the DPA and the SEC's investigation, including:

•Four putative class action lawsuits against ComEd and Exelon were filed in federal court on behalf of ComEd customers in the third quarter of 2020 alleging, among other things, civil violations of federal racketeering laws. In addition, the Citizens Utility Board (CUB) filed a motion to intervene in these cases on October 22, 2020 which was granted on December 23, 2020. On September 9, 2021, the federal court granted Exelon’s and ComEd’s motion to dismiss and dismissed the plaintiffs’ and CUB’s federal law claim with prejudice. The federal court also dismissed the related state law claims made by the federal plaintiffs and CUB on jurisdictional grounds. Plaintiffs appealed dismissal of the federal law claim to the Seventh Circuit Court of Appeals. Plaintiffs and CUB also refiled their state law claims in state court and moved to consolidate them with the already pending consumer state court class action, discussed below. On August 22, 2022, the Seventh Circuit affirmed the dismissal of the consolidated federal cases in their entirety. The time to further appeal has passed and the Seventh Circuit’s decision is ~~for estimated future asbestos-related bodily injury claims anticipated~~final.

•Three putative class action lawsuits against ComEd and Exelon were filed in Illinois state court in the third quarter of 2020 seeking restitution and compensatory damages on behalf of ComEd customers. The cases were consolidated into a single action in October of 2020. In November 2020, CUB filed a motion to ~~arise through 2050, based~~intervene in the cases pursuant to an Illinois statute allowing CUB to intervene as a party or otherwise participate on ~~actuarial~~

behalf of utility consumers in any proceeding which affects the interest of utility consumers. On November 23, 2020, the court allowed CUB’s intervention, but denied CUB's request to stay these cases. Plaintiffs subsequently filed a consolidated complaint, and ComEd and Exelon filed a motion to dismiss on jurisdictional and substantive grounds on January 11, 2021. Briefing on that motion

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Note 12 — Commitments and Contingencies

~~assumptions~~was completed on March 2, 2021. The parties agreed, on March 25, 2021, along with the federal court plaintiffs discussed above, to jointly engage in mediation. The parties participated in a one-day mediation on June 7, 2021 but no settlement was reached. On December 23, 2021, the state court granted ComEd and ~~analyses, which are updated~~Exelon's motion to dismiss with prejudice. On December 30, 2021, plaintiffs filed a motion to reconsider that dismissal and for permission to amend their complaint. The court denied the plaintiffs' motion on ~~an annual basis. On a quarterly basis, Generation monitors actual experience against~~January 21, 2022. Plaintiffs have appealed the ~~number of forecasted claims to be received and expected claim payments and evaluates whether an adjustment~~court's ruling dismissing their complaint to the ~~reserve is necessary.~~

~~On November 22, 2013, the Supreme~~First District Court of ~~Pennsylvania held that~~Appeals. On February 15, 2022, Exelon and ComEd moved to dismiss the ~~Pennsylvania Workers Compensation Act does not apply~~federal plaintiffs' refiled state law claims, seeking dismissal on the same legal grounds asserted in their motion to ~~an employee’s disability or death resulting from occupational disease, such as diseases related to asbestos exposure, which manifests more than 300 weeks after~~dismiss the ~~employee’s last employment-based exposure, and that therefore the exclusivity provision~~original state court plaintiffs' complaint. The court granted dismissal of the ~~Act does not preclude such employee from suing his or her employer in court.~~refiled state claims on February 16, 2022. The ~~Supreme Court’s ruling reverses previous rulings by~~original federal plaintiffs appealed that dismissal on February 18, 2022. The two state appeals were consolidated on March 21, 2022. On September 8, 2023, the ~~Pennsylvania Superior~~Illinois Appellate Court ~~precluding current and former employees from suing their employers in court, despite~~affirmed the fact that the same employee was not eligible for workers compensation benefits for diseases that manifest more than 300 weeks after the employee’s last employment-based exposure to asbestos. Since the Pennsylvania Supreme Court's ruling in November 2013, Exelon, Generation, and PECO have experienced an increase in asbestos-related personal injury claims brought by former PECO employees, all of which have been reserved for on a claim by claim basis. Those additional claims are taken into account in projecting estimates of future asbestos-related bodily injury claims.

~~On November 4, 2015,~~dismissal. Plaintiffs may ask the Illinois Supreme Court found that the provisions of the Illinois' Workers' Compensation Act and the Workers' Occupational Diseases Act barred an employee from bringing a direct civil action against an employer for latent diseases, including asbestos-related diseases that fall outside the 25-year limit of the statute of repose. The Illinois Supreme Court's ruling reversed previous rulings by the Illinois Court of Appeals, which initially ruled that the Illinois Worker's Compensation law shouldto grant them leave to further appeal, but such appeal is not apply in cases where the diagnosis of an asbestos related disease occurred after the 25-year maximum time period for filing a Worker's Compensation claim. Since the Illinois Supreme Court’s ruling in November 2015, Exelon, Generation, and ComEd have not experienced a significant increase in asbestos-related personal injury claims brought by former ComEd employees.

There is a reasonable possibility that Exelon may have additional exposure to estimated future asbestos-related bodily injury claims in excess of the amount accrued and the increases could have a material adverse effect on Exelon's, Generation's, ComEd's, PECO and BGE's future results of operations and cash flows.

~~BGE~~. Since 1993, BGE and certain Constellation (now Generation) subsidiaries have been involved in several actions concerning asbestos. The actions are based upon the theory of “premises liability,” alleging that BGE and Generation knew of and exposed individuals to an asbestos hazard. In addition to BGE and Generation, numerous other parties are defendants in these cases.

To date, most asbestos claims which have been resolved relating to BGE and certain Constellation subsidiaries have been dismissed or resolved without any payment and a small minority of these cases has been resolved for amounts that were not material to BGE or Generation’s financial results. Presently, there are an immaterial number of asbestos cases pending against BGE and certain Constellation subsidiaries.

~~Continuous Power Interruption (Exelon and ComEd)~~

Section 16-125 of the Illinois Public Utilities Act provides that in the event an electric utility, such as ComEd, experiences a continuous power interruption of four hours or more that affects (in ComEd’s case) more than 30,000 customers, the utility may be liable for actual damages suffered by customersallowed as a ~~result~~matter of ~~the interruption~~right.

•On November 3, 2022, a plaintiff filed a putative class action complaint in Lake County, Illinois Circuit Court against ComEd and ~~may be responsible~~Exelon for ~~reimbursement of local governmental emergency~~unjust enrichment and ~~contingency expenses incurred~~deceptive business practices in connection with the ~~interruption. Recovery~~conduct giving rise to the DPA. Plaintiff seeks an accounting and disgorgement of ~~consequential damages is barred.~~any benefits ComEd allegedly obtained from said conduct. Plaintiff served initial discovery requests on ComEd in December 2022, to which ComEd has responded. ComEd and Exelon filed a motion to dismiss the Complaint on February 3, 2023. On June 16, 2023, the court granted Exelon and ComEd's motion to dismiss the action with prejudice. Plaintiff filed its notice of appeal of that dismissal on July 17, 2023. Plaintiff's opening appellate brief was filed on October 19, 2023.

•A putative class action lawsuit against Exelon and certain officers of Exelon and ComEd was filed in federal court in December 2019 alleging misrepresentations and omissions in Exelon’s SEC filings related to ComEd’s lobbying activities and the related investigations. The ~~affected utility may seek~~complaint was amended on September 16, 2020, to dismiss two of the original defendants and add other defendants, including ComEd. Defendants filed a motion to dismiss in November 2020. The court denied the motion in April 2021. On May 26, 2021, defendants moved the court to certify its order denying the motion to dismiss for interlocutory appeal. Briefing on the motion was completed in June 2021, and that motion was denied on January 28, 2022. In May 2021, the parties each filed respective initial discovery disclosures. On June 9, 2021, defendants filed their answer and affirmative defenses to the complaint and the parties engaged thereafter in discovery. On September 9, 2021, the U.S. government moved to intervene in the lawsuit and stay discovery until the parties entered into an amendment to their protective order that would prohibit the parties from requesting discovery into certain matters, including communications with the ~~ICC~~U.S. government. The court ordered said amendment to the protective order on November 15, 2021 and discovery resumed. The court further amended the protective order on October 17, 2022 and extended it until May 15, 2023. Following mediation, the parties reached a ~~waiver~~settlement of ~~these liabilities when~~ the ~~utility can show~~lawsuit, under which defendants agreed to pay plaintiffs $173 million. On May 26, 2023, plaintiffs filed a motion for preliminary approval of the settlement, which the court granted on June 9, 2023. The court granted final settlement approval on September 7, 2023. The settlement was fully covered by insurance and has been paid in full.

•Several shareholders have sent letters to the Exelon Board of Directors since 2020 demanding, among other things, that the ~~cause~~Exelon Board of Directors investigate and address alleged breaches of fiduciary duties and other alleged violations by Exelon and ComEd officers and directors related to the conduct described in the DPA. In the first quarter of 2021, the Exelon Board of Directors appointed a Special Litigation Committee (SLC) consisting of disinterested and independent parties to investigate and address these shareholders’ allegations and make recommendations to the Exelon Board of Directors based on the outcome of the ~~interruption was unpreventable damage due~~SLC’s investigation. In July 2021, one of the demand letter shareholders filed a derivative action against current and former Exelon and ComEd officers and directors, and against Exelon, as nominal defendant, asserting the same claims made in its demand letter. On October 12, 2021, the parties to ~~weather events or conditions, customer tampering, or certain other causes enumerated~~the derivative action filed an agreed motion to stay that litigation for 120 days in order to allow the ~~law. As of September 30, 2017 and December 31, 2016, ComEd~~SLC to continue its investigation, which the court granted. The stay has been extended several times. The parties participated in a mediation in February 2023, but the matter did not ~~have any material liabilities recorded for these storm events.~~

~~Baltimore City Franchise Taxes (Exelon~~resolve at that time. On April 26 and ~~BGE)~~

~~The City of Baltimore~~May 1, 2023, two additional demand letter shareholders each filed a separate derivative lawsuit against current and former Exelon and ComEd officers and directors, and certain third parties, and against Exelon as nominal defendant, asserting claims ~~that BGE has maintained electric facilities~~similar to those made in the City’s public right-of-ways for over one hundred years without the proper franchise rights from the City. BGE has reviewed the City's claim and believes that it lacks merit. BGE has not recorded an accrual for payment of franchise fees for past periods as a range of loss, if any, cannot be reasonably estimated at this time. Franchise fees assessed in future periods may be material to BGE’s results of operations and cash flows.

their respective demand letters. On May 25, 2023, certain demand letter shareholders (Settling

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

Note 12 — Commitments and Contingencies

~~Conduit Lease with City~~Shareholders) filed a separate derivative lawsuit against current and former Exelon and ComEd officers and directors, and against Exelon as nominal defendant, asserting claims similar to those made in their respective demand letters. The then pending derivative lawsuits were subsequently consolidated. On May 26, 2023, prior to lawsuit consolidation, the SLC filed a Notice of ~~Baltimore (Exelon~~Determination and ~~BGE~~)

~~On September 23, 2015,~~Intent to Seek Court Approval of Settlement (Notice of Determination). The Notice of Determination stated that, through mediation efforts, a settlement of the ~~Baltimore City~~derivative claims had been approved by the SLC, the Independent Review Committee of the Board (which had been formed in the third quarter of ~~Estimates approved an increase~~2022, to ensure the Board’s consideration of any SLC recommendations would be independent and objective), the Board, and the Settling Shareholders (the Settling Parties). The Notice of Determination further specified the process by which the Settling Parties would seek court approval of the proposed settlement and resolution and dismissal of all derivative claims and lawsuits, including any lawsuits or actions brought by demand letter shareholders who are not participating in ~~annual rental fees~~the proposed settlement. In furtherance of the proposed settlement, on June 16, 2023, the SLC filed a motion for ~~access~~preliminary approval of the settlement, attaching the Stipulation and Agreement of Settlement (Stipulation), which contains the terms of the proposed settlement. The proposed settlement terms include but are not limited to: a payment of $40 million to Exelon by Exelon’s insurers of which $10 million constitutes the attorneys’ fee award to be paid to the ~~Baltimore City underground conduit system effective November 1, 2015, from $12 million~~Settling Shareholders’ counsel; various compliance and disclosure-related reforms; and certain changes in Board and Committee composition. On June 13, 2023, the non-settling derivative shareholders filed a motion asking the court to ~~$42 million, subject~~set a status conference to discuss lifting the discovery stay. On June 29, 2023, an ~~annual increase thereafter based~~additional shareholder filed a separate derivative lawsuit against current and former Exelon and ComEd officers and directors, and against Exelon as nominal defendant, asserting claims similar to those made in its demand letter. On June 30, 2023, the non-settling shareholders’ motion for status and the SLC’s motion for preliminary approval was heard by the court, during which the court set a briefing schedule on the ~~Consumer Price Index. BGE subsequently entered into litigation~~appropriate standard for evaluating the settlement and the proper scope of requested discovery. Following briefing and a hearing, the court allowed the non-settling shareholders to seek certain, limited discovery, which the SLC, Independent Review Committee, and Exelon responded to on October 5. On October 11, 2023, an additional non-settling shareholder filed a separate derivative lawsuit against current and former Exelon and ComEd officers and directors, and against Exelon as a nominal defendant, asserting claims similar to those made in its demand letter. Plaintiff has informed Exelon that he will move to consolidate this matter with the ~~City regarding~~other pending derivative matters. The SLC filed its renewed motion for preliminary approval on October 26, with supporting submissions filed by the Independent Review Committee, Exelon, and the settling shareholders on that same day. The non-settling plaintiffs have until November 29 to file their response to the renewed motion for preliminary approval, and the SLC has until December 21 to file its reply.

•Several shareholders have sent requests seeking review of certain Exelon books and records since August 2021. Exelon has responded to each request.

In August 2022, the ICC concluded its investigation initiated on August 12, 2021 into rate impacts of conduct admitted in the DPA, including the costs recovered from customers related to the DPA and Exelon's funding of the fine paid by ComEd. On August 17, 2022, the ICC issued its final order accepting ComEd's voluntary customer refund offer of approximately $38 million (of which about $31 million is ICC jurisdictional; the remaining balance is FERC jurisdictional) that resolves the question of whether customer funds were used for DPA related activities. The customer refund includes the cost of every individual or entity that was either (i) identified in the DPA or (ii) identified by ComEd as an associate of the former Speaker of the Illinois House of Representatives in the ICC proceeding. The ICC’s DPA investigation is now closed. The ICC jurisdictional refund was made to customers during the April 2023 billing cycle, as required by the ICC. The FERC jurisdictional refund was included in ComEd's transmission formula rate update proceeding, filed on May 12, 2023. The filed transmission rate, inclusive of the FERC jurisdictional DPA refund, will appear on ComEd retail customers' bills for the June 2023 through May 2024 monthly billing periods, in the line designated as "Transmission Services Charge." The customer refund will not be recovered in rates or charged to customers and ComEd will not seek or accept reimbursement or indemnification from any source other than Exelon. An accrual for the amount of the customer refund has been recorded in Regulatory assets in Exelon’s and ~~basis~~ComEd’s Consolidated Balance Sheets as of September 30, 2023.

Savings Plan Claim (Exelon). On December 6, 2021, seven current and former employees filed a putative ERISA class action suit in U.S. District Court for ~~establishing~~ the ~~conduit fee.~~Northern District of Illinois against Exelon, its Board of Directors, the former Board Investment Oversight Committee, the Corporate Investment Committee, individual

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

Note 12 — Commitments and Contingencies

defendants, and other unnamed fiduciaries of the Exelon Corporation Employee Savings Plan (Plan). The complaint alleges that the defendants violated their fiduciary duties under the Plan by including certain investment options that allegedly were more expensive than and underperformed similar passively-managed or other funds available in the marketplace and permitting a third-party administrative service provider/recordkeeper and an investment adviser to charge excessive fees for the services provided. The plaintiffs seek declaratory, equitable and monetary relief on behalf of the Plan and participants. On February 16, 2022, the court granted the parties' stipulated dismissal of the individual named defendants without prejudice. The remaining defendants filed a motion to dismiss the complaint on February 25, 2022. On March 4, 2022, the Chamber of Commerce filed a brief of amicus curiae in support of the defendants' motion to dismiss. On September 22, 2022, the court granted Exelon’s motion to dismiss without prejudice. The court granted plaintiffs leave until October 31, 2022 to file an amended complaint, which was later extended to November 30, ~~2016,~~2022. Plaintiffs filed their amended complaint on November 30, 2022. Defendants filed their motion to dismiss the ~~Baltimore City Board~~amended complaint on January 20, 2023. On September 29, 2023, the court again granted Exelon's motion to dismiss but granted plaintiffs leave until October 20, 2023 to file a second amended complaint. Plaintiffs did not file an amended complaint by the deadline. On October 25, the parties filed a joint Stipulation of ~~Estimates approved a settlement agreement entered into between BGE~~Dismissal, which provides that plaintiffs agreed that they will not initiate an appeal from the dismissal of this matter, and the ~~City to resolve the disputes~~parties agree that each side shall bear their own costs and pending litigation related to BGE's use of and payment for the underground conduit system. As a result of the settlement, the parties have entered into a six-year lease that reduces the annual expense to $25 millionattorneys’ fees. Plaintiffs also acknowledge in the ~~first three years and caps the annual expense~~Stipulation that defendants have neither paid nor agreed to pay or provide any monetary or equitable remedy in the last three years to not more than $29 million. BGE recorded a credit to Operating and maintenance expense in the fourth quarter of 2016 of approximately $28 million for the reversal of the previously higher fees accrued in the current year as well as the settlement of prior year disputed fee true-up amounts.

~~Deere Wind Energy Assets (Exelon and Generation)~~

In 2013, Deere & Company (“Deere”) filed a lawsuit against Generation in the Delaware Superior Court relating to Generation’s acquisition of the Deere wind energy assets. Under the purchase agreement, Deere was entitled to receive earn-out payments if certain specific wind projects already under development in Michigan met certain development and construction milestones following the sale. In the complaint, Deere seeks to recover a $14 million earn-out payment associated with one such project, which was never completed. Generation has filed counterclaims against Deere for breach of contract, with a right of recoupment and set off. On June 2, 2016, the Delaware Superior Court entered summary judgment in favor of Deere. On January 17, 2017, Generation filed an appeal of the Superior Court’s summary judgment decisionconnection with the ~~Supreme Court~~dismissal of ~~Delaware. Generation has accrued an amount~~this action. On October 27, the court entered final judgment dismissing the matter with prejudice. No loss contingencies have been reflected in Exelon’s consolidated financial statements with respect to ~~cover its potential liability.~~this matter.

~~City of Everett Tax Increment Financing Agreement (Exelon)~~

The City of Everett has filed a petition with the Massachusetts Economic Assistance Coordinating Council (EACC) to revoke the 1999 tax increment financing agreement (TIF Agreement) relating to Mystic 8 & 9 on the grounds that the total investment in Mystic 8 & 9 materially deviates from the investment set forth in the TIF Agreement. The EACC has appointed a three-member panel to conduct an administrative hearing on the City’s petition. Generation has reviewed the City’s claim and believes that it lacks merit. Generation has not recorded an accrual for payment resulting from such a revocation because the range of loss, if any, cannot be reasonably estimated at this time. Property taxes assessed in future periods could be material to Generation’s results of operations and cash flows.

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 Registrants are also from time to time subject to audits and investigations by the FERC and other regulators. The assessment of whether a loss is probable or ~~a reasonable possibility,~~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.

~~Income Taxes (Exelon, Generation, ComEd, PECO~~

13. Shareholders' Equity (Exelon)

At-the-Market Program

On August 4, 2022, Exelon executed an equity distribution agreement (“Equity Distribution Agreement”), with certain sales agents and ~~BGE)~~

~~See Note 12 — Income Taxes for information regarding the Registrants’ income tax refund claims~~forward sellers and certain ~~tax positions, including~~forward purchasers, establishing an ATM equity distribution program under which it may offer and sell shares of its Common stock, having an aggregate gross sales price of up to $1.0 billion. Exelon has no obligation to offer or sell any shares of Common stock under the ~~1999~~Equity Distribution Agreement and may, at any time, suspend or terminate offers and sales under the Equity Distribution Agreement. As of September 30, 2023, Exelon has not issued any shares of Common stock under the ATM program and has not entered into any forward sale ~~of fossil generating assets.~~

agreements.

~~165~~

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 14 — Changes in Accumulated Other Comprehensive Income

~~19.~~14. Changes in Accumulated Other Comprehensive Income (Loss) (Exelon)

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


Nine Months Ended September 30, 2023	Cash Flow Hedges		Pension and Non-Pension Postretirement Benefit Plan Items(a)		Foreign Currency Items		Total
Balance at December 31, 2022	$	2	$	(640)	$	—	$	(638)
OCI before reclassifications	6		(10)		—		(4)
Amounts reclassified from AOCI	—		3		—		3
Net current-period OCI	6		(7)		—		(1)
Balance at March 31, 2023	8		(647)		—		(639)
OCI before reclassifications	9		(3)		—		6
Amounts reclassified from AOCI	—		3		—		3
Net current-period OCI	9		—		—		9
Balance at June 30, 2023	17		(647)		—		(630)
OCI before reclassifications	22		(3)		—		19
Amounts reclassified from AOCI	(1)		16		—		15
Net current-period OCI	21		13		—		34
Balance at September 30, 2023	$	38	$	(634)	$	—	$	(596)


Nine Months Ended September 30, 2022	Cash Flow Hedges		Pension and Non-Pension Postretirement Benefit Plan Items(a)		Foreign Currency Items		Total
Balance at December 31, 2021	$	(6)	$	(2,721)	$	(23)	$	(2,750)
Separation of Constellation	6		1,994		23		2,023

Amounts reclassified from AOCI	—		14		—		14
Net current-period OCI	—		14		—		14
Balance at March 31, 2022	—		(713)		—		(713)
OCI before reclassifications	—		2		—		2
Amounts reclassified from AOCI	—		10		—		10
Net current-period OCI	—		12		—		12
Balance at June 30, 2022	—		(701)		—		(701)

Amounts reclassified from AOCI	—		9		—		9
Net current-period OCI	—		9		—		9
Balance at September 30, 2022	$	—	$	(692)	$	—	$	(692)

__________

(a)This AOCI component is included in the computation of net periodic pension and OPEB cost. Additionally, as of February 1, 2022, in connection with the separation, Exelon's pension and OPEB plans were remeasured. See Note 14 — Retirement Benefits of the 2022 Form 10-K and Note 8 — Retirement Benefits for additional information. See Exelon's Statements of Operations and Comprehensive Income for individual components of AOCI.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 14 — Changes in Accumulated Other Comprehensive Income

The following table presents Income tax benefit (expense) allocated to each component of Exelon's Other comprehensive income (loss):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Pension and non-pension postretirement benefit plans:

Actuarial losses reclassified to periodic benefit cost	$	(5)	$	(3)	$	(7)	$	(11)
Pension and non-pension postretirement benefit plans valuation adjustments	1		—		5		—
Unrealized gains on cash flow hedges	(7)		—		(11)		—

15. Supplemental Financial Information (All Registrants)

Supplemental Statement of Operations Information

The following tables provide additional information about material items recorded in the ~~Registrants’~~Registrants' Consolidated Statements of Operations and Comprehensive ~~Income for the three and nine months ended September 30, 2017 and 2016.~~Income:


	Taxes other than income taxes
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Three Months Ended September 30, 2023
Utility taxes(a)	$	244	$	82	$	50	$	23	$	89	$	82	$	6	$	1
Property	104		9		4		53		38		25		12		1
Payroll	31		8		4		5		7		2		1		1

Three Months Ended September 30, 2022
Utility taxes(a)	$	244	$	84	$	51	$	22	$	87	$	79	$	7	$	1
Property	99		10		4		50		35		23		11		1
Payroll	28		7		5		4		7		2		1		—

Nine Months Ended September 30, 2023
Utility taxes(a)	$	665	$	228	$	128	$	73	$	236	$	213	$	20	$	3
Property	300		27		12		153		108		73		34		1
Payroll	93		22		13		14		22		5		3		3

Nine Months Ended September 30, 2022
Utility taxes(a)	$	667	$	233	$	126	$	70	$	238	$	216	$	19	$	3
Property	287		30		12		142		103		70		31		2
Payroll	92		21		14		13		21		5		4		2

_________

Three Months Ended September 30, 2017
Successor
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning trust funds^(a)

Regulatory agreement units $ 159
$ 159
$ —
$ —
$ —
$ —
$ —
$ —
$ —
Non-regulatory agreement units 59
59
—
—
—
—
—
—
—
Net unrealized gains on decommissioning trust funds
Regulatory agreement units 44
44
—
—
—
—
—
—
—
Non-regulatory agreement units 111
111
—
—
—
—
—
—
—
Net unrealized losses on pledged assets
Zion Station decommissioning (4 ) (4 ) —
—
—
—
—
—
—
Regulatory offset to decommissioning trust fund-related activities^(b)
(161 ) (161 ) —
—
—
—
—
—
—
Total decommissioning-related activities 208
208
—
—
—

—
—
—
—
Investment income 2
1
—
—
—
1
1
—
—
Interest income related to uncertain income tax positions 4
—
—
—
—
—
—
—
—
AFUDC — Equity 17
—
2
2
4
9
6
2
1
Other 6
—
3
—
—
3
—
2
—
Other, net $ 237

$ 209

$ 5

$ 2

$ 4

$ 13

$ 7

$ 4

$ 1

Nine Months Ended September 30, 2017
Successor
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning trust funds^(a)

Regulatory agreement units $ 439
$ 439
$ —
$ —
$ —
$ —
$ —
$ —
$ —
Non-regulatory agreement units 165
165
—
—
—
—
—
—
—
Net unrealized gains on decommissioning trust funds
Regulatory agreement units 253
253
—
—
—
—
—
—
—
Non-regulatory agreement units 347
347
—
—
—
—
—
—
—
Net unrealized losses on pledged assets
Zion Station decommissioning (5 ) (5 ) —
—
—
—
—
—
—
Regulatory offset to decommissioning trust fund-related activities^(b)
(558 ) (558 ) —
—
—
—
—
—
—
Total decommissioning-related activities 641
641
—
—
—
—

—
—
—
Investment income 6
4
—
—
—
2
1
—
—
Interest income related to uncertain income tax positions 3
—
—
—
—
—
—
—
—
Benefit related to uncertain income tax positions^(c)
2
—
—
—
—
—
—
—
—
AFUDC — Equity 51
—
6
6
12
27
17
5
5
Other 22
3
8
—
—
11
4
5
1
Other, net $ 725

$ 648

$ 14

$ 6

$ 12
$ 40

$ 22

$ 10

$ 6

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~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

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

Three Months Ended September 30, 2016
Successor
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning trust funds^(a)

Regulatory agreement units $ 57
$ 57
$ —
$ —
$ —
$ —
$ —
$ —
$ —
Non-regulatory agreement units 35
35
—
—
—
—
—
—
—
Net unrealized gains on decommissioning trust funds
Regulatory agreement units 155
155
—
—
—
—
—
—
—
Non-regulatory agreement units 116
116
—
—
—
—
—
—
—
Net unrealized losses on pledged assets
Zion Station decommissioning (5 ) (5 ) —
—
—
—
—
—
—
Regulatory offset to decommissioning trust fund-related activities^(b)
(168 ) (168 ) —
—
—
—
—
—
—
Total decommissioning-related activities 190
190
—
—
—

—

—
—
—
Investment income (expense) 2
1
—
(1 ) —
—
—
—
—
Interest income related to uncertain income tax positions 8
—
—
—
—
—
—
—
—
Penalty related to uncertain income tax positions^(c)
(106 ) —
(86 ) —
—
—
—
—
—
AFUDC — Equity 19
—
5
2
5
7
5
1
1
Other 7
(6 ) 1
1
—
12
7
2
1
Other, net $ 120

$ 185

$ (80 )
$ 2

$ 5
$ 19

$ 12

$ 3

$ 2

~~167~~

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~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

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

Successor Predecessor
Nine Months Ended September 30, 2016 March 24, 2016 to September 30, 2016 January 1, 2016 to March 23, 2016
Exelon Generation ComEd PECO BGE Pepco DPL ACE PHI PHI
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning trust funds^(a)

Regulatory agreement units $ 181
$ 181
$ —
$ —
$ —
$ —
$ —
$ —
$ —
$ —
Non-regulatory agreement units 95
95
—
—
—
—
—
—
—
—
Net unrealized gains on decommissioning trust funds
Regulatory agreement units 286
286
—
—
—
—
—
—
—
—
Non-regulatory agreement units 216
216
—
—
—
—
—
—
—
—
Net unrealized losses on pledged assets
Zion Station decommissioning (2 ) (2 ) —
—
—
—
—
—
—
—
Regulatory offset to decommissioning trust fund-related activities^(b)
(380 ) (380 ) —
—
—
—
—
—
—
—
Total decommissioning-related activities 396
396
—
—
—

—
—
—
—
—
Investment income (expense) 14
6
—
(1 ) 2
—
—
—
1
—
Long-term lease income 4
—
—
—
—
—
—
—
—
—
Interest income related to uncertain income tax positions 13
—
—
—
—
1
—
1
—
—
Penalty related to uncertain income tax positions^(c)
(106 ) —
(86 ) —
—
—
—
—
—
—
AFUDC — Equity 43
—
8
6
14
14
3
5
15
7
Loss on debt extinguishment (3 ) (2 ) —
—
—
—
—
—
—
—
Other 16
(5 ) 6
1
—
13
6
2
15
(11 )
Other, net $ 377

$ 395

$ (72 )
$ 6

$ 16

$ 28
$ 9
$ 8
$ 31
$ (4 )

~~_________~~


~~(a)~~	~~Includes investment income and realized gains and losses on sales of investments of the trust funds.~~


~~(b)~~	Includes the elimination of NDT fund activity for the Regulatory Agreement Units, including the elimination of net income taxes related to all NDT fund activity for those units. See Note 16 — Asset Retirement Obligations of the Exelon 2016 Form 10-K for additional information regarding the accounting for nuclear decommissioning.


~~(c)~~	~~See Note~~ 12 ~~- Income Taxes for discussion of the penalty related to the Tax Court's decision on Exelon's like-kind exchange tax position.~~

(a)The ~~following~~Registrants' utility taxes are included in revenues and expenses for the three and nine months ended September 30, 2017 and 2016. Generation’s utility tax expense represents gross receipts tax related to its retail operations, and the utility registrants' utility tax expense representsrepresent municipal and state utility taxes and gross receipts taxes related to their operating revenues. The offsetting collection of utility taxes from customers is recorded in revenues onin the Registrants’ Consolidated Statements of Operations and Comprehensive Income.

103

Three Months Ended September 30, 2017
Successor
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Utility taxes $ 245

$ 35

$ 65

$ 35

$ 22
$ 88
$ 83

$ 5

$ —

Nine Months Ended September 30, 2017
Successor
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Utility taxes $ 682

$ 97

$ 181

$ 95

$ 69
$ 240
$ 226

$ 14

$ —

~~168~~

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Three Months Ended September 30, 2016
Successor
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Utility taxes $ 255

$ 35

$ 67

$ 40

$ 21
$ 92
$ 87

$ 5

$ —

~~Supplemental Cash Flow Information~~

~~The following tables provide additional information regarding the Registrants’ Consolidated Statements of Cash Flows for the nine months ended September 30, 2017 and 2016.~~

Nine Months Ended September 30, 2017
Successor
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Depreciation, amortization and accretion
Property, plant and equipment^(a)
$ 2,416
$ 1,010
$ 579
$ 194
$ 233
$ 342
$ 153
$ 92
$ 66
Amortization of regulatory assets^(a)
355
—
52
19
115
169
89
32
47
Amortization of intangible assets, net^(a)
43
36
—
—
—
—
—
—
—
Amortization of energy contract assets and liabilities^(b)
19
19
—
—
—
—
—
—
—
Nuclear fuel^(c)
816
816
—
—
—
—
—
—
—
ARO accretion^(d)
350
350
—
—
—
—
—
—
—
Total depreciation, amortization and accretion $ 3,999

$ 2,231

$ 631

$ 213

$ 348
$ 511
$ 242

$ 124

$ 113

Successor Predecessor
Nine Months Ended September 30, 2016 March 24, 2016 to September 30, 2016 January 1, 2016 to March 23, 2016
Exelon Generation ComEd PECO BGE Pepco DPL ACE PHI PHI
Depreciation, amortization and accretion
Property, plant and equipment^(a)
$ 2,490
$ 1,297
$ 524
$ 181
$ 223
$ 128
$ 82
$ 61
$ 215
$ 94
Amortization of regulatory assets^(a)
293
—
49
20
84
93
38
69
140
58
Amortization of intangible assets, net^(a)
38
32
—
—
—
—
—
—
—
—
Amortization of energy contract assets and liabilities^(b)
(7 ) (7 ) —
—
—
—
—
—
—
—
Nuclear fuel^(c)
862
862
—
—
—
—
—
—
—
—
ARO accretion^(d)
333
332
1
—
—
—
—
—
—
—
Total depreciation, amortization and accretion $ 4,009

$ 2,516

$ 574

$ 201

$ 307
$ 221

$ 120

$ 130
$ 355
$ 152

~~_________~~


~~(a)~~	~~Included in Depreciation and amortization on the Registrants' Consolidated Statements of Operations and Comprehensive Income.~~


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


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


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

~~169~~

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~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

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

Nine Months Ended September 30, 2017
Successor
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs $ 482
$ 170
$ 131
$ 21
$ 47
$ 72
$ 19
$ 10
$ 10
Loss from equity method investments 26
26
—
—
—
—
—
—
—
Provision for uncollectible accounts 103
31
25
17
4
26
11
1
14
Stock-based compensation costs 76
—
—
—
—
—
—
—
—
Other decommissioning-related activity^(a)
(213 ) (213 ) —
—
—
—
—
—
—
Energy-related options^(b)
15
15
—
—
—
—
—
—
—
Amortization of regulatory asset related to debt costs 7
—
3
1
—
3
1
1
1
Amortization of rate stabilization deferral (7 ) —
—
—
7
(14 ) (12 ) (2 ) —
Amortization of debt fair value adjustment (13 ) (9 ) —
—
—
(4 ) —
—
—
Discrete impacts from EIMA and FEJA^(c)
(61 ) —
(61 ) —
—
—
—
—
—
Amortization of debt costs 57
33
3
1
1
1
1
—
—
Provision for excess and obsolete inventory

52
50
1
—
—
1
—
1
—
Merger-related commitments^(d)
—
—
—
—
—
(8 ) (6 ) (2 ) —
Severance costs 33
25
—
—
—
3
—
—
—
Other 46
4
10
(2 ) (7 ) (14 ) (6 ) (3 ) (4 )
Total other non-cash operating activities $ 603

$ 132

$ 112

$ 38

$ 52
$ 66
$ 8

$ 6

$ 21
Non-cash investing and financing activities:
Change in capital expenditures not paid $ (101 ) $ 20
$ (79 ) $ (29 ) $ 16
$ (6 ) $ 7
$ 14
$ (18 )
Fair value of pension obligation transferred in connection with the FitzPatrick acquisition —
33
—
—
—
—
—
—
—
Change in PPE related to ARO update (141 ) (141 ) —
—
—
—
—
—
—
Indemnification of like-kind exchange position^(g)
—
—
21
—
—
—
—
—
—
Non-cash financing of capital projects 16
16
—
—
—
—
—
—
—
Dividends on stock compensation 5
—
—
—
—
—
—

—
—
Dissolution of financing trust due to long-term debt retirement 8
—
—
—
8
—
—
—
—
Fair value adjustment of long-term debt due to retirement (5 ) —
—
—
—
—
—
—
—

~~170~~

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~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

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

Successor Predecessor
Nine Months Ended September 30, 2016 March 24, 2016 to September 30, 2016 January 1, 2016 to March 23, 2016
Exelon Generation ComEd PECO BGE Pepco DPL ACE PHI PHI
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs $ 458
$ 163
$ 124
$ 25
$ 50
$ 24
$ 13
$ 11
$ 58
$ 23
Loss from equity method investments 15
16
—
—
—
—
—
—
—
—
Provision for uncollectible accounts 107
14
31
24
12
15
12
18
27
16
Stock-based compensation costs 88
—
—
—
—
—
—
—
—
3
Other decommissioning-related activity^(a)
(237 ) (237 ) —
—
—
—
—
—
—
—
Energy-related options^(b)
(20 ) (20 ) —
—
—
—
—
—
—
—
Amortization of regulatory asset related to debt costs 7
—
3
1
—
2
—
1
2
1
Amortization of rate stabilization deferral 62
—
—
—
62
3
3
—
—
5
Amortization of debt fair value adjustment (9 ) (9 ) —
—
—
—
—
—
—
—
Discrete impacts from EIMA ^(c)
(36 ) —
(36 ) —
—
—
—
—
—
—
Amortization of debt costs 26
12
(3 ) 2
3
—
—
—
—
—
Provision for excess and obsolete inventory
74
70
4
—
—
1
1
1
—
1
Merger-related commitments ^(d)(e)
508
3
—
—
—
125
73
110
308
—
Severance costs 130
57
—
—
—
—
—
—
53
—
Asset retirement costs —
—
—
—
—
—
5
2
—
—
Lower of cost or net realizable value inventory adjustment 36
36
—
—
—
—
—
—
—
—
Other 15
24
(1 ) (3 ) (18 ) (2 ) (8 ) (5 ) (7 ) (3 )
Total other non-cash operating activities $ 1,224

$ 129

$ 122

$ 49

$ 109
$ 168

$ 99

$ 138
$ 441
$ 46
Non-cash investing and financing activities:
Change in capital expenditures not paid $ (338 ) $ (289 ) $ (42 ) $ (4 ) $ 17
$ 15
$ (10 ) $ 2
$ (5 ) $ 11
Fair value of net assets contributed to Generation in connection with the PHI Merger, net of cash^(d)(f)
—
119
—
—
—
—
—
—
—
—
Fair value of net assets distributed to Exelon in connection with the PHI Merger, net of cash^(d)(f)
—
—
—
—
—
—
—
—
129
—
Fair value of pension obligation transferred in connection with the PHI Merger —
—
—
—
—
—
—
—
53
—
Assumption of member purchase liability —
—
—
—
—
—
—
—
29
—
Assumption of merger commitment liability —
—
—
—
—
33
—
—
33
—
Change in PPE related to ARO update
476
476
—
—
—
—
—
—
—
—
Indemnification of like-kind exchange position^(g)
—
—
157
—
—
—
—
—
—
—
Non-cash financing of capital projects 84
84
—
—
—
—
—
—
—
—
Dividends on stock compensation 2
—
—
—
—
—
—
—
—
—

~~_________~~

~~(a)~~

Includes the elimination of NDT fund activity 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 16 - Asset Retirement Obligations of the Exelon 2016 Form 10-K 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 in Operating revenues.~~

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

~~(c)~~

Reflects the change in distribution rates pursuant to EIMA and FEJA, which allows for the recovery of distribution costs by a utility through a pre-established performance-based formula rate tariff. Beginning June 1, 2017, also reflects the change in energy efficiency rates pursuant to FEJA, which allows for the recovery of energy efficiency costs by a utility through a pre-established performance-based formula rate tariff. See Note 5 — Regulatory Matters for more information.


~~(d)~~	~~See Note 4 — Mergers, Acquisitions and Dispositions for additional information related to the merger with PHI.~~


~~(e)~~	~~Excludes $5 million of forgiveness of Accounts receivable related to merger commitments recorded in connection with the PHI Merger, the balance is included within Provision for uncollectible accounts.~~


~~(f)~~	Immediately following closing of the PHI Merger, the net assets associated with PHI's unregulated business interests were distributed by PHI to Exelon. Exelon contributed a portion of such net assets to Generation.


~~(g)~~	~~See Note 12— Income Taxes for discussion of the like-kind exchange tax position.~~

~~Supplemental Balance Sheet Information~~

~~The following tables provide additional information about assets and liabilities of the Registrants as of September 30, 2017 and December 31, 2016.~~

Successor
September 30, 2017 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Property, plant and equipment:
Accumulated depreciation and amortization $ 20,591
^(a)
$ 11,193
^(a)
$ 4,191

$ 3,366

$ 3,351
$ 448
$ 3,171

$ 1,231

$ 1,060
Accounts receivable:
Allowance for uncollectible accounts $ 339

$ 111

$ 72

$ 57

$ 25
$ 74
$ 29

$ 17

$ 28

Successor

December 31, 2016 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Property, plant and equipment:
Accumulated depreciation and amortization $ 19,169
^(b)
$ 10,562
^(b)
$ 3,937

$ 3,253

$ 3,254
$ 195
$ 3,050

$ 1,175

$ 1,016
Accounts receivable:
Allowance for uncollectible accounts $ 334

$ 91
$ 70

$ 61

$ 32
$ 80
$ 29

$ 24

$ 27

~~_________~~


~~(a)~~	~~Includes accumulated amortization of nuclear fuel in the reactor core of $3,303 million.~~


~~(b)~~	~~Includes accumulated amortization of nuclear fuel in the reactor core of $3,186 million.~~

~~PECO Installment Plan Receivables (Exelon and PECO)~~

PECO enters into payment agreements with certain delinquent customers, primarily residential, seeking to restore their service, as required by the PAPUC. Customers with past due balances that meet certain income criteria are provided the option to enter into an installment payment plan, some of which have terms greater than one year, to repay past due balances in addition to paying for their ongoing service on a current basis. The receivable balance for these payment agreement receivables is recorded in accounts receivable for the current portion and other deferred debits and other assets for the noncurrent portion. The net receivable balance for installment plans with terms greater than one year was $11 million and $9 million as of September 30, 2017 and December 31, 2016, respectively. The allowance for uncollectible accounts reserve methodology and assessment of the credit quality of the installment plan receivables are consistent with the customer accounts receivable methodology discussed in Note 1 — Significant Accounting Policies of the Exelon 2016 Form 10-K. The allowance for uncollectible accounts balance associated with these receivables at September 30, 2017 of $12 million consists of $3 million and $9 million for medium risk and high risk segments, respectively. The allowance for uncollectible accounts balance at December 31, 2016 of $13 million consists of $1 million, $3 million and $9 million for low risk, medium risk and high risk segments, respectively. The balance of the payment agreement is billed to the customer in equal monthly installments over the term of the agreement. Installment receivables outstanding as of September 30, 2017 and December 31, 2016 include balances not yet presented on the customer bill, accounts currently billed and an immaterial amount of past due receivables. When a customer defaults on its payment agreement, the terms of which are defined by plan type, the entire balance of the agreement becomes due and the balance is reclassified to current customer accounts receivable and reserved for in accordance with the methodology discussed in Note 1 — Significant Accounting Policies of the Exelon 2016 Form 10-K.

~~172~~

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~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

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

~~20. Segment Information (All Registrants)~~

Operating segments for each of the Registrants are determined based on information used by the chief operating decision maker(s) (CODM) in deciding how to evaluate performance and allocate resources at each of the Registrants.

In the first quarter of 2016, following the consummation of the PHI Merger, three new reportable segments were added: Pepco, DPL and ACE. As a result, Exelon has twelve reportable segments, which include ComEd, PECO, BGE, PHI's three reportable segments consisting of Pepco, DPL, and ACE, and Generation’s sixreportable segments consisting of the Mid-Atlantic, Midwest, New England, New York, ERCOT and all other power regions referred to collectively as “Other Power Regions”, which includes activities in the South, West and Canada. 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 and return on equity.

Effective with the consummation of the PHI Merger, PHI's reportable segments have changed based on the information used by the CODM to evaluate performance and allocate resources. PHI's reportable segments consist of Pepco, DPL and ACE. PHI's Predecessor periods' segment information has been recast to conform to the current presentation. The reclassification of the segment information did not impact PHI's reported consolidated revenues or net income. PHI's CODM evaluates the performance of and allocates resources to Pepco, DPL and ACE based on net income and return on equity.

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 six 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, which includes portions of Illinois, Pennsylvania, Indiana, Ohio, Michigan, Kentucky and Tennessee, and the United States footprint of MISO, excluding MISO’s Southern Region, which covers all or most of North Dakota, South Dakota, Nebraska, Minnesota, Iowa, Wisconsin, the remaining parts of Illinois, Indiana, Michigan and Ohio not covered by PJM, and parts of Montana, Missouri and Kentucky.

~~New England~~ ~~represents the operations within ISO-NE covering the states of Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont.~~

~~New York~~ ~~represents operations within ISO-NY, which covers the state of New York in its entirety.~~

~~ERCOT~~ ~~represents operations within Electric Reliability Council of Texas, covering most of the state of Texas.~~

~~Other Power Regions~~:

~~South~~ represents operations in the FRCC, MISO’s Southern Region, and the remaining portions of the SERC not included within MISO or PJM, which includes all or most of Florida, Arkansas, Louisiana, Mississippi, Alabama, Georgia, Tennessee, North Carolina, South Carolina and parts of Missouri, Kentucky and Texas. Generation’s South region also includes operations in the SPP, covering Kansas, Oklahoma, most of Nebraska and parts of New Mexico, Texas, Louisiana, Missouri, Mississippi and Arkansas.

~~West~~ represents operations in the WECC, which includes California ISO, and covers the states of California, Oregon, Washington, Arizona, Nevada, Utah, Idaho, Colorado and parts of New Mexico, Wyoming and South Dakota.

~~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 revenues net of purchased power and fuel expense (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

~~173~~

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~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

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

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.

~~Three Months Ended September 30, 2017 and 2016~~

Successor

Generation^(a)
ComEd PECO BGE
PHI^(b)

Other^(c)
Intersegment
Eliminations Exelon
Operating revenues^(d):

2017
Competitive businesses electric revenues $ 4,042
$ —
$ —
$ —
$ —
$ —
$ (295 ) $ 3,747
Competitive businesses natural gas revenues 460
—
—
—
—
—
—
460
Competitive businesses other revenues 249
—
—
—
—
—
—
249
Rate-regulated electric revenues —
1,571
662
658
1,280
—
(7 ) 4,164
Rate-regulated natural gas revenues —
—
53
80
18
—
(2 ) 149
Shared service and other revenues —
—
—
—
12
446
(458 ) —
2016
Competitive businesses electric revenues $ 4,322
$ —
$ —
$ —
$ —
$ —
$ (499 ) $ 3,823
Competitive businesses natural gas revenues 326
—
—
—
—
—
—
326
Competitive businesses other revenues 387
—
—
—
—
—
(1 ) 386
Rate-regulated electric revenues —
1,497
740
735
1,366
—
(8 ) 4,330
Rate-regulated natural gas revenues —
—
48
77
17
—
(5 ) 137
Shared service and other revenues —
—
—
—
11
362
(373 ) —
Intersegment revenues^(e):

2017 $ 294
$ 3
$ 2
$ 3
$ 12
$ 445
$ (759 ) $ —
2016 500
4
2
7
11
362
(885 ) 1
Net income (loss):
2017 $ 348
$ 189
$ 112
$ 62
$ 153
$ 3
$ —
$ 867
2016 271
37
122
56
166
(125 ) (1 ) 526
Total assets:
September 30, 2017 $ 47,744
$ 29,649
$ 11,480
$ 8,923
$ 21,301
$ 10,662
$ (11,286 ) $ 118,473
December 31, 2016 46,974
28,335
10,831
8,704
21,025
10,369
(11,334 ) 114,904

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

~~_________~~

~~(a)~~

Generation includes the six reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions. Intersegment revenues for Generation for the three months ended September 30, 2017 include revenue from sales to PECO of $31 million, sales to BGE of $98 million, sales to Pepco of $57 million, sales to DPL of $47 million, and sales to ACE of $7 million in the Mid-Atlantic region, and sales to ComEd of $54 million in the Midwest region. For the three months ended September 30, 2016, intersegment revenues for Generation include revenue from sales to PECO of $91 million, sales to BGE of $183 million, sales to Pepco of $128 million, sales to DPL of $63 million, and sales to ACE of $15 million in the Mid-Atlantic region, and sales to ComEd of $20 million in the Midwest region.


~~(b)~~	~~Amounts included represent activity for PHI's successor period, three months ended September 30, 2017 and 2016. PHI includes the three reportable segments: Pepco, DPL and ACE.~~


~~(c)~~	~~Other primarily includes Exelon’s corporate operations, shared service entities and other financing and investment activities.~~


~~(d)~~	Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses on the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 19 — Supplemental Financial Information for total utility taxes for the three months ended September 30, 2017 and 2016.

~~(e)~~

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 accounting guidance. For Exelon, these amounts are included in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income.

~~Successor PHI:~~

Pepco DPL ACE
Other^(b)
Intersegment
Eliminations PHI
Operating revenues^(a):
Three Months Ended September 30, 2017 - Successor
Rate-regulated electric revenues $ 604
$ 309
$ 370
$ —
$ (3 ) $ 1,280
Rate-regulated natural gas revenues —
18
—
—
—
18
Shared service and other revenues —
—
—
12
—
12
Three Months Ended September 30, 2016 - Successor
Rate-regulated electric revenues $ 635
$ 314
$ 421
$ —
$ (4 ) $ 1,366
Rate-regulated natural gas revenues —
17
—
—
—
17
Shared service and other revenues —
—
—
11
—
11
Intersegment revenues:
Three Months Ended September 30, 2017 - Successor $ 1
$ 2
$ —
$ 13
$ (4 ) $ 12
Three Months Ended September 30, 2016 - Successor 1
2
1
11
(4 ) 11
Net income (loss):
Three Months Ended September 30, 2017 - Successor $ 87
$ 31
$ 41
$ (18 ) $ 12
$ 153
Three Months Ended September 30, 2016 - Successor 79
44
47
(15 ) 11
166
Total assets:
September 30, 2017 - Successor $ 7,775
$ 4,276
$ 3,510
$ 10,724
$ (4,984 ) $ 21,301
December 31, 2016 - Successor 7,335
4,153
3,457
10,804
(4,724 ) 21,025

~~_________~~


~~(a)~~	Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses on the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 19 — Supplemental Financial Information for total utility taxes for the three months ended September 30, 2017 and 2016.


~~(b)~~	~~Other primarily includes PHI’s corporate operations, shared service entities and other financing and investment activities.~~

~~175~~

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~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

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

~~Generation total revenues:~~

Three Months Ended September 30, 2017 Three Months Ended September 30, 2016

Revenues
from external
customers^(a)

Intersegment
revenues
Total
Revenues
Revenues
from external
customers^(a)

Intersegment
revenues
Total
Revenues
Mid-Atlantic $ 1,421
$ 11
$ 1,432
$ 1,813
$ (13 ) $ 1,800
Midwest 1,049
(11 ) 1,038
1,163
1
1,164
New England 482
(1 ) 481
455
(4 ) 451
New York 434
(6 ) 428
331
(8 ) 323
ERCOT 308
6
314
289
6
295
Other Power Regions 348
(13 ) 335
271
(33 ) 238
Total Revenues for Reportable Segments 4,042
(14 ) 4,028
4,322
(51 ) 4,271
Other^(b)
709
14
723
713
51
764
Total Generation Consolidated Operating Revenues $ 4,751
$ —
$ 4,751
$ 5,035
$ —
$ 5,035

~~_________~~


~~(a)~~	~~Includes all wholesale and retail electric sales 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 $13 million and $21 million decrease to revenues for the amortization of intangible assets and liabilities related to commodity contracts recorded at fair value for the three months ended September 30, 2017 and 2016, respectively, unrealized mark-to-market gain of $52 million and $187 million for the three months ended September 30, 2017 and 2016, respectively, and elimination of intersegment revenues.

~~Generation total revenues net of purchased power and fuel expense:~~

Three Months Ended September 30, 2017 Three Months Ended September 30, 2016

RNF
from external
customers^(a)

Intersegment
RNF
Total RNF
RNF
from external
customers^(a)

Intersegment
RNF
Total RNF
Mid-Atlantic $ 817
$ 38
$ 855
$ 881
$ 6
$ 887
Midwest 697
—
697
782
(1 ) 781
New England 151
(6 ) 145
170
(10 ) 160
New York 296
—
296
195
(1 ) 194
ERCOT 229
(111 ) 118
144
(51 ) 93
Other Power Regions 118
(50 ) 68
143
(66 ) 77
Total Revenues net of purchased power and fuel for Reportable Segments 2,308

(129 )
2,179

2,315

(123 )
2,192
Other^(b)
112
129
241
131
123
254
Total Generation Revenues net of purchased power and fuel expense $ 2,420

$ —

$ 2,420

$ 2,446

$ —

$ 2,446

~~_________~~


~~(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 $19 million and $22 million decrease to RNF for the amortization of intangible assets and liabilities related to commodity contracts for the three months ended September 30, 2017 and 2016, respectively, unrealized mark-to-market gains of $73 million and $88 million for the three months ended September 30, 2017 and 2016, respectively, accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 7 - Early Nuclear Plant Retirements of the Combined Notes to Consolidated Financial Statements of $6 million and $28 million decrease to revenue net of purchased power and fuel expense for the three months ended September 30, 2017 and 2016, respectively, and the elimination of intersegment revenue net of purchased power and fuel expense.

~~176~~

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~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

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

~~Nine Months Ended September 30, 2017 and 2016~~

Successor

Generation^(a)
ComEd PECO BGE
PHI^(b)

Other^(c)
Intersegment
Eliminations Exelon
Operating revenues^(d):
2017
Competitive businesses electric revenues $ 11,485
$ —
$ —
$ —
$ —
$ —
$ (888 ) $ 10,597
Competitive businesses natural gas revenues 1,807
—
—
—
—
—
—
1,807
Competitive businesses other revenues 520
—
—
—
—
—
—
520
Rate-regulated electric revenues —
4,227
1,802
1,895
3,417
—
(23 ) 11,318
Rate-regulated natural gas revenues —
—
339
468
105
—
(6 ) 906
Shared service and other revenues —
—
—
—
35
1,316
(1,350 ) 1
2016
Competitive businesses electric revenues $ 11,677
$ —
$ —
$ —
$ —
$ —
$ (1,118 ) $ 10,559
Competitive businesses natural gas revenues 1,515
—
—
—
—
—
—
1,515
Competitive businesses other revenues 171
—
—
—
—
—
(2 ) 169
Rate-regulated electric revenues —
4,031
1,971
1,998
2,485
—
(24 ) 10,461
Rate-regulated natural gas revenues —
—
322
423
46
—
(10 ) 781
Shared service and other revenues —
—
—
—
34
1,166
(1,199 ) 1
Intersegment revenues^(e):

2017 $ 888
$ 12
$ 5
$ 12
$ 35
$ 1,312
$ (2,262 ) $ 2
2016 1,121
12
5
16
34
1,166
(2,351 ) 3
Net income (loss):
2017 $ 491
$ 447
$ 327
$ 231
$ 359
$ 58
$ (2 ) $ 1,911
2016 556
297
346
191
(91 ) (340 ) (3 ) 956

~~177~~

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~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

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

~~_________~~

~~(a)~~

Generation includes the six reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions. Intersegment revenues for Generation for the nine months ended September 30, 2017 include revenue from sales to PECO of $111 million, sales to BGE of $330 million, sales to Pepco of $209 million, sales to DPL of $138 million, and sales to ACE of $23 million in the Mid-Atlantic region, and sales to ComEd of $77 million in the Midwest region. For the nine months ended September 30, 2016, intersegment revenues for Generation include revenue from sales to PECO of $234 million and sales to BGE of $489 million in the Mid-Atlantic region, and sales to ComEd of $38 million in the Midwest region. For the Successor period of March 24, 2016 to September 30, 2016, intersegment revenues for Generation include revenue from sales to Pepco of $223 million, sales to DPL of $109 million, and sales to ACE of $28 million in the Mid-Atlantic region.


~~(b)~~	Amounts included represent activity for PHI's successor period, nine months ended September 30, 2017 and March 24, 2016 through September 30, 2016. PHI includes the three reportable segments: Pepco, DPL and ACE. See tables below for PHI's predecessor period, including Pepco, DPL and ACE, for January 1, 2016 to March 23, 2016.


~~(c)~~	~~Other primarily includes Exelon’s corporate operations, shared service entities and other financing and investment activities.~~


~~(d)~~	Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses on the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 19 — Supplemental Financial Information for total utility taxes for the nine months ended September 30, 2017 and 2016.

~~(e)~~

~~Successor and Predecessor PHI:~~

Pepco DPL ACE
Other^(b)
Intersegment
Eliminations PHI
Operating revenues^(a):

Nine Months Ended September 30, 2017 - Successor
Rate-regulated electric revenues $ 1,649
$ 866
$ 915
$ —
$ (13 ) $ 3,417
Rate-regulated natural gas revenues —
105
—
—
—
105
Shared service and other revenues —
—
—
37
(2 ) 35
March 24, 2016 to September 30, 2016 - Successor
Rate-regulated electric revenues $ 1,184
$ 593
$ 714
$ 3
$ (9 ) $ 2,485
Rate-regulated natural gas revenues —
46
—
—
—
46
Shared service and other revenues —
—
—
34
—
34
January 1, 2016 to March 23, 2016 - Predecessor
Rate-regulated electric revenues $ 511
$ 279
$ 268
$ 42
$ (4 ) $ 1,096
Rate-regulated natural gas revenues —
56
—
1
—
57
Shared service and other revenues —
—
—
—
—
—
Intersegment revenues:
Nine Months Ended September 30, 2017 - Successor $ 4
$ 6
$ 2
$ 37
$ (14 ) $ 35
March 24, 2016 to September 30, 2016 - Successor 2
4
2
35
(9 ) 34
January 1, 2016 to March 23, 2016 - Predecessor 1
2
1
—
(4 ) —
Net income (loss):
Nine Months Ended September 30, 2017 - Successor $ 188
$ 107
$ 77
$ (48 ) $ 35
$ 359
March 24, 2016 to September 30, 2016 - Successor (12 ) (42 ) (55 ) (16 ) 34
(91 )
January 1, 2016 to March 23, 2016 - Predecessor 32
26
5
(44 ) —
19

~~_________~~


~~(a)~~	Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses on the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 19 — Supplemental Financial Information for total utility taxes for the nine months ended September 30, 2017 and 2016.


~~(b)~~	Other primarily includes PHI’s corporate operations, shared service entities and other financing and investment activities. For the predecessor period presented, Other includes the activity of PHI’s unregulated businesses which were distributed to Exelon and Generation as a result of the PHI Merger.

~~178~~

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~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

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

~~Generation total revenues:~~

Nine Months Ended September 30, 2017 Nine Months Ended September 30, 2016

Revenues
from external
customers^(a)
Intersegment
revenues Total
Revenues
Revenues
from external
customers^(a)
Intersegment
revenues Total
Revenues
Mid-Atlantic $ 4,207
$ 15
$ 4,222
$ 4,776
$ (40 ) $ 4,736
Midwest 3,158
(17 ) 3,141
3,330
13
3,343
New England 1,469
(8 ) 1,461
1,278
(6 ) 1,272
New York 1,095
(14 ) 1,081
906
(33 ) 873
ERCOT 749
4
753
659
6
665
Other Power Regions 807
(28 ) 779
728
(42 ) 686
Total Revenues for Reportable Segments 11,485

(48 )
11,437

11,677

(102 )
11,575
Other^(b)
2,327
48
2,375
1,686
102
1,788
Total Generation Consolidated Operating Revenues $ 13,812

$ —

$ 13,812

$ 13,363

$ —

$ 13,363

~~_________~~


~~(a)~~	~~Includes all wholesale and retail electric sales 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 $30 million and $10 million decrease to revenues for the amortization of intangible assets and liabilities related to commodity contracts recorded at fair value for the nine months ended September 30, 2017 and 2016, respectively, unrealized mark-to-market losses of $47 million and $366 million for the nine months ended September 30, 2017 and 2016, respectively, and elimination of intersegment revenues.

~~Generation total revenues net of purchased power and fuel expense:~~

Nine Months Ended September 30, 2017 Nine Months Ended September 30, 2016

RNF
from external
customers^(a)

Intersegment
RNF
Total RNF
RNF
from external
customers^(a)

Intersegment
RNF
Total RNF
Mid-Atlantic $ 2,330
$ 81
$ 2,411
$ 2,541
$ 15
$ 2,556
Midwest 2,129
11
2,140
2,225
4
2,229
New England 423
(20 ) 403
373
(23 ) 350
New York 679
(1 ) 678
607
(15 ) 592
ERCOT 446
(188 ) 258
335
(104 ) 231
Other Power Regions 359
(139 ) 220
357
(104 ) 253
Total Revenues net of purchased power and fuel expense for Reportable Segments 6,366

(256 )
6,110

6,438

(227 )
6,211
Other^(b)
160
256
416
316
227
543
Total Generation Revenues net of purchased power and fuel expense $ 6,526

$ —

$ 6,526

$ 6,754

$ —

$ 6,754

~~_________~~


~~(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 $41 million and $15 million decrease to RNF for the amortization of intangible assets and liabilities related to commodity contracts for the nine months ended September 30, 2017 and 2016, respectively, unrealized mark-to-market losses of $161 million and $113 million for the nine months ended September 30, 2017 and 2016, respectively, accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 7 - Early Nuclear Plant Retirements of the Combined Notes to Consolidated Financial Statements of $8 million and $38 million decrease to revenue net of purchased power and fuel expense for the nine months ended September 30, 2017 and 2016, respectively, and the elimination of intersegment revenue net of purchased power and fuel expense.

~~179~~

~~Table of Contents~~

~~Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations~~

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

Note 15 — Supplemental Financial Information


	Other, Net
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Three Months Ended September 30, 2023
AFUDC — Equity	$	40	$	7	$	10	$	4	$	19	$	15	$	3	$	1
Non-service net periodic benefit cost	(18)		—		—		—		—		—		—		—

Three Months Ended September 30, 2022
AFUDC — Equity	$	38	$	10	$	7	$	5	$	16	$	12	$	2	$	2
Non-service net periodic benefit cost	16		—		—		—		—		—		—		—

Nine Months Ended September 30, 2023
AFUDC — Equity	$	113	$	25	$	22	$	11	$	55	$	42	$	7	$	6
Non-service net periodic benefit cost	(18)		—		—		—		—		—		—		—

Nine Months Ended September 30, 2022
AFUDC — Equity	$	112	$	28	$	22	$	17	$	45	$	35	$	5	$	5
Non-service net periodic benefit cost	48		—		—		—		—		—		—		—

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
	Exelon(a)		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Nine Months Ended September 30, 2023
Property, plant, and equipment(b)	$	2,073	$	815	$	287	$	381	$	550	$	232	$	155	$	145
Amortization of regulatory assets(b)	537		230		10		106		191		97		27		67
Amortization of intangible assets, net(b)	6		—		—		—		—		—		—		—



Total depreciation and amortization	$	2,616	$	1,045	$	297	$	487	$	741	$	329	$	182	$	212

Nine Months Ended September 30, 2022
Property, plant, and equipment(b)	$	2,024	$	770	$	267	$	355	$	502	$	214	$	141	$	126
Amortization of regulatory assets(b)	532		212		10		115		195		98		31		66
Amortization of intangible assets, net(b)	10		—		—		—		—		—		—		—
Amortization of energy contract assets and liabilities(c)	3		—		—		—		—		—		—		—
Nuclear fuel(d)	66		—		—		—		—		—		—		—
ARO accretion(e)	44		—		—		—		—		—		—		—
Total depreciation, amortization, and accretion	$	2,679	$	982	$	277	$	470	$	697	$	312	$	172	$	192

__________

(a)Exelon's 2022 amounts include amounts related to Generation prior to the separation. See Note 2 — Discontinued Operations for additional information.

(b)Included in Depreciation and amortization in the Registrants' Consolidated Statements of Operations and Comprehensive Income.

(c)Included in Electric operating revenues or Purchased power expense in Exelon’s Consolidated Statements of Operations and Comprehensive Income.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 15 — Supplemental Financial Information

(d)Included in Purchased fuel expense in Exelon's Consolidated Statement of Operations and Comprehensive Income.

(e)Included in Operating and maintenance expense in Exelon's Consolidated Statement of Operations and Comprehensive Income.


	Other non-cash operating activities
	Exelon(a)		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Nine Months Ended September 30, 2023
Pension and OPEB costs (benefit)	$	152	$	19	$	(10)	$	41	$	74	$	26	$	13	$	10
Allowance for credit losses	86		4		31		4		47		27		9		11


True-up adjustments to decoupling mechanisms and formula rates(b)	(522)		(405)		(1)		(47)		(69)		(28)		(15)		(26)





Amortization of operating ROU asset	29		2		—		4		21		5		6		2
Change in environmental liabilities	37		—		—		—		37		37		—		—

AFUDC — Equity	(113)		(25)		(22)		(11)		(55)		(42)		(7)		(6)

Nine Months Ended September 30, 2022
Pension and OPEB costs (benefit)	$	124	$	45	$	(6)	$	34	$	39	$	6	$	3	$	9
Allowance for credit losses	130		40		32		18		42		21		9		12
Other decommissioning-related activity	36		—		—		—		—		—		—		—
Energy-related options	60		—		—		—		—		—		—		—
True-up adjustments to decoupling mechanisms and formula rates(b)	(92)		(163)		(1)		40		33		15		3		14


Long-term incentive plan	35		—		—		—		—		—		—		—


Amortization of operating ROU asset	47		1		—		14		21		5		6		3


AFUDC — Equity	(112)		(28)		(22)		(17)		(45)		(35)		(5)		(5)

__________

(a)Exelon's 2022 amounts include amounts related to Generation prior to the separation. See Note 2 — Discontinued Operations for additional information.

(b)For ComEd, reflects the true-up adjustments in regulatory assets and liabilities associated with its distribution, energy efficiency, distributed generation, and transmission formula rates. For PECO, reflects the change in regulatory assets and liabilities associated with its transmission formula rates. For BGE, Pepco, DPL, and ACE, reflects the change in regulatory assets and liabilities associated with their decoupling mechanisms and transmission formula rates. See Note 3 — Regulatory Matters of the 2022 Form 10-K for additional information.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 15 — Supplemental Financial Information

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.


	Cash, cash equivalents, and restricted cash
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance at September 30, 2023
Cash and cash equivalents	$	300	$	79	$	43	$	15	$	121	$	31	$	5	$	14
Restricted cash and cash equivalents	435		360		9		1		25		25		1		—
Restricted cash included in Other deferred debits and other assets	212		212		—		—		—		—		—		—
Total cash, restricted cash, and cash equivalents	$	947	$	651	$	52	$	16	$	146	$	56	$	6	$	14

Balance at December 31, 2022
Cash and cash equivalents	$	407	$	67	$	59	$	43	$	198	$	45	$	31	$	72
Restricted cash and cash equivalents	566		327		9		24		175		54		121		—
Restricted cash included in Other deferred debits and other assets	117		117		—		—		—		—		—		—
Total cash, restricted cash, and cash equivalents	$	1,090	$	511	$	68	$	67	$	373	$	99	$	152	$	72

Balance at September 30, 2022
Cash and cash equivalents	$	446	$	63	$	94	$	20	$	219	$	21	$	49	$	112
Restricted cash and cash equivalents	744		342		9		130		234		77		157		—
Restricted cash included in Other deferred debits and other assets	83		83		—		—		—		—		—		—
Total cash, restricted cash, and cash equivalents	$	1,273	$	488	$	103	$	150	$	453	$	98	$	206	$	112

Balance at December 31, 2021
Cash and cash equivalents	$	672	$	131	$	36	$	51	$	136	$	34	$	28	$	29
Restricted cash and cash equivalents	321		210		8		4		77		34		43		—
Restricted cash included in Other deferred debits and other assets	44		43		—		—		—		—		—		—
Cash, restricted cash, and cash equivalents from discontinued operations	582		—		—		—		—		—		—		—
Total cash, restricted cash, and cash equivalents	$	1,619	$	384	$	44	$	55	$	213	$	68	$	71	$	29

For additional information on restricted cash see Note 1 — Significant Accounting Policies of the 2022 Form 10-K.

Supplemental Balance Sheet Information

The following table provides additional information about material items recorded in the Registrants' Consolidated Balance Sheets.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 15 — Supplemental Financial Information


	Accrued expenses
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance at September 30, 2023
Compensation-related accruals(a)	$	548	$	162	$	67	$	63	$	99	$	27	$	17	$	14
Taxes accrued	255		148		61		100		120		88		19		13
Interest accrued	391		78		52		59		81		38		24		17


Balance at December 31, 2022
Compensation-related accruals(a)	$	613	$	179	$	81	$	79	$	104	$	29	$	20	$	16
Taxes accrued	211		92		10		34		70		52		8		12
Interest accrued	338		124		47		42		61		32		9		14

__________

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

16. Related Party Transactions (All Registrants)

Utility Registrants' expense with Generation

The Utility Registrants incurred expenses from transactions with the Generation affiliate as described in the footnotes to the table below prior to separation on February 1, 2022. Such expenses were primarily recorded as Purchased power from affiliate and an immaterial amount recorded as Operating and maintenance expense from affiliates at the Utility Registrants. Effective February 1, 2022, Generation is no longer considered a related party.


	Nine Months Ended September 30,
	2022
ComEd(a)	$	59
PECO(b)	33
BGE(c)	18
PHI	51
Pepco(d)	39
DPL(e)	10
ACE(f)	2

__________

(a)ComEd had an ICC-approved RFP contract with Generation to provide a portion of ComEd’s electric supply requirements. ComEd also purchased RECs and ZECs from Generation.

(b)PECO received electric supply from Generation under contracts executed through PECO’s competitive procurement process. In addition, PECO had a ten-year agreement with Generation to sell solar AECs.

(c)BGE received a portion of its energy requirements from Generation under its MDPSC-approved market-based SOS and gas commodity programs.

(d)Pepco received electric supply from Generation under contracts executed through Pepco's competitive procurement process approved by the MDPSC and DCPSC.

(e)DPL received a portion of its energy requirements from Generation under its MDPSC and DEPSC approved market-based SOS commodity programs.

(f)ACE received electric supply from Generation under contracts executed through ACE's competitive procurement process approved by the NJBPU.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 16 — Related Party Transactions

Service Company Costs for Corporate Support

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:


	Operating and maintenance from affiliates								Capitalized costs
	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022		2023		2022		2023		2022
Exelon
BSC									$	162	$	156	$	502	$	500
PHISCO									25		20		74		60
ComEd
BSC	$	92	$	69	$	263	$	234	71		70		230		222
PECO
BSC	55		44		160		140		29		24		89		80
BGE
BSC	58		46		166		148		23		26		69		86
PHI
BSC	50		39		135		135		39		36		114		112
PHISCO	—		—		—		—		24		20		73		60
Pepco
BSC	30		24		85		80		13		13		41		41
PHISCO	31		28		91		86		9		8		30		24

DPL
BSC	19		16		54		51		12		11		32		34
PHISCO	24		24		73		73		7		7		22		20

ACE
BSC	16		13		45		42		13		12		39		37
PHISCO	23		20		67		63		7		5		20		16

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 16 — Related Party Transactions

Current Receivables from/Payables to affiliates

The following tables present current Receivables from affiliates and current Payables to affiliates:

September 30, 2023


				Receivables from affiliates:
	Payables to affiliates:			ComEd			PECO			BGE			Pepco			DPL			ACE			BSC			PHISCO			Other			Total
ComEd					$	—		$	—		$	—		$	—		$	—		$	57		$	—		$	5		$	62
PECO		$	—					—			—			—			—			31			—			6			37
BGE		—			—						—			—			—			31			—			2			33
PHI		—			—			—			—			—			—			6			—			11			17
Pepco		—			—			—						—			—			16			15			1			32
DPL		—			1			—			—						—			13			11			—			25
ACE		—			—			—			—			—						11			10			1			22
Other		3			—			—			—			—			3			(1)			1						6
Total		$	3		$	1		$	—		$	—		$	—		$	3		$	164		$	37		$	26		$	234

December 31, 2022


				Receivables from affiliates:
	Payables to affiliates:			ComEd			PECO			BGE			Pepco			DPL			ACE			BSC			PHISCO			Other			Total
ComEd					$	—		$	—		$	—		$	—		$	—		$	66		$	—		$	8		$	74
PECO		$	—					—			—			—			—			39			—			3			42
BGE		—			—						—			—			—			38			—			1			39
PHI		—			—			—			—			—			—			4			—			10			14
Pepco		—			—			—						—			—			20			13			1			34
DPL		—			2			—			—						—			12			8			—			22
ACE		—			2			—			—			—						14			9			1			26
Other		3			—			—			—			—			1			—			—						4
Total		$	3		$	4		$	—		$	—		$	—		$	1		$	193		$	30		$	24		$	255

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. PECO and PHI Corporate participate in the Exelon intercompany money pool. Pepco, DPL, and ACE participate in the PHI intercompany money pool.

Long-term debt to financing trusts

The following table presents Long-term debt to financing trusts:


	September 30, 2023						December 31, 2022
	Exelon		ComEd		PECO		Exelon		ComEd		PECO
ComEd Financing III	$	206	$	205	$	—	$	206	$	205	$	—
PECO Trust III	81		—		81		81		—		81
PECO Trust IV	103		—		103		103		—		103
Total	$	390	$	205	$	184	$	390	$	205	$	184

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ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Exelon

Executive Overview

Exelon ~~a utility services holding company, operates through the following principal subsidiaries:~~

~~Generation,~~ whose 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.

~~ComEd,~~ whose business consists of the purchase and regulated retail sale of electricity and the provision of electricity transmission and distribution services in northern Illinois, including the City of Chicago.

~~PECO,~~ whose business consists of the purchase and regulated retail sale of electricity and the provision of electricity 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 natural gas distribution services in the Pennsylvania counties surrounding the City of Philadelphia.

~~BGE,~~ whose business consists of the purchase and regulated retail sale of electricity and natural gas and the provision of electricity distribution and transmission and natural gas distribution services in central Maryland, including the City of Baltimore.

~~Pepco,~~ whose business consists of the purchase and regulated retail sale of electricity and the provision of electricity distribution and transmission in the District of Columbia and major portions of Prince George's County and Montgomery County in Maryland.

~~DPL,~~ whose business consists of the purchase and regulated retail sale of electricity and the provision of electricity distribution and transmission services in portions of Maryland and Delaware, and the purchase and regulated retail sale of natural gas and the provision of natural gas distribution services in northern Delaware.

~~ACE,~~ ~~whose business consists of the purchase and regulated retail sale of electricity and the provision of electricity transmission and distribution services in southern New Jersey.~~

~~Pepco, DPL and ACE are operating companies of PHI, which~~ is a utility services holding company engaged in the energy transmission and ~~a wholly owned subsidiary of Exelon.~~

~~Exelon has twelve reportable segments consisting of Generation’s~~distribution businesses through it's six reportable ~~segments (Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions in Generation),~~segments: ComEd, PECO, BGE, ~~and PHI's three utility reportable segments (Pepco,~~Pepco, DPL, and ~~ACE).~~ACE. See Note ~~20 -~~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.

Through its business services subsidiary BSC, Exelon provides its operating subsidiaries with a variety of support services at cost. The costs of these services are directly charged or allocated to the applicable operating segments. Additionally, the results of Exelon’s corporate operations include costs for corporate governance and interest costs and income from various investment and financing activities.

PHI Service Company, a wholly owned subsidiary of PHI, provides a variety of support services at cost, including legal, accounting, engineering, distribution and transmission planning, asset management, system operations, and power procurement, to PHI and its operating subsidiaries. These services are directly charged or allocated pursuant to service agreements among PHI Service Company and the participating operating subsidiaries.

Exelon’s consolidated financial information includes the results of its ~~eight~~seven separate operating subsidiary registrants, ~~Generation,~~ ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE, which, along with Exelon, are collectively

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referred to as the Registrants. The following combined Management’s Discussion and Analysis of Financial Condition and Results of Operations 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.

Financial Results of Operations

GAAP Results of ~~Operations~~

Operations. The following ~~tables set~~table sets forth Exelon's GAAP consolidated ~~results of~~Net income attributable to common shareholders from continuing operations by Registrant for the three and nine months ended September 30, ~~2017~~2023 compared to the same period in 2016. The 2016 amounts include the operations of PHI, Pepco, DPL and ACE from March 24, 2016 through September 30, 2016. All amounts presented below are before the impact of income taxes, except as noted.

Three Months Ended September 30, Favorable
(Unfavorable)
Variance
2017 2016
Generation ComEd PECO BGE PHI Other Exelon
Exelon^(b)

Operating revenues $ 4,751
$ 1,571
$ 715
$ 738
$ 1,310
$ (316 ) $ 8,769
$ 9,002
$ (233 )
Purchased power and fuel 2,331
529
235
269
473
(295 ) 3,542
3,754
212
Revenue net of purchased power and fuel^(a)
2,420
1,042
480
469
837
(21 ) 5,227
5,248
(21 )
Other operating expenses
Operating and maintenance 1,374
346
197
175
251
(43 ) 2,300
2,338
38
Depreciation and amortization 410
212
72
109
179
20
1,002
1,195
193
Taxes other than income 141
80
42
61
122
10
456
449
(7 )
Total other operating expenses 1,925
638
311
345
552
(13 ) 3,758
3,982
224
(Loss) Gain on sales of assets (2 ) —
—
—
—
1
(1 ) 1
(2 )
Bargain purchase gain 7
—
—
—
—
—
7
—
7
Operating income (loss) 500
404
169
124
285
(7 ) 1,475
1,267
208
Other income and (deductions)
Interest expense, net (113 ) (89 ) (31 ) (26 ) (62 ) (65 ) (386 ) (516 ) 130
Other, net 209
5
2
4
13
4
237
120
117
Total other income and (deductions) 96
(84 ) (29 ) (22 ) (49 ) (61 ) (149 ) (396 ) 247
Income (loss) before income taxes 596
320
140
102
236
(68 ) 1,326
871
455
Income taxes 240
131
28
40
83
(70 ) 452
340
(112 )
Equity in (losses) earnings of unconsolidated affiliates (8 ) —
—
—
—
1
(7 ) (5 ) (2 )
Net income 348
189
112
62
153
3
867
526
341
Net income attributable to noncontrolling interests and preference stock dividends 43
—
—
—
—
—
43
36
(7 )
Net income attributable to common shareholders $ 305
$ 189
$ 112
$ 62
$ 153
$ 3
$ 824
$ 490
$ 334

~~_________~~

~~(a)~~

The Registrants evaluate operating performance using the measure of revenues net of purchased power and fuel expense. The Registrants believe that revenues net of purchased power and fuel expense is a useful measurement because it provides information that can be used to evaluate their operational performance. Revenues net of purchased power and fuel expense 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.


~~(b)~~	~~As a result of the PHI Merger, Exelon includes the consolidated results of PHI, Pepco, DPL and ACE from July 1, 2016 through September 30, 2016.~~

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~~Table of Contents~~

Nine Months Ended September 30,
Favorable
(Unfavorable)
Variance
2017 2016
Generation ComEd PECO BGE PHI Other Exelon
Exelon^(b)

Operating revenues $ 13,812
$ 4,227
$ 2,141
$ 2,363
$ 3,557
$ (951 ) $ 25,149
$ 23,486
$ 1,663
Purchased power and fuel expense 7,286
1,241
719
853
1,318
(890 ) 10,527
9,462
(1,065 )
Revenue net of purchased power and fuel expense^(a)
6,526

2,986

1,422

1,510

2,239
(61 )
14,622

14,024
598
Other operating expenses

Operating and maintenance 4,871
1,096
595
532
774
(136 ) 7,732
7,677
(55 )
Depreciation and amortization 1,046
631
213
348
511
65
2,814
2,821
7
Taxes other than income 425
223
116
180
344
25
1,313
1,168
(145 )
Total other operating expenses 6,342

1,950

924

1,060

1,629
(46 )
11,859

11,666
(193 )
Gain on sales of assets 3
—
—
—
1
—
4
41
(37 )
Bargain purchase gain 233
—
—
—
—
—
233
—
233
Operating income (loss) 420

1,036

498

450

611
(15 )
3,000

2,399
601
Other income and (deductions)
Interest expense, net (342 ) (275 ) (93 ) (80 ) (183 ) (221 ) (1,194 ) (1,179 ) (15 )
Other, net 648
14
6
12
40
5
725
377
348
Total other income and (deductions) 306

(261 )
(87 )
(68 )
(143 ) (216 )
(469 )
(802 ) 333
Income (loss) before income taxes 726
775
411
382
468
(231 ) 2,531
1,597
934
Income taxes 209
328
84
151
109
(286 ) 595
625
30
Equity in (losses) earnings of unconsolidated affiliates (26 ) —
—
—
—
1
(25 ) (16 ) (9 )
Net income 491

447

327

231

359

56

1,911

956
955
Net income attributable to noncontrolling interests and preference stock dividends 12
—
—
—
—
—
12
26
14
Net income attributable to common shareholders $ 479

$ 447

$ 327

$ 231

$ 359
$ 56

$ 1,899

$ 930
$ 969

~~_________~~

~~(a)~~


~~(b)~~	~~As a result of the PHI Merger, Exelon includes the consolidated results of PHI, Pepco, DPL and ACE from March 24, 2016 through September 30, 2016.~~

~~Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016.~~ Exelon’s Net income attributable to common shareholders was $824 million for the three months ended September 30, 2017 as compared to $490 million for the three months ended September 30, 2016, and diluted earnings per average common share were $0.85 for the three months ended September 30, 2017 as compared to $0.53 for the three months ended September 30, 2016.

Revenue net of purchased power and fuel expense, which is a non-GAAP measure discussed below, decreased by $21 million for the three months ended September 30, 2017 as compared to the same period in 2016. The quarter-over-quarter decrease in Revenue net of purchased power and fuel expense was primarily due to the following unfavorable factors:

~~Decrease of $36 million at PECO primarily due to unfavorable weathers conditions;~~

~~Decrease of $15 million at Generation due to mark-to-market gains of $73 million in 2017 compared to $88 million in 2016; and~~

Decrease of $11 million at Generation due to the unfavorable impacts of lower load volumes delivered due to mild weather and lower realized energy prices related to Exelon's ratable hedging strategy, partially offset by the impact of the New York CES, increased capacity prices, increased nuclear volumes primarily as a result of the acquisition of FitzPatrick and decreased nuclear outage days, and the addition of two combined-cycle gas turbines in Texas.

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~~Table of Contents~~

~~The quarter-over-quarter decrease in Revenue net of purchase power and fuel expense was partially offset by the following favorable factors:~~

~~Increase of $26 million at PHI primarily due to increased distribution revenue as a result of rate increases; and~~

~~Increase of $17 million at BGE primarily due to increased transmission revenue as a result of rate increases.~~

~~Operating and maintenance expense decreased by $38 million for the three months ended September 30, 2017 as compared to the same period in 2016 primarily due to the following favorable factors:~~

~~Decrease of $32 million at Exelon due to the net recovery of $2 million of merger-related costs in 2017 compared to merger-related costs of $30 million in 2016; and~~

~~Decrease of $31 million at ComEd primarily due to the change to defer and recover over time energy efficiency costs pursuant to the Illinois Future Energy Jobs Act.~~

The quarter-over-quarter decrease in Operating and maintenance expense was partially offset by an increase of $38 million at Generation primarily due to the announcement of the early retirement of Generation's TMI nuclear facility in 2017 compared to the previous decision to early retire Generation's Clinton and Quad Cities nuclear facilities in 2016 and higher asset impairment charges, partially offset by decreased nuclear refueling outage costs and labor, contracting and materials expense.

Depreciation and amortization expense decreased by $193 million primarily due to lower accelerated depreciation and amortization as a result of the 2017 decision to early retire the TMI nuclear facility compared to the previous decision in 2016 to early retire the Clinton and Quad Cities nuclear facilities, partially offset by increased depreciation expense as a result of ongoing capital expenditures across all operating companies for the three months ended September 30, 2017 as compared to the same period in 2016.

~~Taxes other than income increased by $7 millionprimarily due to increased property taxes as a result of the addition of FitzPatrick at Generation for the three months ended September 30, 2017 as compared to the same period in 2016.~~

~~Gain on sales of assets remained relatively consistent for the three months ended September 30, 2017 as compared to the same period in 2016.~~

Bargain purchase gain increased by $7 million due to a measurement period adjustment to the bargain purchase gain for the FitzPatrick acquisition for the three months ended September 30, 2017 as compared to the same period in 2016.

Interest expense, net decreased by $130 million primarily due to additional interest recorded in the third quarter 2016 related to Exelon's like-kind exchange tax position, partially offset by the the impact of project in-service dates on the capitalization of interest and higher outstanding debt at Generation for the three months ended September 30, 2017 as compared to the same period in 2016.

Other, net increased by $117 million primarily due to the penalty recorded in the third quarter of 2016 related to Exelon's like-kind exchange tax position and higher net realized gains on NDT funds at Generation for the three months ended September 30, 2017 as compared to the same period in 2016.

Exelon’s effective income tax rates for the three months ended September 30, 2017 and 2016 were 34.1% and 39.0%, respectively. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for2022. For additional information ~~regarding the components of the effective income tax rates.~~

~~Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016.~~ Exelon’s Net income attributable to common shareholders was $1,899 million for the nine months ended September 30, 2017 as compared to $930 million for the nine months ended September 30, 2016, and diluted earnings per average common share were $2.01 for the nine months ended September 30, 2017 as compared to $1.00 for the nine months ended September 30, 2016.

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~~Table of Contents~~

Revenue net of purchased power and fuel expense, which is a non-GAAP measure discussed below, increased by $598 million for the nine months ended September 30, 2017 as compared to the same period in 2016. The year-over-year increase in Revenue net of purchased power and fuel expense was primarily due to the following favorable factors:

Increase of $96 million at ComEd primarily due to higher electric distribution and transmission formula rate revenues resulting from increased capital investment and higher allowed electric distribution ROE, partially offset by the impact of favorable weather conditions in 2016;

Increase of $83 million at BGE primarily due to the impacts of the electric and natural gas distribution rate increases issued by the MDPSC in June 2016 and July 2016 and an increase in transmission formula rate revenues; and

Increase of $711 million in Revenue net of purchased power and fuel due to the inclusion of PHI's results for the nine months ended September 30, 2017 compared to the period March 24, 2016 to September 30, 2016, as well as distribution rate increases effective in 2016 and 2017.

~~The year-over-year increase in Revenue net of purchased power and fuel expense was partially offset by the following unfavorable factors:~~

Decrease of $180 million at Generation primarily due to the conclusion of the Ginna Reliability Support Services Agreement, the impact of declining natural gas prices on Generation's natural gas portfolio, the impacts of lower load volumes delivered due to mild weather and lower realized energy prices related to Exelon's ratable hedging strategy, partially offset by the impact of the New York CES, increased nuclear volumes primarily as a result of the acquisition of FitzPatrick, the addition of two combined-cycle gas turbines in Texas and the absence of oil inventory write downs in 2017.

~~Decrease of $62 million at PECO primarily due to unfavorable weather conditions; and~~

~~Decrease of $48 million at Generation due to mark-to-market losses of $161 million in 2017 compared to $113 million in 2016.~~

~~Operating and maintenance expense increased by $55 million for the nine months ended September 30, 2017 as compared to the same period in 2016 primarily due to the following unfavorable factors:~~

~~Increase of $288 million at Generation due to higher asset impairment charges;~~

~~Increase of $88 million at Generation due to increased nuclear outage costs;~~

~~Increase in Generation's labor, contracting and materials costs of $74 million primarily due to the acquisition of FitzPatrick beginning on March 31, 2017; and~~

~~Increase of $253 million at PHI due to the inclusion of PHI's results for the nine months ended September 30, 2017 compared to the period March 24, 2016 to September 30, 2016.~~

~~The year-over-year increase in Operating and maintenance expense was partially offset by the following favorable factors:~~

~~Decrease of $589 million at Exelon due to merger commitment and other merger-related costs of $63 million in 2017 compared to $652 million in 2016; and~~

~~Decrease of $56 million at BGE primarily due to certain disallowances contained in the June and July 2016 rate orders.~~

Depreciation and amortization expense decreased by $7 million primarily due to lower accelerated depreciation and amortization expense as a result of the 2017 decision to early retire the TMI nuclear facility compared to the previous decision in 2016 to early retire the Clinton and Quad Cities nuclear facilities, partially offset by increased depreciation expense as a result of ongoing capital expenditures across all operating companies and the inclusion of PHI's results for the nine months ended September 30, 2017 compared to the period March 24, 2016 to September 30, 2016.

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Taxes other than income increased by $145 million primarily due to increased property taxes as a result of the addition of FitzPatrick, increased gross receipts tax expense and increased sales and use tax expense at Generation, as well as the inclusion of PHI's results for the nine months ended September 30, 2017 compared to the period March 24, 2016 to September 30, 2016.

~~Gain on sales of assets decreased by $37 million primarily due to Generation's gain associated with the sale of the New Boston generating site in 2016.~~

~~Bargain purchase gain increased by $233 million due to the gain associated with Generation's acquisition of FitzPatrick in 2017.~~

Interest expense, net increased by $15 million primarily due to additional interest recorded in the second quarter 2017 related to Exelon's like-kind exchange tax position, higher outstanding debt and the inclusion of PHI's results for the nine months ended September 30, 2017 compared to the period March 24, 2016 to September 30, 2016, partially offset by additional interest recorded in the third quarter 2016 related to Exelon's like-kind exchange tax position.

Other, net increased by $348 million primarily due to higher net unrealized and realized gains on NDT funds at Generation for the nine months ended September 30, 2017 as compared to the same period in 2016 and the penalty recorded in 2016 related to Exelon's like-kind exchange tax position.

Exelon’s effective income tax rates for the nine months ended September 30, 2017 and 2016 were 23.5% and 39.1%, respectively. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

~~For further detail~~ regarding the financial results for the three and nine months ended September 30, ~~2017, including explanation of the non-GAAP measure Revenue net of purchased power~~2023 and ~~fuel expense,~~2022, see the discussions of Results of Operations by ~~Segment below.~~Registrant.

~~Adjusted (non-GAAP) Operating Earnings~~


	Three Months Ended September 30,				Favorable (Unfavorable) Variance		Nine Months Ended September 30,				Favorable (Unfavorable) Variance
	2023		2022				2023		2022
Exelon	$	700	$	676	$	24	$	1,711	$	1,622	$	89
ComEd	333		291		42		822		706		116
PECO	146		135		11		410		474		(64)
BGE	45		33		12		286		267		19
PHI	232		289		(57)		490		518		(28)
Pepco	120		145		(25)		249		261		(12)
DPL	43		52		(9)		128		130		(2)
ACE	71		94		(23)		122		131		(9)
Other(a)	(56)		(72)		16		(297)		(343)		46

__________

(a)Other primarily includes eliminating and consolidating adjustments, Exelon’s ~~adjusted (non-GAAP) operating earnings~~corporate operations, shared service entities, and other financing and investment activities.

The separation of Constellation, including Generation and its subsidiaries, meets the criteria for discontinued operations and as such, Generation's results of operations are presented as discontinued operations and have been excluded from Exelon's continuing operations for the three and nine months ended September 30, 2022 presented in the table above. See Note 1 — Significant Accounting Policies and Note 2 — Discontinued Operations for additional information.

Accounting rules require that certain BSC costs previously allocated to Generation be presented as part of Exelon’s continuing operations as these costs do not qualify as expenses of the discontinued operations. Such costs are included in Other in the table above and were $28 million on a pre-tax basis, for the nine months ended September 30, 2022. There were no such costs included in Exelon's continuing operations for the three months ended September 30, ~~2017~~2022.

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Three Months Ended September 30, 2023 Compared to Three Months Ended September 30, 2022. Net income attributable to common shareholders from continuing operations increased by $24 million and diluted earnings per average common share from continuing operations increased to $0.70 in 2023 from $0.68 in 2022 primarily due to:

•Higher electric distribution formula rate earnings from higher allowed ROE due to an increase in U.S. treasury rates and impacts of higher rate base at ComEd;

•Favorable impacts of rate increases at PECO, BGE, and PHI; and

•Carrying costs related to the CMC regulatory assets at ComEd.

The increases were ~~$821~~partially offset by:

•Higher operating expense as a result of higher storm costs at PECO, BGE and PHI;

•Higher interest expense at BGE and Exelon Corporate;

•Unfavorable weather at PECO; and

•Higher depreciation expense at BGE and PHI.

Nine Months Ended September 30, 2023 Compared to Nine Months Ended September 30, 2022. Net income attributable to common shareholders from continuing operations increased by $89 million ~~or $0.85~~and diluted earnings per ~~diluted~~average common share ~~compared with adjusted~~from continuing operations increased to $1.72 in 2023 from $1.65 in 2022 primarily due to:

•Higher electric distribution formula rate earnings from higher allowed ROE due to an increase in U.S. treasury rates and impacts of higher rate base at ComEd;

•The favorable impacts of rate increases at PECO, BGE, and PHI;

•Carrying costs related to the CMC regulatory assets at ComEd; and

•Lower BSC costs presented in Exelon’s continuing operations, which were previously allocated to Generation but did not qualify as discontinued operation expenses per the accounting rules.

The increases were partially offset by:

•Higher interest expense at PECO, BGE, PHI and Exelon Corporate;

•Unfavorable weather at PECO and PHI;

•Higher depreciation expense at PECO, BGE and PHI; and

•Higher operating expense as a result of higher storm costs at PECO and BGE.

Adjusted (non-GAAP) operating earnings of $841 million, or $0.91 per diluted share for the same period in 2016. Exelon’s adjusted (non-GAAP) operating earnings for the nine months ended September 30, 2017 were $1,935 million, or $2.05 per diluted share, compared with adjusted (non-GAAP) operating earnings of $2,078 million, or $2.24 per diluted share for the same period in 2016. earnings. In addition to ~~net~~Net income, Exelon evaluates its operating performance using the measure of ~~adjusted~~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 ~~period-over-period~~year-over-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.

~~185~~

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The following tables provide a reconciliation between ~~net~~Net income attributable to common shareholders from continuing operations as determined in accordance with GAAP and ~~adjusted~~Adjusted (non-GAAP) operating earnings for the three and nine months ended September 30, ~~2017 as~~2023 compared to the same ~~period~~periods in ~~2016.~~2022:


	Three Months Ended September 30,
	2023				2022
(In millions, except per share data)			Earnings per Diluted Share				Earnings per Diluted Share
Net income attributable to common shareholders from continuing operations	$	700	$	0.70	$	676	$	0.68
Mark-to-market impact of economic hedging activities (net of taxes of $4)	12		0.01		—		—

Asset retirement obligation (net of taxes of $1 and $2, respectively)	(1)		—		(4)		—
Asset impairments (net of taxes of $10)(a)	—		—		37		0.04



Separation costs (net of taxes of $5 and $1, respectively)(b)	14		0.01		(3)		—
Income tax-related adjustments (entire amount represents tax expense)(c)	(54)		(0.05)		38		0.04
Adjusted (non-GAAP) operating earnings	$	671	$	0.67	$	745	$	0.75

Three Months Ended September 30,
2017 2016
(All amounts in millions after tax)
Earnings per
Diluted Share

Earnings per
Diluted Share
Net Income Attributable to Common Shareholders $ 824
$ 0.85
$ 490
$ 0.53
Mark-to-Market Impact of Economic Hedging Activities^(a)(net of taxes of $29 and $35, respectively)
(45 ) (0.05 ) (54 ) (0.06 )
Unrealized Gains Related to NDT Fund Investments^(b) (net of taxes of $45 and $48, respectively)
(67 ) (0.07 ) (70 ) (0.07 )
Amortization of Commodity Contract Intangibles^(c) (net of taxes of $8 and $8, respectively)
12
0.01
13
0.01
Merger and Integration Costs^(d)(net of taxes of $1 and $10, respectively)
(1 ) —
13
0.01
Merger Commitments^(e)(net of taxes of $1)
—
—
5
0.01
Long-Lived Asset Impairments^(f)(net of taxes of $16 and $5, respectively)
24
0.03
11
0.01
Plant Retirements and Divestitures^(g)(net of taxes of $47 and $129, respectively)
71
0.08
204
0.22
Cost Management Program^(h)(net of taxes of $8 and $5, respectively)
13
0.01
7
0.01
Like-Kind Exchange Tax Position⁽ⁱ⁾(net of taxes of $61)
—
—
199
0.21
Asset Retirement Obligation^(j) (net of taxes of $1)
(2 ) —
—
—
Bargain Purchase Gain^(k) (net of taxes of $0)
(7 ) (0.01 ) —
—
Reassessment of State Deferred Income Taxes^(l) (entire amount represents tax expense)
(21 ) (0.02 ) —
—
Noncontrolling Interests^(m)(net of taxes of $4 and $5, respectively)
20
0.02
23
0.03
Adjusted (non-GAAP) Operating Earnings $ 821
$ 0.85
$ 841
$ 0.91


	Nine Months Ended September 30,
	2023				2022
(In millions, except per share data)			Earnings per Diluted Share				Earnings per Diluted Share
Net income attributable to common shareholders from continuing operations	$	1,711	$	1.72	$	1,622	$	1.65
Mark-to-market impact of economic hedging activities (net of taxes of $4)	14		0.01		—		—
Change in environmental liabilities (net of taxes of $8)	29		0.03		—		—
ERP system implementation costs (net of taxes of $0)(d)	—		—		1		—
Asset retirement obligation (net of taxes of $1 and $2, respectively)	(1)		—		(4)		—
SEC matter loss contingency (net of taxes of $0)	46		0.05		—		—
Asset impairments (net of taxes of $10)(a)	—		—		37		0.04
Separation costs (net of taxes of $7 and $10, respectively)(b)	19		0.02		25		0.03
Change in FERC audit liability (net of taxes of $4)	11		0.01		—		—
Income tax-related adjustments (entire amount represents tax expense)(e)	(54)		(0.05)		130		0.13
Adjusted (non-GAAP) operating earnings	$	1,774	$	1.78	$	1,811	$	1.84

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Nine Months Ended September 30,
2017 2016
(All amounts in millions after tax)
Earnings per
Diluted Share

Earnings per
Diluted Share
Net Income Attributable to Common Shareholders $ 1,899
$ 2.01
$ 930
$ 1.00
Mark-to-Market Impact of Economic Hedging Activities^(a) (net of taxes of $62 and $46, respectively)
97
0.10
67
0.07
Unrealized Gains Related to NDT Fund Investments^(b)(net of taxes of $137 and $89, respectively)
(211 ) (0.22 ) (127 ) (0.13 )
Amortization of Commodity Contract Intangibles^(c)(net of taxes of $17 and $6, respectively)
27
0.03
8
0.01
Merger and Integration Costs^(d)(net of taxes of $24 and $36, respectively)
39
0.04
92
0.10
Merger Commitments^(e)(net of taxes of $137 and $114, respectively)
(137 ) (0.15 ) 400
0.43
Long-Lived Asset Impairments^(f)(net of taxes of $188 and $67, respectively)
293
0.31
104
0.11
Plant Retirements and Divestitures^(g)(net of taxes of $89 and $214, respectively)
137
0.15
338
0.37
Cost Management Program^(h)(net of taxes of $15 and $17, respectively)
24
0.03
26
0.03
Like-Kind Exchange Tax Position⁽ⁱ⁾(net of taxes of $66 and $61, respectively)
(26 ) (0.03 ) 199
0.21
Asset Retirement Obligation^(j) (net of taxes of $1)
(2 ) —
—
—
Bargain Purchase Gain^(k)(net of taxes of $0)
(233 ) (0.25 ) —
—
Reassessment of State Deferred Income Taxes^(l)(entire amount represents tax expense)
(42 ) (0.04 ) —
—
Tax Settlements⁽ⁿ⁾(net of taxes of $1)
(5 ) (0.01 ) —
—
Noncontrolling Interests^(m)(net of taxes of $16 and $8, respectively)
75
0.08
41
0.04
Adjusted (non-GAAP) Operating Earnings $ 1,935
$ 2.05
$ 2,078
$ 2.24

~~_________~~__________

Note:

Amounts may not sum due to rounding.

Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net ~~Income~~income and Adjusted (non-GAAP) ~~Operating Earnings~~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 fund investments, the~~The marginal statutory income tax rates for 2023 and 2022 ranged from ~~39.0 percent~~24.0% to ~~41.0 percent. Under IRS regulations, NDT fund investment returns are taxed at differing rates for investments in qualified vs. non-qualified funds. The tax rates applied to unrealized gains and losses~~29.0%.

(a)Reflects costs related to ~~NDT Fund investments were 43.2 percent~~the impairment of an office building at BGE, which are recorded in Operating and ~~46.2 percent~~maintenance expense.

(b)Represents costs related to the separation primarily comprised of system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the separation, and employee-related severance costs, which are recorded in Operating and maintenance expense and Other, net.

(c)In 2022, reflects an adjustment to exclude one-time non-cash impacts associated with the remeasurement of deferred income taxes as a result of the reduction in Pennsylvania corporate income tax rate. In 2023, reflects the adjustment to state deferred income taxes due to changes in forecasted apportionment.

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(d)Reflects costs related to a multi-year ERP system implementation, which are recorded in Operating and maintenance expense.

(e)In 2022, for PECO, reflects an adjustment to exclude one-time non-cash impacts associated with the remeasurement of deferred income taxes as a result of the reduction in Pennsylvania corporate income tax rate. For Corporate, in connection with the separation, Exelon recorded an income tax expense primarily due to the long-term marginal state income tax rate change, the recognition of valuation allowances against the net deferred tax assets positions for certain standalone state filing jurisdictions, and nondeductible transaction costs partially offset by a one-time impact associated with a state tax benefit. In 2023, reflects the adjustment to state deferred income taxes dues to changes in forecasted apportionment.

Significant 2023 Transactions and Developments

Separation

On February 21, 2021, Exelon’s Board of Directors approved a plan to separate the Utility Registrants and Generation, creating two publicly traded companies (“the separation”). Exelon completed the separation on February 1, 2022. Constellation was newly formed and incorporated in Pennsylvania on June 15, 2021 for the ~~three~~purpose of separation and ~~nine months ended September 30, 2017, respectively,~~holds Generation. The separation represented a strategic shift that would have a major effect on Exelon’s operations and ~~52.6 percent and 52.5 percent~~financial results. Accordingly, the separation met the criteria for ~~the three and nine months ended September 30, 2016, respectively.~~


~~(a)~~	~~Reflects the impact of net gains and losses on Generation’s economic hedging activities. See Note 10 - Derivative Financial Instruments~~discontinued operations. See Note 2 — Discontinued Operations of the Combined Notes to ~~Consolidated Financial Statements for additional detail related to Generation’s hedging activities.~~


~~(b)~~	Reflects the impact of net unrealized gains on Generation’s NDT fund investments for Non-Regulatory Agreement Units. See Note 13 - Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements for additional detail related to Generation’s NDT fund investments.


~~(c)~~	Reflects the non-cash amortization of intangible assets, net, primarily related to commodity contracts recorded at fair value related to the ConEdison Solutions and FitzPatrick acquisitions in 2017, and in 2016, the Integrys and ConEdison Solutions acquisitions.


~~(d)~~	Reflects certain costs incurred for the PHI acquisition in 2017 and 2016 and Generation's FitzPatrick acquisition in 2017, including professional fees, employee-related expenses and integration activities. See Note 4 - Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional detail related to merger and acquisition costs.

~~(e)~~

Represents a decrease in reserves for uncertain tax positions related to the deductibility of certain merger commitments associated with the 2012 CEG and 2016 PHI acquisitions in 2017, and costs and adjustments incurred as part of the settlement orders approving the PHI acquisition in 2017 and 2016. See Note 4 - Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional detail related to PHI Merger commitments.


~~(f)~~	~~Primarily reflects impairments as a result of the ExGenTexas Power, LLC assets held for sale in 2017 and impairments of Upstream assets and certain wind projects at Generation in 2016.~~

~~(g)~~

Primarily reflects accelerated depreciation and amortization expenses, increases to materials and supplies inventory reserves, charges for severance reserves and construction work in progress impairments associated with Generation's previous decision to early retire the Clinton and Quad Cities nuclear facilities in 2016, partially offset in 2016 by a gain associated with Generation's sale of the New Boston generating site and Generation's decision to early retire the Three Mile Island nuclear facility in 2017.


~~(h)~~	~~Reflects severance and reorganization costs related to a cost management program.~~

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~~(i)~~	Represents adjustments to income tax, penalties and interest expenses in 2017 as a result of the finalization of the IRS tax computation related to Exelon’s like-kind exchange tax position, and in 2016, the recognition of a penalty and associated interest expense in 2016 as a result of a tax court decision on Exelon’s like-kind exchange tax position.


~~(j)~~	~~Reflects a non-cash benefit pursuant to the annual update of the Generation nuclear decommissioning obligation related to the nonregulatory units.~~


~~(k)~~	~~Represents the excess of the fair value of assets and liabilities acquired over the purchase price for the FitzPatrick acquisition.~~


~~(l)~~	Reflects the non-cash impact of the remeasurement of state deferred income taxes, primarily as a result of changes in forecasted apportionment related to the PHI acquisition in 2016, and in 2017, changes in the Illinois and District of Columbia statutory tax rates and changes in forecasted apportionment.


~~(m)~~	Represents elimination from Generation’s results of the noncontrolling interest related to certain exclusion items, primarily related to the impact of unrealized gains and losses on NDT fund investments at CENG.


~~(n)~~	~~Reflects benefits related to the favorable settlement in 2017 of certain income tax positions related to PHI's unregulated business interests that were transferred to Generation.~~

~~Merger, Integration and Acquisition Costs~~

As a result of the PHI Merger that was completed on March 23, 2016, the Registrants have incurred costs associated with evaluating, structuring and executing the PHI Merger transaction itself, and will continue to incur cost associated with meeting the various commitments set forth by regulators and agreed-upon with other interested parties as part of the merger approval process, and integrating the former PHI businesses into Exelon. In addition, as a result of the acquisition of the FitzPatrick nuclear generating station on March 31, 2017, Exelon and Generation incurred costs associated with evaluating, structuring, and executing the transaction and integrating FitzPatrick into Exelon.

~~For the three and nine months ended September 30, 2017 and 2016, expense has been recognized for the PHI Merger and Generation's FitzPatrick acquisition as follows:~~

Pre-tax Expense
Three Months Ended September 30, 2017
Merger, Integration and Acquisition Costs:
Exelon^(a)

Generation^(a)
ComEd PECO BGE
PHI^(a)(b)

Pepco^(a)(c)

DPL^(a)

ACE^(a)(d)
Transaction^(e)
$ —
$ —
$ —
$ —
$ —
$ —
$ —
$ —
$ —
Other^(f)
(3 ) 11
—
1
1
(15 ) (8 ) 1
(8 )
Total $ (3 ) $ 11
$ —
$ 1
$ 1
$ (15 ) $ (8 ) $ 1
$ (8 )

Pre-tax Expense
Three Months Ended September 30, 2016
Merger, Integration and Acquisition Costs:
Exelon^(a)

Generation^(a)
ComEd PECO BGE
PHI^(a)

Pepco^(a)

DPL^(a)

ACE^(a)
Transaction^(e)
$ 1
$ —
$ —
$ —
$ —
$ —
$ —
$ —
$ —
Employee-Related^(g)
1
—
—
—
—
1
—
—
—
Other^(f)
21
11
—
2
2
7
3
2
2
Total $ 23
$ 11
$ —
$ 2
$ 2
$ 8
$ 3
$ 2
$ 2

Pre-tax Expense
Nine Months Ended September 30, 2017
Merger, Integration and Acquisition Costs:
Exelon^(a)

Generation^(a)
ComEd PECO BGE
PHI^(a)(b)

Pepco^(a)(c)

DPL^(a)(h)

ACE^(a)(d)
Transaction^(e)
$ 5
$ 4
$ —
$ —
$ —
$ —
$ —
$ —
$ —
Other^(f)
57
67
1
3
3
(17 ) (6 ) (6 ) (6 )
Total $ 62
$ 71
$ 1
$ 3
$ 3
$ (17 ) $ (6 ) $ (6 ) $ (6 )

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Pre-tax Expense
Nine Months Ended September 30, 2016
Merger, Integration and Acquisition Costs:
Exelon^(a)

Generation^(a)

ComEd⁽ⁱ⁾
PECO
BGE^(j)

PHI^(a)(b)

Pepco^(a)(c)

DPL^(a)(h)

ACE^(a)
Transaction^(e)
$ 36
$ —
$ —
$ —
$ —
$ —
$ —
$ —
$ —
Employee-Related^(g)
74
10
1
1
1
61
29
17
14
Other^(f)
16
21
(8 ) 3
(3 ) 2
(3 ) 1
3
Total $ 126
$ 31

$ (7 )
$ 4

$ (2 ) $ 63
$ 26
$ 18
$ 17

~~_________~~


~~(a)~~	~~For Exelon, Generation, PHI, Pepco, DPL, and ACE, includes the operations of the acquired businesses beginning on March 24, 2016.~~

~~(b)~~

~~(c)~~


~~(d)~~	For the three and nine months ended September 30, 2017, includes the reversal of previously incurred acquisition, integration and financing costs of $8 million incurred at ACE that have been deferred and recorded as a regulatory asset for anticipated recovery. See Note 5—Regulatory Matters for more information.


~~(e)~~	External, third party costs paid to advisors, consultants, lawyers and other experts to integrate PHI processes and systems into Exelon, to assist in the due diligence and regulatory approval processes and in the closing of transactions.


~~(f)~~	~~Costs to integrate PHI processes and systems into Exelon. For the three and nine months ended September 30, 2017, also includes costs to integrate FitzPatrick processes and systems into Exelon.~~


~~(g)~~	~~Costs primarily for employee severance, pension and OPEB expense and retention bonuses.~~

~~(h)~~


~~(i)~~	For the nine months ended September 30, 2016, includes the reversal of previously incurred acquisition, integration and financing costs of $8 million, incurred at ComEd that have been deferred and recorded as a regulatory asset for anticipated recovery. See Note 5—Regulatory Matters for more information.


~~(j)~~	For the nine months ended September 30, 2016, includes the reversal of previously incurred acquisition, integration and financing costs of $6 million incurred at BGE that have been deferred and recorded as a regulatory asset for anticipated recovery. See Note 5—Regulatory Matters for more information.

As of September 30, 2017, Exelon expects to incur total PHI acquisition and integration related costs of approximately $700 million, excluding merger commitments. Of this amount, including costs incurred from 2014 through September 30, 2017, Exelon and PHI have incurred approximately $675 million.

~~Significant 2017 Transactions and Developments~~

~~Early Retirement of Three Mile Island Facility~~

On May 30, 2017, Generation announced it will permanently cease generation operations at Three Mile Island Generating Station (TMI) on or about September 30, 2019. The TMI nuclear plant did not clear in the May 2017 PJM capacity auction for the 2020-2021 planning year and will not receive capacity revenue for that period, the third consecutive year that TMI failed to clear the PJM base residual capacity auction. The plant is currently committed to operate through May 2019. In 2017, as a result of the plant retirement decision of TMI, Exelon and Generation recognized one-time charges in Operating and maintenance expense of $76 million related to materials and supplies inventory reserve adjustments, employee-related costs and construction work-in-progress (CWIP) impairments, among other items. In addition to these one-time charges, there will be ongoing annual incremental non-cash charges to earnings stemming from shortening the expected economic useful life of TMI primarily related to accelerated depreciation of plant assets (including any asset retirement costs (ARC)), accelerated amortization of nuclear fuel, and additional asset retirement obligation (ARO) accretion expense associated with the changes in decommissioning timing and cost assumptions. During the three and nine months ended September 30, 2017, both Exelon’s and Generation’s results include an incremental $112 million and $149 million, respectively, of pre-tax expense for these items.

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~~The following table summarizes the estimated annual amount and timing of expected incremental non-cash expense items through 2019.~~

September 30, 2017
Projected^(a)
Income statement expense (pre-tax) 2017 2018 2019
Depreciation and Amortization
Accelerated depreciation^(b)
$ 141
$ 250
$ 430
$ 325
Accelerated nuclear fuel amortization 8
10
20
5
Total $ 149
$ 260
$ 450
$ 330

~~_________~~


~~(a)~~	~~Actual results may differ based on incremental future capital additions, actual units of production for nuclear fuel amortization, future revised ARO assumptions, etc.~~


~~(b)~~	~~Reflects incremental accelerated depreciation of plant assets, including any ARC.~~

~~EGTP Consent Agreement~~

~~In September 2014, EGTP, an indirect subsidiary of Exelon and Generation, issued $675 million~~ aggregate principal amount of a nonrecourse senior secured term loan. EGTP’s operating cash flows have been negatively impacted by certain market conditions and the seasonality of its cash flows. On May 2, 2017, 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, the proceeds from which will first be used to pay the administrative costs of the sale, the normal and ordinary costs of operating the plants and repayment of the secured debt of EGTP, including the revolving credit facility. As a result, in the second quarter 2017, Exelon and Generation classified certain EGTP assets and liabilities on Exelon’s and Generation’s Consolidated Balance Sheets as held for sale at their respective fair values less costs to sell and included in the other current assets and other current liabilities balances on Exelon's and Generation's Consolidated Balance Sheets. For the three and nine months ended September 30, 2017, a $40 million and $458 million pre-tax impairment loss was recorded within Operating and maintenance expense on Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. See Note 4 - Mergers, Acquisitions and Dispositions, Note 6 - Impairment of Long-Lived Assets and Note 11 - Debt and Credit Agreements for more information for additional information regarding EGTP and the associated nonrecourse debt.

~~Acquisition of James A. FitzPatrick Nuclear Generating Station~~

On March 31, 2017, Generation acquired the 838 MW single-unit James A. FitzPatrick (FitzPatrick) nuclear generating station for a total purchase price of $289 million. In accounting for the acquisition as a business combination, Exelon and Generation recorded an after-tax bargain purchase gain of $233 million which is included within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. See Note 4 - Mergers, Acquisitions and Dispositions of the Combined Notes to the Consolidated Financial Statements for additional information ~~regarding~~on the ~~Generation's acquisition of FitzPatrick~~separation and ~~related costs.~~discontinued operations.

~~Illinois Future Energy Jobs Act~~

On December 7, 2016, FEJA was signed into law by the Governor of Illinois. FEJA was effective June 1, 2017, and includes, among other provisions, (1) a Zero Emission Standard (ZES) providing compensation for certain nuclear-powered generating facilities, (2) an extension of and certain adjustments to ComEd’s electric distribution formula rate, (3) new cumulative persisting annual energy efficiency MWh savings goals for ComEd, (4) revisions to the Illinois RPS requirements, (5) provisions for adjustments to or termination of FEJA programs if the average impact on ComEd’s customer rates exceeds specified limits, (6) revisions to the existing net metering statute and (7) support for low income rooftop and community solar programs. FEJA establishes new or adjusts existing rate recovery mechanisms for ComEd to recover costs associated with the new or expanded energy efficiency and RPS requirements. Regulatory or legal challenges over the validity of FEJA are possible. See Note 5 - Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for additional information regarding FEJA. See Note 7 - Early Nuclear Plant Retirements of the Combined Notes to the Consolidated Financial Statements for additional information regarding the economic challenges facing Generation's Clinton and Quad Cities nuclear plants and the expected benefits of the ZES.

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~~Dismissal of Litigation Challenging ZEC Programs~~

On July 14, 2017, the U.S. District Court for the Northern District of Illinois dismissed two lawsuits challenging the ZEC program contained in FEJA. On July 17, 2017, the plaintiffs appealed the court’s decisions to the U.S. Court of Appeals for the Seventh Circuit. Plaintiffs-Appellants initial brief was filed on August 28, 2017 and the state’s and Exelon’s briefs were filed on October 27, 2017. Reply briefs are due on December 12, 2017.

Additionally, on July 25, 2017, the U.S. District Court for the Southern District of New York dismissed a lawsuit challenging the ZEC program contained in the New York CES. On August 24, 2017, the plaintiffs appealed the decision to the Second Circuit. Plaintiffs-Appellants’ initial brief was filed on October 13 and the state’s and Exelon’s briefs are due on November 17, 2017. Reply briefs are due on December 1, 2017.

These court decisions uphold the ZEC programs which support Illinois’s and New York’s efforts to advance clean energy and preserve affordable and reliable energy resources for customers. See Note 5 - Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for additional information regarding FEJA and the New York CES.

~~Merger Commitment Unrecognized Tax Benefits~~

~~Exelon established a liability for an uncertain tax position associated with the tax deductibility of certain merger commitments incurred by Exelon in~~In connection with the ~~acquisitions~~separation, Exelon incurred separation costs/(benefit) impacting continuing operations of Constellation in 2012 and PHI in 2016. In the first quarter 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~~and $(2) million ~~$21 million, $16~~on a pre-tax basis for the three months ended September 30, 2023 and 2022, respectively, and $26 million and ~~$22~~$35 million ~~respectively, as of~~on a pre-tax basis for the nine months ended September 30, ~~2017, resulting~~2023 and 2022, respectively, which are recorded in ~~a benefit~~Operating and maintenance expense. Total separation costs impacting continuing operations for the remainder of 2023 are not expected to ~~Income taxes on Exelon’s, Generation’s, PHI’s, Pepco’s, DPL’s~~be material. These costs are excluded from Adjusted (non-GAAP) Operating Earnings. The separation costs are primarily comprised of system-related costs, third-party costs paid to advisors, consultants, lawyers, and ~~ACE’s Consolidated Statements of Operations and Comprehensive Income and corresponding decreases in their effective tax rates.~~

~~Combined-Cycle Gas Turbine Projects~~

In June 2017, Generation commenced commercial operations of two new combined-cycle gas turbines (CCGTs) at the Colorado Bend and Wolf Hollow Generating Stations in Texas. The two new CCGTs have added nearly 2,200 MWs of capacity to Generation’s fleet, enhancing Generation’s strategy to match generation to customer load. Generation invested approximately $1.5 billion over the past three years to complete the new plant construction, which utilizes new General Electric technology to make them among the cleanest, most efficient CCGTsother experts assisting in the ~~nation.~~separation, and employee-related severance costs.

~~Utility Rates and~~Distribution Base Rate Case 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.~~

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statements.

The following tables show the Utility Registrants’ completed and pending distribution base rate case proceedings in ~~2017.~~

~~Completed Distribution Rate Case Proceedings~~

Company Jurisdiction
Approved Revenue Requirement Increase
(in millions)
Approved Return on Equity Completion Date Rate Effective Date
DPL Maryland (Electric) $ 38
9.6 % February 15, 2017 February 15, 2017
DPL Delaware (Electric) $ 31.5
9.7 % May 23, 2017 June 1, 2017
DPL Delaware (Natural Gas) $ 4.9
9.7 % June 6, 2017 July 1, 2017
Pepco District of Columbia (Electric) $ 37
9.5 % July 25, 2017 August 15, 2017
ACE New Jersey (Electric) $ 43
9.6 % September 22, 2017 October 1, 2017
Pepco Maryland (Electric) $ 32
9.5 % October 27, 2017 October 20, 2017

~~Pending Distribution Rate Case Proceedings~~

Company Jurisdiction
Requested Revenue Requirement Increase
(in millions)
Requested Return on Equity Filing Date Expected Completion Timing
ComEd
Illinois (Electric)^(a)
$ 96
^(b)
8.4 %
^(c)
April 13, 2017 Fourth quarter 2017
DPL Maryland (Electric) $ 22
10.1 % July 14, 2017 (Updated on September 28, 2017) First quarter 2018
DPL Delaware (Electric) $ 31
10.1 % August 17, 2017 (Updated on October 18, 2017) Third quarter 2018
DPL Delaware (Natural Gas) $ 13
10.1 % August 17, 2017 Third quarter 2018

~~________~~

~~(a)~~

Pursuant to EIMA, ComEd’s electric distribution rates are established through a performance-based formula through which ComEd is required to file an annual update on or before May 1, 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 for the year (annual reconciliation).


~~(b)~~	~~Reflects an increase of $78 million for the initial revenue requirement for 2017 and an increase of $18 million related to the annual reconciliation.~~

~~(c)~~

ComEd’s allowed ROE under its electric distribution formula rate is the annual average rate on 30-year treasury notes plus 580 basis points and is subject to reduction if ComEd does not deliver certain reliability and customer service benefits. The initial revenue requirement for 2017 reflects an allowed ROE of 8.40%, while the annual reconciliation reflects an allowed ROE of 8.34%, which is inclusive of a 6 basis point performance penalty.

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~~Transmission Formula Rates~~

~~The following total increases/(decreases) were included in ComEd’s, BGE’s, Pepco's, DPL's and ACE's 2017 annual electric transmission formula rate filings:~~

~~_________~~


~~(a)~~	~~All rates are effective June 2017, subject to review by the FERC and other parties, which is due by fourth quarter 2017.~~


~~(b)~~	~~BGE's transmission revenues include a FERC approved dedicated facilities charge 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)~~

~~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 would be updated annually to ensure that under this rate customers pay the actual costs of providing transmission services. The formula rate filing includes a requested increase of $22 million to PECO’s annual transmission revenues and a requested rate of return on common equity of 11%, inclusive of a 50 basis point adder for being a member of a regional transmission organization. PECO requested that the new transmission rate be effective as of July 2017. 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. PECO cannot predict the final outcome of the settlement or hearing proceedings, or the transmission formula FERC may approve.

2023. See Note ~~5 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for further details on these regulatory proceedings.~~

~~Westinghouse Electric Company LLC Bankruptcy~~

On March 29, 2017, Westinghouse Electric Company LLC (Westinghouse) and its affiliated debtors filed petitions for relief under Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of New York. In the petitions and supporting documents, Westinghouse makes clear that its requests for relief center on one business area that is losing money3 — the construction of nuclear power plants in Georgia and South Carolina. Through the bankruptcy, Westinghouse seeks to reorganize around its profitable core business, which includes nuclear fuel fabrication and related services and other services provided to existing nuclear power plants in the U.S. and around the world. For these reasons, at this time, Generation does not anticipate disruption to the Westinghouse fuel fabrication contracts for Braidwood, Byron, or Ginna or other existing contracts for Generation's nuclear power plants. Generation is monitoring the bankruptcy proceeding to ensure that its rights are protected.

~~ExGen Renewables Holdings, LLC Transaction~~

On July 6, 2017, ExGen Renewables Holdings, LLC, a wholly owned subsidiary of Generation, completed the sale of a 49% interest of ExGen Renewables Partners, LLC, a newly formed owner and operator of approximately 1,296 megawatts of Generation's operating wind and solar electric generating facilities. ExGen Renewables Holdings will be the managing member of ExGen Renewables Partners, LLC, and have day-to-day control and management

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over its renewable generation portfolio. The closing of the transaction was subject to certain regulatory approvals, including the Federal Energy Regulatory Commission (FERC) and the Public Utility Commission of Texas (PUCT) which were received during the second quarter of 2017. The sale price was $400 million plus immaterial working capital and other customary post-closing adjustments. The net proceeds, after approximately $100 million of income taxes, will be used to pay down debt and for general corporate purposes. Generation will continue to consolidate ExGen Renewables Partners, LLC and will record a noncontrolling interest on its Consolidated Balance Sheet for the investor's initial equity share as well as earnings attributable to the noncontrolling interest in the Consolidated Statements of Operations and Comprehensive Income each period going forward.

~~Hurricanes Harvey, Irma and Maria Impacts~~

Although Exelon subsidiaries provided substantial assistance to recovery efforts following Hurricanes Harvey and Irma, Hurricanes Harvey, Irma and Maria are not expected to have a material impact on the Registrants’ businesses or financial results given the limited operations in the areas affected by the storms.

~~Exelon’s Strategy and Outlook for 2017 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:

~~Exelon’s utilities 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 in long-term, contracted assets 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 Exelon utilities 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 Exelon utilities 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 meter 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. Exelon's Board of Directors has approved a dividend policy providing a raise of 2.5% each year for three years, beginning with the June 2016 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

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~~to which Exelon is actively pursuing in a variety of jurisdictions and venues. See ITEM 1A. RISK FACTORS of the Exelon 2016 Form 10-K for additional information regarding market and financial factors.~~

Continually optimizing the cost structure is a key component of Exelon’s financial strategy. In a cost management program initiated late in 2015, the company committed to reducing operation and maintenance expenses and capital costs by approximately $350 million and $50 million, respectively, of which approximately 35% of run-rate savings was achieved by the end of 2016. Approximately 60% of run-rate savings are expected to be achieved by the end of 2017 and fully realized in 2018. At least 75% of the savings are expected to be related to Generation, with the remaining amount related to the Utility Registrants.

In November 2017, Exelon announced the elimination of approximately $250 million of annual ongoing costs, primarily at Generation, by 2020. This announcement is a result of Exelon’s continuous focus on improving its cost profile through enhanced efficiency and productivity. These cost reductions result in a cost profile that better aligns with current market conditions. The targeted cost savings are incremental to the expected savings from previous cost management initiatives.

~~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 PHI merger provides an opportunity to accelerate Exelon’s regulated growth to provide stable cash flows, earnings accretion, and dividend support. Additionally, the Utility Registrants anticipate investing approximately $25 billion over the next five years in electric and natural gas infrastructure improvements and modernization projects, including smart meter and smart grid initiatives, storm hardening, advanced reliability technologies, and transmission projects, which is projected to result in an increase to current rate base of approximately $9 billion by the end of 2021. 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 5—~~Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional ~~information on the Smart Meter and Smart Grid Initiatives 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. As of September 30, 2017, Generation has currently approved plans to invest a total of approximately $300 million through 2018 to complete new plant construction currently in progress.

~~Liquidity Considerations~~

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.). The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs and capital expenditure requirements.

Exelon, Generation, ComEd, PECO, BGE, Pepco, DPL and ACE have unsecured syndicated revolving credit facilities with aggregate bank commitments of $0.6 billion, $5.3 billion, $1 billion, $0.6 billion, $0.6 billion, $0.3 billion, $0.3 billion and $0.3 billion, respectively. Generation also has bilateral credit facilities with aggregate maximum availability of $0.5 billion. See Liquidity and Capital Resources - Credit Matters - Exelon Credit Facilities below.

~~For further detail regarding the Registrants' liquidity for the nine months ended September 30, 2017, see Liquidity and Capital Resources discussion below.~~

information.

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Completed Distribution Base Rate Case Proceedings

~~Project Financing~~


Registrant/Jurisdiction	Filing Date	Service	Requested Revenue Requirement Increase		Approved Revenue Requirement Increase		Approved ROE		Approval Date	Rate Effective Date
ComEd - Illinois	April 15, 2022	Electric	$	199	$	199	7.85	%	November 17, 2022	January 1, 2023

PECO - Pennsylvania	March 31, 2022	Natural Gas	82		55		N/A		October 27, 2022	January 1, 2023
BGE - Maryland	May 15, 2020 (amended September 11, 2020)	Electric	203		140		9.50	%	December 16, 2020	January 1, 2021
		Natural Gas	108		74		9.65	%
Pepco - Maryland	October 26, 2020 (amended March 31, 2021)	Electric	104		52		9.55	%	June 28, 2021	June 28, 2021
DPL - Maryland	May 19, 2022	Electric	38		29		9.60	%	December 14, 2022	January 1, 2023

~~Generation utilizes individual project financings as a means to finance~~

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Pending Distribution Base Rate Case Proceedings

Registrant/Jurisdiction

Filing Date

Service

Requested Revenue Requirement Increase

Requested ROE

Expected Approval Timing

ComEd - Illinois

January 17, 2023

Electric

1,487

10.50% to 10.65%

Fourth quarter of 2023

ComEd - Illinois

April 21, 2023

Electric

247

8.91

Fourth quarter of 2023

BGE - Maryland

February 17, 2023

Electric

313

10.40

Fourth quarter of 2023

Natural Gas

289

10.40

Pepco - District of Columbia

April 13, 2023

Electric

191

10.50

Second quarter of 2024

Pepco - Maryland

May 16, 2023

Electric

214

10.50

Second quarter of 2024

DPL - Delaware

December 15, 2022 (amended September 29, 2023)

Electric

10.50

Second quarter of 2024

ACE - New Jersey

February 15, 2023 (amended August 21, 2023)

Electric

10.50

Fourth quarter of 2023

Transmission Formula Rates

For 2023, the construction of various generating asset projects. Project financing is based upon a nonrecourse financial structure, in which project debt and equity used to finance the project are paid back from the cash generated by the newly constructed asset once operational. Borrowings under these agreements are secured by the assets and equity of each respective project. The lenders do not have recourse against Exelon or Generationfollowing total increases/(decreases) were included 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.Utility Registrants' electric transmission formula rate updates. See Note ~~6 Impairment of Long-Lived Assets and Note 11 - Debt and Credit Agreements~~3 — Regulatory Matters of the Combined Notes to ~~the~~ Consolidated Financial Statements for additional information.


Registrant	Initial Revenue Requirement Increase		Annual Reconciliation Increase (Decrease)		Total Revenue Requirement Increase		Allowed Return on Rate Base		Allowed ROE
ComEd	$	20	$	63	$	83	8.09	%	11.50	%
PECO	24		23		47		7.41	%	10.35	%
BGE	19		(12)		4		7.34	%	10.50	%
Pepco	37		(5)		32		7.57	%	10.50	%
DPL	32		(3)		29		7.08	%	10.50	%
ACE	41		(12)		29		7.08	%	10.50	%

ComEd's FERC Audit

The Utility Registrants are subject to periodic audits by FERC. FERC’s Division of Audits and Accounting initiated a nonpublic audit of ComEd in April 2021 evaluating ComEd’s compliance with (1) approved terms, rates, and conditions of its federally regulated service; (2) accounting requirements of the Uniform System of Accounts; (3) reporting requirements of the FERC Form 1; and (4) the requirements for record retention. The audit period extends back to January 1, 2017. During the first quarter of 2023, ComEd was provided with information from FERC about several potential findings, including ComEd's methodology regarding the allocation of certain overhead costs to capital under FERC regulations. Based on ~~nonrecourse debt.~~the preliminary findings and discussions with FERC staff, ComEd determined that a loss was probable and recorded a regulatory liability to reflect its best estimate of that loss as of March 31, 2023.

On July 27, 2023, FERC issued a final audit report which included, among other things, findings and recommendations related to ComEd's methodology regarding the allocation of certain overhead costs to

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capitalized construction costs under FERC regulations. On August 28, 2023, ComEd filed a formal notice of the issues it will contest. The final outcome and resolution of any contested audit issues as well as a reasonable estimate of potential future losses cannot be accurately estimated at this stage; however, the final resolution of these matters could result in recognition of future losses, above the amounts currently accrued, that could be material to the Exelon and ComEd financial statements.

Other Key Business Drivers and Management Strategies

~~Power Markets~~

~~Price~~The following discussion of ~~Fuels~~

~~The use~~other key business drivers and management strategies includes current developments of previously disclosed matters and 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 resultsissues arising during the period that may impact future financial statements. This section should be read 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).

~~Capacity Market Changes in PJM~~

In the wake of the January 2014 Polar Vortex that blanketed much of the Eastern and Midwestern United States, it became clear that while a major outage event was narrowly avoided, resources in PJM were not providing the level of reliability expected by customers. As a result, on December 12, 2014, PJM filed at FERC a proposal to make significant changes to its current capacity market construct, the Reliability Pricing Model (RPM). PJM’s proposed changes generally sought to improve resource performance and reliability largely by limiting the excuses for non-performance and by increasing the penalties for performance failures. The proposal permits suppliers to include in capacity market offers additional costs and risk so they can meet these higher performance requirements. While offers are expected to put upward pressure on capacity clearing prices, operational improvements made as a result of PJM’s proposal are expected to improve reliability, to reduce energy production costs as a result of more efficient operations and to reduce the need for out of market energy payments to suppliers. Generation participated actively in PJM’s stakeholder process through which PJM developed the proposal and also actively participatedconjunction with ITEM 1. Business in the FERC proceeding including filing comments. On June 9, 2015, FERC approved PJM's filing largely as proposed by PJM, including transitional auction rules for delivery years 2016/2017 through 2017/2018. As a result2022 Form 10-K, ITEM 7. Management's Discussion and Analysis of ~~this~~Financial Condition and ~~several related orders, PJM hosted its 2018/2019 Base Residual Auction (results posted on August 21, 2015)~~Results of Operations — Other Key Business Drivers and its transitional auction for delivery year 2016/2017 (results posted on August 31, 2015) and its transitional auction for delivery years 2017/2018 (results posted on September 9, 2015). On May 10, 2016, FERC largely denied rehearing, and a number of parties appealed to the U.S. Court of Appeals for the DC Circuit for review of the decision. On June 20, 2017, the DC Circuit denied all the appeals.

~~MISO Capacity Market Results~~

On April 14, 2015, the Midcontinent Independent System Operator (MISO) released the results of its capacity auction covering the June 2015 through May 2016 delivery year. As a result of the auction, capacity prices for the zone 4 region in downstate Illinois increased to $150 per MW per day beginning in June 2015, an increase from the prior pricing of $16.75 per MW per day that was in effect from June 2014 to May 2015. Generation had an offer that was selectedManagement Strategies in the auction. However, due to Generation's ratable hedging strategy, the results of the capacity auction have not had a material impact on Exelon's and Generation's consolidated results of operations and cash flows.

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Additionally, in late May and June 2015, separate complaints were filed at the FERC by each of the State of Illinois, the Southwest Electric Cooperative, Public Citizens, Inc., and the Illinois Industrial Energy Consumers challenging the results of this MISO capacity auction for the 2015/2016 delivery in MISO delivery zone 4. The complaints allege generally that 1) the results of the capacity auction for zone 4 are not just and reasonable, 2) the results should be suspended, set for hearing and replaced with a new just and reasonable rate, 3) a refund date should be established and that 4) certain alleged behavior by one of the market participants other than Exelon or Generation, be investigated.

On October 1, 2015, FERC announced that it was conducting a non-public investigation (that does not involve Exelon or Generation) into whether market manipulation or other potential violations occurred related to the auction. On December 31, 2015, FERC issued a decision that certain of the rules governing the establishment of capacity prices in downstate Illinois are “not just and reasonable” on a prospective basis. FERC ordered that certain rules be changed prior to the April 2016 auction which set capacity prices for the 2016/2017 planning year. In response to this order, MISO filed certain rule changes with FERC. On March 18, 2016, FERC largely denied rehearing of its December 31, 2015 order. FERC continues to conduct its non-public investigation to determine if the April 2015 auction results were manipulated and, if so, whether refunds are appropriate. FERC did establish May 28, 2015, the day the first complaint was filed, as the date from which refunds (if ordered) would be calculated, and it also made clear that the findings in the December 31, 2015 order do not prejudge the investigation or related proceedings. Generation cannot predict the impact the FERC order may ultimately have on future auction results, capacity pricing or decisions related to the potential early retirement of the Clinton nuclear plant, however, such impacts could be material to Generation's future results of operations and cash flows. ~~See Note 7 - Early Nuclear Plant Retirements of the Combined Notes to the Consolidated Financial Statements for additional information on the impacts of the MISO announcement.~~

~~Subsidized Generation~~

~~The rate of expansion of subsidized generation, in the markets in which Generation’s output is sold can negatively impact wholesale power prices, and in turn, Generation’s results of operations.~~

Various states have attempted to implement or propose legislation, regulations or other policies to subsidize new generation development which may result in artificially depressed wholesale energy and capacity prices. For example, the New Jersey legislature enacted into law in January 2011, the Long Term Capacity Pilot Program Act (LCAPP). LCAPP provides eligible generators with 15-year fixed contracts for the sale of capacity in the PJM capacity market. Under LCAPP, the local utilities in New Jersey are required to pay (or receive) the difference between the price eligible generators receive in the capacity market and the price guaranteed under the 15-year contract. New Jersey ultimately selected three proposals to participate in LCAPP and build new generation in the state. In addition, on April 12, 2012, the MDPSC issued an order directing the Maryland electric utilities to enter into a 20-year contract for differences (CfD) with CPV Maryland, LLC (CPV), under which CPV was required to construct an approximately 700 MW combined cycle gas turbine in Waldorf, Maryland. The CfD mandated that utilities (including BGE, Pepco and DPL) pay (or receive) the difference between CPV’s contract price and the revenues it receives for capacity and energy from clearing the unit in the PJM capacity market.

Exelon and others challenged the constitutionality and other aspects of the New Jersey legislation in federal court. The actions taken by the MDPSC were also challenged in federal court in an action to which Exelon was not a party. The federal trial courts in both the New Jersey and Maryland actions effectively invalidated the actions taken by the New Jersey legislature and the MDPSC, respectively. Each of those decisions was upheld by the U.S. Court of Appeals for the Third Circuit and the U.S. Court of Appeals for the Fourth Circuit, respectively. On April 19, 2016, the U.S. Supreme Court affirmed the decision of the U.S. Court of Appeals for the Fourth Circuit, and subsequently denied certiorari with respect to the appeal from the U.S. Court of Appeals for the Third Circuit, leaving in place that Court’s decision. The matter is now considered closed.

As required under their contracts, generator developers who were selected in the New Jersey and Maryland programs (including CPV) offered and cleared in PJM’s capacity market auctions. To the extent that the state-required customer subsidies are included under their respective contracts, Exelon believes that these projects may have artificially suppressed capacity prices in PJM in these auctions and may continue to do so in future auctions to the detriment of Exelon. While the court decisions are positive developments, continuation of these state efforts, if successful and unabated by an effective minimum offer price rule (MOPR) for future capacity auctions, could continue to result in artificially depressed wholesale capacity and/or energy prices. Other states could seek to establish programs, which could substantially impact Exelon’s position and could have a significant effect on Exelon’s financial results of operations, financial position and cash flows.

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One such state is Ohio, where state-regulated utility companies FirstEnergy Ohio (FE) and AEP Ohio (AEP) initiated actions at the Public Utilities Commission of Ohio (PUCO) to obtain approval for Riders that would effectively allow these two companies to pass through to all customers in their service territories the differences between their costs and market revenues on PPAs entered into between the utility and its merchant generation affiliate for what was collectively more than 6,000 MW of primarily coal-fired generation. Thus, the Riders were similar to the CfDs described above (except that the PPA Riders in Ohio would apply to existing generation facilities whereas the CfDs applied to new generation facilities). While FERC orders on April 27, 2016 largely alleviated the concerns related to the Riders by holding that the PPAs ran afoul of affiliate restrictions on FE and AEP, we continue to closely monitor developments in Ohio.

In addition, Exelon continues to monitor developments in Maryland, New Jersey, and other states and participates in stakeholder and other processes to ensure that similar state subsidies are not developed. Exelon remains active in advocating for competitive markets, while opposing policies that require taxpayers and/ or consumers to subsidize or give preferential treatment to generation providers or technologies that do not provide superior reliability or environmental benefits, or that would threaten the reliability and value of the integrated electricity grid.

~~Complaints at FERC Seeking to Mitigate Illinois and New York Programs Providing ZECs~~

PJM and NYISO capacity markets include a Minimum Offer Price Rule (MOPR) that is intended to preclude buyers from exercising buyer market power. If a resource is subjected to a MOPR, its offer is adjusted to remove the revenues it receives through a federal, state or other government-provided financial support program - resulting in a higher offer that may not clear the capacity market. Currently, the MOPRs in PJM and NYISO apply only to certain new resources. Exelon has generally opposed policies that require subsidies or give preferential treatment to generation providers or technologies that do not provide superior reliability or environmental benefits, or that would threaten the reliability and value of the integrated electricity grid. Thus, Exelon has supported a MOPR as a means of minimizing the detrimental impact certain subsidized resources could have on capacity markets (such as the New Jersey (LCAPP) and Maryland (CfD) programs). However, in Exelon’s view, MOPRs should not be applied to resources that receive compensation for providing superior reliability or environmental benefits.

On January 9, 2017, the Electric Power Supply Association (EPSA) filed two requests with FERC: one seeking to amend a prior complaint against PJM and another seeking expedited action on a pending NYISO compliance filing in an existing proceeding. Both filings allege that the relevant MOPR should be expanded to also apply to existing resources receiving ZEC compensation under the New York CES and Illinois ZES programs. The EPSA parties have filed motion to expedite both proceedings. Exelon has filed protests at FERC in response to each filing, arguing generally that ZEC payments provide compensation for an environmental attribute that is distinct from the energy and capacity sold in the FERC-jurisdictional markets, and therefore, are no different than other renewable support programs like the PTC and RPS that have generally not been subject to a MOPR. However, if successful, for Generation's facilities in NYISO and PJM expected to receive ZEC compensation (Quad Cities, Ginna, Nine Mile Point and FitzPatrick), an expanded MOPR could require exclusion of ZEC compensation when bidding into future capacity auctions such that these facilities would have an increased risk of not clearing in those auctions and thus no longer receiving capacity revenues during the respective ZEC programs. Any such mitigation of these generating resources could have a material effect on Exelon’s and Generation’s future cash flows and results of operations. On August 30, 2017, EPSA filed motions to lodge the district court decisions dismissing the complaints and urging FERC to act expeditiously on its requests to expand the MOPR. On September 14, 2017, Exelon filed a response in each docket noting that it does not oppose the motions to lodge but arguing that the requests to expedite a decision on the requests to expand the MOPR have no merit. The timing of FERC’s decision with respect to both proceedings is currently unknown and the outcome of these matters is currently uncertain.

~~DOE Notice of Proposed Rulemaking~~

On August 23, 2017, the DOE 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 baseload 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 October 2, 2017, the FERC issued a notice inviting comments regarding the DOE NOPR within 21 days and established a new docket wherein the FERC will consider the matter. On October 23, 2017, Exelon filed comments with the FERC, supporting the goals of the NOPR and urging the agency to take swift action to protect customers from power supply interruptions

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and ensure resiliency in a way that appropriately balances the value and cost to customers. Exelon cannot predict the final outcome of the proceeding or its potential impact, if any, on Exelon or Generation.

~~Energy Demand~~

Modest economic growth partially offset by energy efficiency initiatives is resulting in flat to declining load growth in electricity for the utilities. There is a decrease in projected load for electricity for ComEd, PECO, BGE, and ACE, and an essentially flat projected load for electricity for DPL. ComEd, PECO, BGE, Pepco, DPL, and ACE are projecting load volumes to decrease by (1.2)%, (0.4)%, (2.9)%, (2.3)%, (0.4)%, and (3.5)% respectively, in 2017 compared to 2016.

~~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. The market experienced high price volatility in the first quarter of 2014 which contributed to bankruptcies and consolidations within the industry during the year. However, 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.

~~Strategic Policy Alignment~~

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 declared first quarter 2017 dividends of $0.3275 per share on Exelon's common stock. The first quarter 2017 dividend was paid on March 10, 2017. The dividend increased from fourth quarter 2016 amount to reflect the Board's decision to raise Exelon's dividend 2.5% each year for the next three years, beginning with the June 2016 dividend.

~~Exelon's Board of Directors declared the second quarter 2017 dividends of $0.3275 per share each on Exelon's common stock. The second quarter 2017 dividend was paid on June 9, 2017.~~

~~Exelon's Board of Directors declared the third quarter 2017 dividends of $0.3275 per share each on Exelon's common stock. The third quarter 2017 dividend was paid on September 8, 2017.~~

~~Exelon's Board of Directors declared the fourth quarter 2017 dividends of $0.3275 per share each on Exelon's common stock. The fourth quarter 2017 dividend is payable on December 8, 2017.~~

~~All future quarterly dividends require approval by Exelon's Board of Directors.~~

~~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. Generation has hedges in place that significantly mitigate this risk for 2017 and 2018. However, Generation is exposed to relatively greater commodity price risk in the subsequent years with respect to which a larger portion of its electricity portfolio is currently unhedged. As of September 30, 2017, the percentage of expected generation hedged is 98%-101%, 79%-82% and 45%-48% for 2017, 2018, and 2019 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 generating facilities 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, such as wholesale and retail sales of power, options and

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~~swaps. Generation has been and will continue to be proactive in using hedging strategies to mitigate commodity price risk in subsequent years as well.~~

Generation procures oil and natural gas through long-term and short-term contracts and spot-market purchases. Nuclear fuel is obtained predominantly through long-term uranium concentrate supply contracts, contracted conversion services, contracted enrichment services, or a combination thereof, and contracted fuel fabrication services. The supply markets for uranium concentrates and certain nuclear fuel services, coal, oil and natural gas 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 2017 through 2021 are supplied by three producers. 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 position.

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

~~Tax Matters~~

~~Potential Corporate Tax Reform~~

President Trump and Congressional Republicans have stated that one of their top priorities is enactment of comprehensive tax reform. On September 27, 2017, the Trump Administration and Republican Congressional leaders issued a unified framework which outlines their goals for comprehensive tax reform. Specifically, the framework proposes a reduction in the corporate tax rate from the current 35% to 20%, immediate expensing of new investments in depreciable assets for at least five years, elimination of the domestic production activities deduction and partial limitation of the deduction for interest. It is uncertain whether, to what extent, or when any changes in federal tax policies will be enacted or the transition time frame for such changes. The Utility Registrants’ regulators may impose rate reductions to provide the benefit of any reduction in income tax expense to customers as well as to refund the "excess" deferred income taxes previously collected through rates. The amount and timing of any such rate changes would be subject to the discretion of the rate regulator in each specific jurisdiction. For these reasons, the Registrants cannot predict the impact any potential changes may have on their future results of operations, cash flows or financial position, and such changes could be material.

~~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

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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. The initial compliance deadline to meet the new standards was April 16, 2015; however, facilities may have been granted an additional one or two year extension in limited cases. 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. The U.S. Supreme Court, however, did not vacate the rule; rather, it was remanded to the D.C. Circuit Court to take further action consistent with the U.S. Supreme Court’s opinion on this single issue. On April 27, 2017, the D.C. Circuit 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. Following EPA’s review and determination of its course of action for the MATS rule, the parties will have 30 days to file motions on future proceedings. 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.~~

~~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. On October 10, 2017, EPA issued a proposed rule to repeal the CPP in its entirety, based on a proposed change in the Agency’s legal interpretation of Clean Air Act Section 111(d) regarding actions that the Agency can consider when establishing the Best System of Emission Reduction (“BSER”) for existing power plants. Under the proposed interpretation, the Agency exceeded its authority under the Clean Air Act by regulating beyond individual sources of GHG emissions. The EPA has also indicated its intent to issue an advance notice of proposed rulemaking to solicit information on systems of emission reduction that are in accord with the Agency’s proposed revised legal interpretation; namely, only by regulating emission reductions that can be implemented at and to individual sources.

~~2015 Ozone National Ambient Air Quality Standards (NAAQS).~~ On April 11, 2017, the D.C. Circuit ordered that the consolidated 2015 ozone NAAQS litigation be held in abeyance pending EPA’s further review of the 2015 Rule. EPA did not meet the October 1, 2017 deadline to promulgate initial designations for areas in attainment or non-attainment of the standard. A number of states and environmental organizations have notified the EPA of their intent to file suit to compel EPA to issue the designations.

~~Water Quality~~

Section 316(b) of the Clean Water Act requires that 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 changes to the existing regulations. Those facilities are Calvert Cliffs, Clinton, Dresden, Eddystone, Fairless Hills, FitzPatrick, Ginna, Gould Street, Handley, Mountain Creek, Mystic 7, Nine Mile Point Unit 1, Oyster Creek, Peach Bottom, Quad Cities, Riverside and Salem. ~~See ITEM 1.—BUSINESS, "Water Quality" of the Exelon 2016~~2022 Form 10-K, ~~for further discussion.~~

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~~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—~~12 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in this report for ~~further detail related to~~additional information on various environmental ~~matters, including the impact of environmental regulation.~~matters.

~~Other~~ Legislative and Regulatory Developments

~~NRC Task Force~~City of Chicago Franchise Agreement

The current ComEd Franchise Agreement with the City of Chicago (the City) has been in force since 1992. The Franchise Agreement grants rights to use the public right of way to install, maintain, and operate the wires, poles, and other infrastructure required to deliver electricity to residents and businesses across the City. The Franchise Agreement became terminable on ~~Fukushima Daiichi Accident (Exelon~~one year notice as of December 31, 2020. It now continues in effect indefinitely unless and ~~Generation).~~

~~In July 2011,~~until either party issues a notice of termination, effective one year later, or it is replaced by mutual agreement with a new franchise agreement between ComEd and the City. If either party terminates and no new agreement is reached between the parties, the parties could continue with ComEd providing electric services within the City with no franchise agreement in place. The City also has an ~~NRC Task Force formed in~~option to terminate and purchase the ~~aftermath of the March 11, 2011, 9.0 magnitude earthquake and ensuing tsunami, that seriously damaged the nuclear units at the Fukushima Daiichi Nuclear Power Station,~~ComEd system (“municipalize”), which also requires one year notice. Neither party has issued a ~~report~~notice of termination at this time, the City has not exercised its ~~review of~~municipalization option, and no new agreement has become effective. Accordingly, the ~~accident, including tiered recommendations~~1992 Franchise Agreement remains in effect at this time. In April 2021, the City invited interested parties to respond to a Request for ~~future regulatory action~~Information (RFI) regarding the franchise for electricity delivery. Final responses to the RFI were due on July 30, 2021, however, on July 29, 2021, the City chose to extend the final submission deadline to September 30, 2021. ComEd submitted its response to the RFI by the ~~NRC~~due date. However, the City did not proceed to ~~be taken in~~issue an RFP. Since that time, ComEd and the ~~near~~City continued to negotiate and ~~longer term.~~have arrived at a proposed Chicago Franchise Agreement (CFA) and an Energy and Equity Agreement (EEA). These agreements together are intended t o grant ComEd the right to continue providing electric utility services using public ways within the City of Chicago, and to create a new non-profit entity to advance energy and energy-related equity projects. On February 1, 2023, the proposed CFA and EEA were introduced to the City Council. The ~~Task Force’s report concluded that nuclear reactors in the United States are operating safely~~proposed CFA and ~~do not present an imminent risk~~EEA remain subject to public health and safety. The NRC and its staff have issued orders and implementation guidance for commercial reactor licensees operating in the United States. Generation has assessed the impacts of the Tier 1 orders and information requests and will continue monitoring the additional recommendations under reviewapproval by the ~~NRC staff, both from an operational~~City Council and ~~a financial impact standpoint. Generation’s current assessments are specific to~~ the ~~Tier 1 recommendations. In May 2017, the NRC finalized its decision that no actions are required with respect to the Tier 2~~Exelon Board.

While Exelon and ~~Tier 3 recommendations. Generation will continue to engage in nuclear industry assessments and actions and obtain stakeholder input.~~

~~Employees~~

In January 2017, an election was held at BGE which resulted in union representation for approximately 1,400 employees. BGE and IBEW Local 410 have begun negotiations for an initial agreement which could result in some modifications to wages, hours and other terms and conditions of employment. No agreement has been finalized to date and managementComEd cannot predict the ultimate outcome of ~~such negotiations.~~ these processes, fundamental changes in the agreements or other adverse actions affecting ComEd’s business in the City would require changes in their business planning models and operations and could have a material adverse impact on Exelon’s and ComEd’s consolidated financial statements. If the City were to disconnect from the ComEd system, ComEd would seek full compensation for the business and its associated property taken by the City, as well as for all damages resulting to ComEd and its system. ComEd would also seek appropriate compensation for stranded costs with FERC.

Infrastructure Investment and Jobs Act

On November 15, 2021, President Biden signed the $1.2 trillion IIJA into law. IIJA provides for approximately $550 billion in new federal spending. Categories of funding include funding for a variety of infrastructure needs, including but not limited to: (1) power and grid reliability and resilience, (2) resilience for cybersecurity to address critical infrastructure needs, and (3) electric vehicle charging infrastructure for alternative fuel corridors. Federal agencies are developing guidelines to implement spending programs under IIJA. The time needed to develop these guidelines will vary with some limited program applications opened as early as the first quarter of 2022. The Registrants continue to evaluate programs under the legislation and consider possible opportunities to apply

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for funding, either directly or in potential collaborations with state and/or local agencies and key stakeholders. The Registrants cannot predict the ultimate timing and success of securing funding from programs under IIJA.

In September 2022, ComEd and BGE applied for the MMG, which establishes and funds construction, improvement, or acquisition of middle mile broadband infrastructure which creates high-speed internet services. The MMG addresses inequitable broadband access by expansion and extension of the middle mile infrastructure in underserved communities. In June 2023, the National Telecommunications and Information Administration (NTIA) announced it selected two of the applications submitted by BGE and ComEd; awarding ComEd and BGE $14.5 million and $15.4 million respectively. The applications selected by NTIA for BGE and ComEd proposed projects designed to enhance electric grid reliability and resiliency while leading and advancing shared local, state, and national goals to increase broadband connectivity, redundancy, affordability, and equity.

In March 2023, Exelon, ComEd, and PHI submitted three applications related to the Smart Grid Grants program under section 40107 of IIJA. These applications are focused on replacing existing Advanced Distribution Management Systems (ADMS) in support of distributed energy resources (DERs) and grid-edged technologies, strengthening interoperability and data architecture of systems in support of two-way power flows and accelerating advanced metering deployment in disadvantaged communities. In October 2023, ComEd’s project, Deployment of a Community-Oriented Interoperable Control Framework for Aggregating and Integrating Distributed Energy Resources and Other Grid-Edge Devices, was recommended by the Grid Deployment Office (GDO) for negotiation of a final award up to $50 million. This project will enable ComEd and its local partners to deploy the next generation of grid technologies that support the growth of solar and electric vehicles (EVs), while piloting new local workforce training initiatives to support job creation connected to the clean energy transition. The GDO has indicated the award negotiation process can take approximately 120 days.

In April ~~2017,~~2023, ComEd, PECO, BGE, and PHI submitted seven applications related to the Grid Resilience Grants program under section 40101(c) of IIJA. These applications are broadly focused on improving grid resilience with an emphasis on disadvantaged communities, relief of capacity constraints and modernizing infrastructure, deployment of DER and microgrid technologies and providing improved resilience through storm hardening projects. In October 2023, PECO’s project, Creating a Resilient, Equitable, and Accessible Transformation in Energy for Greater Philadelphia (CREATE), was recommended by the GDO for negotiation of a final award up to $100 million. This project will support critical electric infrastructure investments to help reduce the impact of extreme weather and historic flooding on the company's electric distribution system. The GDO has indicated the award negotiation process can take approximately 120 days.

The Registrants are supporting three different Regional Clean Hydrogen Hub opportunities, covering all five states that Exelon ~~Nuclear Security successfully ratified its CBA with~~operates in plus Washington D.C. under a program that will create networks of hydrogen producers, consumers, and local connective infrastructure to accelerate the ~~SPFPA Local 238 at Quad Cities to an extension~~use of hydrogen as a clean energy carrier that can deliver or store energy. Applications for the three ~~years.~~opportunities under this program were submitted in April 2023. In October 2023 the DOE announced it selected two of the projects for further negotiation: (1) the Mid-Atlantic Clean Hydrogen Hub (MACH2), which is being supported by PECO and PHI, and (2) the Midwest Alliance for Clean Hydrogen (MachH2), which is being supported by ComEd.

PJM Regional Transmission Expansion

On April 6, 2023, PJM received a deactivation notice for Brandon Shores, a 1,282 MW coal generation plant located in BGE service territory. The deactivation was requested for June 1, 2025 and will result in numerous reliability issues across the region. In June ~~2017,~~2023, PJM assigned a portion of transmission system upgrades to mitigate these reliability impacts to PECO, BGE, and Pepco. In July 2023, PJM Board of Managers approved assigning Exelon ~~Nuclear Security successfully ratified~~transmission system upgrades to mitigate these reliability impacts to PECO, BGE, and Pepco. The most recent projected capital expenditures associated with these upgrades are approximately $80 million, $650 million, and $80 million for PECO, BGE, and Pepco, respectively. These amounts include a scope reduction estimated by PJM for PECO of $60 million associated with a transmission proposal window, as disclosed at a Transmission Expansion Advisory Committee meeting on October 31, 2023. The upgrades are expected to be completed by the end of 2028.

Separately, PJM held a competitive transmission proposal window from February 24, 2023 through May 31, 2023 to address reliability issues driven by significant load increases in northern Virginia. PECO, BGE, and Pepco submitted four solution proposals. At a meeting of the Transmission Expansion Advisory Committee on October 31, 2023, PJM recommended that PECO, BGE, Pepco, and DPL be awarded a portion of the work for the

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proposed solution. Initial estimated costs for these upgrades, as posted by PJM on its ~~CBA with~~website on October 27, 2023, are approximately $55 million, $700 million, $80 million, and $5 million for PECO, BGE, Pepco, and DPL, respectively. The PJM Board of Managers is scheduled to approve the ~~UGSOA Local 12 at Limerick~~solution in December 2023 and the upgrades are expected to ~~an extension~~be completed by the end of ~~three years.~~2030.

Critical Accounting Policies and Estimates

Management of each of the Registrants makes a number of significant estimates, assumptions, and judgments in the preparation of its financial statements. As of September 30, 2023, the Registrants’ critical accounting policies and estimates had not changed significantly from December 31, 2022. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — ~~CRITICAL ACCOUNTING POLICIES AND ESTIMATES~~Critical Accounting Policies and Estimates in ~~Exelon’s, Generation’s, ComEd’s, PECO’s, BGE’s, PHI's, Pepco's, DPL's and ACE's combined 2016~~the 2022 Form 10-K for a discussion of the estimates and judgments necessary in the Registrants’ accounting for AROs, goodwill, purchase accounting, unamortized energy assets and liabilities, asset impairments, depreciable lives of property, plant and equipment, defined benefit pension and other postretirement benefits, regulatory accounting, derivative instruments, taxation, contingencies, revenue recognition, and allowance for uncollectible accounts. At September 30, 2017, the Registrants’ critical accounting policies and estimates had not changed significantly from December 31, 2016.

further information.

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Results of Operations ~~By Registrant~~

~~Net Income (Loss) Attributable to Common Shareholders~~ by Registrant

Three Months Ended
September 30,
Favorable
(Unfavorable)
Variance
Nine Months Ended
September 30,
Favorable
(Unfavorable)
Variance
2017 2016 2017
2016^(a)

Exelon $ 824
$ 490
$ 334
$ 1,899
$ 930
$ 969
Generation 305
236
69
479
538
(59 )
ComEd 189
37
152
447
297
150
PECO 112
122
(10 ) 327
346
(19 )
BGE 62
54
8
231
183
48
Pepco 87
79
8
188
20
168
DPL 31
44
(13 ) 107
(16 ) 123
ACE 41
47
(6 ) 77
(50 ) 127

~~_________~~


~~(a)~~	For Pepco, DPL and ACE, reflects that Registrant's operations for the nine months ended September 30, 2016. For Exelon and Generation, includes the operations of the PHI acquired businesses for the period of March 24, 2016 through September 30, 2016.

Successor Predecessor
Three Months Ended September 30, 2017 Three Months Ended September 30, 2016 Nine Months Ended September 30, 2017 March 24, 2016 to September 30, 2016 January 1, 2016 to March 23, 2016
PHI $ 153
$ 166
$ 359
$ (91 ) $ 19

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Results of Operations — ~~Generation~~ComEd


	Three Months Ended September 30,				Favorable (Unfavorable) Variance		Nine Months Ended September 30,				Favorable (Unfavorable) Variance
	2023		2022				2023		2022
Operating revenues	$	2,268	$	1,378	$	890	$	5,836	$	4,536	$	1,300
Operating expenses
Purchased power	896		121		(775)		2,068		1,041		(1,027)
Operating and maintenance	385		355		(30)		1,077		1,045		(32)
Depreciation and amortization	357		333		(24)		1,045		982		(63)
Taxes other than income taxes	100		104		4		282		289		7
Total operating expenses	1,738		913		(825)		4,472		3,357		(1,115)
Loss on sales of assets	—		—		—		—		(2)		2
Operating income	530		465		65		1,364		1,177		187
Other income and (deductions)
Interest expense, net	(119)		(104)		(15)		(357)		(308)		(49)
Other, net	16		14		2		50		40		10
Total other income and (deductions)	(103)		(90)		(13)		(307)		(268)		(39)
Income before income taxes	427		375		52		1,057		909		148
Income taxes	94		84		(10)		235		203		(32)
Net income	$	333	$	291	$	42	$	822	$	706	$	116

Three Months Ended
September 30,
Favorable
(Unfavorable)
Variance
Nine Months Ended
September 30,
Favorable
(Unfavorable)
Variance
2017 2016 2017 2016
Operating revenues $ 4,751
$ 5,035
$ (284 ) $ 13,812
$ 13,363
$ 449
Purchased power and fuel expense 2,331
2,589
258
7,286
6,609
(677 )
Revenues net of purchased power and fuel expense^(a)
2,420
2,446
(26 ) 6,526
6,754
(228 )
Other operating expenses
Operating and maintenance 1,374
1,336
(38 ) 4,871
4,333
(538 )
Depreciation and amortization 410
632
222
1,046
1,329
283
Taxes other than income 141
136
(5 ) 425
380
(45 )
Total other operating expenses 1,925
2,104
179
6,342
6,042
(300 )
(Loss) Gain on sales of assets (2 ) —
(2 ) 3
31
(28 )
Bargain purchase gain 7
—
7
233
—
233
Operating income 500

342
158
420

743
(323 )
Other income and (deductions)
Interest expense, net (113 ) (77 ) (36 ) (342 ) (273 ) (69 )
Other, net 209
185
24
648
395
253
Total other income and (deductions) 96
108
(12 ) 306
122
184
Income before income taxes 596
450
146
726
865
(139 )
Income taxes 240
173
(67 ) 209
293
84
Equity in losses of unconsolidated affiliates (8 ) (6 ) (2 ) (26 ) (16 ) (10 )
Net income 348

271

77

491

556

(65 )
Net income attributable to noncontrolling interests 43
35
(8 ) 12
18
6
Net income attributable to membership interest $ 305
$ 236
$ 69
$ 479
$ 538
$ (59 )

~~_________~~

~~(a)~~

Generation evaluates its operating performance using the measure of revenue net of purchased power and fuel expense. Generation believes that revenue net of purchased power and fuel expense is a useful measurement because it provides information that can be used to evaluate its operational performance. Revenue net of purchased power and fuel expense 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.

~~Net Income Attributable to Membership Interest~~

Three Months Ended September 30, ~~2017~~2023 Compared to Three Months Ended September 30, ~~2016.~~ ~~Generation’s~~ 2022. Net income ~~attributable to membership interest for the three months ended September 30, 2017~~ increased ~~compared to the same period in 2016, primarily due to lower Depreciation and amortization expenses, a Bargain purchase gain in 2017, and higher other income, partially offset~~ by lower Revenue net of purchased power and fuel expense, higher Operating and maintenance expenses, and higher interest expense. The decrease in Depreciation and amortization is primarily due to lower accelerated depreciation and amortization as a result of the 2017 decision to early retire the TMI nuclear facility compared to the previous decision in 2016 to early retire Clinton and Quad Cities nuclear facilities. The Bargain purchase gain is primarily due to a measurement period adjustment for the FitzPatrick Acquisition. The increase in other income is primarily due to higher realized NDT fund gains. The decrease in Revenue net of purchased power and fuel expense primarily relates to the impacts of lower load volumes delivered due to mild weather and lower realized energy prices related to Exelon's ratable hedging strategy, partially offset by the impact of the New York CES, the acquisition of the FitzPatrick nuclear facility, a decrease in nuclear outage days, increased capacity prices, and the addition of the two combined-cycle gas turbines in Texas. The increase in Operating and maintenance is primarily due to the impairment of ExGen Texas Power in 2017. The increase in interest expense is primarily due to the impact of project in-service dates on the capitalization of interest and higher outstanding debt.

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~~Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016.~~ Generation’s Net income attributable to membership interest for the nine months ended September 30, 2017 decreased compared to the same period in 2016, primarily due to lower Revenue net of purchased power and fuel expense, higher Operating and maintenance expenses, higher taxes other than income, and higher interest expense, partially offset by lower Depreciation and amortization, a bargain purchase gain in 2017, and higher other income. The decrease in Revenue net of purchased power and fuel expense primarily relates to the conclusion of the Ginna Reliability Support Services Agreement, the impact of declining natural gas prices on Generation's natural gas portfolio, the impacts of lower load volumes due to mild weather and lower realized energy prices related to Exelon's ratable hedging strategy, partially offset by the impact of the New York CES, the acquisition of the FitzPatrick nuclear facility, increased capacity prices, the addition of two combined-cycle gas turbines in Texas, the absence of oil inventory write downs in 2017, and decreased fuel prices. The increase in operating and maintenance expenses primarily relates to the impairment of EGTP assets held for sale compared to the impairment of upstream assets and certain wind projects in 2016, an increase in the number of nuclear outage days in 2017 and increased salaries, wages and contracting costs related to the acquisition of the FitzPatrick nuclear facility. The increase in taxes other than income relates to increased sales and use tax, increased gross receipts tax, and increased property taxes due to the FitzPatrick Acquisition. The increase in interest expense is primarily due to the impact of project in-service dates on the capitalization of interest and higher outstanding debt. The decrease in Depreciation and amortization is primarily due to lower accelerated depreciation and amortization as a result of the 2017 decision to early retire the TMI nuclear facility compared to the previous decision in 2016 to early retire Clinton and Quad Cities nuclear facilities. The bargain purchase gain is the result of the FitzPatrick acquisition in Q1 2017. The increase in other income is primarily due to increased unrealized gains on NDT funds in 2017 compared to 2016.

~~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. Descriptions of each of Generation’s six reportable segments are as follows:

~~New England~~ ~~represents the operations within ISO-NE covering the states of Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont.~~

~~New York~~ ~~represents operations within ISO-NY, which covers the state of New York in its entirety.~~

~~ERCOT~~ ~~represents operations within Electric Reliability Council of Texas, covering most of the state of Texas.~~

~~Other Power Regions~~:

~~West~~ represents operations in the WECC, which includes California ISO, and covers the states of California, Oregon, Washington, Arizona, Nevada, Utah, Idaho, Colorado, and parts of New Mexico, Wyoming and South Dakota.

~~Canada~~ ~~represents operations across the entire country of Canada and includes AESO, OIESO and the Canadian portion of MISO.~~

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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 Generation's overall operating revenues or results of operations. Further, the following activities are not allocated to a region, and are reported in Other: amortization of certain intangible assets relating to commodity contracts recorded at fair value from mergers and acquisitions; accelerated nuclear fuel amortization associated with nuclear decommissioning; and other miscellaneous revenues.

Generation evaluates the operating performance of its electric business activities using the measure of Revenue net of purchased power and fuel expense, which is a non-GAAP measurement. 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 owned generation and fuel costs associated with tolling agreements.

~~For the three and nine months ended September 30, 2017 and 2016, Generation’s Revenue net of purchased power and fuel expense by region were as follows:~~

Three Months Ended
September 30, Variance % Change Nine Months Ended
September 30, Variance % Change
2017 2016 2017 2016
Mid-Atlantic^(a)
$ 855
$ 887
$ (32 ) (3.6 )% $ 2,411
$ 2,556
$ (145 ) (5.7 )%
Midwest^(b)
697
781
(84 ) (10.8 )% 2,140
2,229
(89 ) (4.0 )%
New England 145
160
(15 ) (9.4 )% 403
350
53
15.1 %
New York^(d)
296
194
102
52.6 % 678
592
86
14.5 %
ERCOT 118
93
25
26.9 % 258
231
27
11.7 %
Other Power Regions 68
77
(9 ) (11.7 )% 220
253
(33 ) (13.0 )%
Total electric revenue net of purchased power and fuel expense 2,179
2,192
(13 ) (0.6 )% 6,110
6,211
(101 ) (1.6 )%
Proprietary Trading 4
3
1
33.3 % 11
9
2
22.2 %
Mark-to-market (losses) gains 73
88
(15 ) (17.0 )% (161 ) (113 ) (48 ) 42.5 %
Other^(c)
164
163
1
0.6 % 566
647
(81 ) (12.5 )%
Total revenue net of purchased power and fuel expense $ 2,420
$ 2,446
$ (26 ) (1.1 )% $ 6,526
$ 6,754
$ (228 ) (3.4 )%

~~_________~~


~~(a)~~	Results of transactions with PECO and BGE are included in the Mid-Atlantic region. Results of transactions with Pepco, DPL, and ACE are included in the Mid-Atlantic region beginning on March 24, 2016, the day after the PHI merger was completed.


~~(b)~~	~~Results of transactions with ComEd are included in the Midwest region.~~

~~(c)~~

Other represents activities not allocated to a region. See text above for a description of included activities. Includes amortization of intangible assets related to commodity contracts recorded at fair value of a $19$42 million and $22 million decrease to revenue net of purchased power and fuel expense for the three months ended September 30, 2017 and 2016, respectively, and accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 7 - Early Nuclear Plant Retirements of the Combined Notes to the Consolidated Financial Statements of $6 million and $28 million decrease to revenue net of purchased power and fuel expense for the three months ended September 30, 2017 and 2016, respectively. Also includes amortization of intangible assets related to commodity contracts recorded at fair value of a $41 million and $15 million decrease to revenue net of purchased power and fuel expense for the nine months ended September 30, 2017 and 2016, respectively, and accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 7 - Early Nuclear Plant Retirements of the Combined Notes to the Consolidated Financial Statements of $8 million and $38 million decrease to revenue net of purchased power and fuel expense for the nine months ended September 30, 2017 and 2016, respectively.


~~(d)~~	~~Includes the ownership of the FitzPatrick nuclear facility from March 31, 2017.~~

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~~Generation’s supply sources by region are summarized below:~~

Three Months Ended
September 30, Variance % Change Nine Months Ended
September 30, Variance % Change
Supply source (GWhs) 2017 2016 2017 2016
Nuclear generation
Mid-Atlantic^(a)
16,480
15,604
876
5.6 % 48,271
47,035
1,236
2.6 %
Midwest 24,362
24,262
100
0.4 % 69,422
70,925
(1,503 ) (2.1 )%
New York^(a)(d)
6,905
4,843
2,062
42.6 % 17,623
14,002
3,621
25.9 %
Total Nuclear Generation 47,747
44,709
3,038
6.8 % 135,316

131,962
3,354
2.5 %
Fossil and Renewables

Mid-Atlantic 596
706
(110 ) (15.6 )% 2,330
2,290
40
1.7 %
Midwest 218
273
(55 ) (20.1 )% 1,053
1,046
7
0.7 %
New England 1,919
1,886
33
1.7 % 5,921
5,826
95
1.6 %
New York 1
1
—
— % 3
3
—
— %
ERCOT 5,703
2,472
3,231
130.7 % 9,388
5,726
3,662
64.0 %
Other Power Regions 2,149
2,103
46
2.2 % 5,656
6,245
(589 ) (9.4 )%
Total Fossil and Renewables 10,586
7,441
3,145
42.3 % 24,351

21,136
3,215
15.2 %
Purchased Power

Mid-Atlantic 2,541
7,139
(4,598 ) (64.4 )% 8,840
14,024
(5,184 ) (37.0 )%
Midwest 217
461
(244 ) (52.9 )% 1,018
1,855
(837 ) (45.1 )%
New England 4,513
3,927
586
14.9 % 13,920
11,863
2,057
17.3 %
New York —
—
—
— % 28
—
28
— %
ERCOT 1,199
2,895
(1,696 ) (58.6 )% 5,724
7,448
(1,724 ) (23.1 )%
Other Power Regions 3,982
3,803
179
4.7 % 10,357
10,281
76
0.7 %
Total Purchased Power 12,452
18,225
(5,773 ) (31.7 )% 39,887

45,471
(5,584 ) (12.3 )%
Total Supply/Sales by Region^(b)

Mid-Atlantic^(c)
19,617
23,449
(3,832 ) (16.3 )% 59,441
63,349
(3,908 ) (6.2 )%
Midwest^(c)
24,797
24,996
(199 ) (0.8 )% 71,493
73,826
(2,333 ) (3.2 )%
New England 6,432
5,813
619
10.6 % 19,841
17,689
2,152
12.2 %
New York 6,906
4,844
2,062
42.6 % 17,654
14,005
3,649
26.1 %
ERCOT 6,902
5,367
1,535
28.6 % 15,112
13,174
1,938
14.7 %
Other Power Regions 6,131
5,906
225
3.8 % 16,013
16,526
(513 ) (3.1 )%
Total Supply/Sales by Region 70,785
70,375
410
0.6 % 199,554

198,569
985
0.5 %

~~_________~~


~~(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)~~	Excludes physical proprietary trading volumes of 2,601 GWhs and 1,506 GWhs for the three months ended September 30, 2017 and 2016, respectively, and 6,763 GWhs and 4,015 GWhs for the nine months ended September 30, 2017 and 2016.


~~(c)~~	Includes affiliate sales to PECO and BGE in the Mid-Atlantic region and affiliate sales to ComEd in the Midwest region. As a result of the PHI Merger, includes affiliate sales to Pepco, DPL and ACE in the Mid-Atlantic region beginning on March 24, 2016.


~~(d)~~	~~Includes the ownership of the FitzPatrick nuclear facility from March 31, 2017.~~

~~Mid-Atlantic~~

~~Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016.~~ The $32 million decrease in Revenue net of purchased power and fuel expense in the Mid-Atlantic primarily reflects lower load volumes and lower realized energy prices, partially offset by decreased nuclear outage days and increased capacity prices.

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~~Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016.~~ The $145 million decrease in Revenue net of purchased power and fuel expense in the Mid-Atlantic primarily reflects lower load volumes, lower realized energy prices and decreased capacity prices, partially offset by the absence of oil inventory write-downs in 2017 and decreased nuclear outage days.

~~Midwest~~

~~Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016.~~ The $84 million decrease in Revenue net of purchased power and fuel expense in the Midwest primarily reflects lower realized energy prices, partially offset by increased capacity prices and decreased nuclear fuel prices.

~~Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016.~~ The $89 million decrease in Revenue net of purchased power and fuel expense in the Midwest primarily reflects lower realized energy prices and increased nuclear outage days, partially offset by decreased fuel prices.

~~New England~~

~~Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016.~~ ~~The $15 million decrease in Revenue net of purchased power and fuel expense in New England primarily reflects lower realized energy prices, partially offset by increased capacity prices.~~

~~Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016.~~ ~~The $53 million increase in Revenue net of purchased power and fuel expense in New England was driven by increased capacity prices, partially offset by lower realized energy prices.~~

~~New York~~

~~Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016.~~ The $102 million increase in Revenue net of purchased power and fuel expense in New York was primarily due to the impact of the New York CES and the acquisition of FitzPatrick, partially offset by the conclusion of the Ginna Reliability Support Service Agreement and lower realized energy prices.

~~Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016.~~ The $86 million increase in Revenue net of purchased power and fuel expense in New York was primarily due to impact of the New York CES and the acquisition of FitzPatrick, partially offset by the conclusion of the Ginna Reliability Support Service Agreement and lower realized energy prices.

~~ERCOT~~

~~Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016.~~ ~~The $25 million increase in Revenue net of purchased power and fuel expense in ERCOT was primarily due to the addition of two combined-cycle gas turbines in Texas.~~

~~Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016.~~ The $27 million increase in Revenue net of purchased power and fuel expense in ERCOT was primarily due to the addition of two combined-cycle gas turbines in Texas, partially offset by lower realized energy prices.

~~Other Power Regions~~

~~Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016.~~ ~~The $9 million decrease in Revenue net of purchased power and fuel expense in Other Power Regions was primarily due to lower realized energy prices.~~

~~Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016.~~ ~~The $33 million decrease in Revenue net of purchased power and fuel expense in Other Power Regions was primarily due to lower realized energy prices.~~

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~~Proprietary Trading~~

~~Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016.~~ ~~The $1 million increase in Revenue net of purchased power and fuel expense in Proprietary Trading was primarily due to congestion activity.~~

~~Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016.~~ ~~The $2 million increase in Revenue net of purchased power and fuel expense in Proprietary Trading was primarily due to congestion activity.~~

~~Mark-to-market~~

~~Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016.~~ Mark-to-market gains on economic hedging activities were $73 million for the three months ended September 30, 2017 compared to gains of $88 million for the three months ended September 30, 2016. See Notes 9 — Fair Value of Financial Assets and Liabilities and 10 — Derivative Financial Instruments of the Combined Notes to the Consolidated Financial Statements for information on gains and losses associated with mark-to-market derivatives.

~~Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016.~~ Mark-to-market losses on economic hedging activities were $161 million for the nine months ended September 30, 2017 compared to losses of $113 million for the nine months ended September 30, 2016. See Notes 9 — Fair Value of Financial Assets and Liabilities and 10 — Derivative Financial Instruments of the Combined Notes to the Consolidated Financial Statements for information on gains and losses associated with mark-to-market derivatives.

~~Other~~

~~Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016.~~ The $1 million increase in Revenue net of purchased power and fuel expense in Other was due to the decline in revenues related to the distributed generation business, offset by lower accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 7 - Early Nuclear Plant Retirements of the Combined Notes to the Consolidated Financial Statements.

~~Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016.~~ The $81 million decrease in other revenue net of purchased power and fuel was primarily due to the impacts of declining natural gas prices on Generation’s natural gas portfolio and amortization of energy contracts recorded at fair value associated with prior acquisitions, partially offset by revenue related to the inclusion of Pepco Energy Services results in 2017 and lower accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 7 - Early Nuclear Plant Retirements of the Combined Notes to the Consolidated Financial Statements.

~~Nuclear Fleet Capacity Factor~~

~~The following table presents nuclear fleet operating data for the three and nine months ended September 30, 2017~~ as compared to the same period in 2016, for the Generation-operated plants. 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.

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Nuclear fleet capacity factor^(a)
96.1 % 96.3 % 93.7 % 94.8 %
Refueling outage days^(a)
13
17
233
174
Non-refueling outage days^(a)
15
—
35
31

~~_________~~


~~(a)~~	~~Excludes Salem, which is operated by PSEG Nuclear, LLC. Reflects ownership percentage of stations operated by Exelon. Includes the ownership of the FitzPatrick nuclear facility from March 31, 2017.~~

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~~Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016.~~ ~~The nuclear fleet capacity factor decreased~~2022, primarily due to ~~more non-refueling outage days~~increases in electric distribution formula rate earnings (reflecting higher allowed ROE due to an increase in U.S. Treasury rates and ~~was partially offset by fewer refueling outage days, excluding Salem outages, during~~ the ~~three months ended September 30, 2017 compared~~impacts of higher rate base) and carrying costs related to the ~~same period in 2016.~~CMC regulatory assets.

Nine Months Ended September 30, ~~2017~~2023 Compared to Nine Months Ended September 30, ~~2016.~~ The nuclear fleet capacity factor decreased primarily due to more refueling and non-refueling outage days, excluding Salem outages, during the nine months ended September 30, 2017 compared to the same period in 2016.

~~Operating and Maintenance~~

~~The changes in Operating and maintenance expense for the three and nine months ended September 30, 2017~~2022. Net income increased by $116 million as compared to the same period in ~~2016, consisted of the following:~~

Three Months Ended
September 30, Nine Months Ended
September 30,

Increase (Decrease)^(a)

Increase (Decrease)^(a)
Labor, other benefits, contracting, materials^(b)
$ (8 ) $ 74
Nuclear refueling outage costs, including the co-owned Salem plants^(c)
(12 ) 88
Corporate allocations 19
29
Merger and integration costs^(d)
(4 ) 36
Merger commitments —
(3 )
Plant retirements and divestitures^(e)
41
(15 )
Cost management program 5
(7 )
ARO update (3 ) (4 )
Long-lived asset impairments^(f)
25
288
Pension and non-pension postretirement benefits expense 3
4
Allowance for uncollectible accounts 12
35
Accretion expense^(g)
10
27
Other (50 ) (14 )
Increase in operating and maintenance expense $ 38
$ 538

~~_________~~


~~(a)~~	~~The 2017 financial results include Generation's acquisition of the FitzPatrick nuclear generating station from March 31, 2017.~~


~~(b)~~	~~Reflects increased salaries, wages and contracting costs primarily related to the acquisition of the FitzPatrick nuclear facility beginning on March 31, 2017.~~


~~(c)~~	Primarily reflects a decrease in the number of nuclear outage days for the three months ended September 30, 2017 compared to 2016 and an increase in the number of nuclear outage days for the nine months ended September 30, 2017 compared to the same period in 2016.


~~(d)~~	Reflects certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses and integration activities related to the PHI and FitzPatrick acquisitions.


~~(e)~~	Represents the announcement of the early retirement of Generation's TMI nuclear facility in 2017 compared to the previous decision to early retire Generation's Clinton and Quad Cities nuclear facilities in 2016.


~~(f)~~	~~Primarily reflects charges to earnings related to impairments as a result of the EGTP assets held for sale in 2017 and impairment of Upstream assets and certain wind projects in 2016.~~


~~(g)~~	~~Reflects the impact of increased accretion expenses primarily due to the acquisition of FitzPatrick on March 31, 2017.~~

~~Depreciation and Amortization~~

~~Depreciation and amortization expense for the three and nine months ended September 30, 2017 compared to the three and nine months ended September 30, 2016 decreased~~2022, primarily due to ~~lower accelerated depreciation and amortization as a result of the 2017 decision to early retire the TMI nuclear facility compared to the previous decision~~increases in ~~2016 to early retire the Clinton and Quad Cities nuclear facilities.~~

~~Taxes Other Than Income~~

Taxes other than income taxes, which can vary period to period, include non-income municipal and state utility taxes, real estate taxes and payroll taxes. Taxes other than income for the three and nine months ended September 30, 2017 compared to the three and nine months ended September 30, 2016 increased primarily due to increased property

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~~taxes as a result of the addition of FitzPatrick, increased gross receipts tax expense, and increased sales and use tax expense.~~

~~(Loss) gain on Sales of Assets~~

Loss on sales of assets for the three months ended September 30, 2017 compared to the three months ended September 30, 2016 remained relatively stable. Gain on sales of assets for the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016 decreased primarily due to the gain associated with Generation's sale of the New Boston generating site in 2016.

~~Bargain Purchase Gain~~

Bargain purchase gain for the three and nine months ended September 30, 2017 compared to the three and nine months ended September 30, 2016 increased as a result of the gain associated with the FitzPatrick acquisition. Refer to Note 4 — Mergers, Acquisitions and Dispositions of the Combined Notes to the Consolidated Financial Statements for additional information.

~~Interest Expense, net~~

Interest expense, net for the three and nine months ended September 30, 2017 compared to the three and nine months ended September 30, 2016 increased primarily due to the impact of project in-service dates on the capitalization of interest and higher outstanding debt.

~~Other, Net~~

Other, net for the three and nine months ended September 30, 2017 compared to the three and nine months ended September 30, 2016 increased primarily due to the change in the realized and unrealized gains and losses related to NDT funds of Non-Regulatory Agreement Units as described in the table below. Other, net also reflects $37 million and $39 million for the three months ended September 30, 2017 and 2016, respectively, and $129 million and $84 million for the nine months ended September 30, 2017 and 2016, respectively, related to the contractual elimination of income tax expense (benefit) associated with the NDT funds of the Regulatory Agreement Units. Refer to Note 13 — Nuclear Decommissioning of the Combined Notes to the Consolidated Financial Statements for additional information regarding NDT funds.

The following table provides unrealized and realized gains and losses on the NDT funds of the Non-Regulatory Agreement Units recognized in Other, net for the three and nine months ended September 30, 2017 and 2016:

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Net unrealized gains on decommissioning trust funds $ 111

$ 116
$ 347
$ 216
Net realized gains on sale of decommissioning trust funds 33
12
82
26

~~Equity in Losses of Unconsolidated Affiliates~~

~~Equity in losses of unconsolidated affiliates for the three and nine months ended September 30, 2017 compared to the three and nine ended September 30, 2016 remained relatively stable.~~

~~Effective Income Tax Rate~~

Generation's effective income tax rate was 40.3% and 38.4% for the three months ended September 30, 2017 and 2016, respectively. Generation's effective income tax rate was 28.8% and 33.9% for the nine months ended September 30, 2017 and 2016, respectively. See Note 12 — Income Taxes of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in the effective income tax rate.

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~~Results of Operations — ComEd~~

Three Months Ended
September 30,
Favorable
(Unfavorable)
Variance
Nine Months Ended
September 30,
Favorable
(Unfavorable)
Variance
2017 2016 2017 2016
Operating revenues $ 1,571
$ 1,497
$ 74
$ 4,227
$ 4,031
$ 196
Purchased power expense 529
454
(75 ) 1,241
1,141
(100 )
Revenues net of purchased power expense^(a)(b)
1,042
1,043
(1 ) 2,986
2,890
96
Other operating expenses
Operating and maintenance 346
377
31
1,096
1,113
17
Depreciation and amortization 212
196
(16 ) 631
574
(57 )
Taxes other than income 80
82
2
223
222
(1 )
Total other operating expenses 638
655
17
1,950
1,909
(41 )
Gain on sales of assets —
1
(1 ) —
6
(6 )
Operating income 404
389
15
1,036
987
49
Other income and (deductions)
Interest expense, net (89 ) (197 ) 108
(275 ) (374 ) 99
Other, net 5
(80 ) 85
14
(72 ) 86
Total other income and (deductions) (84 ) (277 ) 193
(261 ) (446 ) 185
Income before income taxes 320
112
208
775
541
234
Income taxes 131
75
(56 ) 328
244
(84 )
Net income $ 189
$ 37
$ 152
$ 447
$ 297
$ 150

~~_________~~

~~(a)~~

ComEd evaluates its operating performance using the measure of Revenue net of purchased power expense. ComEd believes that Revenue net of purchased power expense is a useful measurement because it provides information that can be used to evaluate its operational performance. In general, ComEd only earns margin based on the delivery and transmission of electricity. ComEd has included its discussion of Revenue net of purchased power expense below as a complement to the financial information provided in accordance with GAAP. However, Revenue net of purchased power expense 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.


~~(b)~~	~~For regulatory recovery mechanisms, including ComEd’s~~ electric distribution and transmission formula rates, and riders, revenues increase and decrease i) as fully recoverable costs fluctuate (with no impact on net earnings), and ii) pursuant to changes in rate base, capital structure and ROE (which impact net earnings).

~~Net Income~~

~~Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016.~~ ComEd’s Net income for the three months ended September 30, 2017 was higher than the same period in 2016, primarily due to the recognition of the penalty and the after-tax interest due on the asserted penalty related to the Tax Court's decision on Exelon's like-kind exchange tax position in the third quarter of 2016 and increased electric distribution and transmission formula rate earnings (reflecting higher allowed ROE due to an increase in U.S. Treasury rates and the impacts of ~~increased capital investment~~higher rate base) and higher allowed electric distribution ROE). The higher Net income was partially offset by the impact of weather conditions in the third quarter of 2016. See Revenue Decoupling discussion below for additional information on the impact of weather.

~~Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016.~~ ComEd’s Net income for the nine months ended September 30, 2017 was higher than the same period in 2016, primarily due to the recognition of the penalty and the after-tax interest due on the asserted penaltycarrying costs related to the ~~Tax Court's decision on Exelon's like-kind exchange tax position~~CMC regulatory assets.

The changes in the third quarter of 2016 and increased electric distribution and transmission formula rate earnings (reflecting the impacts of increased capital investment and higher allowed electric distribution ROE). The higher Net income was partially offset by additional tax and interest recorded in the second quarter of 2017 relating to Exelon's like-kind exchange tax position and the impact of weather conditions in the second and third quarters of 2016. See Revenue Decoupling discussion below for additional information on the impact of weather.

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~~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 is permitted to recover electricity, REC, and ZEC procurement costs from retail customers without mark-up. Therefore, these costs have no significant impact on Revenue net of purchased power expense. See Note 3 — Regulatory Matters of the Exelon 2016 Form 10-K for additional information on ComEd’s electricity procurement process.

All ComEd customers have the choice to purchase electricity from a competitive electric generation supplier. Customer choice programs do not impact ComEd’s volume of deliveries, but do affect ComEd’s Operating revenues related to supplied energy, which is fully offset in Purchased power expense. Therefore, customer choice programs have no impact on Revenue net of purchased power expense.

~~Retail deliveries purchased from competitive electric generation suppliers (as a percentage of kWh sales) for the three and nine months ended September 30, 2017 and 2016,~~ consisted of the following:


	Three Months Ended September 30, 2023		Nine Months Ended September 30, 2023
	Increase		Increase (Decrease)
Distribution	$	103	$	277
Transmission	3		(4)
Energy efficiency	17		55
Other	8		11
	131		339
Regulatory required programs	759		961
Total increase	$	890	$	1,300

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Electric 68 % 70 % 70 % 72 %

~~Retail customers purchasing electric generation from competitive electric generation suppliers at September 30, 2017 and 2016 consisted of the following:~~

September 30, 2017 September 30, 2016
Number of customers % of total retail customers Number of customers % of total retail customers
Electric 1,360,800
34 % 1,526,900
39 %

~~The changes in ComEd’s Revenue net of purchased power expense for the three and nine months ended September 30, 2017, compared to the same period in 2016 consisted of the following:~~

Three Months Ended
September 30, 2017 Nine Months Ended
September 30, 2017
Increase (Decrease) Increase (Decrease)
Weather^(a)
$ (34 ) $ (37 )
Volume^(a)
(5 ) (11 )
Electric distribution revenue 59
119
Transmission revenue 11
45
Energy efficiency revenue^(b)
5
6
Regulatory required programs^(b)
(39 ) (24 )
Uncollectible accounts recovery, net (3 ) (5 )
Pricing and customer mix^(a)
—
(1 )
Other 5
4
Total increase (decrease) $ (1 ) $ 96

~~_________~~

~~(a)~~

These changes only reflect the 2016 impacts of weather, volume, and pricing and customer mix. As further described below, pursuant to the revenue decoupling provision in FEJA, ComEd began recording an adjustment to revenue in the first quarter of 2017 to eliminate the favorable or unfavorable impacts associated with variations in delivery volumes associated with above or below normal weather, number of customers or usage per customer.


~~(b)~~	Beginning on June 1, 2017, ComEd is deferring energy efficiency costs as a regulatory asset that will be recovered through the energy efficiency formula rate over the weighted average useful life of the related energy efficiency measures.

Revenue Decoupling.The demand for electricity is affected by weather ~~conditions. Very warm weather in summer months~~ and ~~very cold weather in other months are referred to as "favorable weather conditions" because these weather conditions result in increased~~ customer usage. ~~Conversely, mild weather reduces demand.~~

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Under EIMA, ComEd's electric distribution formula rate provided for an adjustment to future billings if its earned ROE fell outside a 50 bps collar of its allowed ROE, which partially eliminated the impacts of weather and load on ComEd's revenue. As allowed under FEJA, ComEd will revise its electric distribution formula rate to eliminate the ROE collar beginning with the reconciliation filed in 2018 for the 2017 calendar year. Elimination of the ROE collar effectively offsets the favorable or unfavorable impacts to Operating revenues ~~associated with variations in delivery volumes associated with above~~are not impacted by abnormal weather, usage per customer, or ~~below normal weather, numbers~~number of customers ~~or usage per customer. ComEd began recognizing the impacts~~as a result of ~~this change beginning in the first quarter of 2017. During the three~~revenue decoupling mechanisms implemented pursuant to FEJA.

Distribution Revenue. EIMA and nine months ended September 30, 2017, ComEd recorded a decrease to Electric distribution revenues of approximately $15 million and an increase to Electric distribution revenues of approximately $21 million, respectively, to eliminate weather and load impacts.

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 ComEd's service territory with cooling degree days generally having a more significant impact to ComEd, particularly during the summer months. The changes in heating and cooling degree days in ComEd’s service territory for the three and nine months ended September 30, 2017 and 2016, consisted of the following:

Heating and Cooling Degree-Days % Change
Three Months Ended September 30, 2017 2016 Normal 2017 vs. 2016 2017 vs. Normal
Heating Degree-Days 42
23
97
82.6 % (56.7 )%
Cooling Degree-Days 699
840
641
(16.8 )% 9.0 %

Nine Months Ended September 30,
Heating Degree-Days 3,269
3,678
3,972
(11.1 )% (17.7 )%
Cooling Degree-Days 962
1,130
882
(14.9 )% 9.1 %

~~Electric Distribution Revenue.~~ ~~EIMA provides~~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. ~~Under EIMA, electric~~Electric distribution revenue varies from year to year based upon fluctuations

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ComEd

in the underlying costs, (e.g., severe weather and storm restoration), investments being recovered, and allowed ROE. ComEd’s allowed ROE is the annual average rate on 30-year treasury notes plus 580 basis points. In addition, ComEd's allowed ROE is subject to reduction if ComEd does not deliver the reliability and customer service benefits to which it has committed over the ten-year life of the investment program. Electric distribution revenue increased ~~during~~for the three and nine months ended September 30, ~~2017, primarily~~2023 as compared to the same period in 2022, due to ~~increased capital investment, increased Depreciation expense, and~~ higher allowed ROE due to an increase in ~~treasury~~U.S. Treasury rates, ~~as compared to~~ the ~~same period in 2016~~impact of a higher rate base, and due to revenue decoupling impacts (as described above) during the nine months ended September 30, 2017. See Depreciation and amortization expense discussions below, and Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.higher fully recoverable costs.

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. For the three and nine months ended September 30, 2017, ComEd recorded increased transmission revenue due to increased capital investment, higher Depreciation expense and increased highest daily peak load as compared to the same period in 2016. See Operating and maintenance expense below and Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Energy Efficiency Revenue. ~~Beginning June 1, 2017,~~ 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. ~~ComEd’s allowed ROE~~Energy efficiency revenue increased for the three and nine months ended September 30, 2023 as compared to the same period in 2022, primarily due to increased regulatory asset amortization, which is fully recoverable.

Other Revenue primarily includes assistance provided to other utilities through mutual assistance programs. Other revenue increased for the ~~annual average rate on 30-year treasury notes plus 580 basis points. Beginning January 1, 2018, ComEd’s allowed ROE is subject~~three and nine months ended September 30, 2023 as compared 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~~the same period in 2022, which primarily reflects mutual assistance revenues associated with storm restoration efforts.

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~~savings goal.~~Regulatory Required Programs represents revenues collected under approved riders to recover costs incurred for regulatory programs such as recoveries under the credit loss expense tariff, environmental costs associated with MGP sites, ETAC, and costs related to electricity, ZEC, CMC, and REC procurement. See ~~Depreciation and amortization expense discussions below, and~~ Note 53 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional ~~information.~~

~~Regulatory Required Programs.~~ ~~This represents the change~~information regarding CMCs. ETAC is a retail customer surcharge collected by electric utilities operating in ~~Operating revenues collected under approved rate riders~~Illinois established by CEJA and remitted to ~~recover costs incurred~~an Illinois state agency for ~~regulatory~~ programs ~~such as ComEd’s purchased power administrative costs~~to support clean energy jobs and ~~energy efficiency and demand response through June 1, 2017 pursuant to FEJA.~~training. The riders are designed to provide full and current cost recovery. ~~An equal and offsetting amount has been~~The costs of these programs are included in ~~Operating and maintenance expense. See~~Purchased power expense, Operating and maintenance expense, ~~discussion below~~Depreciation and amortization expense and Taxes other than income. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries as ComEd remains the distribution service provider for ~~additional information on included programs.~~

~~Uncollectible Accounts Recovery, Net.~~ ~~Uncollectible accounts recovery, net represents recoveries under ComEd’s uncollectible accounts tariff. See~~all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, ComEd either acts as the billing agent or the competitive supplier separately bills its own customers, and ~~maintenance~~therefore does not record Operating revenues or Purchased power expense ~~discussion below for additional information on this tariff.~~

~~Other.~~ ~~Other revenue, which can vary period to period, includes rental revenue, revenue~~ related to ~~late payment charges, assistance provided~~the electricity. For customers that choose to ~~other utilities through mutual assistance programs, recoveries~~purchase electric generation from ComEd, ComEd is permitted to recover the electricity, ZEC, CMC, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power expense related to the electricity, ZECs, CMCs, and RECs.

See Note 5 — Segment Information of ~~environmental costs associated with MGP sites, and recoveries~~the Combined Notes to Consolidated Financial Statements for the presentation of ~~energy procurement costs.~~ComEd's revenue disaggregation.

~~Operating and Maintenance Expense~~

Three Months Ended
September 30,
Increase
(Decrease)
Nine Months Ended
September 30, Increase (Decrease)
2017 2016 2017 2016
Operating and maintenance expense — baseline $ 344
$ 336
$ 8
$ 1,000
$ 993
$ 7
Operating and maintenance expense — regulatory required programs^(a)
2
41
$ (39 ) 96
120
(24 )
Total operating and maintenance expense $ 346

$ 377

$ (31 )
$ 1,096

$ 1,113

$ (17 )

~~_________~~


~~(a)~~	Operating and maintenance expense for regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues.

The increase ~~in Operating~~of $775 million and ~~maintenance expense~~$1,027 million for the three and nine months ended September 30, ~~2017~~2023 compared to the same period in ~~2016,~~2022, in Purchased power expense is primarily due to the CMCs from the participating nuclear-powered generating facilities including the deferral of any associated carrying costs. This increase is primarily offset by an increase in Operating revenues as part of regulatory required programs. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding CMCs.

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


	Three Months Ended September 30, 2023		Nine Months Ended September 30, 2023
	Increase (Decrease)		Increase (Decrease)

Labor, other benefits, contracting and materials	$	10	$	36
Storm-related costs	(4)		4
BSC costs	23		28

Pension and non-pension postretirement benefits expense	(3)		(11)

Other	27		25
	53		82
Regulatory required programs(a)	(23)		(50)
Total increase	$	30	$	32

Three Months Ended
September 30, 2017 Nine Months Ended
September 30, 2017
Increase (Decrease) Increase (Decrease)
Baseline
Labor, other benefits, contracting and materials $ (5 ) $ (11 )
Pension and non-pension postretirement benefits expense 1
2
Storm-related costs 1
1
Uncollectible accounts expense — provision^(a)
(4 ) (8 )
Uncollectible accounts expense — recovery, net^(a)
1
3
BSC costs^(b)
21
35
Other (7 ) (15 )
8
7
Regulatory required programs
Energy efficiency and demand response programs^(c)
(39 ) (24 )
Decrease in operating and maintenance expense $ (31 ) $ (17 )
__________

~~_________~~

~~(a)~~

ComEd is allowed to recover from or refund to customers the difference between the utility’s annual uncollectible accounts expense and the amounts collected in rates annually through a rider mechanism. During the three and nine months ended September 30, 2017, ComEd recorded a net decrease in Operating and maintenance expense related to uncollectible accounts due to the timing of regulatory cost recovery. An equal and offsetting decrease has been recognized in Operating revenues for the period presented.


~~(b)~~	For the three and nine months ended September 30, 2017, includes the $8 million write-off of a regulatory asset related to Constellation merger and integration costs for which recovery is no longer expected.


~~(c)~~	Beginning on June 1, 2017, ComEd is deferring energy efficiency costs as a regulatory asset that will be recovered through the energy efficiency formula rate over the weighted average useful life of the related energy efficiency measures.

(a)ComEd is allowed to recover from or refund to customers the difference between its annual credit loss expense and the amounts collected in rates annually through a rider mechanism.

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~~Depreciation and Amortization Expense~~

The ~~increase~~changes in Depreciation and amortization expense ~~during the three and nine months ended September 30, 2017, compared to the same period in 2016,~~ consisted of the following:


	Three Months Ended September 30, 2023		Nine Months Ended September 30, 2023
	Increase		Increase
Depreciation and amortization(a)	$	16	$	45
Regulatory asset amortization(b)	8		18

Total increase	$	24	$	63

Three Months Ended
September 30, 2017 Nine Months Ended
September 30, 2017
Increase (Decrease) Increase (Decrease)
Depreciation expense^(a)
$ 14
$ 47
Regulatory asset amortization^(b)
1
2
Other 1
8
Total increase $ 16
$ 57
__________

~~_________~~


~~(a)~~	~~Primarily reflects ongoing capital expenditures for the three and nine months ended September 30, 2017.~~


~~(b)~~	~~Beginning in June 2017, includes amortization of ComEd's energy efficiency formula rate regulatory asset.~~

~~Taxes Other Than Income~~(a)Reflects ongoing capital expenditures and higher depreciation rates effective January 2023.

~~Taxes other than income, which can vary year to year, include municipal~~(b)Includes amortization of ComEd's energy efficiency formula rate regulatory asset.

Interest expense, net increased by $15 million and ~~state utility taxes, real estate taxes and payroll taxes. Taxes other than income taxes remained relatively consistent~~$49 million for the three and nine months ended September 30, ~~2017,~~2023, compared to the same period in ~~2016.~~

~~Gain on Sales of Assets~~

~~The decrease in Gain on sales of assets during the nine months ended September 30, 2017, compared to the same period in 2016, is~~2022, primarily due to ~~the sale of land during March 2016.~~

~~Interest Expense, Net~~

~~The changes~~an increase in interest ~~expense, net, for~~rates and the ~~three and nine months ended September 30, 2017, compared to the same period in 2016, consisted~~issuance of ~~the following:~~

Three Months Ended
September 30, 2017 Nine Months Ended
September 30, 2017
Increase (Decrease) Increase (Decrease)
Interest expense related to uncertain tax positions^(a)
$ (110 ) $ (103 )
Interest expense on debt (including financing trusts) (1 ) 3
Other 3
1
Decrease in interest expense, net $ (108 ) $ (99 )

~~_________~~


~~(a)~~	Primarily reflects the recognition of the after-tax interest due on the asserted penalty related to the Tax Court's decision on Exelon's like-kind exchange tax position in the third quarter of 2016, partially offset by additional interest recorded in the second quarter of 2017 related to Exelon's like-kind exchange tax position.

~~Other, Net~~

~~Other, net, decreased~~debt during the three and nine months ended September 30, 2017, compared to the same period in 2016 primarily due to the recognition of the penalty related to the Tax Court's decision on Exelon's like-kind exchange tax position in the third quarter of 2016.year.

Effective ~~Income Tax Rate~~

~~ComEd's effective~~ income tax ~~rate was 40.9%~~rates were 22.0% and ~~67.0%~~22.4% for the three months ended September 30, ~~2017~~2023 and ~~2016, respectively. ComEd's effective income tax rate was 42.3%~~2022, respectively, and ~~45.1%~~22.2% and 22.3% for the nine months ended September 30, ~~2017~~2023 and ~~2016,~~2022, respectively. The decreases in the effective income tax rates for the three and nine months ended September 30, 2017 as compared to the same period in 2016 are primarily due to a non-deductible penalty incurred in 2016. See Note 127 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

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PECO

~~ComEd Electric Operating Statistics and Revenue Detail~~

Three Months Ended
September 30, % Change
Weather-
Normal
% Change
Nine Months Ended
September 30, % Change
Weather-
Normal
% Change
Retail Deliveries to Customers (in GWhs) 2017 2016 2017 2016
Retail Deliveries^(a)

Residential 8,004
9,014
(11.2 )% (0.6 )% 20,164
21,738
(7.2 )% (1.3 )%
Small commercial & industrial 8,488
8,833
(3.9 )% (1.0 )% 23,634
24,447
(3.3 )% (1.6 )%
Large commercial & industrial 7,232
7,565
(4.4 )% (2.5 )% 20,712
21,057
(1.6 )% (0.5 )%
Public authorities & electric railroads 302
308
(1.9 )% (1.7 )% 928
947
(2.0 )% (1.4 )%
Total retail deliveries 24,026

25,720
(6.6 )% (1.3 )% 65,438

68,189
(4.0 )% (1.1 )%

As of September 30,
Number of Electric Customers 2017 2016
Residential 3,610,091
3,578,846
Small commercial & industrial 376,309
372,603
Large commercial & industrial 1,954
2,010
Public authorities & electric railroads 4,763
4,738
Total 3,993,117

3,958,197

Three Months Ended
September 30, Nine Months Ended
September 30,
Electric Revenue 2017 2016
%
Change
2017 2016
%
Change
Retail Sales^(a)

Residential $ 825
$ 786
5.0 % $ 2,108
$ 2,018
4.5 %
Small commercial & industrial 369
356
3.7 % 1,051
1,007
4.4 %
Large commercial & industrial 121
126
(4.0 )% 352
350
0.6 %
Public authorities & electric railroads 11
10
10.0 % 34
33
3.0 %
Total retail 1,326
1,278
3.8 % 3,545
3,408
4.0 %
Other revenue^(b)
245
219
11.9 % 682
623
9.5 %
Total electric revenue^(c)
$ 1,571
$ 1,497
4.9 % $ 4,227
$ 4,031
4.9 %

~~_________~~


~~(a)~~	Reflects delivery revenue and volume from customers purchasing electricity directly from ComEd and customers purchasing electricity from a competitive electric generation supplier, as all customers are assessed delivery charges. For customers purchasing electricity from ComEd, revenue also reflects the cost of energy and transmission.


~~(b)~~	Other revenue primarily includes transmission revenue from PJM. Other revenue also includes rental revenue, revenue related to late payment charges, revenue from other utilities for mutual assistance programs and recoveries of remediation costs associated with MGP sites.


~~(c)~~	Includes operating revenues from affiliates totaling $3 million and $4 million for the three and nine months ended September 30, 2017 and 2016, and $12 million and $12 million for the nine months ended September 30, 2017 and 2016, respectively.

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Results of Operations — PECO


	Three Months Ended September 30,				Favorable (Unfavorable) Variance		Nine Months Ended September 30,				Favorable (Unfavorable) Variance
	2023		2022				2023		2022
Operating revenues	$	1,037	$	1,014	$	23	$	2,977	$	2,877	$	100
Operating expenses
Purchased power and fuel	411		403		(8)		1,197		1,093		(104)
Operating and maintenance	277		243		(34)		786		705		(81)
Depreciation and amortization	100		92		(8)		297		277		(20)
Taxes other than income taxes	59		60		1		156		155		(1)
Total operating expenses	847		798		(49)		2,436		2,230		(206)

Operating income	190		216		(26)		541		647		(106)
Other income and (deductions)
Interest expense, net	(52)		(45)		(7)		(149)		(129)		(20)
Other, net	11		8		3		26		23		3
Total other income and (deductions)	(41)		(37)		(4)		(123)		(106)		(17)
Income before income taxes	149		179		(30)		418		541		(123)
Income taxes	3		44		41		8		67		59


Net income	$	146	$	135	$	11	$	410	$	474	$	(64)

Three Months Ended
September 30,
Favorable
(Unfavorable)
Variance
Nine Months Ended
September 30, Favorable
(Unfavorable)
Variance
2017 2016 2017 2016
Operating revenues $ 715
$ 788
$ (73 ) $ 2,141
$ 2,293
$ (152 )
Purchased power and fuel expense 235
272
37
719
809
90
Revenues net of purchased power and fuel expense^(a)
480
516
(36 ) 1,422
1,484
(62 )
Other operating expenses
Operating and maintenance 197
199
2
595
604
9
Depreciation and amortization 72
67
(5 ) 213
201
(12 )
Taxes other than income 42
46
4
116
126
10
Total other operating expenses 311
312
1
924
931
7
Operating income 169
204
(35 ) 498
553
(55 )
Other income and (deductions)
Interest expense, net (31 ) (30 ) (1 ) (93 ) (92 ) (1 )
Other, net 2
2
—
6
6
—
Total other income and (deductions) (29 ) (28 ) (1 ) (87 ) (86 ) (1 )
Income before income taxes 140
176
(36 ) 411
467
(56 )
Income taxes 28
54
26
84
121
37
Net income $ 112
$ 122
$ (10 ) $ 327
$ 346
$ (19 )

~~_________~~

~~(a)~~

PECO evaluates its operating performance using the measures of revenue net of purchased power expense for electric sales and revenue net of fuel expense for gas sales. PECO believes revenue net of purchased power expense and revenue net of fuel expense are useful measurements of its performance because they provide information that can be used to evaluate its net revenue from operations. PECO has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, revenue net of purchased power expense and revenue net of fuel expense figures are not presentations defined under GAAP and may not be comparable to other companies’ presentations or more useful than the GAAP information provided elsewhere in this report.

~~Net Income~~

Three Months Ended September 30, ~~2017~~2023 Compared to Three Months Ended September 30, ~~2016.~~ ~~PECO's~~ 2022. Net income ~~decreased from the same period in 2016, primarily due to lower Revenues net of purchased power and fuel from unfavorable weather conditions in PECO's service territory.~~

~~Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016.~~ ~~PECO's Net income decreased from the same period in 2016, primarily due to lower Revenues net of purchased power and fuel from unfavorable weather conditions in PECO's service territory.~~

~~Revenues Net of Purchased Power and Fuel Expense~~

~~Electric and natural gas revenue and purchased power and fuel expense are affected~~increased by fluctuations in commodity procurement costs. PECO's electric supply and natural gas cost rates charged to customers are subject to adjustments at least quarterly that are designed to recover or refund the difference between the actual cost of electric supply and natural gas and the amount included in rates in accordance with the PAPUC's GSA and PGC, respectively. Therefore, fluctuations in electric supply and natural gas procurement costs have no impact on electric and natural gas revenue net of purchased power and fuel expense.

Electric and natural gas revenue and purchased power and fuel expense are also affected by fluctuations in participation in the Customer Choice Program. All PECO customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers, respectively. The customers' choice of suppliers does not impact the volume of deliveries, but affects revenue collected from customers related to supplied energy and natural gas service. Customer choice program activity has no impact on electric and natural gas revenue net of purchased power and fuel expense.

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Retail deliveries purchased from competitive electric generation and natural gas suppliers (as a percentage of kWh and mmcf sales, respectively) for the three and nine months ended September 30, 2017 and 2016, consisted of the following:

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Electric 70 % 69 % 71 % 70 %
Natural Gas 29 % 31 % 26 % 26 %

~~Retail customers purchasing electric generation and natural gas from competitive electric generation and natural gas suppliers at September 30, 2017 and 2016 consisted of the following:~~

September 30, 2017 September 30, 2016
Number of customers % of total retail customers Number of customers % of total retail customers
Electric 570,500
35 % 581,600
36 %
Natural Gas 82,600
16 % 81,300
16 %

~~The changes in PECO’s Operating revenues net of purchased power and fuel expense for the three and nine months ended September 30, 2017~~$11 million as compared to the same period in ~~2016~~2022, primarily due to Pennsylvania corporate income tax legislation passed in July 2022 driving a one-time non-cash decrease to net income for 2022, partially offset by an increase in operating expense as a result of higher storm costs.

Nine Months Ended September 30, 2023 Compared to Nine Months Ended September 30, 2022. Net income decreased by $64 million as compared to the same period in 2022, primarily due to increases in operating expenses as a result of higher storm costs, depreciation and amortization expense, and interest expense.

The changes in Operating revenues consisted of the following:


	Three Months Ended September 30, 2023						Nine Months Ended September 30, 2023
	(Decrease) Increase						(Decrease) Increase
	Electric		Gas		Total		Electric		Gas		Total
Weather	$	(38)	$	—	$	(38)	$	(96)	$	(27)	$	(123)
Volume	15		—		15		5		—		5
Pricing	2		6		8		20		35		55
Transmission	23		—		23		24		—		24
Other	(3)		—		(3)		(4)		6		2
	(1)		6		5		(51)		14		(37)
Regulatory required programs	28		(10)		18		145		(8)		137
Total increase	$	27	$	(4)	$	23	$	94	$	6	$	100

Three Months Ended
September 30, 2017 Nine Months Ended
September 30, 2017
Increase (Decrease) Increase (Decrease)
Electric Natural Gas Total Electric Natural Gas Total
Weather $ (48 ) $ —
$ (48 ) $ (45 ) $ (3 ) $ (48 )
Volume —
1
1
(12 ) 4
(8 )
Pricing 9
—
9
13
—
13
Regulatory required programs (6 ) —
(6 ) (29 ) —
(29 )
Other 7
1
8
10
—
10
Total decrease $ (38 ) $ 2
$ (36 ) $ (63 ) $ 1
$ (62 )

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. During the three and nine months ended September 30, ~~2017~~2023 compared to the same period in ~~2016,~~2022, Operating ~~revenue net~~revenues related to weather decreased by the impact of ~~purchased power decreased due to unfavorable summer weather conditions. Operating revenue net of fuel expense was relatively consistent.~~ ~~During the nine months ended September 30, 2017 compared to the same period in 2016, Operating revenue net of purchased power and fuel expense decreased due to~~ unfavorable weather ~~conditions.~~

conditions in PECO's service territory.

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PECO

Heating and cooling ~~degree days~~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~~degree-days for a 30-year period in PECO's service territory. The changes in heating and cooling ~~degree days~~degree-days in PECO’s service territory for the three and nine months ended September 30, ~~2017~~2023 compared to the same ~~periods~~period in ~~2016~~2022 and normal weather consisted of the following:


	Three Months Ended September 30,			% Change
PECO Service Territory	2023	2022	Normal	2023 vs. 2022		2023 vs. Normal
Heating Degree-Days	18	19	22	(5.3)	%	(18.2)	%
Cooling Degree-Days	1,064	1,290	1,022	(17.5)	%	4.1	%
	Nine Months Ended September 30,			% Change
	2023	2022	Normal	2023 vs. 2022		2023 vs. Normal
Heating Degree-Days	2,236	2,632	2,866	(15.0)	%	(22.0)	%
Cooling Degree-Days	1,297	1,725	1,408	(24.8)	%	(7.9)	%

Heating and Cooling Degree-Days Normal % Change
Three Months Ended September 30, 2017 2016 2017 vs. 2016 2017 vs. Normal
Heating Degree-Days 14
10
35
40.0 % (60.0 )%
Cooling Degree-Days 989
1,288
923
(23.2 )% 7.2 %

Nine Months Ended September 30,
Heating Degree-Days 2,437
2,616
2,974
(6.8 )% (18.1 )%
Cooling Degree-Days 1,404
1,684
1,271
(16.6 )% 10.5 %

Volume. Operating revenue net of purchased power and fuel related to delivery volume, exclusive of the effects of weather, remained relatively consistent for the three months ended September 30, 2017 compared to the same period in 2016. The decrease in Operating revenue net of purchased power related to deliveryElectric volume, exclusive of the effects of weather, for the three and nine months ended September 30, ~~2017~~2023 compared to the same period in 2016, primarily reflects the impacts of energy efficiency initiatives on customer usage partially offset by moderate economic and customer growth, as well as a shift in the volume profile across classes from residential and small commercial and industrial to large commercial and industrial. Operating revenue net of fuel expense for the nine months ended September 30, 2017 compared to the same period in 20162022, increased due to ~~strong~~ customer ~~growth~~mix and ~~moderate economic~~load growth.

~~Pricing.~~ ~~Operating revenues net of purchased power as a result of pricing~~ Natural gas volume for the three and nine months ended September 30, ~~2017~~2023 compared to the same period in ~~2016 increased primarily due to higher overall effective rates due to decreased usage across~~2022, remained relatively consistent.


Electric Retail Deliveries to Customers (in GWhs)	Three Months Ended September 30,		% Change		Weather - Normal % Change(b)		Nine Months Ended September 30,		% Change		Weather - Normal % Change(b)
	2023	2022					2023	2022
Residential	4,134	4,386	(5.7)	%	4.9	%	10,186	11,204	(9.1)	%	0.7	%
Small commercial & industrial	2,070	2,139	(3.2)	%	0.8	%	5,616	5,889	(4.6)	%	—	%
Large commercial & industrial	3,830	3,943	(2.9)	%	(0.4)	%	10,398	10,691	(2.7)	%	(0.3)	%
Public authorities & electric railroads	152	172	(11.6)	%	(10.8)	%	464	489	(5.1)	%	(5.0)	%
Total electric retail deliveries(a)	10,186	10,640	(4.3)	%	1.7	%	26,664	28,273	(5.7)	%	0.1	%


	At September 30,
Number of Electric Customers	2023	2022
Residential	1,531,168	1,523,269
Small commercial & industrial	155,932	155,516
Large commercial & industrial	3,111	3,120
Public authorities & electric railroads	10,416	10,393
Total	1,700,627	1,692,298

__________

(a)Reflects delivery volumes 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 ~~major customer classes. Operating revenues net~~change in delivery volumes assuming normalized weather based on the historical 30-year average.


Natural Gas Deliveries to Customers (in mmcf)	Three Months Ended September 30,		% Change		Weather - Normal % Change(b)		Nine Months Ended September 30,		% Change		Weather - Normal % Change(b)
	2023	2022					2023	2022
Residential	2,134	2,197	(2.9)	%	(5.4)	%	23,697	28,240	(16.1)	%	(3.9)	%
Small commercial & industrial	1,939	2,054	(5.6)	%	(8.1)	%	14,381	16,238	(11.4)	%	(1.8)	%
Large commercial & industrial	4	6	(33.3)	%	(7.1)	%	39	20	95.0	%	3.6	%
Transportation	5,278	5,162	2.2	%	8.3	%	17,482	18,508	(5.5)	%	(2.3)	%
Total natural gas retail deliveries(a)	9,355	9,419	(0.7)	%	1.1	%	55,599	63,006	(11.8)	%	(2.9)	%

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PECO


	At September 30,
Number of Natural Gas Customers	2023	2022
Residential	505,370	500,934
Small commercial & industrial	44,743	46,074
Large commercial & industrial	9	9
Transportation	629	656
Total	550,751	547,673

__________

(a)Reflects delivery volumes from customers purchasing natural gas directly from PECO 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.

Pricing for the three and nine months ended September 30, ~~2017~~2023 compared to the same period in ~~2016~~2022 increased primarily due to an increase in gas distribution rates charged to customers.

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.

Other revenue primarily includes revenue related to late payment charges. Other revenue for the three and nine months ended September 30, 2023 compared to the same period in 2022 remained relatively consistent.

Regulatory Required ~~Programs.~~ ~~This~~ Programs represents ~~the change in Operating revenue~~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 Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Income taxes. ~~Refer to the Operating and maintenance expense discussion below for additional information on included programs.~~

~~Other.~~ Other revenue, which can vary period to period, primarily includes wholesale transmission revenue, rental revenue, revenue related to late payment charges and assistance provided to other utilities through mutual assistance programs.

~~Operating and Maintenance Expense~~

Three Months Ended
September 30,
Increase
(Decrease)
Nine Months Ended
September 30, Increase
(Decrease)
2017 2016 2017 2016
Operating and maintenance expense — baseline $ 183
$ 185
$ (2 ) $ 552
$ 545
$ 7
Operating and maintenance expense — regulatory required programs^(a)
14
14
—
43
59
(16 )
Total operating and maintenance expense $ 197
$ 199
$ (2 ) $ 595
$ 604
$ (9 )

~~_________~~


~~(a)~~	Operating and maintenance expenses for regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues.

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~~The changes in Operating and maintenance expense for the three and nine months ended September 30, 2017 compared to the same period in 2016, consisted of the following:~~

Three Months Ended
September 30, 2017 Nine Months Ended
September 30, 2017
Increase (Decrease) Increase (Decrease)
Baseline
Labor, other benefits, contracting and materials $ 7
$ 14
Storm-related costs (3 ) (7 )
Pension and non-pension postretirement benefits expense (1 ) (2 )
PHI merger and integration costs 1
1
BSC costs 5
6
Uncollectible accounts expense (6 ) (6 )
Other (5 ) 1
(2 ) 7
Regulatory Required Programs
Energy efficiency 1
(15 )
Other (1 ) (1 )
—
(16 )
Total decrease $ (2 ) $ (9 )

~~Depreciation and Amortization Expense~~

~~The changes in Depreciation and amortization expense for the three and nine months ended September 30, 2017 compared to the same period in 2016, consisted of the following:~~

Three Months Ended
September 30, 2017 Nine Months Ended
September 30, 2017
Increase (Decrease) Increase (Decrease)
Depreciation and amortization expense $ 5
$ 13
Regulatory asset amortization —
(1 )
Total increase $ 5
$ 12

~~Taxes Other Than Income~~

Taxes other than income, which can vary period to period, include municipal and state utility taxes, real estate taxes and payroll taxes. Taxes other than income decreased for the three and nine months ended September 30, 2017 compared to the same period in 2016 due to a decrease in gross receipts tax driven by a decrease in electric revenue.

~~Interest Expense, Net~~

~~Interest expense, net for the three and nine months ended September 30, 2017 remained consistent compared to the same period in 2016.~~

~~Other, Net~~

~~Other, net for the three and nine months ended September 30, 2017 remained consistent compared to the same period in 2016.~~

~~Effective Income Tax Rate~~

PECO's effective income tax rate was 20.0% and 30.7% for the three months ended September 30, 2017 and 2016, respectively, and 20.4% and 25.9% for the nine months ended September 30, 2017 and 2016, respectively. See

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~~Table of Contents~~

~~Note 12 — Income Taxes of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in effective income tax rate.~~

~~PECO Electric Operating Statistics and Revenue Detail~~

Three Months Ended
September 30, % Change
Weather -
Normal
% Change
Nine Months Ended
September 30, % Change Weather -
Normal
% Change
Retail Deliveries to Customers (in GWhs) 2017 2016 2017 2016
Retail Deliveries^(a)

Residential 3,752
4,358
(13.9 )% 0.2 % 9,939
10,682
(7.0 )% (1.4 )%
Small commercial & industrial 2,158
2,324
(7.1 )% (1.0 )% 6,048
6,236
(3.0 )% (1.1 )%
Large commercial & industrial 4,137
4,234
(2.3 )% 1.4 % 11,593
11,598
— % 0.8 %
Public authorities & electric railroads 198
240
(17.5 )% (17.5 )% 618
672
(8.0 )% (8.0 )%
Total retail deliveries 10,245

11,156
(8.2 )% — % 28,198

29,188
(3.4 )% (0.6 )%

As of September 30,
Number of Electric Customers 2017 2016
Residential 1,463,906
1,451,533
Small commercial & industrial 150,964
149,646
Large commercial & industrial 3,112
3,094
Public authorities & electric railroads 9,665
9,820
Total 1,627,647
1,614,093

Three Months Ended
September 30, % Change Nine Months Ended
September 30, % Change
Electric Revenue 2017 2016 2017 2016
Retail Sales^(a)

Residential $ 434
$ 513
(15.4 )% $ 1,147
$ 1,278
(10.3 )%
Small commercial & industrial 106
109
(2.8 )% 303
334
(9.3 )%
Large commercial & industrial 59
59
— % 168
182
(7.7 )%
Public authorities & electric railroads 7
8
(12.5 )% 23
25
(8.0 )%
Total retail 606
689
(12.0 )% 1,641
1,819
(9.8 )%
Other revenue^(b)
56
51
9.8 % 161
152
5.9 %
Total electric revenue^(c)
$ 662
$ 740
(10.5 )% $ 1,802
$ 1,971
(8.6 )%

~~_________~~


~~(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. For customers purchasing electricity from PECO, revenue also reflects the cost of energy and transmission.


~~(b)~~	~~Other revenue primarily includes transmission revenue from PJM and wholesale electric revenue, in addition to rental income.~~


~~(c)~~	Includes operating revenues from affiliates totaling $1 million and $2 million for the three months ended September 30, 2017 and 2016, respectively, and $4 million and $5 million for the nine months ended September 30, 2017 and 2016, respectively.

~~PECO Natural Gas Operating Statistics and Revenue Detail~~

Three Months Ended
September 30, % Change
Weather -
Normal
% Change
Nine Months Ended
September 30, % Change
Weather -
Normal
% Change
Deliveries to Customers (in mmcf) 2017 2016 2017 2016
Retail Delivery
Retail sales^(a)
3,993
3,494
14.3 % 9.4 % 38,825
38,488
0.9 % 2.7 %
Transportation and other 5,674
7,315
(22.4 )% (14.5 )% 19,122
20,917
(8.6 )% (5.9 )%
Total natural gas deliveries 9,667
10,809
(10.6 )% (6.0 )% 57,947
59,405
(2.5 )% (0.1 )%

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~~Table of Contents~~

As of September 30,
Number of Natural Gas Customers 2017 2016
Residential 474,766
470,024
Commercial & industrial 43,358
42,997
Total retail 518,124

513,021
Transportation 771
802
Total 518,895

513,823

Three Months Ended
September 30, % Change Nine Months Ended
September 30, % Change
Natural Gas Revenue 2017 2016 2017 2016
Retail Sales
Retail sales^(a)
$ 46
$ 41
12.2 % $ 315
$ 298
5.7 %
Transportation and other 7
7
— % 24
24
— %
Total natural gas revenues^(b)
$ 53

$ 48
10.4 % $ 339

$ 322
5.3 %

~~_________~~


~~(a)~~	Reflects delivery volumes and revenue from customers purchasing natural gas directly from PECO and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges. For customers purchasing natural gas from PECO, revenue also reflects the cost of natural gas.


~~(b)~~	~~Includes operating revenues from affiliates totaling less than $1 million for the three and nine months ended September 30, 2017 and 2016.~~

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~~Results of Operations — BGE~~

Three Months Ended
September 30,
Favorable
(Unfavorable)
Variance
Nine Months Ended
September 30,
Favorable
(Unfavorable)
Variance
2017 2016 2017 2016
Operating revenues $ 738
$ 812
$ (74 ) $ 2,363
$ 2,421
$ (58 )
Purchased power and fuel expense 269
360
91
853
994
141
Revenues net of purchased power and fuel expense^(a)
469
452
17
1,510
1,427
83
Other operating expenses
Operating and maintenance 175
178
3
532
588
56
Depreciation and amortization 109
101
(8 ) 348
307
(41 )
Taxes other than income 61
58
(3 ) 180
172
(8 )
Total other operating expenses 345
337
(8 ) 1,060
1,067
7
Operating income 124
115
9
450
360
90
Other income and (deductions)
Interest expense, net (26 ) (28 ) 2
(80 ) (76 ) (4 )
Other, net 4
5
(1 ) 12
16
(4 )
Total other income and (deductions) (22 ) (23 ) 1
(68 ) (60 ) (8 )
Income before income taxes 102
92
10
382
300
82
Income taxes 40
36
(4 ) 151
109
(42 )
Net income 62
56
6
231
191
40
Preference stock dividends —
2
2
—
8
8
Net income attributable to common shareholder $ 62
$ 54
$ 8
$ 231
$ 183
$ 48

~~_________~~

~~(a)~~

BGE evaluates its operating performance using the measures of revenue net of purchased power expense for electric sales and revenue net of fuel expense for gas sales. BGE believes revenues net of purchased power and fuel expense are useful measurements of its performance because they provide information that can be used to evaluate its net revenue from operations. BGE has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, revenues net of purchased power and fuel expense figures are not a presentation defined under GAAP and may not be comparable to other companies’ presentations or more useful than the GAAP information provided elsewhere in this report.

~~Net Income Attributable to Common Shareholder~~

~~Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016~~. BGE’s Net income attributable to common shareholder for the three months ended September 30, 2017 was higher than the same period in 2016, primarily due to an increase in Revenues net of purchased power and fuel expense, predominantly as a result of an increase in transmission formula rate revenues. This item was partially offset by an increase in Depreciation and amortization expense primarily related to the impacts of increased capital investment.

~~Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016~~. BGE’s Net income attributable to common shareholder for the nine months ended September 30, 2017 was higher than the same period in 2016, primarily due to an increase in Revenues net of purchased power and fuel expense and lower Operating and maintenance expense. The increase in Revenues net of purchased power and fuel expense was primarily due to the impacts of the electric and natural gas distribution rate orders issued by the MDPSC in June 2016 and July 2016 and an increase in transmission formula rate revenues. The lower Operating and maintenance expense was primarily due to the absence of cost disallowances resulting from the 2016 distribution rate orders issued by the MDPSC and decreased storm costs in 2017. These items were partially offset by higher income tax expense primarily resulting from a cumulative adjustment to reduce tax expense in 2016 for transmission-related regulatory assets and an increase in Depreciation and amortization expense primarily related to the initiation of cost recovery of the AMI programs under the distribution rate orders and the impacts of increased capital investment.

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~~Table of Contents~~

~~Revenues Net of Purchased Power and Fuel Expense~~

There are certain drivers to Operating revenues that are offset by their impact on Purchased power and fuel expense, such as commodity procurement costs and programs allowing customers to select a competitive electric or natural gas supplier. Operating revenues and Purchased power and fuel expense are affected by fluctuations in commodity procurement costs. BGE’s electric and natural gas rates charged to customers are subject to periodic adjustments that are designed to recover or refund the difference between the actual cost of purchased electric power and purchased natural gas and the amount included in rates in accordance with the MDPSC’s market-based SOS and gas commodity programs, respectively.

Electric and natural gas revenue and purchased power and fuel expense are also affected by fluctuations in the number of customers electing to use a competitive electric generation or natural gas supplier. All BGE customersCustomers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas ~~suppliers, respectively. The customers'~~suppliers. Customer choice ~~of suppliers does~~programs do not impact the volume of deliveries ~~but~~as PECO remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation or natural gas from competitive suppliers, PECO either acts as the billing agent or the competitive supplier separately bills its own customers and therefore PECO does ~~affect revenue collected from customers~~not record Operating revenues or Purchased power and fuel expense related to ~~supplied energy and~~the electricity and/or natural gas.

~~Retail deliveries purchased from competitive~~ For customers that choose to purchase electric generation ~~and~~or natural gas ~~suppliers (as a percentage~~from PECO, PECO is permitted to recover the electricity, natural gas, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power and fuel expense related to the electricity, natural gas, and RECs.

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

The increase of $104 million and ~~mmcf sales, respectively)~~$8 million for the three and nine months ended September 30, ~~2017~~2023 compared to the same period in 2022, in Purchased power and ~~2016~~fuel expense is offset in Operating revenues as part of regulatory required programs.

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PECO

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


	Three Months Ended September 30, 2023		Nine Months Ended September 30, 2023
	Increase (Decrease)		Increase (Decrease)
Storm-related costs	$	26	$	28
BSC costs	11		19
Labor, other benefits, contracting and materials	(7)		15
Pension and non-pension postretirement benefit expense	—		(3)
Credit loss expense	1		(1)
Other	(6)		(5)
	25		53
Regulatory required programs	9		28
Total increase	$	34	$	81

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Electric 60 % 58 % 60 % 59 %
Natural Gas 74 % 80 % 57 % 59 %

The ~~number of retail customers purchasing electric generation~~changes in Depreciation and ~~natural gas from competitive electric generation and natural gas suppliers at September 30, 2017 and 2016~~amortization expense consisted of the following:


	Three Months Ended September 30, 2023		Nine Months Ended September 30, 2023
	Increase		Increase
Depreciation and amortization(a)	$	7	$	20
Regulatory asset amortization	1		—

Total increase	$	8	$	20

September 30, 2017 September 30, 2016
Number of Customers % of total retail customers Number of customers % of total retail customers
Electric 339,300
27 % 334,100
26 %
Natural Gas 148,600
22 % 150,000
23 %
__________

~~The changes in BGE’s Operating revenues~~(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.

Interest expense, net ~~of purchased power~~increased $7 million and ~~fuel expense~~$20 million for the three and nine months ended September 30, ~~2017,~~2023, compared to the same period in ~~2016, consisted of the following:~~

Three Months Ended
September 30, 2017 Nine Months Ended
September 30, 2017
Increase (Decrease) Increase (Decrease)
Electric Gas Total Electric Gas Total
Distribution rate increase $ —
$ —
$ —
$ 21
$ 29
$ 50
Regulatory required programs 2
—
2
11
1
12
Transmission revenue 7
—
7
10
—
10
Other, net 4
4
8
5
6
11
Total increase $ 13
$ 4
$ 17
$ 47
$ 36
$ 83

~~Distribution Rate Increase.~~ ~~The~~2022, primarily due to an increase in ~~distribution revenues~~interest rates and the issuance of debt in 2022 and 2023.

Effective income tax rates were 2.0% and 24.6% for the three months ended September 30, 2023 and 2022, respectively, and 1.9% and 12.4% for the nine months ended September 30, ~~2017, compared to the same period in 2016, was primarily due to the impact of the electric~~2023 and natural gas distribution rates charged to customers that became effective in June 2016 in accordance with the electric and natural gas distribution rate orders issued by the MDPSC in June 2016 and July 2016. See Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

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~~Table of Contents~~

~~Revenue Decoupling.~~ The demand for electricity and natural gas is affected by weather and usage conditions. The MDPSC allows BGE to record a monthly adjustment to its electric and natural gas distribution revenue from all residential customers, commercial electric customers, the majority of large industrial electric customers, and all firm service natural gas customers to eliminate the effect of abnormal weather and usage patterns per customer on BGE's electric and natural gas distribution volumes, thereby recovering a specified dollar amount of distribution revenue per customer, by customer class, regardless of fluctuations in actual consumption levels. This allows BGE to recognize revenue at MDPSC-approved distribution charges per customer, regardless of what BGE's actual distribution volumes were for a billing period. Therefore, while this revenue is affected by customer growth (i.e., increase in the number of customers), it will not be affected by actual weather or usage conditions (i.e., changes in consumption per customer). BGE bills or credits customers in subsequent months for the difference between approved revenue levels under revenue decoupling and actual customer billings.

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 BGE's service territory. The changes in heating and cooling degree days in BGE's service territory for the three and nine months ended September 30, 2017 compared to the same period in 2016 consisted of the following:

Heating and Cooling Degree-Days % Change
Three Months Ended September 30, 2017 2016 Normal 2017 vs. 2016 2017 vs. Normal
Heating Degree-Days 64
24
78
166.7 % (17.9 )%
Cooling Degree-Days 595
747
596
(20.3 )% (0.2 )%

Nine Months Ended September 30,
Heating Degree-Days 2,524
2,878
2,992
(12.3 )% (15.6 )%
Cooling Degree-Days 877
966
850
(9.2 )% 3.2 %

~~Regulatory Required Programs.~~ Revenue from regulatory required programs are billings for the costs of various legislative and/or regulatory programs that are recoverable from customers on a full and current basis. These programs are designed to provide full 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 in BGE's Consolidated Statements of Operations and Comprehensive Income.

~~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 other billing determinants. The increase in transmission revenue for the three and nine months ended September 30, 2017, compared to the same period in 2016, was primarily due to increases in capital investment and operating and maintenance expense recoveries. See Operating and Maintenance Expense below and Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

~~Other, Net.~~ Other net revenue, which can vary from period to period, primarily includes late payment fees and other miscellaneous revenue such as service application fees and assistance provided to other utilities through BGE's mutual assistance program.

~~Operating and Maintenance Expense~~

Three Months Ended
September 30,
Increase
(Decrease)
Nine Months Ended
September 30, Increase
(Decrease)
2017 2016 2017 2016
Operating and maintenance expense — baseline $ 167
$ 170
$ (3 ) $ 499
$ 561
$ (62 )
Operating and maintenance expense — regulatory required programs^(a)
8
8
—
33
27
6
Total operating and maintenance expense $ 175
$ 178
$ (3 ) $ 532
$ 588
$ (56 )

~~_________~~


~~(a)~~	Operating and maintenance expense for regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues.

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~~The changes in Operating and maintenance expense for the three and nine months ended September 30, 2017 compared to the same period in 2016, consisted of the following:~~

Three Months Ended
September 30, 2017 Nine Months Ended
September 30, 2017
Increase (Decrease) Increase (Decrease)
Baseline
Impairment on long-lived assets and losses on regulatory assets^(a)
$ 1
$ (50 )
City of Baltimore conduit fees (4 ) (12 )
Storm-related costs 3
(11 )
Uncollectible accounts expense (8 ) (8 )
BSC costs 8
10
Other (3 ) 9
(3 ) (62 )
Regulatory Required Programs
Other $ —
$ 6
—
6
Total decrease $ (3 ) $ (56 )

~~__________~~


~~(a)~~	~~See Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.~~

~~Depreciation and Amortization~~

~~The changes in Depreciation and amortization expense for the three and nine months ended September 30, 2017 compared to the same period in 2016 consisted of the following:~~

Three Months Ended
September 30, 2017 Nine Months Ended
September 30, 2017
Increase (Decrease) Increase (Decrease)
Depreciation expense^(a)
$ 5
$ 10
Regulatory asset amortization^(b)
1
25
Regulatory required programs^(c)
2
6
Total increase $ 8
$ 41

~~_________~~


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

~~(b)~~

Regulatory asset amortization increased for the three and nine months ended September 30, 2017 compared to the same period in 2016 primarily due to an increase in regulatory asset amortization related to energy efficiency programs and the initiation of cost recovery of the AMI programs under the final electric and natural gas distribution rate case order issued by the MDPSC in June 2016 and increased depreciation from AMI program capital expenditures. See Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.


~~(c)~~	Depreciation and amortization expenses for regulatory required programs are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues.

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~~Table of Contents~~

~~Taxes Other Than Income~~

Taxes other than income, which can vary period to period, include municipal and state utility taxes, real estate taxes and payroll taxes. Taxes other than income for the three and nine months ended September 30, 2017 compared to the same period in 2016 remained relatively consistent.

~~Interest Expense, Net~~

~~Interest expense, net for the three and nine months ended September 30, 2017, compared to the same period in 2016 remained relatively consistent.~~

~~Effective Income Tax Rate~~

BGE’s effective income tax rate was 39.2% and 39.1% for the three months ended September 30, 2017 and 2016, respectively. BGE’s effective income tax rate was 39.5% and 36.3% for the nine months ended September 30, 2017 and 2016,2022, respectively. See Note 127 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

~~228~~

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Table of Contents

BGE

~~BGE Electric Operating Statistics and Revenue Detail~~

Three Months Ended
September 30, % Change Weather -
Normal
% Change Nine Months Ended
September 30, % Change Weather -
Normal
% Change
Retail Deliveries to Customers (in GWhs) 2017
2016 2017 2016
Retail Deliveries^(a)

Residential 3,370
3,900
(13.6 )% (2.9 )% 9,126
9,996
(8.7 )% (4.3 )%
Small commercial & industrial 785
877
(10.5 )% (9.0 )% 2,210
2,343
(5.7 )% (5.8 )%
Large commercial & industrial 3,781
3,992
(5.3 )% (3.9 )% 10,422
10,627
(1.9 )% (2.6 )%
Public authorities & electric railroads 64
72
(11.1 )% (2.5 )% 204
215
(5.1 )% (2.5 )%
Total electric deliveries 8,000
8,841
(9.5 )% (4.0 )% 21,962
23,181
(5.3 )% (3.7 )%

As of September 30,
Number of Electric Customers 2017 2016
Residential 1,156,659
1,145,020
Small commercial & industrial 113,224
112,609
Large commercial & industrial 12,144
12,030
Public authorities & electric railroads 274
282
Total 1,282,301
1,269,941

Three Months Ended
September 30, % Change Nine Months Ended
September 30, % Change
Electric Revenue 2017
2016 2017 2016
Retail Sales^(a)

Residential $ 376
$ 451
(16.6 )% $ 1,096
$ 1,203
(8.9 )%
Small commercial & industrial 67
74
(9.5 )% 202
212
(4.7 )%
Large commercial & industrial 120
123
(2.4 )% 343
337
1.8 %
Public authorities & electric railroads 8
9
(11.1 )% 23
27
(14.8 )%
Total retail 571

657
(13.1 )% 1,664

1,779
(6.5 )%
Other revenue^(b)(c)
87
78
11.5 % 231
219
5.5 %
Total electric revenue $ 658

$ 735
(10.5 )% $ 1,895

$ 1,998
(5.2 )%

~~_________~~


~~(a)~~	Reflects delivery volumes and revenue from customers purchasing electricity directly from BGE and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from BGE, revenue also reflects the cost of energy and transmission.


~~(b)~~	~~Other revenue primarily includes wholesale transmission revenue and late payment charges.~~


~~(c)~~	~~Includes operating revenues from affiliates totaling $1 million for both the three months ended September 30, 2017 and 2016 and $5 million for both the nine months ended September 30, 2017 and 2016.~~

~~BGE Natural Gas Operating Statistics and Revenue Detail~~

Three Months Ended
September 30, % Change Weather -
Normal
% Change Nine Months Ended
September 30, % Change Weather -
Normal
% Change
Deliveries to Customers (in mmcf) 2017 2016 2017 2016
Retail Deliveries^(a)

Retail sales 11,221
13,159
(14.7 )% (14.3 )% 60,620
69,415
(12.7 )% (5.3 )%
Transportation and other^(b)
68
1,311
(94.8 )% n/a
2,463
4,078
(39.6 )% n/a
Total natural gas deliveries 11,289
14,470
(22.0 )% (14.3 )% 63,083
73,493
(14.2 )% (5.3 )%

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As of September 30,
Number of Gas Customers 2017
2016
Residential 626,039
619,837
Commercial & industrial 43,973
43,957
Total 670,012

663,794

Three Months Ended
September 30, % Change Nine Months Ended
September 30, % Change
Natural Gas Revenue 2017 2016 2017 2016
Retail Sales^(a)

Retail sales $ 77
$ 71
8.5 % $ 445
$ 403
10.4 %
Transportation and other^(b)
3
6
(50.0 )% 23
20
15.0 %
Total natural gas revenues^(c)
$ 80
$ 77
3.9 % $ 468
$ 423
10.6 %

~~_________~~


~~(a)~~	Reflects delivery volumes and revenue from customers purchasing natural gas directly from BGE and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges. For customers purchasing natural gas from BGE, revenue also reflects the cost of natural gas.


~~(b)~~	Transportation and other natural gas revenue includes off-system revenue of 68 mmcfs ($1 million) and 1,311 mmcfs ($4 million) for the three months ended September 30, 2017 and 2016, respectively, and 2,463 mmcfs ($15 million) and 4,078 mmcfs ($14 million) for the nine months ended September 30, 2017 and 2016, respectively.


~~(c)~~	Includes operating revenues from affiliates totaling $2 million and $6 million for the three months ended September 30, 2017 and 2016, respectively, and $7 million and $11 million for the nine months ended September 30, 2017 and 2016, respectively.

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Results of Operations — ~~PHI~~BGE

~~PHI’s results~~


	Three Months Ended September 30,				Favorable (Unfavorable) Variance		Nine Months Ended September 30,				Favorable (Unfavorable) Variance
	2023		2022				2023		2022
Operating revenues	$	932	$	870	$	62	$	2,986	$	2,810	$	176
Operating expenses
Purchased power and fuel	380		350		(30)		1,145		1,093		(52)
Operating and maintenance	214		235		21		632		658		26
Depreciation and amortization	161		148		(13)		487		470		(17)
Taxes other than income taxes	80		77		(3)		239		225		(14)
Total operating expenses	835		810		(25)		2,503		2,446		(57)

Operating income	97		60		37		483		364		119
Other income and (deductions)
Interest expense, net	(47)		(39)		(8)		(135)		(110)		(25)
Other, net	6		5		1		14		16		(2)
Total other income and (deductions)	(41)		(34)		(7)		(121)		(94)		(27)
Income before income taxes	56		26		30		362		270		92
Income taxes	11		(7)		(18)		76		3		(73)
Net income	$	45	$	33	$	12	$	286	$	267	$	19

Three Months Ended September 30, 2023 Compared to Three Months Ended September 30, 2022. Net income increased $12 million primarily due to favorable impacts of ~~operations include~~ the ~~results~~multi-year plans, partially offset by an increase in storm costs, an increase in depreciation and amortization, and an increase in interest expense. See Note 3 — Regulatory Matters of ~~its~~the Combined Notes to Consolidated Financial Statements for additional information on the three-year electric and natural gas distribution multi-year plans.

Nine Months Ended September 30, 2023 Compared to Nine Months Ended September 30, 2022. Net Income increased $19 million primarily due to favorable impacts of the multi-year plans, partially offset by an increase in storm costs, an increase in depreciation and amortization, and an increase in interest expense. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the three-year electric and natural gas distribution multi-year plans.

The changes in Operating revenues consisted of the following:


	Three Months Ended September 30, 2023						Nine Months Ended September 30, 2023
	Increase (Decrease)						Increase (Decrease)
	Electric		Gas		Total		Electric		Gas		Total
Distribution	$	19	$	4	$	23	$	61	$	33	$	94
Transmission	4		—		4		34		—		34
Other	—		1		1		(1)		3		2
	23		5		28		94		36		130
Regulatory required programs	56		(22)		34		106		(60)		46
Total increase (decrease)	$	79	$	(17)	$	62	$	200	$	(24)	$	176

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 monthly rate adjustment that provides for fixed distribution revenue 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.

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BGE


	At September 30,
Number of Electric Customers	2023	2022
Residential	1,208,230	1,200,786
Small commercial & industrial	115,557	115,778
Large commercial & industrial	13,007	12,774
Public authorities & electric railroads	264	266
Total	1,337,058	1,329,604


	At September 30,
Number of Natural Gas Customers	2023	2022
Residential	655,753	653,413
Small commercial & industrial	37,950	38,128
Large commercial & industrial	6,289	6,222

Total	699,992	697,763

Distribution Revenue increased for the three ~~reportable segments, Pepco, DPL~~ and ~~ACE~~nine months ended September 30, 2023,compared to the same period in 2022, due to favorable impacts of the multi-year plans.

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 increased for the three and nine months ended September 30, 2023, compared to the same period in 2022, primarily due to increases in underlying costs and capital investments.

Other Revenue includes revenue related to late payment, charges, mutual assistance, off-system sales, and service application fees. Other Revenue remained relatively the same for the three and nine months ended September 30, 2023 compared to the same period in 2022.

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 Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. 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 as BGE remains the distribution service provider for all ~~periods presented below.~~customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For ~~"Predecessor" reporting periods, PHI's results of operations also include~~customers that choose to purchase electric generation or natural gas from competitive suppliers, BGE acts as the ~~results of PES~~billing agent and ~~PCI.~~ therefore does 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 BGE, BGE is permitted to recover the electricity and natural gas procurement costs from customers and therefore records the amounts related to the electricity and/or natural gas in Operating revenues and Purchased power and fuel expense. BGE recovers electricity and natural gas procurement costs from customers with a slight mark-up.

See Note ~~20 -~~5 — Segment Information of the Combined Notes to Consolidated Financial Statements for ~~additional information regarding PHI's reportable segments. All material intercompany accounts~~the presentation of BGE's revenue disaggregation.

The increase of $30 million and ~~transactions have been eliminated in consolidation. A separate specific discussion of the results of operations for Pepco, DPL and ACE is presented elsewhere in this report.~~

As a result of the PHI Merger, the following consolidated financial results present two separate reporting periods for 2016. The "Predecessor" reporting period represents PHI's results of operations for the period from January 1, 2016 to March 23, 2016. The "Successor" reporting periods represent PHI's results of operations$52 million for the three and nine months ended September 30, ~~2017,~~2023 compared to the ~~three~~same period in 2022, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.

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


	Three Months Ended September 30, 2023		Nine Months Ended September 30, 2023
	Increase (Decrease)		Increase (Decrease)
Labor, other benefits, contracting, and materials	$	3	$	15
Storm-related costs	12		12
Pension and non-pension postretirement benefits expense	2		4
BSC costs	12		18
Credit loss expense	1		(14)

Other(a)	(51)		(62)
	(21)		(27)
Regulatory required programs	—		1

Total decrease	$	(21)	$	(26)

__________

(a)Primarily relates to the prior year asset impairment of $46 million. See Note 11 - Asset Impairments of the 2022 Form 10-K for additional information.

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


	Three Months Ended September 30, 2023		Nine Months Ended September 30, 2023
	Increase		Increase (Decrease)
Depreciation and amortization(a)	$	9	$	22
Regulatory required programs	4		(4)
Regulatory asset amortization	—		(1)

Total increase	$	13	$	17

__________

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

Interest expense, net increased by $25 million for the nine months ended September 30, ~~2016~~2023, respectively compared to the same period in 2022, primarily due to an increase in interest rates and the issuance of debt in 2023 and 2022.

Taxes other than income taxes increased by $14 million for the ~~period from March 24, 2016 to September 30, 2016. All amounts presented below are before the impact of income taxes, except as noted.~~

Successor Successor Predecessor
Three Months Ended September 30, Favorable (Unfavorable) Variance Nine Months Ended September 30, March 24 to September 30, January 1 to March 23,
2017 2016 2017 2016 2016
Operating revenues $ 1,310
$ 1,394
$ (84 ) $ 3,557
$ 2,565
$ 1,153
Purchased power and fuel expense 473
583
110
1,318
1,037
497
Revenue net of purchased power and fuel expense^(a)
837
811
26
2,239
1,528
656
Other operating expenses
Operating and maintenance 251
226
(25 ) 774
921
294
Depreciation and amortization 179
182
3
511
355
152
Taxes other than income 122
124
2
344
248
105
Total other operating
expenses 552
532
(20 ) 1,629
1,524
551
Gain on sales of assets —
—
—
1
—
—
Operating income 285
279
6
611
4
105
Other income and (deductions)
Interest expense, net (62 ) (64 ) 2
(183 ) (135 ) (65 )
Other, net 13
19
(6 ) 40
31
(4 )
Total other income and
(deductions) (49 ) (45 ) (4 ) (143 ) (104 ) (69 )
Income (loss) before income taxes 236
234
2
468
(100 ) 36
Income taxes 83
68
(15 ) 109
(9 ) 17
Net income (loss) $ 153
$ 166
$ (13 ) $ 359
$ (91 ) $ 19

~~_________~~

~~(a)~~

PHI evaluates its operating performance using the measure of revenue net of purchased power and fuel expense for electric and natural gas sales. PHI believes revenue net of purchased power and fuel expense is a useful measurement because it provides information that can be used to evaluate its operational performance. PHI has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, Revenue net of purchased power and fuel expense 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.

~~Successor Period Three Months Ended September 30, 2017 Compared to Successor Period Three Months Ended September 30, 2016~~

~~Net Income~~

~~PHI's Net income for the Successor period of three~~nine months ended September 30, ~~2017 was $153 million~~2023, respectively, compared to ~~$166 million for~~ the ~~Successor~~same period ~~of three months ended September 30, 2016. The decrease~~ in ~~Net~~2022, primarily due to increased property taxes.

Effective income ~~reflects the September 2016 pre-tax recording of a $50 million reallocation of merger-related commitments from Pepco, DPL~~tax rateswere 19.6% and ~~ACE to Exelon, which resulted in more commitments becoming obligations of Exelon. The increase in Operating~~

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and maintenance expense is partially offset by the impact of increases in electric distribution and natural gas rates within Revenue net of purchased power expense (Pepco electric distribution rates effective November 2016 in Maryland, Pepco electric distribution rates effective August 2017 in the District of Columbia, DPL electric distribution rates effective February 2017 in Maryland, DPL electric distribution and natural gas rates effective July 2016 and December 2016 in Delaware, and ACE electric distribution rates effective August 2016 in New Jersey).

~~Operating Revenue Net of Purchased Power and Fuel Expense~~

~~Operating revenue net of purchased power and fuel expense, which is a non-GAAP measure discussed above, increased by $26 million~~(26.9)% for the three months ended September 30, ~~2017 as compared to~~2023 and 2022 respectively, and 21.0% and 1.1% for the ~~three~~nine months ended September 30, ~~2016. The increase is primarily attributable to the following factors:~~

~~Increase of $17 million at DPL primarily related to the impact of the new electric distribution~~2023 and natural gas rates charged to Delaware customers that became effective in July 2016 and December 2016 and the impact of new electric distribution rates charged to Maryland customers that became effective in February 2017;

Increase of $14 million at Pepco primarily related to the impact of the new electric distribution rates charged to customers in Maryland that became effective in November 2016 and and the impact of new electric distribution rates charged to customers in the District of Columbia effective August 2017; and

Decrease of $6 million at ACE primarily related to lower average customer usage and unfavorable weather related sales, partially offset by the impact of the new electric distribution base rate charged to customers that became effective in August 2016.

~~Operating and Maintenance Expense~~

Operating and maintenance expense increased by $25 million for the three months ended September 30, 2017 as compared to the three months ended September 30, 2016. The increase is attributable to the following factors:

~~Increase of $24 million at DPL due primarily to a merger commitment reallocation from DPL to Exelon that decreased Operating and maintenance expense in 2016;~~

Increase of $5 million at ACE primarily due to a merger commitment reallocation from ACE to Exelon that decreased Operating and maintenance expense in 2016, partially offset by the deferral of merger-related costs to a regulatory asset; and

Decrease of $6 million at Pepco primarily due to the deferral of merger-related, rate case, and customer billing system costs to a regulatory asset, partially offset by a merger commitment reallocation from Pepco to Exelon that decreased Operating and maintenance expense in 2016.

~~Depreciation and Amortization Expense~~

Depreciation and amortization expense decreased by $3 million primarily due to lower amortization expense at ACE resulting from lower revenue due to rate decreases effective October 2016 for the ACE Transition Bond Charge and ACE Market Transition Charge Tax, partially offset by higher depreciation as a result of higher Maryland depreciation rates at Pepco effective November 2016 and at DPL effective February 2017 and due to ongoing capital expenditures at Pepco, DPL, and ACE.

~~Taxes Other Than Income~~

~~Taxes other than income decreased by $2 million primarily due to lower utility taxes that are collected and passed through by Pepco, partially offset by higher property taxes at Pepco.~~

~~Interest Expense, Net~~

~~Interest expense decreased by $2 million primarily due to the redemption of long-term debt in December 2016 and lower short-term debt interest rates.~~

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~~Other, Net~~

Other, net decreased by $6 million primarily due to the September 2016 reversal of contributions in aid of construction tax gross-up reserves due to the determination that there is no legal obligation to refund customers per contract terms.

~~Effective Income Tax Rate~~

~~PHI's effective income tax rate was 35.2% and 29.1% for the three months ended September 30, 2017 and 2016,~~2022, respectively. See Note ~~12 -~~7 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

~~Successor Period~~

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PHI

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. All material intercompany accounts and transactions have been eliminated in consolidation. The following table sets forth PHI's GAAP consolidated Net income, by Registrant, for the three and nine months ended September 30, 2023 compared to the same period in 2022. See the Results of Operations for Pepco, DPL, and ACE for additional information.


	Three Months Ended September 30,				Unfavorable Variance		Nine Months Ended September 30,				Unfavorable Variance
	2023		2022				2023		2022
PHI	$	232	$	289	$	(57)	$	490	$	518	$	(28)
Pepco	120		145		(25)		249		261		(12)
DPL	43		52		(9)		128		130		(2)
ACE	71		94		(23)		122		131		(9)
Other(a)	(2)		(2)		—		(9)		(4)		(5)

__________

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

Three Months Ended September 30, 2023 Compared to Three Months Ended September 30, 2022. Net Income decreased by $57 millionprimarily due to an increase in depreciation expense, higher contracting costs partially due to timing of maintenance projects, an increase in credit loss expense at Pepco, higher storm costs at DPL, timing of decoupling revenues in the District of Columbia, timing of excess deferred tax amortization at DPL and ACE, and an increase in various operating expenses, partially offset by higher transmission rates, higher distribution rates at DPL Delaware, and favorable impacts of the Pepco Maryland and DPL Maryland multi-year plans.

Nine Months Ended September 30, ~~2017~~2023 Compared to Nine Months Ended September 30, 2022. Net Income decreased by $28 millionprimarily due to an increase in environmental liabilities at Pepco, an increase in depreciation expense, an increase in interest expense, unfavorable weather at DPL Delaware electric and natural gas service territories, and an increase in various operating expenses, partially offset by higher transmission rates, higher distribution rates at DPL Delaware, and favorable impacts of the Pepco Maryland and DPL Maryland multi-year plans.

~~PHI's~~

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Pepco

Results of Operations — Pepco


	Three Months Ended September 30,				Favorable (Unfavorable) Variance		Nine Months Ended September 30,				Favorable (Unfavorable) Variance
	2023		2022				2023		2022
Operating revenues	$	822	$	724	$	98	$	2,174	$	1,919	$	255


Operating expenses
Purchased power	288		230		(58)		750		605		(145)
Operating and maintenance	149		121		(28)		440		380		(60)
Depreciation and amortization	112		99		(13)		329		312		(17)
Taxes other than income taxes	109		105		(4)		291		291		—
Total operating expenses	658		555		(103)		1,810		1,588		(222)

Operating income	164		169		(5)		364		331		33
Other income and (deductions)
Interest expense, net	(41)		(37)		(4)		(122)		(111)		(11)
Other, net	18		14		4		50		39		11
Total other income and (deductions)	(23)		(23)		—		(72)		(72)		—
Income before income taxes	141		146		(5)		292		259		33
Income taxes	21		1		(20)		43		(2)		(45)
Net income	$	120	$	145	$	(25)	$	249	$	261	$	(12)

Three Months Ended September 30, 2023Compared to Three Months Ended September 30, 2022. Net ~~income~~Income decreased by$25 million primarily due to the timing of decoupling revenues in the District of Columbia, higher contracting costs partially due to timing of maintenance projects, an increase in depreciation expense, credit loss expense, interest expense, and various operating expenses, partially offset by favorable impacts of the Maryland multi-year plan and higher transmission rates.

Nine Months Ended September 30, 2023 Compared to Nine Months Ended September 30, 2022. Net Income decreased by$12 million primarily due to an increase in environmental liabilities, depreciation expense, interest expense, and various operating expenses, partially offset by favorable impacts of the Maryland multi-year plan, higher transmission rates, and customer growth.

The changes in Operating revenues consisted of the following:


	Three Months Ended September 30, 2023		Nine Months Ended September 30, 2023
	Increase (Decrease)		Increase
Distribution	$	17	$	69
Transmission	16		44
Other	(1)		2
	32		115
Regulatory required programs	66		140
Total increase	$	98	$	255

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 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.

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Pepco


	At September 30,
Number of Electric Customers	2023	2022
Residential	862,321	853,873
Small commercial & industrial	54,082	54,423
Large commercial & industrial	22,952	22,789
Public authorities & electric railroads	205	196
Total	939,560	931,281

Distribution Revenue increased for the ~~Successor~~three months ended September 30, 2023 compared to the same period in 2022 primarily due to higher rates due to the expiration of customer offsets and favorable impacts of the Maryland multi-year plan, partially offset by the timing of decoupling revenues in the District of Columbia. Distribution revenue increased for the nine months ended September 30, ~~2017 was $359 million. Therewere no significant changes~~2023 compared to the same period in 2022 primarily due to higher rates due to the expiration of customer offsets, favorable impacts of the Maryland multi-year plan, and customer growth.

Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying ~~trends affecting PHI's operations during~~costs and capital investments being recovered. Transmission revenue increased for both the ~~Successor period of~~three and nine months ended September 30, ~~2017 except for~~2023, compared to the ~~impact of~~same period in 2022, primarily due to increases in ~~electric distribution~~underlying costs and ~~natural gas rates within~~capital investment.

Other Revenue ~~net~~ includes rental revenue, revenue related to late payment charges, mutual assistance revenues, and recoveries of ~~purchased~~other taxes.

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 procurement and 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 Purchased power expense, (Pepco electric distribution rates effective November 2016 in Maryland, Pepco electric distribution rates effective August 2017 in the District of Columbia, DPL electric distribution rates effective February 2017 in Maryland, DPL electric distribution and natural gas rates effective July 2016 and December 2016 in Delaware, and ACE electric distribution rates effective August 2016 in New Jersey). The deferral of merger-related, rate case, and customer billing system costs to a regulatory asset and lower uncollectible accounts expense contributed to lower Operating and maintenance ~~expense. Income taxes were lower due~~expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to ~~unrecognized tax benefits~~purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of ~~$59 million~~deliveries, as Pepco remains the distribution service provider for ~~uncertain tax positions~~all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, Pepco acts as the billing agent and therefore, Pepco does not record Operating revenues or Purchased power expense related to the ~~deductibility~~electricity. For customers that choose to purchase electric generation from Pepco, Pepco is permitted to recover the electricity and REC procurement costs from customers and therefore records the amounts related to the electricity and RECs in Operating revenues and Purchased power expense. Pepco recovers electricity and REC procurement costs from customers with a slight mark-up.

See Note 5 — Segment Information of ~~certain merger commitments in~~ the ~~first quarter of 2017.~~

~~PHI's effective income tax rate~~ Combined Notes to Consolidated Financial Statements for the ~~Successor period~~presentation of Pepco's revenue disaggregation.

The increase of $58 million and $145 million for the three and nine months ended September 30, ~~2017 was 23.3%.~~2023 compared to the same period in 2022, respectively, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.

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Pepco

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


	Three Months Ended September 30, 2023		Nine Months Ended September 30, 2023
	Increase (Decrease)		Increase (Decrease)
BSC and PHISCO costs	$	9	$	10
Labor, other benefits, contracting and materials(a)	6		29
Credit Loss expense	6		—
Pension and non-pension postretirement benefits expense	3		8
Storm-related costs	(2)		(7)

Other	3		12
	25		52

Regulatory required programs	3		8
Total increase	$	28	$	60

__________

(a)Primarily reflects an increase in environmental liabilities for the nine months ended September 30, 2023.

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


	Three Months Ended September 30, 2023		Nine Months Ended September 30, 2023
	Increase		Increase (Decrease)
Depreciation and amortization(a)	$	10	$	17
Regulatory asset amortization	3		10
Regulatory required programs	—		(10)
Total increase	$	13	$	17

__________

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

Interest expense, net increased by $4 million and $11 million for the three and nine months ended September 30, 2023 compared to the same period in 2022, respectively, primarily due to an increase in interest rates and the issuance of debt in 2022 and 2023.

Other, net increased by $4 million and $11 million for the three and nine months ended September 30, 2023 compared to the same period in 2022, respectively, primarily due to higher AFUDC equity.

Effective income tax rates were 14.9% and 0.7% for the three months ended September 30, 2023 and 2022, respectively, and 14.7% and (0.8)% for the nine months ended September 30, 2023 and 2022, respectively. See Note ~~12 -~~7 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

~~Successor Period March 24, 2016 to September 30, 2016~~

~~PHI's Net loss for the Successor period from March 24, 2016 to September 30, 2016was $91 million~~. ~~There~~were no significant changes in the underlying trends affecting PHI's results of operations during the Successor period of March 24, 2016 to September 30, 2016 except for the pre-tax recording of $375 million of non-recurring merger-related costs within Operating and maintenance expense.

PHI's effective income tax rate for the Successor period of March 24, 2016 to September 30, 2016 was 9.0%. See Note 12 - Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

~~Predecessor Period January 1, 2016 to March 23, 2016~~

~~PHI's Net income for the Predecessor period of January 1, 2016 to March 23, 2016was $19 million~~. ~~There~~were no significant changes in the underlying trends affecting PHI's results of operations during the Predecessor period of January 1, 2016 to March 23, 2016 except for the pre-tax recording of $29 million of non-recurring merger-related costs within Operating and maintenance expense and $18 million of preferred stock derivative expense within Other, net.

PHI's effective income tax rate for the Predecessor period of January 1, 2016 to March 23, 2016 was 47.2%. See Note 12 - Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

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DPL

Results of Operations ~~- Pepco~~— DPL


	Three Months Ended September 30,				Favorable (Unfavorable) Variance		Nine Months Ended September 30,				Favorable (Unfavorable) Variance
	2023		2022				2023		2022
Operating revenues	$	450	$	412	$	38	$	1,273	$	1,176	$	97
Operating expenses
Purchased power and fuel	201		183		(18)		562		507		(55)
Operating and maintenance	104		84		(20)		278		266		(12)
Depreciation and amortization	62		59		(3)		182		172		(10)
Taxes other than income taxes	19		19		—		57		54		(3)
Total operating expenses	386		345		(41)		1,079		999		(80)

Operating income	64		67		(3)		194		177		17
Other income and (deductions)
Interest expense, net	(18)		(16)		(2)		(53)		(48)		(5)
Other, net	5		3		2		12		9		3
Total other income and (deductions)	(13)		(13)		—		(41)		(39)		(2)
Income before income taxes	51		54		(3)		153		138		15
Income taxes	8		2		(6)		25		8		(17)
Net income	$	43	$	52	$	(9)	$	128	$	130	$	(2)

Three Months Ended September 30, Favorable (Unfavorable) Variance Nine Months Ended September 30, Favorable (Unfavorable) Variance
2017 2016 2017 2016
Operating revenues $ 604
$ 635
$ (31 ) $ 1,649
$ 1,695
$ (46 )
Purchased power expense 168
213
45
478
563
85
Revenue net of purchased power expense^(a)
436
422
14
1,171
1,132
39
Other operating expenses
Operating and maintenance 103
109
6
336
508
172
Depreciation and amortization 82
76
(6 ) 242
221
(21 )
Taxes other than income 102
105
3
282
287
5
Total other operating expenses 287
290
3
860
1,016
156
Gain on sales of assets —
—
—
1
8
(7 )
Operating income 149
132
17
312
124
188
Other income and (deductions)

Interest expense, net (31 ) (30 ) (1 ) (89 ) (98 ) 9
Other, net 7
12
(5 ) 22
28
(6 )
Total other income and (deductions) (24 ) (18 ) (6 ) (67 ) (70 ) 3
Income before income taxes 125
114
11
245
54
191
Income taxes 38
35
(3 ) 57
34
(23 )
Net income $ 87
$ 79
$ 8
$ 188
$ 20
$ 168

~~_________~~

~~(a)~~

Pepco evaluates its operating performance using the measure of revenue net of purchased power expense for electric sales. Pepco believes revenue net of purchased power expense is a useful measurement because it provides information that can be used to evaluate its operational performance. Pepco has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, Revenue net of purchased power expense 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.

~~Net Income~~

Three Months Ended September 30, ~~2017~~2023 Compared to Three Months Ended September 30, ~~2016.~~ ~~Pepco's~~ 2022. Net income ~~for the three months ended September 30, 2017, was higher than the same period in 2016,~~decreased $9 million primarily due to an increase in ~~Revenue net~~storm costs, depreciation expense, various operating expenses, and the timing of ~~purchased power expense resulting from higher electric distribution revenues as a result~~excess deferred tax amortization, partially offset by favorable impacts of the Maryland multi-year plan, higher Delaware electric and natural gas distribution ~~rate increase approved by the MDPSC effective November 2016~~rates, and ~~the distribution rate increase approved by the DCPSC effective August 2017.~~higher transmission rates.

Nine Months Ended September 30, ~~2017~~2023 Compared to Nine Months Ended September 30, ~~2016.~~ ~~Pepco's~~ 2022. Net income ~~for the nine months ended September 30, 2017, was higher than the same period in 2016,~~decreased $2 million primarily due to unfavorable weather conditions at Delaware electric and natural gas service territories, an increase in depreciation expense, and interest expense, partially offset by favorable impacts of the Maryland multi-year plan, higher Delaware electric and natural gas distribution rates, and higher transmission rates.

The changes in Operating revenues consisted of the following:


	Three Months Ended September 30, 2023						Nine Months Ended September 30, 2023
	(Decrease) Increase						(Decrease) Increase
	Electric		Gas		Total		Electric		Gas		Total
Weather	$	(1)	$	—	$	(1)	$	(11)	$	(5)	$	(16)
Volume	(1)		—		(1)		(3)		(3)		(6)
Distribution	7		1		8		26		6		32
Transmission	12		—		12		25		—		25
Other	2		—		2		4		1		5
	19		1		20		41		(1)		40
Regulatory required programs	33		(15)		18		64		(7)		57
Total increase (decrease)	$	52	$	(14)	$	38	$	105	$	(8)	$	97

Revenue ~~net of purchased power expense resulting~~Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from ~~higher~~ electric distribution ~~revenues~~in Maryland are not impacted by abnormal weather or usage per customer as a result of the distribution rate increase approved by the MDPSC effective November 2016 and the distribution rate increase approved by the DCPSC effective August 2017, lower Operating and maintenance expense due to merger-related costs recognized in March 2016, and a decrease in income tax reserves in the first quarter of 2017 for uncertain tax positions related to the deductibility of certain merger commitments, partially offset by higher depreciation expense due to increased depreciation rates in Maryland effective November 2016.

~~Operating Revenue Net of Purchased Power Expense~~

Operating revenues include revenue from the distribution and supply of electricity to Pepco’s customers within its service territories at regulated rates. Operating revenues also include transmission service revenue that Pepco receives as a transmission owner from PJM at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.

Electric revenues and purchased power expense are also affected by fluctuations in participation in the Customer Choice Program. All Pepco customers have the choice to purchase electricity from competitive electric generation

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~~suppliers. The customers' choice of supplier does not impact the volume of deliveries, but affects revenue collected from customers related to supplied energy service.~~

Retail deliveries purchased from competitive electric generation suppliers (as a percentage of kWh sales) for the three and nine months ended September 30, 2017, compared to the same periods in 2016, consisted of the following:

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Electric 65 % 63 % 66 % 65 %

~~Retail customers purchasing electric generation from competitive electric generation suppliers at September 30, 2017 and 2016 consisted of the following:~~

September 30, 2017 September 30, 2016
Number of customers % of total retail customers Number of customers % of total retail customers
Electric 179,106
21 % 175,960
21 %

Retail deliveries purchased from competitive electric generation suppliers represented 72% and 73% of Pepco’s retail kWh sales to the District of Columbia customers and 60% and 60% of Pepco’s retail kWh sales to Maryland customers for the three and nine months ended September 30, 2017, respectively and 71% and 72% of Pepco’s retail kWh sales to the District of Columbia customers and 58% and 59% of Pepco’s retail kWh sales to Maryland customers for the three and nine months ended September 30, 2016, respectively.

~~Operating revenues include transmission enhancement credits that Pepco receives as a transmission owner from PJM in consideration for approved regional transmission expansion plan expenditures.~~

Operating revenues also include work and services performed on behalf of customers, including other utilities, which is generally not subject to price regulation. Work and services includes mutual assistance to other utilities, highway relocation, rentals of pole attachments, late payment fees and collection fees.

Purchased power expense consists of the cost of electricity purchased by Pepco to fulfill its default electricity supply obligation and, as such, is recoverable from customers in accordance with the terms of public service commission orders.

~~The changes in Pepco’s operating revenues net of purchased power expense for the three and nine months ended September 30, 2017 compared to the same periods in 2016 consisted of the following:~~

Three Months Ended September 30, 2017 Nine Months Ended September 30, 2017
Increase (Decrease) Increase (Decrease)
Volume $ 5
$ 13
Distribution rate increase 17
45
Regulatory required programs (6 ) (11 )
Transmission revenues 3
9
Other (5 ) (17 )
Total increase $ 14
$ 39

~~Volume.~~ The increase in operating revenue net of purchased power and fuel expense related to delivery volume, exclusive of the effects of weather, for the three and nine months ended September 30, 2017 compared to the same periods in 2016, primarily reflects the impact of customer growth.

~~Distribution Rate Increase.~~ ~~The increase in electric operating revenues net of purchased power expense for the three and nine months ended September 30, 2017 compared to the same periods in 2016 was primarily due to the~~

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impact of higher electric distribution rates charged to customers in Maryland that became effective in November 2016 and higher electric distribution rates charged to customers in the District of Columbia that became effective August 2017. See Note 5—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

~~Revenue Decoupling.~~ Pepco’s results historically have been seasonal, generally producing higher revenue and income in the warmest and coldest periods of the year. For retail customers of Pepco in Maryland and in the District of Columbia, revenues are not affected by unseasonably warmer or colder weather because a bill stabilization adjustment (BSA) for retail customers was implementedBSA that provides for a fixed distribution charge per ~~customer. The BSA has the effect of decoupling the~~customer by customer class. While Operating revenues from electric distribution ~~revenue recognized in a reporting period from the amount of power delivered during the period. As a result, the only factors that will cause distribution revenue from~~ customers in Maryland ~~and the District of Columbia to fluctuate from period to period~~ are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of ~~customers~~customers.

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DPL

Weather. The demand for electricity and ~~changes~~natural gas in Delaware is affected by weather conditions. With respect to the ~~approved distribution charge per customer. Changes~~electric business, very warm weather in ~~customer usage (due~~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 three months ended September 30, 2023, compared to the same period in 2022, Operating revenues related to weather ~~conditions, energy prices, energy efficiency programs or other reasons) from period to period have no impact on reported distribution revenue for customers to whom~~remained relatively consistent. During the ~~BSA applies.~~

~~In accounting for the BSA in Maryland and the District of Columbia, a Revenue Decoupling Adjustment is recorded representing either (i) a positive adjustment equal~~nine months ended September 30, 2023, compared to the ~~amount by which revenue from Maryland~~same period in 2022, Operating revenues related to weather decreased due to unfavorable weather conditions in Delaware electric and the District of Columbia retail distribution sales falls short of the revenue that Pepco is entitled to earn based on the approved distribution charge per customer or (ii) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that Pepco is entitled to earn based on the approved distribution charge per customer.natural gas service territories.

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 ~~Pepco's~~the Delaware electric service territory and a 30-year period in the Delaware natural gas service territory. The changes in heating and cooling degree days in ~~Pepco’s~~the Delaware service territory for the three and nine months ended September 30, ~~2017~~2023 compared to ~~the~~ same ~~periods~~period in ~~2016~~2022 and normal weather consisted of the following:


	Three Months Ended September 30,			% Change
Delaware Electric Service Territory	2023	2022	Normal	2023 vs. 2022		2023 vs. Normal
Heating Degree-Days	37	32	27	15.6	%	37.0	%
Cooling Degree-Days	996	1,043	911	(4.5)	%	9.3	%

	Nine Months Ended September 30,			% Change
Delaware Electric Service Territory	2023	2022	Normal	2023 vs. 2022		2023 vs. Normal
Heating Degree-Days	2,306	2,828	2,984	(18.5)	%	(22.7)	%
Cooling Degree-Days	1,249	1,374	1,248	(9.1)	%	0.1	%


	Three Months Ended September 30,			% Change
Delaware Natural Gas Service Territory	2023	2022	Normal	2023 vs. 2022		2023 vs. Normal
Heating Degree-Days	37	32	35	15.6	%	5.7	%

	Nine Months Ended September 30,			% Change
Delaware Natural Gas Service Territory	2023	2022	Normal	2023 vs. 2022		2023 vs. Normal
Heating Degree-Days	2,306	2,828	3,020	(18.5)	%	(23.6)	%

Volume, exclusive of the effects of weather, remained relatively consistent for the three months ended September 30, 2023 compared to the same period in 2022 and decreased for the nine months ended September 30, 2023 compared to the same period in 2022 primarily due to customer usage, partially offset by customer growth.


Electric Retail Deliveries to Delaware Customers (in GWhs)	Three Months Ended September 30,		% Change		Weather - Normal % Change(b)		Nine Months Ended September 30,		% Change		Weather - Normal % Change(b)
	2023	2022					2023	2022
Residential	995	978	1.7	%	0.6	%	2,403	2,548	(5.7)	%	(0.2)	%
Small commercial & industrial	405	400	1.3	%	0.6	%	1,081	1,107	(2.3)	%	(0.1)	%
Large commercial & industrial	849	856	(0.8)	%	(0.2)	%	2,349	2,394	(1.9)	%	(0.7)	%
Public authorities & electric railroads	7	7	—	%	(5.8)	%	23	24	(4.2)	%	(4.3)	%
Total electric retail deliveries(a)	2,256	2,241	0.7	%	0.3	%	5,856	6,073	(3.6)	%	(0.4)	%

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DPL

% Change
2017 2016 Normal 2017 vs. 2016 2017 vs. Normal
Three Months Ended September 30,
Heating Degree-Days 8
1
19
700.0 % (57.9 )%
Cooling Degree-Days 1,130
1,418
1,133
(20.3 )% (0.3 )%

Nine Months Ended September 30,

Heating Degree-Days 1,963
2,408
2,477
(18.5 )% (20.8 )%
Cooling Degree-Days 1,679
1,872
1,611
(10.3 )% 4.2 %


	At September 30,
Number of Total Electric Customers (Maryland and Delaware)	2023	2022
Residential	484,425	480,779
Small commercial & industrial	64,101	63,685
Large commercial & industrial	1,245	1,230
Public authorities & electric railroads	593	597
Total	550,364	546,291

~~Regulatory Required Programs.This represents~~__________

(a)Reflects delivery volumes 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 ~~operating revenues collected under approved riders to recover costs incurred~~delivery volumes assuming normalized weather based on the historical 20-year average.


Natural Gas Retail Deliveries to Delaware Customers (in mmcf)	Three Months Ended September 30,		% Change		Weather - Normal % Change(b)		Nine Months Ended September 30,		% Change		Weather - Normal % Change(b)
	2023	2022					2023	2022
Residential	414	374	10.7	%	8.3	%	4,781	5,810	(17.7)	%	(4.9)	%
Small commercial & industrial	350	331	5.7	%	4.4	%	2,494	2,882	(13.5)	%	(0.3)	%
Large commercial & industrial	381	397	(4.0)	%	(4.0)	%	1,166	1,259	(7.4)	%	(7.2)	%
Transportation	1,119	1,284	(12.9)	%	(13.0)	%	4,350	4,934	(11.8)	%	(7.9)	%
Total natural gas deliveries(a)	2,264	2,386	(5.1)	%	(5.7)	%	12,791	14,885	(14.1)	%	(5.2)	%


	At September 30,
Number of Delaware Natural Gas Customers	2023	2022
Residential	129,436	129,005
Small commercial & industrial	10,039	10,044
Large commercial & industrial	14	16
Transportation	165	156
Total	139,654	139,221

__________

(a)Reflects delivery volumes 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 ~~regulatory programs such as energy efficiency programs. The riders are designed to provide full~~both the three 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 Taxes other than income in Pepco's Consolidated Statements of Operations and Comprehensive Income. Refernine months ended September 30, 2023 compared to the ~~Operating~~same period in2022 primarily due to favorable impacts of the higher electric distribution rates in Delaware that became effective July 2023, favorable impacts of the Maryland multi-year plan that became effective in January 2023, and ~~maintenance expense and Depreciation and amortization expense discussion below for additional information on included programs.~~higher natural gas distribution rates effective in August 2022.

Transmission ~~Revenues~~. 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 and other billing adjustments. The increase in revenue net of purchased power expense for the three months ended September 30, 2017 compared to the same period in 2016 is a result of higher rates effective June 1, 2017 related to increases in transmission plant investment and operating expenses. The increase in revenue net of purchased power expense for the nine months ended September 30, 2017 compared to the same period in 2016 is a result of higher rates effective June 1, 2017 and June 1, 2016 related to increases in transmission plant investment and operating expenses, partially offset by lower revenue related to the MAPP abandonment recovery period that ended in March 2016.

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~~Other.~~ The decrease in other operating revenue net of purchased power and fuel expense for the three and nine months ended September 30, 2017 compared to the same periods in 2016 is primarily due to lower pass-through revenue (which is substantially offset in Taxes other than income) primarily the result of lower sales that resulted in a decrease in utility taxes that are collected by Pepco on behalf of the jurisdiction.

~~Operating and Maintenance Expense~~

Three Months Ended
September 30, Increase (Decrease) Nine Months Ended
September 30,
Increase
(Decrease)
2017 2016 2017 2016
Operating and maintenance expense - baseline $ 100
$ 106
$ (6 ) $ 331
$ 500
$ (169 )
Operating and maintenance expense - regulatory required programs^(a)
3
3
—
5
8
(3 )
Total operating and maintenance expense $ 103
$ 109
$ (6 ) $ 336
$ 508
$ (172 )

~~_________~~


~~(a)~~	Operating and maintenance expenses for regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues.

~~The changes in Operating and maintenance expense for the three and nine months ended September 30, 2017 compared to the same periods in 2016, consisted of the following:~~

Three Months Ended September 30, 2017 Nine Months Ended September 30, 2017
Increase (Decrease) Increase (Decrease)
Baseline
Labor, other benefits, contracting and materials $ 2
$ 14
Storm-related costs (1 ) —
Remeasurement of AMI-related regulatory asset^(a)
(4 ) (11 )
Uncollectible accounts expense 1
(1 )
Deferral of merger-related costs to regulatory asset (8 ) (1 )
Deferral of rate case and customer billing system costs (6 ) (6 )
BSC and PHISCO allocations^(b)
1
(22 )
Merger commitments^(c)
13
(132 )
Other (4 ) (10 )
(6 ) (169 )
Regulatory required programs
Purchased power administrative costs —
(3 )
Total decrease $ (6 ) $ (172 )

~~_________~~


~~(a)~~	~~Related to a remeasurement of a regulatory asset for legacy meters recognized in 2016.~~


~~(b)~~	~~Primarily related to merger severance and compensation costs recognized in 2016.~~


~~(c)~~	~~Primarily related to merger-related commitments for customer rate credits and charitable contributions recognized in 2016.~~

~~Depreciation and Amortization Expense~~

~~The changes in Depreciation and amortization expense for the three and nine months ended September 30, 2017 compared to the same periods in 2016, consisted of the following:~~

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Three Months Ended September 30, 2017 Nine Months Ended September 30, 2017
Increase (Decrease) Increase (Decrease)
Depreciation expense^(a)
$ 9
$ 25
Regulatory asset amortization 3
4
Regulatory required programs^(b)
(6 ) (8 )
Total increase $ 6
$ 21

~~_________~~


~~(a)~~	~~Depreciation expense increased due to higher depreciation rates in Maryland effective November 2016 and due to ongoing capital expenditures.~~


~~(b)~~	Depreciation and amortization expenses for regulatory required programs are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues and Operating and maintenance expense.

~~Taxes Other Than Income~~

Taxes other than income for the three and nine months ended September 30, 2017 compared to the same periods in 2016, decreased due to a decrease in the utility taxes that are collected and passed through by Pepco (which is substantially offset in Operating revenues), partially offset by higher property taxes.

~~Gain on sales of assets~~

~~Gain on sales of assets for the nine months ended September 30, 2017 compared to the same period in 2016 decreased due to a second quarter 2016 gain recorded from the sale of land.~~

~~Interest Expense, Net~~

~~Interest expense, net for the three months ended September 30, 2017 compared to the same period in 2016, remained relatively constant.~~

Interest expense, net for the nine months ended September 30, 2017 compared to the same period in 2016 decreased primarily due to the recording of interest expense for an uncertain tax position in the first quarter of 2016 and an increase in capitalized AFUDC interest.

~~Other, Net~~

Other, net for the three and nine months ended September 30, 2017 compared to the same periods in 2016 decreased primarily due to the September 2016 reversal of contributions in aid of construction tax gross-up reserves due to the determination that there is no legal obligation to refund customers per contract terms.

~~Effective Income Tax Rate~~

Pepco's effective income tax rate was 30.4% and 30.7% for the three months ended September 30, 2017 and 2016, respectively. Pepco's effective income tax rate was 23.3% and 63.0% for the nine months ended September 30, 2017 and 2016, respectively. In the first quarter of 2017, Pepco decreased its liability for unrecognized tax benefits by $21 million resulting in a benefit to Income taxes and a corresponding decrease in its effective tax rate. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates.

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~~Pepco Electric Operating Statistics and Revenue Detail~~

Three Months Ended
September 30, Nine Months Ended
September 30,
Retail Deliveries to Customers (in GWhs) 2017 2016 % Change Weather - Normal % Change 2017 2016 % Change Weather - Normal % Change
Retail Deliveries^(a)

Residential 2,281
2,675
(14.7 )% (5.2 )% 6,038
6,652
(9.2 )% (2.7 )%
Small commercial & industrial 347
394
(11.9 )% (7.2 )% 999
1,124
(11.1 )% (8.4 )%
Large commercial & industrial 4,146

4,314
(3.9 )% 0.8 % 11,306
11,890
(4.9 )% (3.0 )%
Public authorities & electric railroads 180
180
— % 1.1 % 542
544
(0.4 )% (0.2 )%
Total retail deliveries 6,954
7,563
(8.1 )% (1.7 )% 18,885
20,210
(6.6 )% (3.1 )%

As of September 30,
Number of Electric Customers 2017 2016
Residential 790,032
775,911
Small commercial & industrial

53,543
53,425
Large commercial & industrial 21,733
21,315
Public authorities & electric railroads 143
129
Total 865,451
850,780

Three Months Ended
September 30, Nine Months Ended
September 30,
Electric Revenue 2017 2016 % Change 2017 2016 % Change
Retail Sales^(a)

Residential $ 283
$ 315
(10.2 )% $ 744
$ 791
(5.9 )%
Small commercial & industrial 38
43
(11.6 )% 113
116
(2.6 )%
Large commercial & industrial 221
219
0.9 % 608
613
(0.8 )%
Public authorities & electric railroads 8
7
14.3 % 24
23
4.3 %
Total retail 550
584
(5.8 )% 1,489
1,543
(3.5 )%
Other revenue^(b)
54
51
5.9 % 160
152
5.3 %
Total electric revenue^(c)
$ 604
$ 635
(4.9 )% $ 1,649
$ 1,695
(2.7 )%

~~_________~~


~~(a)~~	Reflects delivery volumes and revenues from customers purchasing electricity directly from Pepco and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from Pepco, revenue also reflects the cost of energy and transmission.


~~(b)~~	~~Other revenue includes transmission revenue from PJM and wholesale electric revenues.~~


~~(c)~~	Includes operating revenues from affiliates totaling $1 million for the three months ended September 30, 2017 and 2016 and $4 million and $3 million for the nine months ended September 30, 2017 and 2016, respectively.

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~~Results of Operations - DPL~~

Three Months Ended September 30, Favorable (Unfavorable) Variance Nine Months Ended September 30, Favorable (Unfavorable) Variance
2017 2016 2017 2016
Operating revenues $ 327
$ 331
$ (4 ) $ 971
$ 974
$ (3 )
Purchased power and fuel expense 129
150
21
399
448
49
Revenues net of purchased power and fuel expense^(a)
198
181
17
572
526
46
Other operating expenses

Operating and maintenance 79
55
(24 ) 227
338
111
Depreciation and amortization 45
44
(1 ) 124
120
(4 )
Taxes other than income 15
14
(1 ) 43
42
(1 )
Total other operating expenses 139
113
(26 ) 394
500
106
Gain on sales of asset —
4
(4 ) —
4
(4 )
Operating income 59
72
(13 ) 178
30
148
Other income and (deductions)

Interest expense, net (13 ) (12 ) (1 ) (38 ) (37 ) (1 )
Other, net 4
3
1
10
9
1
Total other income and (deductions) (9 ) (9 ) —
(28 ) (28 ) —
Income before income taxes 50

63
(13 ) 150

2
148
Income taxes 19
19
—
43
18
(25 )
Net income (loss) $ 31
$ 44
$ (13 ) $ 107
$ (16 ) $ 123

~~_________~~

~~(a)~~

DPL evaluates its operating performance using the measure of revenue net of purchased power expense for electric sales and revenue net of fuel expense for natural gas sales. DPL believes revenue net of purchased power expense and revenue net of fuel expense are useful measurements because they provide information that can be used to evaluate its operational performance. DPL has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, Revenue net of purchased power expense and Revenue net of fuel expense 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.

~~Net Income (Loss)~~

~~Three Months Ended September 30, 2017 Compared to~~ Three Months Ended September 30, 2016. DPL's Net income for the three months ended September 30, 2017, was lower than the same period in 2016 as a result of the merger commitment reallocation from DPL to Exelon that decreased Operating and maintenance expense in 2016, partially offset by an increase in Revenue net of purchased power and fuel expense primarily resulting from higher electric distribution and natural gas revenues as a result of the distribution rate increases approved by the DPSC effective July 2016 and December 2016 and by the MDPSC effective February 2017.

~~Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016.~~ DPL's Net income (loss) for the nine months ended September 30, 2017, was higher than the same period in 2016 as a result of an increase in Revenue net of purchased power and fuel expense primarily resulting from higher electric distribution and natural gas revenues as a result of the distribution rate increases approved by the DPSC effective July 2016 and December 2016 and by the MDPSC effective February 2017, lower Operating and maintenance expense due to merger-related costs recognized in March 2016, lower uncollectible accounts expense, and the deferral of merger-related costs to a regulatory asset in 2017, and a decrease in income tax reserves in the first quarter of 2017 for uncertain tax positions related to the deductibility of certain merger commitments.

~~Revenues Net of Purchased Power and Fuel Expense~~

Operating revenues include revenue from the distribution and supply of electricity to DPL’s customers within its service territories at regulated rates. Operating revenues also include transmission service revenue that DPL receives as a transmission owner from PJM at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.

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Electric and natural gas revenues and purchased power and fuel expense are also affected by fluctuations in participation in the Customer Choice Program. All DPL customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers, respectively. The customers' choice of suppliers does not impact the volume of deliveries, but affects revenue collected from customers related to supplied energy and natural gas service.

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Electric 51 % 49 % 52 % 51 %
Natural Gas 53 % 51 % 35 % 32 %

~~Retail customers purchasing electric generation and natural gas from competitive electric generation and natural gas suppliers at September 30, 2017 and 2016 consisted of the following:~~

September 30, 2017 September 30, 2016
Number of customers % of total retail customers Number of customers % of total retail customers
Electric 78,426
15.0 % 79,501
15.4 %
Natural Gas 155
0.1 % 157
0.1 %

Retail deliveries purchased from competitive electric generation suppliers represented 53% and 54% of DPL’s retail kWh sales to Delaware customers and 48% and 48% of DPL's retail kWh sales to Maryland customers for the three and nine months ended September 30, 2017, respectively and 51% and 53% of DPL's retail kWh sales to Delaware customers and 47% and 47% of DPL's retail kWh sales to Maryland customers for the three and nine months ended September 30, 2016, respectively.

~~Operating revenues include transmission enhancement credits that DPL receives as a transmission owner from PJM in consideration for approved regional transmission expansion plan expenditures.~~

Natural gas operating revenue includes sources that are subject to price regulation (Regulated Gas Revenue) and those that generally are not subject to price regulation (Other Gas Revenue). Regulated gas revenue includes the revenue DPL receives from on-system natural gas delivered sales and the transportation of natural gas for customers within its service territory at regulated rates. Other gas revenue consists of off-system natural gas sales and the short-term release of interstate pipeline transportation and storage capacity not needed to serve customers. Off-system sales are made possible when low demand for natural gas by regulated customers creates excess pipeline capacity.

Purchased power expense consists of the cost of electricity purchased by DPL to fulfill its default electricity supply obligation and, as such, is recoverable from customers in accordance with the terms of public service commission orders. Purchased fuel expense consists of the cost of gas purchased by DPL to fulfill its obligation to regulated gas customers and, as such, is recoverable from customers in accordance with the terms of public service commission orders. It also includes the cost of gas purchased for off-system sales.

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The changes in DPL’s operating revenues net of purchased power and fuel expense for the three and nine months ended September 30, 2017 compared to the same periods in 2016 consisted of the following:

Three Months Ended
September 30, 2017 Nine Months Ended
September 30, 2017
Increase (Decrease)
Increase (Decrease)
Electric Gas Total Electric Gas Total
Weather $ (6 ) $ 1
$ (5 ) $ (9 ) $ (13 ) $ (22 )
Volume 2
(1 ) 1
3
10
13
Pricing - distribution revenues 17
—
17
49
2
51
Regulatory required programs (3 ) —
(3 ) (2 ) —
(2 )
Transmission revenues 5
—
5
4
—
4
Other 3
(1 ) 2
5
(3 ) 2
Total increase (decrease) $ 18
$ (1 ) $ 17
$ 50
$ (4 ) $ 46

~~Revenue Decoupling.~~ DPL’s results historically have been seasonal, generally producing higher revenue and income in the warmest and coldest periods of the year. For retail customers of DPL in Maryland, revenues are not affected by unseasonably warmer or colder weather because a bill stabilization adjustment (BSA) for retail customers was implemented that provides for a fixed distribution charge per customer. The BSA has the effect of decoupling the distribution revenue recognized in a reporting period from the amount of power delivered during the period. As a result, the only factors that will cause distribution revenue from customers in Maryland to fluctuate from period to period are changes in the number of customers and changes in the approved distribution charge per customer. A modified fixed variable rate design, which would provide for a charge not tied to a customer’s volumetric consumption of electricity or natural gas, has been proposed for DPL electricity and natural gas customers in Delaware. Changes in customer usage (due to weather conditions, energy prices, energy efficiency programs or other reasons) from period to period have no impact on reported distribution revenue for customers to whom the BSA applies.

In accounting for the BSA in Maryland, a Revenue Decoupling Adjustment is recorded representing either (i) a positive adjustment equal to the amount by which revenue from Maryland retail distribution sales falls short of the revenue that DPL is entitled to earn based on the approved distribution charge per customer or (ii) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that DPL is entitled to earn based on the approved distribution charge per customer.

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~~Weather.~~ The demand for electricity and natural gas in areas not subject to the BSA 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.recovered. During the three and nine months ended September 30, ~~2017~~2023 compared to the same ~~periods in 2016, operating revenue net of purchased power and fuel expense was lower due to the impact of unfavorable weather conditions in DPL'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 DPL's electric service territory and a 30-year period in DPL's natural gas service territory. The changes in heating and cooling degree days in DPL’s service territory for the three and nine months ended September 30, 2017 compared to the same periods in 2016 and normal weather consisted of the following:

Electric Service Territory % Change
Three Months Ended September 30, 2017 2016 Normal 2017 vs. 2016 2017 vs. Normal
Heating Degree-Days 24
14
33
71.4 % (27.3 )%
Cooling Degree-Days 867
1,103
856
(21.4 )% 1.3 %

Nine Months Ended September 30,
Heating Degree-Days 2,384
2,812
2,933
(15.2 )% (18.7 )%
Cooling Degree-Days 1,228
1,410
1,184
(12.9 )% 3.7 %

Natural Gas Service Territory % Change
Three Months Ended September 30, 2017 2016 Normal 2017 vs. 2016 2017 vs. Normal
Heating Degree-Days 28
20
42
40.0 % (33.3 )%

Nine Months Ended September 30,
Heating Degree-Days 2,431
2,913
3,062
(16.5 )% (20.6 )%

~~Volume.~~ ~~The increase in operating~~2022, transmission revenue net of purchased power and fuel expense related to delivery volume, exclusive of the effects of weather, for the three and nine months ended September 30, 2017 compared to the same periods in 2016, primarily reflects the impact of increased ~~natural gas average customer usage and customer growth.~~

~~Pricing—Distribution Revenues.~~ ~~The increase in electric operating revenues net of purchased power expense as a result of pricing for the three and nine months ended September 30, 2017 compared to the same periods in 2016 was~~ primarily due to ~~the impact of higher electric distribution~~increases in underlying costs and ~~natural gas rates charged to Delaware customers that became effective in July~~capital investment.

Other Revenue includes rental revenue, service connection fees, and December 2016 and the impact of higher electric distribution rates charged to Maryland customers that became effective in February 2017. See Note 5—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.mutual assistance revenues.

Regulatory Required ~~Programs.~~ ~~This represents the change in operating~~Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency ~~programs.~~programs, DE Renewable Portfolio Standards, SOS procurement and administrative costs, and GCR costs. The riders are designed to provide full and current cost recovery as well as a ~~return.~~return in certain instances. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income ~~in DPL's Consolidated Statements~~taxes. All customers have the choice to purchase electricity from competitive electric generation suppliers; however, only certain commercial and industrial customers have the choice to purchase natural gas from competitive natural gas suppliers. Customer choice programs do not impact the volume of ~~Operations~~deliveries as DPL remains the distribution service provider for all customers and ~~Comprehensive Income. Refer to the Operating and maintenance expense and Depreciation and amortization expense discussion below~~charges a regulated rate for ~~additional information on included programs.~~

~~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 other billing adjustments. The increase in revenue net of purchased power expense for the three months ended September 30, 2017 compared to the same period in 2016 is a result of higher rates effective June 1, 2017 related to increases in transmission plant investment and operating expenses. The increase in revenue net of purchased power expense for the nine months

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~~ended September 30, 2017 compared~~distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation or natural gas from competitive suppliers, DPL either acts as the ~~same period in 2016 is a result of higher rates effective June 1, 2017~~billing agent or the competitive supplier separately bills its own customers, and ~~June 1, 2016 related to increases in transmission plant investment~~therefore does not record Operating revenues or Purchased power and ~~operating expenses, partially offset by lower revenue~~fuel expense related to the ~~MAPP abandonment recovery period~~electricity and/or natural gas. For customers that ~~ended in March 2016.~~

~~Other.~~ ~~Other revenue, which can vary period~~choose to ~~period, includes rental revenue, revenue~~purchase electric generation or natural gas from DPL, DPL is permitted to recover the electricity, natural gas, and REC procurement costs from customers and therefore records the amounts related to ~~late payment charges, assistance provided to other utilities through mutual assistance programs,~~the electricity, natural gas, and ~~recoveries of other taxes.~~

~~Operating and Maintenance Expense~~

Three Months Ended
September 30, Increase (Decrease) Nine Months Ended
September 30, Increase (Decrease)
2017 2016 2017 2016
Operating and maintenance expense - baseline $ 76
$ 50
$ 26
$ 221
$ 328
$ (107 )
Operating and maintenance expense - regulatory required programs^(a)
3
5
(2 ) 6
10
(4 )
Total operating and maintenance expense $ 79
$ 55
$ 24
$ 227
$ 338
$ (111 )

~~_________~~


~~(a)~~	Operating and maintenance expenses for regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues.

~~The changes~~RECs in Operating revenues and ~~maintenance expense~~Purchased power and fuel expense. DPL recovers electricity and REC procurement costs from customers with a slight mark-up, and natural gas costs without mark-up.

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

The increase of $18 million and $55 million for the three and nine months ended September 30, ~~2017~~2023, compared to the same ~~periods~~period in ~~2016,~~2022, respectively, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.

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


	Three Months Ended September 30, 2023		Nine Months Ended September 30, 2023
	Increase		Increase (Decrease)
Storm-related Costs	$	7	$	5
BSC and PHISCO costs	4		3
Labor and contracting	3		(3)
Credit Loss Expense	2		—
Pension and non-pension postretirement benefits expense	1		4
Other	3		2
	20		11
Regulatory required programs	—		1
Total increase	$	20	$	12

Three Months Ended September 30, 2017 Nine Months Ended September 30, 2017
Increase (Decrease)
Increase (Decrease)
Baseline
Labor, other benefits, contracting and materials $ 3
$ 3
Storm-related costs (2 ) 4
Uncollectible accounts expense (2 ) (7 )
Remeasurement of AMI-related regulatory asset^(a)
(1 ) (2 )
Deferral of merger-related costs to regulatory asset —
(6 )
BSC and PHISCO allocations^(b)
(1 ) (15 )
Merger commitments^(c)
27
(79 )
Other 2
(5 )
26
(107 )
Regulatory required programs
Purchased power administrative costs (2 ) (4 )
Total increase (decrease) $ 24
$ (111 )

~~_________~~


~~(a)~~	~~Related to a remeasurement of a regulatory asset for legacy meters recognized in 2016.~~


~~(b)~~	~~Primarily related to merger severance and compensation costs recognized in 2016.~~


~~(c)~~	~~Primarily related to merger-related commitments for customer rate credits and charitable contributions recognized in 2016.~~

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~~Depreciation and Amortization Expense~~

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


	Three Months Ended September 30, 2023		Nine Months Ended September 30, 2023
	Increase		Increase (Decrease)
Depreciation and amortization(a)	$	3	$	15
Regulatory required programs	—		(4)
Regulatory asset amortization	—		(1)
Total increase	$	3	$	10

__________

(a)For the three months ended September 30, 2023, reflects ongoing capital expenditures and higher transmission depreciation rates effective September 2022. For the nine months ended September 30, 2023, reflects ongoing capital expenditures, higher distribution depreciation rates in Maryland effective March 2022, and higher transmission depreciation rates effective September 2022.

Interest expense, net increased by $2 million and $5 million for the three and nine months ended September 30, ~~2017~~2023 compared to the same ~~periods~~period in ~~2016 consisted~~2022, respectively, primarily due to an increase in interest rates and the issuance of ~~the following:~~debt in 2022 and 2023.

Three Months Ended September 30, 2017 Nine Months Ended September 30, 2017
Increase (Decrease)
Increase (Decrease)
Depreciation expense^(a)
$ 3
$ 9
Regulatory asset amortization —
(2 )
Regulatory required programs^(b)

(2 ) (3 )
Total increase $ 1
$ 4

~~_________~~


~~(a)~~	~~Depreciation expense increased due to higher depreciation rates in Maryland effective February 2017 and due to ongoing capital expenditures.~~


~~(b)~~	Depreciation and amortization expenses for regulatory required programs are recoverable from customers on a full and current basis through approved regulated rates. A partially offsetting amount has been reflected in Operating revenues and Operating and maintenance expense.

~~Taxes Other Than Income~~

~~Taxes other than income for the three and nine months ended September 30, 2017 compared to the same periods in 2016 remained relatively constant.~~

~~Interest Expense, Net~~

~~Interest expense, net for the three and nine months ended September 30, 2017 compared to the same periods in 2016 remained relatively constant.~~

~~Other, Net~~

~~Other, net for the three and nine months ended September 30, 2017 compared to the same periods in 2016 remained relatively constant.~~

Effective ~~Income Tax Rate~~

~~DPL's effective~~ income tax ~~rate was 38.0%~~rateswere 15.7% and ~~30.2%~~3.7% for the three months ended September 30, ~~2017~~2023 and ~~2016, respectively. DPL's effective income tax rate was 28.7%~~2022, respectively, and ~~900.0%~~16.3% and 5.8% for the nine months ended September 30, ~~2017~~2023 and ~~2016,~~2022, respectively. ~~In the first quarter of 2017, DPL decreased its liability for unrecognized tax benefits by $16 million resulting in a benefit to Income taxes and a corresponding decrease in its effective tax rate.~~ See Note ~~12 -~~7 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

~~DPL Electric Operating Statistics and Revenue Detail~~

136

Three Months Ended
September 30, % Change Weather - Normal % Change Nine Months Ended
September 30, % Change Weather - Normal % Change
Retail Deliveries to Customers (in GWhs) 2017 2016 2017 2016
Retail Deliveries^(a)

Residential 1,439
1,601
(10.1 )% (2.2 )% 3,843
4,066
(5.5 )% 0.4 %
Small commercial & industrial 636
642
(0.9 )% 3.2 % 1,693
1,746
(3.0 )% (0.9 )%
Large commercial & industrial 1,245
1,250
(0.4 )% 4.1 % 3,440
3,492
(1.5 )% 0.3 %
Public authorities & electric railroads 10
9
11.1 % 11.1 % 35
35
— % — %
Total retail deliveries 3,330
3,502
(4.9 )% 1.2 % 9,011
9,339
(3.5 )% 0.1 %

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ACE

As of September 30,
Number of Electric Customers 2017 2016
Residential 458,790
455,640
Small commercial & industrial 60,542
60,034
Large commercial & industrial

1,406
1,414
Public authorities & electric railroads 633
643
Total 521,371
517,731

Three Months Ended
September 30, % Change Nine Months Ended
September 30, % Change
Electric Revenue 2017 2016 2017 2016
Retail Sales^(a)

Residential $ 183
$ 200
(8.5 )% $ 508
$ 522
(2.7 )%
Small commercial & industrial 49
48
2.1 % 138
143
(3.5 )%
Large commercial & industrial 26
24
8.3 % 77
74
4.1 %
Public authorities & electric railroads 3
2
50.0 % 11
9
22.2 %
Total retail 261
274
(4.7 )% 734
748
(1.9 )%
Other revenue^(b)
48
40
20.0 % 132
124
6.5 %
Total electric revenue^(c)
$ 309
$ 314
(1.6 )% $ 866
$ 872
(0.7 )%

~~_________~~


~~(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. For customers purchasing electricity from DPL, revenue also reflects the cost of energy and transmission.


~~(b)~~	~~Other revenue includes transmission revenue from PJM and wholesale electric revenues.~~


~~(c)~~	~~Includes operating revenues from affiliates totaling $2 million for the three months ended September 30, 2017 and 2016 and $6 million for the nine months ended September 30, 2017 and 2016.~~

~~DPL Natural Gas Operating Statistics and Revenue Detail~~

Three Months Ended
September 30, % Change Weather - Normal % Change Nine Months Ended
September 30, % Change Weather - Normal % Change
Retail Deliveries to Customers (in mmcf) 2017 2016 2017 2016
Retail Deliveries
Retail sales 1,069
1,121
(4.6 )% (6.4 )% 8,679
9,253
(6.2 )% 6.5 %
Transportation & other 1,197
1,166
2.7 % 2.4 % 4,690
4,455
5.3 % 7.9 %
Total natural gas deliveries 2,266
2,287
(0.9 )% (2.0 )% 13,369
13,708
(2.5 )% 7.0 %

As of September 30,
Number of Gas Customers 2017 2016
Residential 121,238
120,075
Commercial & industrial 9,700
9,656
Transportation & other 155
157
Total 131,093
129,888

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~~Table of Contents~~

Three Months Ended
September 30, % Change Nine Months Ended
September 30, % Change
Natural Gas Revenue 2017 2016 2017 2016
Retail Sales^(a)

Retail sales $ 12
$ 13
(7.7 )% $ 87
$ 87
— %
Transportation & other^(b)
6
4
50.0 % 18
15
20.0 %
Total natural gas revenues $ 18
$ 17
5.9 % $ 105
$ 102
2.9 %

~~__________~~


~~(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. For customers purchasing natural gas from DPL, revenue also reflects the cost of natural gas.


~~(b)~~	~~Transportation and other revenue includes off-system natural gas sales and the short-term release of interstate pipeline transportation and storage capacity not needed to serve customers.~~

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Results of Operations -— ACE


	Three Months Ended September 30,				Favorable (Unfavorable) Variance		Nine Months Ended September 30,				Favorable (Unfavorable) Variance
	2023		2022				2023		2022
Operating revenues	$	502	$	462	$	40	$	1,172	$	1,120	$	52


Operating expenses
Purchased power	221		197		(24)		493		497		4
Operating and maintenance	94		80		(14)		259		251		(8)
Depreciation and amortization	77		74		(3)		212		192		(20)
Taxes other than income taxes	2		2		—		7		7		—
Total operating expenses	394		353		(41)		971		947		(24)

Operating income	108		109		(1)		201		173		28
Other income and (deductions)
Interest expense, net	(19)		(17)		(2)		(52)		(49)		(3)
Other, net	5		3		2		13		9		4
Total other income and (deductions)	(14)		(14)		—		(39)		(40)		1
Income before income taxes	94		95		(1)		162		133		29
Income taxes	23		1		(22)		40		2		(38)
Net income	$	71	$	94	$	(23)	$	122	$	131	$	(9)

Three Months Ended September 30, Favorable (Unfavorable) Variance Nine Months Ended September 30, Favorable (Unfavorable) Variance
2017 2016 2017 2016
Operating revenues $ 370
$ 421
$ (51 ) $ 915
$ 982
$ (67 )
Purchased power expense 176
221
45
442
520
78
Revenues net of purchased power expense^(a)
194
200
(6 ) 473
462
11
Other operating expenses

Operating and maintenance 72
67
(5 ) 225
346
121
Depreciation and amortization 41
49
8
113
130
17
Taxes other than income 2
1
(1 ) 6
6
—
Total other operating expenses 115
117
2
344
482
138
Gain on sales of assets —
—
—
—
1
(1 )
Operating income (loss) 79
83
(4 ) 129
(19 ) 148
Other income and (deductions)

Interest expense, net (15 ) (15 ) —
(46 ) (47 ) 1
Other, net 1
2
(1 ) 6
8
(2 )
Total other income and (deductions) (14 )
(13 ) (1 ) (40 )
(39 ) (1 )
Income (loss) before income taxes 65

70
(5 ) 89

(58 ) 147
Income taxes 24
23
(1 ) 12
(8 ) (20 )
Net income (loss) $ 41
$ 47
$ (6 ) $ 77
$ (50 ) $ 127

~~_________~~

~~(a)~~

ACE evaluates its operating performance using the measure of revenue net of purchased power expense for electric sales. ACE believes Revenue net of purchased power expense is a useful measurement of its performance because it provides information that can be used to evaluate its operational performance. ACE has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, Revenue net of purchased power expense 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.

~~Net Income (Loss)~~

Three Months Ended September 30, ~~2017~~2023 Compared to Three Months Ended September 30, ~~2016.~~ ~~ACE's~~2022. Net income ~~for the three months ended September 30, 2017, was lower than the same period in 2016,~~ decreased by $23 million primarily due to ~~a decrease~~timing of excess deferred tax amortization and an increase in ~~Revenue net of purchased power~~depreciation expense ~~resulting from lower distribution revenues due to lower average customer usage~~ and ~~unfavorable weather related sales, partially offset by the impact of distribution rate increases approved by the NJBPU effective August 2016.~~various operating expenses.

Nine Months Ended September 30, ~~2017~~2023 Compared to Nine Months Ended September 30, ~~2016.~~ ~~ACE's~~2022. Net income ~~(loss) for the nine months ended September 30, 2017, was higher than the same period in 2016,~~ decreased by $9 million primarily due to an increase in depreciation expense and various operating expenses, partially offset by higher transmission rates.

The changes in Operating revenues consisted of the following:


	Three Months Ended September 30, 2023		Nine Months Ended September 30, 2023
	Increase (Decrease)		Increase (Decrease)
Distribution	$	15	$	27
Transmission	5		30
Other	(1)		(1)
	19		56
Regulatory required programs	21		(4)
Total increase	$	40	$	52

Revenue ~~net of purchased power expense resulting~~Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from ~~higher~~ electric distribution ~~revenues~~in New Jersey are not impacted by abnormal weather or usage per customer as a result of ~~a distribution rate increase approved by~~ the ~~NJBPU~~CIP which became effective, ~~August 2016, lower Operating and maintenance expense mostly due to merger-related costs recognized in March 2016 and a decrease in income tax reserves~~prospectively, in the ~~first~~third quarter ~~2017 for uncertain tax positions related~~of 2021. The CIP compares current distribution revenues by customer class to ~~the deductibility of~~approved target revenues established in ACE’s most recent distribution base rate case. The CIP is calculated annually, and recovery is subject to certain ~~merger commitments.~~

~~Revenues Net of Purchased Power Expense~~

conditions, including an earnings test and ceilings on customer rate increases. While Operating revenues include revenue from the distribution and supply of electricity to ACE’s customers within its service territories at regulated rates. Operating revenues also include transmission service revenue that ACE receives as a transmission owner from PJM at rates regulatedare not impacted by ~~FERC. Transmission rates~~abnormal weather or usage per customer, they are ~~updated annually based on a FERC-approved formula methodology.~~

~~Electric revenues and purchased power expense are also affected~~impacted by ~~fluctuations in participation~~changes in the ~~Customer Choice Program. All ACE customers have the choice to purchase electricity from competitive electric generation suppliers. The customer's choice~~number of ~~supplier does not impact the volume of deliveries, but affects revenue collected from customers related to supplied energy service.~~

customers.

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	At September 30,
Number of Electric Customers	2023	2022
Residential	504,330	501,869
Small commercial & industrial	62,410	62,204
Large commercial & industrial	2,980	3,075
Public authorities & electric railroads	729	731
Total	570,449	567,879

~~Retail deliveries purchased from competitive electric generation suppliers (as a percentage of kWh sales)~~Distribution Revenue increased for both the three and nine months ended September 30, ~~2017, compared to the same periods in 2016, consisted of the following:~~

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Electric 44 % 44 % 48 % 46 %

~~Retail customers purchasing electric generation from competitive electric generation suppliers at September 30, 2017 and 2016 consisted of the following:~~

September 30, 2017 September 30, 2016
Number of customers % of total retail customers Number of customers % of total retail customers
Electric 91,219
17 % 96,837
18 %

Operating revenues include revenue from Transition Bond Charges that ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds, revenue from the resale in the PJM wholesale markets for energy and capacity purchased under contacts with unaffiliated NUGs, and revenue from transmission enhancement credits.

Purchased power expense consists of the cost of electricity purchased by ACE to fulfill its default electricity supply obligation and, as such, is recoverable from customers in accordance with the terms of public service commission orders.

~~The changes in ACE’s operating revenue net of purchased power expense for the three and nine months ended September 30, 2017 compared to the same periods in 2016 consisted of the following:~~

Three Months Ended
September 30, 2017 Nine Months Ended
September 30, 2017
Increase (Decrease) Increase (Decrease)
Weather $ (5 ) $ (7 )
Volume (12 ) (15 )
Pricing - distribution revenues 16
36
Regulatory required programs (9 ) (19 )
Transmission revenues 4
17
Other —
(1 )
Total (decrease) increase $ (6 ) $ 11

~~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 three and nine months ended September 30, 2017 compared to the same periods in 2016, operating revenue net of purchased power and fuel expense was lower due to the impact of unfavorable weather conditions in ACE's service territory.

For retail customers of ACE, distribution revenues are not decoupled from the distribution of electricity by ACE, and thus are subject to variability due to changes in customer consumption. Therefore, changes in customer usage (due to weather conditions, energy prices, energy savings programs or other reasons) from period to period have a direct impact on reported distribution revenue for customers in ACE's service territory.

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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 three and nine months ended September 30, 2017 compared to the same periods in 2016 consisted of the following:

Normal % Change
2017 2016 2017 vs. 2016 2017 vs. Normal
Three Months Ended September 30,
Heating Degree-Days 23
17
42
35.3 % (45.2 )%
Cooling Degree-Days 830
1,006
806
(17.5 )% 3.0 %

Nine Months Ended September 30,

Heating Degree-Days 2,608
2,938
3,103
(11.2 )% (16.0 )%
Cooling Degree-Days 1,153
1,267
1,092
(9.0 )% 5.6 %

~~Volume.~~ ~~During the three months ended September 30, 2017,~~2023 compared to the same period in ~~2016, the decrease in operating revenue net of purchased power expense related to delivery volume, exclusive of the effects of weather, is primarily~~2022 due to lower average customer usage. During the nine months ended September 30, 2017 compared to the same period in 2016, primarily reflects lower average customer usage, partially offset by the impact of customer growth.

~~Pricing—Distribution Revenues.~~ ~~The increase in operating revenue net of purchased power expense for the three and nine months ended September 30, 2017, compared to the same periods in 2016, was~~higher distribution rates primarily due to the ~~impact~~expiration of higher electric distribution base rates charged to customers that became effective in August 2016. See Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

~~Regulatory Required Programs.~~ This represents the change in operating revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs. 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 Taxes other than income in ACE's Consolidated Statements of Operations and Comprehensive Income. Refercustomer credits related to the ~~Operating and maintenance expense and Depreciation and amortization expense discussion below for additional information on included programs.~~TCJA tax benefits.

Transmission Revenues.Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being ~~recovered~~recovered. Transmission revenue increased for both the three and ~~other billing adjustments. The increase in revenue net of purchased power expense for the three~~nine months ended September 30, ~~2017~~2023 compared to the same period in ~~2016 is a result of higher rates effective June 1, 2017 and related~~2022, primarily due to increases in ~~transmission plant investment~~underlying costs and ~~operating expenses. The increase in~~capital investment.

Other Revenue includes rental revenue, ~~net of purchased power expense for the nine months ended September 30, 2017 compared to the same period in 2016 is a result of higher rates effective June 1, 2017 and June 1, 2016~~revenue related to ~~increases~~late payment charges, mutual assistance revenues, and recoveries of other taxes.

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 Bond Charge, and BGS procurement and administrative costs. The riders are designed to provide full and current cost recovery as well as a return in ~~transmission plant investment and operating expenses.~~

~~Operating and Maintenance Expense~~

Three Months Ended September 30, Increase (Decrease) Nine Months Ended September 30,
Increase
(Decrease)
2017 2016 2017 2016
Operating and maintenance expense - baseline $ 71
$ 66
$ 5
$ 222
$ 343
$ (121 )
Operating and maintenance expense - regulatory required programs^(a)
1
1
—
3
3
—
Total operating and maintenance expense $ 72
$ 67
$ 5
$ 225
$ 346
$ (121 )

~~_________~~


~~(a)~~	~~Operating and maintenance expenses for regulatory required programs are~~certain instances. The costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues.

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~~The changes~~these programs are included in Purchased power expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries, as ACE remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, ACE acts as the billing agent and therefore, ACE does not record Operating revenues or Purchased power expense related to the electricity. For customers that choose to purchase electric generation from ACE, ACE is permitted to recover the electricity, ZEC, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power expense related to the electricity, ZECs, and RECs.

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

The increase of $24 million and decrease of $4 million for the three and nine months ended September 30, ~~2017~~2023 compared to the same ~~periods~~period in ~~2016~~2022, respectively, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.

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ACE

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


	Three Months Ended September 30, 2023		Nine Months Ended September 30, 2023
	Increase		Increase (Decrease)
BSC and PHISCO costs	$	5	$	6
Labor and contracting	5		2
Storm-related costs	3		—
Pension and non-pension postretirement benefits expense	—		1

Other	1		1
	14		10

Regulatory required programs(a)	—		(2)
Total increase	$	14	$	8

Three Months Ended
September 30, 2017 Nine Months Ended
September 30, 2017
Increase (Decrease) Increase (Decrease)
Baseline
Labor, other benefits, contracting and materials $ 3
$ 6
Storm-related costs (3 ) (2 )
BSC and PHISCO allocations^(a)
—
(11 )
Deferral of merger-related costs to regulatory asset (9 ) (9 )
Merger commitments^(b)
10
(111 )
Other 4
6
Total increase (decrease) $ 5
$ (121 )
__________

~~_________~~


~~(a)~~	~~Primarily related to merger severance and compensation costs recognized in 2016.~~


~~(b)~~	~~Primarily related to merger-related commitments for customer rate credits and charitable contributions recognized in 2016.~~

~~Depreciation~~(a)ACE is allowed to recover from or refund to customers the difference between its annual credit loss expense and ~~Amortization Expense~~the amounts collected in rates annually through the Societal Benefits Charge.

The changes in Depreciation and amortizationexpense consisted of the following:


	Three Months Ended September 30, 2023		Nine Months Ended September 30, 2023
	Increase (Decrease)		Increase
Depreciation and amortization(a)	$	6	$	19

Regulatory required programs(b)	(3)		1
Total increase	$	3	$	20

__________

(a)Reflects ongoing capital expenditures and higher transmission depreciation rates effective September 2022.

(b)For the nine months ended September 30, 2023, regulatory required programs increased primarily due to the regulatory asset amortization of the PPA termination obligation which is fully offset in Operating revenues.

Interest expense, net increased by $2 million and $3 million for the three and nine months ended September 30, ~~2017~~2023 compared to the same ~~periods~~period in ~~2016 consisted~~2022, respectively, primarily due to an increase in interest rates and the issuance of ~~the following:~~debt in 2022 and 2023.

Three Months Ended
September 30, 2017 Nine Months Ended
September 30, 2017
Increase (Decrease) Increase (Decrease)
Depreciation expense^(a)
$ 1
$ 4
Regulatory asset amortization —
(2 )
Regulatory required programs^(b)
(9 ) (19 )
Total decrease $ (8 ) $ (17 )

~~_________~~


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

~~(b)~~

Regulatory required programs decreased for the three and nine months ended September 30, 2017 compared to the same periods in 2016 as a result of lower revenue due to rate decreases effective October 2016 for the ACE Transition Bond Charge and Market Transition Charge Tax. Depreciation and amortization expenses for regulatory required programs are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues and Operating and maintenance expense.

~~Taxes Other Than Income~~

~~Taxes other than income for the three and nine months ended September 30, 2017 compared to the same periods in 2016, remained relatively constant.~~

~~Gain on sales of assets~~

~~Gain on sales of assets for the three and nine months ended September 30, 2017 compared to the same periods in 2016 remained relatively constant.~~

~~Interest Expense, Net~~

~~Interest expense, net for the three and nine months ended September 30, 2017 compared to the same periods in 2016 remained relatively constant.~~

~~Other, Net~~

~~Other, net for the three and nine months ended September 30, 2017 compared to the same periods in 2016, remained relatively constant.~~

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Effective ~~Income Tax Rate~~

~~ACE's effective~~ income tax ~~rate was 36.9%~~rates were 24.5% and ~~32.9%~~1.1% for the three months ended September 30, ~~2017~~2023 and ~~2016, respectively. ACE's effective income tax rate was 13.5%~~2022, respectively, and ~~13.8%~~24.7% and 1.5% for the nine months ended September 30, ~~2017~~2023 and ~~2016,~~2022, respectively. ~~In the first quarter of 2017, ACE decreased its liability for unrecognized tax benefits by $22 million resulting in a benefit to Income taxes and a corresponding decrease in its effective tax rate.~~ See Note ~~12 -~~7 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

~~ACE Electric Operating Statistics and Revenue Detail~~

139

Three Months Ended
September 30, % Change Weather - Normal % Change Nine Months Ended
September 30, % Change Weather - Normal % Change
Retail Deliveries to Customers (in GWhs) 2017 2016 2017 2016
Retail Deliveries^(a)

Residential 1,349
1,575
(14.3 )% (10.4 )% 3,042
3,327
(8.6 )% (6.0 )%
Small commercial & industrial 407
426
(4.5 )% (1.9 )% 992
998
(0.6 )% 0.8 %
Large commercial & industrial 939
1,032
(9.0 )% (6.3 )% 2,557
2,705
(5.5 )% (4.6 )%
Public authorities & electric railroads 9
11
(18.2 )% (18.2 )% 33
35
(5.7 )% (5.7 )%
Total retail deliveries 2,704
3,044
(11.2 )% (7.8 )% 6,624
7,065
(6.2 )% (4.5 )%

As of September 30,
Number of Electric Customers 2017 2016
Residential 486,212
483,542
Small commercial & industrial 60,982
60,875
Large commercial & industrial 3,726
3,796
Public authorities & electric railroads 633
593
Total 551,553
548,806

Three Months Ended
September 30, % Change Nine Months Ended
September 30, % Change
Electric Revenue 2017 2016 2017 2016
Retail Sales^(a)

Residential $ 211
$ 249
(15.3 )% $ 484
$ 530
(8.7 )%
Small commercial & industrial 53
55
(3.6 )% 129
133
(3.0 )%
Large commercial & industrial 49
57
(14.0 )% 143
158
(9.5 )%
Public authorities & electric railroads 3
4
(25.0 )% 10
10
— %
Total retail 316
365
(13.4 )% 766
831
(7.8 )%
Other revenue^(b)
54
56
(3.6 )% 149
151
(1.3 )%
Total electric revenue^(c)
$ 370
$ 421
(12.1 )% $ 915
$ 982
(6.8 )%

~~_________~~


~~(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. For customers purchasing electricity from ACE, revenue also reflects the cost of energy and transmission.


~~(b)~~	~~Other revenue includes transmission revenue from PJM and wholesale electric revenues.~~


~~(c)~~	Includes operating revenues from affiliates totaling $0 million and $1 million for the three months ended September 30, 2017 and 2016, respectively, and $2 million and $3 million for the nine months ended September 30, 2017 and 2016, respectively.

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Liquidity and Capital Resources (All Registrants)

Exelon activity presented below includes the activity of PHI, Pepco, DPL and ACE, from the PHI Merger effective date of March 24, 2016 through September 30, 2017. Exelon prior year activity is unadjusted for the effects of the PHI Merger. Due to the application of push-down accounting to the PHI entity, PHI's activity is presented in two separate reporting periods, the legacy PHI activity through March 23, 2016 (Predecessor), and PHI activity for the remainder of the period after the PHI merger date (Successor). For each of Pepco, DPL and ACE the activity presented below include its activity for the nine months ended September 30, 2017 and 2016. 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, including construction expenditures, retire debt, pay dividends, and fund pension and OPEB obligations. The Registrants spend a significant amount of cash on capital improvements and construction projects that have a long-term return on investment. Additionally, the Utility Registrants 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. 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 ~~unsecured revolving~~ credit facilities with aggregate bank commitments of $9$4.0 billion. ~~In addition, Generation has $525 millionin bilateral facilities with banks which have various expirations between December 2017 and January 2019.~~ 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”~~Matters and Cash Requirements” section below for ~~further discussion.~~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 1110 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for ~~further discussion of~~additional information on the Registrants’ debt and credit agreements.

~~NRC Minimum Funding Requirements~~

~~NRC regulations require that licensees~~Cash flows related to Generation have not been presented as discontinued operations and are included in the Consolidated Statements of ~~nuclear generating facilities demonstrate reasonable assurance that sufficient funds will be available in certain minimum amounts to decommission~~Cash Flows for only 2022. The Exelon Consolidated Statement of Cash Flows for 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 13 - Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements for additional information on the NRC minimum funding requirements.

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 Exelon to post parental guarantees for Generation’s share of the obligations. However, the amount of any required guarantees will ultimately depend on the decommissioning approach adopted at each site, the associated level of costs, and the decommissioning trust fund investment performance going forward. Within two years after shutting down a plant, Generation must submit a post-shutdown decommissioning activities report (PSDAR) to the NRC that includes the planned option for decommissioning the site. As discussed in Note 13 — Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements, Generation filed its biennial decommissioning funding status report with the NRC on March 31, 2017 and demonstrated adequate funding assurance for all nuclear units currently operating. As ofnine months ended September 30, ~~2017, across the four alternative decommissioning approaches available, Generation estimates a parental guarantee~~2022 includes one month of ~~up to $115 million~~cash flows from Exelon could be required for TMI, dependent upon the ultimate decommissioning approach selected. TMI passes the NRC minimum funding test based on the unit's 2019 retirement date under the decommissioning approach currently considered to be the most likely. For Oyster Creek, none of the alternative decommissioning approaches available would require Exelon to post a parental guarantee.Generation.

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.

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However, the NRC must approve an additional 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). While the ultimate amounts may vary greatly and could be reduced by alternate decommissioning scenarios and/or reimbursement of certain costs under the United States Department of Energy reimbursement agreements or future litigation, across the four alternative decommissioning approaches available, if TMI or Oyster Creek were to fail to obtain the exemption, Generation estimates it could incur spent fuel management and site restoration costs over the next ten years of up to $190 million and $150 million net of taxes, respectively, dependent upon the ultimate decommissioning approach selected. Under the decommissioning approach currently considered the most likely for each unit, Generation estimates it could incur spent fuel management and site restoration costs over the next ten years of up to $170 million and $130 million net of taxes, respectively, if TMI or Oyster Creek were to fail to obtain the exemption.

~~Junior Subordinated Notes~~

In June 2014, Exelon issued $1.15 billion of junior subordinated notes in the form of 23 million equity units at a stated amount of $50.00 per unit. Each equity unit represented an undivided beneficial ownership interest in Exelon’s $1.15 billion of 2.50% junior subordinated notes due in 2024 (“2024 notes”) and a forward equity purchase contract. As contemplated in the June 2014 equity unit structure, in April 2017, Exelon completed the remarketing of the 2024 notes into $1.15 billion of 3.497% junior subordinated notes due in 2022 (“Remarketing”). Exelon conducted the Remarketing on behalf of the holders of equity units and did not directly receive any proceeds therefrom. Instead, the former holders of the 2024 notes used debt remarketing proceeds towards settling the forward equity purchase contract with Exelon on June 1, 2017. Exelon issued approximately 33 million shares of common stock from treasury stock and received $1.15 billion upon settlement of the forward equity purchase contract. When reissuing treasury stock Exelon uses the average price paid to repurchase shares to calculate a gain or loss on issuance and records gains or losses directly to retained earnings. A loss on reissuance of treasury shares of $1.05 billion was recorded to retained earnings as of September 30, 2017. See Note 17 - Earnings Per Share and Equity of the Combined Notes to Consolidated Financial Statements for further information on the issuance of common stock.

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. Additionally, ComEd is required to purchase CMCs from participating nuclear-powered generating facilities for a five-year period that began in June 2022, and all of its costs of doing so will be recovered through a rider. The price to be paid for each CMC is established through a competitive bidding process. ComEd will provide net payments to, or collect net payments from, customers for the difference between customer credits issued and the credit to be received from the participating nuclear-powered generating facilities. ComEd’s cash flows are affected by the establishment of CMC prices and the timing of recovering costs through the CMC regulatory asset.

See Note 3 — Regulatory Matters of the 2022 Form 10-K and Notes 3 — Regulatory Matters and 2412 — Commitments and Contingenciesof the Combined Notes to Consolidated Financial Statements ~~of the Exelon 2016 Form 10-K~~ for ~~further discussion of~~additional information on regulatory and legal proceedings and proposed legislation.

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The following table provides a summary of the ~~major items affecting Exelon’s~~change in cash flows from ~~operations~~operating activities for the nine months ended September 30, ~~2017~~2023 and ~~2016:~~2022 by Registrant:

Nine Months Ended
September 30,
2017
2016^(c)
Variance
Net income $ 1,911
$ 956
$ 955
Add (subtract):
Non-cash operating activities^(a)
5,011
5,946
(935 )
Pension and non-pension postretirement benefit contributions (344 ) (283 ) (61 )
Income taxes 167
527
(360 )
Changes in working capital and other noncurrent assets and liabilities^(b)
(1,003 ) (516 ) (487 )
Option premiums received (paid), net 35
(24 ) 59
Collateral (posted) received, net (100 ) 757
(857 )
Net cash flows provided by operations $ 5,677
$ 7,363
$ (1,686 )

~~_________~~

~~(a)~~

Represents, when applicable, depreciation, amortization and accretion, net fair value changes related to derivatives, deferred income taxes, provision for uncollectible accounts, pension and other postretirement benefit expense, equity in earnings and losses of unconsolidated affiliates and investments, decommissioning-related items, stock compensation expense, impairment of long-lived assets, PHI merger commitment and severance charges, and other non-cash charges. See Note 19 - Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements for further detail on non-cash operating activity.


~~(b)~~	~~Changes in working capital and other noncurrent assets and liabilities exclude the changes in commercial paper, income taxes and the current portion of long-term debt.~~


~~(c)~~	~~Includes PHI Consolidated activity from March 24, 2016 to September 30, 2016.~~

~~Pension and Other Postretirement Benefits~~


(Decrease) increase in cash flows from operating activities	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Net income (loss)	$	(28)	$	116	$	(64)	$	19	$	(28)	$	(12)	$	(2)	$	(9)
Adjustments to reconcile net income to cash:
Non-cash operating activities	(790)		(268)		(85)		(90)		58		62		(6)		4
Option premiums (paid), net	39		—		—		—		—		—		—		—
Collateral (paid) received, net	(1,639)		(41)		—		(147)		(421)		(72)		(234)		(115)
Income taxes	47		50		46		39		40		40		11		(1)
Pension and non-pension postretirement benefit contributions	499		153		12		49		60		—		1		6
Regulatory assets and liabilities, net	294		251		28		(38)		80		37		56		(22)
Changes in working capital and other assets and liabilities	729		(118)		184		276		48		77		20		(53)
(Decrease) increase in cash flows from operating activities	$	(849)	$	143	$	121	$	108	$	(163)	$	132	$	(154)	$	(190)

On October 3, 2017, the US Department of Treasury and IRS released final regulations updating the mortality tables to be used for defined benefit pension plan funding, as well as the valuation of lump sum and other accelerated distribution options, effective for plan years beginning in 2018. The new mortality tables reflect improved projected life expectancy as compared to the existing table, which is generally expected to increase minimum pension funding requirements, Pension Benefit Guaranty Corporation premiums and the value of lump sum distributions. The IRS will permit plan sponsors the option of using existing mortality tables for determining minimum funding requirements for 2018. The one-year delay does not apply for use of the mortality tables to determine the present value of lump sum distributions. Exelon is still evaluating any potential impacts of the new mortality tables.

OPEB funding generally follows accounting cost; however, Exelon’s management has historically considered several factors in determining the level of contributions to its funded other postretirement benefit plans, including liabilities management, levels of benefit claims paid and regulatory implications (amounts deemed prudent to meet regulator expectations and best assure continued recovery).

To the extent interest rates decline significantly or the pension plans do not earn the expected asset return rates, annual pension contribution requirements in future years could increase. Additionally, expected contributions could change if Exelon changes its pension or OPEB funding strategy.

~~Tax Matters~~

~~The Registrants’ future cash flows from operating activities may be affected by the following tax matters:~~

Exelon appealed the Tax Court’s like-kind exchange decision in the third quarter of 2017 and expects that a payment of approximately $1.3 billion related to the like-kind exchange will be due, including $300 million attributable to ComEd, in the fourth quarter of 2017. While Exelon will receive a tax benefit of approximately $350 million associated with the deduction for the interest, Exelon currently has a net operating loss carryforward and thus does not expect to realize the cash benefit until 2018. After taking into account these interest deduction tax benefits, the total estimated net cash outflow for the like-kind exchange is

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approximately $950 million, of which approximately $300 million is attributable to ComEd after giving consideration to Exelon’s agreement to hold ComEd harmless from any unfavorable impacts on ComEd’s equity from the like-kind exchange position.

Of the above amounts payable, Exelon deposited with the IRS $1.25 billion in October of 2016. In the third quarter of 2017, the $300 million payable discussed above attributable to ComEd, net of ComEd’s receivable pursuant to the hold harmless agreement, was settled with Exelon. Any remaining amounts due to the IRS will be paid by Exelon in the fourth quarter of 2017. Exelon funded the $1.25 billion deposit with a combination of cash on hand and short-term borrowings. See Note 12 - Income Taxes for further discussion of the like-kind exchange tax position.

State and local governments continue to face increasing financial challenges, which may increase the risk of additional income tax, property taxes and other taxes or the imposition, extension or permanence of temporary tax increases. On July 6, 2017, Illinois enacted Senate Bill 9, which permanently increased Illinois’ total corporate income tax rate from 7.75% to 9.50% effective July 1, 2017. The rate increase is not expected to have a material ongoing impact to Exelon’s, Generation’s or ComEd’s future cash taxes. See Note 12 - ~~Income Taxes~~ ~~for further discussion of the Illinois tax rate change.~~

~~Cash flows from operations for the nine months ended September 30, 2017 and 2016 by Registrant were as follows:~~

Nine Months Ended
September 30,
2017 2016
Exelon $ 5,677
$ 7,363
Generation 2,270
3,723
ComEd 1,120
1,749
PECO 603
582
BGE 704
660
Pepco 348
504
DPL 292
267
ACE 158
315

Successor Predecessor
Nine Months Ended September 30, 2017
March 24, 2016 to September 30, 2016
January 1, 2016 to March 23, 2016
PHI $ 797
$ 546
$ 264

Changes in the Registrants'cash flows from operations were generally consistent with changes in each Registrant’s respective results of operations, as adjusted by changes in working capital in the normal course of business, except as discussed below. ~~In addition, significant~~See above for additional information related to cash flows from Generation. Significant operating cash flow impacts for the Registrants and Generation for the nine months ended September 30, ~~2017~~2023 and ~~2016~~2022 were as follows:

~~Generation~~•See Note 15 — Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements and the Registrants’ Consolidated Statements of Cash Flows for additional information on non-cash operating activities.

~~Depending~~•Changes in collateral depended upon whether ~~Generation is~~the Registrant was in a net mark-to-market liability or asset position, and collateral may behave been required to be posted with or collected from its counterparties. In addition, the collateral posting and collection requirements ~~differ~~differed depending on whether the transactions ~~are~~were on an exchange or in the ~~OTC~~over-the-counter markets. ~~During~~Changes in collateral for the Registrants are dependent upon the credit exposure of procurement contracts that may require suppliers to post collateral. The amount of cash collateral received from external counterparties decreased due to decreasing energy prices. See Note 9 — Derivative Financial Instruments for additional information.

•See Note 7 — Income Taxes of the Combined Notes to Consolidated Financial Statements and the Registrants' Consolidated Statements of Cash Flows for additional information on income taxes.

•Changes in Pension and non-pension postretirement benefit contributions relate to Exelon's funding strategy and incremental contributions made in 2022 in connection with the separation. See Note 14 — Retirement Benefits of the 2022 Form 10-K for additional information.

•Changes in regulatory assets and liabilities, net, are due to the timing of cash payments for costs recoverable, or cash receipts for costs recovered, under our regulatory mechanisms differs from the recovery period of those costs. Included within the changes is energy efficiency spend for ComEd of $428 million and $394 million for the nine months ended September 30, ~~2017~~2023 and ~~2016, Generation had net (payments)/collections~~2022, respectively. Also included within the changes is energy efficiency and demand response programs spend for BGE, Pepco, DPL and ACE of ~~counterparty cash collateral of $(77)~~$102 million, $49 million, $19 million, and ~~$759~~$14 million ~~respectively, primarily due to market conditions that resulted in changes to Generation’s net mark-to-market position.~~

~~During~~for the nine months ended September 30, ~~2017~~2023 and ~~2016, Generation had net (payments) collections of approximately $(35)~~$83 million, $50 million, $21 million, and ~~$24~~$7 million respectively, related to purchases and sales of options. The level of option activity in a given period may vary due to several factors, including changes in market conditions as well as changes in hedging strategy.

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~~ComEd~~

~~During~~for the nine months ended September 30, ~~2017~~2022, respectively. PECO had no energy efficiency and ~~2016, ComEd posted approximately $24 million and $2 million~~demand response programs spend recorded to the regulatory asset for the nine

141

Table of cash collateral with PJM, respectively. ComEd’s collateral posted with PJM has increased year over year primarily due to an increase in ComEd’s RPM credit requirements and peak market activity with PJM. As ofContents

months ended September 30, ~~2017~~2023 and ~~2016, ComEd had approximately $47 million and $33 million cash collateral posted with PJM, respectively.~~

~~For further discussion regarding changes in non-cash operating activities, please refer to~~2022. See Note ~~19 - Supplemental Financial Information~~3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

•Changes in working capital and other assets and liabilities for the ~~Financial Statements.~~Utility Registrants and Exelon Corporate totaled $406 million and for Generation total $323 million. The change for Generation primarily relates to the revolving accounts receivable financing arrangement which was entered into in April 2020. The change in working capital and other noncurrent assets and liabilities for Exelon Corporate and the Utility Registrants is dependent upon the normal course of operations for all Registrants. For ComEd, it is also dependent upon whether the participating nuclear-powered generating facilities are owed money from ComEd as a result of the established pricing for CMCs. For the nine months ended September 30, 2023, the established pricing resulted in ComEd owing payments to nuclear-powered generating facilities, which is reported within the cash flows from operations as a change in accounts payable and accrued expense.

Cash Flows from Investing Activities

~~Cash~~The following table provides a summary of the change in cash flows ~~used in~~from investing activities for the nine months ended September 30, ~~2017~~2023 and ~~2016~~2022 by ~~Registrant were as follows:~~ Registrant:

Nine Months Ended
September 30,
2017
2016
Exelon $ (5,810 ) $ (13,219 )
Generation (1,903 ) (3,278 )
ComEd (1,731 ) (1,919 )
PECO (457 ) (438 )
BGE (586 ) (614 )
Pepco (439 ) (435 )
DPL (293 ) (254 )
ACE (241 ) (227 )

Successor Predecessor

Nine Months Ended September 30, 2017
March 24, 2016 to September 30, 2016
January 1, 2016 to March 23, 2016
PHI $ (991 )
$ (631 ) $ (343 )


Decrease in cash flows from investing activities	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Capital expenditures	$	(361)	$	(125)	$	(77)	$	(68)	$	(336)	$	(115)	$	(122)	$	(92)

Investment in NDT fund sales, net	28		—		—		—		—		—		—		—
Collection of DPP	(169)		—		—		—		—		—		—		—
Proceeds from sales of assets and businesses	(16)		—		—		—		—		—		—		—
Changes in intercompany money pool	—		—		(51)		—		—		(7)		15		—

Other investing activities	(11)		(13)		(7)		(1)		3		6		(2)		(1)
Decrease in cash flows from investing activities	$	(529)	$	(138)	$	(135)	$	(69)	$	(333)	$	(116)	$	(109)	$	(93)

Significant investing cash flow impacts for the Registrants for nine months ended September 30, ~~2017~~2023 and ~~2016~~2022 were as follows:

~~Exelon~~

~~During the nine months ended September 30, 2017, Exelon had~~•Changes in capital expenditures ~~of $23 million and $178 million relating~~ are primarily due to the ~~acquisitions~~timing of ~~ConEdison Solutions~~cash expenditures for capital projects. See the "Credit Matters and Cash Requirements" section below for additional information on projected capital expenditure spending for the ~~FitzPatrick facility, respectively. During the nine months ended September 30, 2016, Exelon had expenditures of $6.6 billion relating to the acquisition of PHI.~~

~~During the nine months ended September 30, 2016, Exelon had proceeds of $360 million as a result of early termination of direct financing leases.~~

~~Generation~~

During the nine months ended September 30, 2017, Exelon had expenditures of $23 million and $178 million relating to the acquisitions of ConEdison Solutions and the FitzPatrick facility, respectively.

~~Capital Expenditure Spending~~

~~Generation~~

Generation has entered into several agreements to acquire equity interests in privately held and development stage entities which develop energy-related technologies. The agreements contain a series of scheduled investment commitments, including in-kind service contributions. There are anticipated expenditures remaining through 2019 to

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~~Table of Contents~~

~~fund anticipated planned capital and operating needs of the associated companies.~~Utility Registrants. See Note 242 — ~~Commitments and Contingencies~~Discontinued Operations of the Combined Notes to Consolidated Financial Statements ~~of the Exelon 2016 Form 10-K~~ for ~~further details of Generation’s equity interests.~~

~~Capital expenditures by Registrant for the nine months ended September 30, 2017 and 2016 and projected amounts for the full year 2017 are as follows:~~

Projected
Full Year
2017^(a)
Nine Months Ended
September 30,
2017 2016
Exelon^(b)
$ 8,075
$ 5,556
$ 6,368
Generation 2,450
1,654
2,651
ComEd^(c)
2,200
1,698
1,950
PECO 775
537
448
BGE 925
615
611
Pepco 625
439
392
DPL 425
294
260
ACE 300
242
227

Projected
Full Year
2017 ^(a)
Successor Predecessor
Nine Months Ended September 30, 2017
March 24, 2016 to September 30, 2016 January 1, 2016 to March 23, 2016
PHI^(d)
$ 1,375
$ 995
$ 624
$ 273

~~_________~~


~~(a)~~	~~Total projected capital expenditures do not include adjustments for non-cash activity.~~


~~(b)~~	~~Includes corporate operations, BSC, and PHISCO rounded to the nearest $25 million.~~


~~(c)~~	The 2017 projections include approximately $274 million of expected incremental spending pursuant to EIMA, ComEd has committed to invest approximately $2.6 billion over a ten year period, through 2022, to modernize and storm-harden its distribution system and to implement smart grid technology.


~~(d)~~	~~Includes PHISCO rounded to the nearest $25 million.~~

~~Projected capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors.~~

Approximately 37% and 21% of the projected 2017 capital expenditures at Generation are for the acquisition of nuclear fuel and growth (primarily new plant construction and distributed generation), respectively, with the remaining amounts reflecting additions and upgrades to existing facilities (including material condition improvements during nuclear refueling outages). Generation anticipates that they will fund capital expenditures with internally generated funds and borrowings.

~~ComEd, PECO, BGE, Pepco, DPL and ACE~~

Approximately 93% of the projected 2017 capital expenditures at ComEd and 100% of the projected of the projected 2017 capital expenditures at PECO, BGE, Pepco, DPL, and ACE are for continuing projects to maintain and improve operations, including enhancing reliability and adding capacity to the transmission and distribution systems such as ComEd’s reliability related investments required under EIMA, and the Utility Registrants' construction commitments under PJM’s RTEP. In addition to the capital expenditure for continuing projects, ComEd’s total expenditures include smart grid/smart meter technology required under EIMA.

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, PECO and BGE 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, PECO’s and BGE’s forecasted 2017 capital expenditures above reflect capital spending for remediation to be completed through 2018. Pepco, DPL and ACE have substantially completed their assessments and thus do not expect significant capital expenditures related to ~~this guidance~~Generation prior to the separation.

•Collection of DPP relates to Generation's revolving accounts receivable financing agreement which Generation entered into in ~~2017.~~April 2020.

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~~Table of Contents~~

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, including ComEd’s capital expenditures associated with EIMA as further discussed•Changes in ~~Note 5 — Regulatory Matters of~~intercompany money pool are driven by short-term borrowing needs. Refer to more information regarding the ~~Combined Notes to Consolidated Financial Statements.~~intercompany money pool below.

Cash Flows from Financing Activities

~~Cash~~The following table provides a summary of the change in cash flows ~~provided by (used in)~~from financing activities for the nine months ended September 30, ~~2017~~2023 and ~~2016~~2022 by ~~Registrant~~Registrant:

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Table of Contents


Increase (decrease) in cash flows from financing activities	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Changes in short-term borrowings, net	$	(756)	$	(133)	$	(239)	$	(375)	$	227	$	(124)	$	34	$	317
Long-term debt, net	357		225		100		150		(65)		35		—		(100)
Changes in intercompany money pool	—		—		—		—		(18)		(25)		—		17
Issuance of common stock	(563)		—		—		—		—		—		—		—
Dividends paid on common stock	(75)		(126)		(4)		(12)		—		200		(2)		17

Distributions to member	—		—		—		—		215		—		—		—
Contributions from parent/member	—		67		74		51		(312)		(157)		(48)		(110)
Transfer of cash, restricted cash, and cash equivalents to Constellation	2,594		—		—		—		—		—		—		—
Other financing activities	24		(2)		8		1		(18)		(18)		(2)		1
Increase (decrease) in cash flows from financing activities	$	1,581	$	31	$	(61)	$	(185)	$	29	$	(89)	$	(18)	$	142

Significant financing cash flow impacts for the Registrants for the nine months ended September 30, 2023 and 2022 were as follows:

Nine Months Ended
September 30,
2017 2016
Exelon $ 701
$ 1,251
Generation (297 ) (501 )
ComEd 812
147
PECO 121
77
BGE (112 ) 286
Pepco 199
28
DPL (42 ) (14 )
ACE (13 ) 74

Successor Predecessor
Nine Months Ended September 30, 2017 March 24, 2016 to September 30, 2016 January 1, 2016 to March 23, 2016
PHI $ 161
$ 65
$ 372

~~Debt~~

•Changes in short-term borrowings, net, is driven by repayments on and issuances of notes due in less than 365 days. See Note 1110 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for ~~further details~~additional information on short-term borrowings for the Registrants.

•Long-term debt, net, varies due to debt issuances and redemptions each year. See Note 10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on debt issuances. Refer to the debt redemptions table below for additional information.

•Changes in intercompany money pool are driven by short-term borrowing needs. Refer below for more information regarding the intercompany money pool.

•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 Contingenciesof the 2022 Form 10-K for additional information on dividend restrictions. See below for quarterly dividends declared.

•Refer to Note 2 — Discontinued Operations for the transfer of cash, restricted cash, and cash equivalents to Constellation related to the separation.

Debt

See Note 10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt issuances.

~~Dividends~~

~~Cash dividend payments and distributions during~~During the nine months ended September 30, ~~2017 and 2016 by Registrant were as follows:~~2023, the following long-term debt was retired and/or redeemed:

Nine Months Ended
September 30,
2017 2016
Exelon $ 921
$ 873
Generation 494
167
ComEd 316
275
PECO 216
208
BGE^(a)
148
142
Pepco 133
92
DPL 82
39
ACE 53
24

143

Successor Predecessor
Nine Months Ended September 30, 2017
March 24, 2016 to September 30, 2016 January 1, 2016 to March 23, 2016
PHI $ 267
$ 174
$ —

~~_________~~


~~(a)~~	~~Includes dividends paid on BGE’s preference stock in 2016.~~

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Table of Contents

Company

Type

Interest Rate

Maturity

Amount

Exelon

SMBC Term Loan Agreement

SOFR plus 0.65%

July 21, 2023

300

Exelon

US Bank Term Loan Agreement

SOFR plus 0.65%

July 21, 2023

300

Exelon

PNC Term Loan Agreement

SOFR plus 0.65%

July 24, 2023

250

Exelon

Long-Term Software License Agreement

3.70

August 9, 2025

Exelon

Long-Term Software License Agreement

3.95

May 1, 2024

Exelon

Long-Term Software License Agreement

3.70

August 9, 2025

PECO

Loan Agreement

2.00

June 20, 2023

BGE

Notes

3.35

July 1, 2023

300

Dividends

Quarterly dividends declared by the Exelon Board of Directors during the nine months ended September 30, ~~2017~~2023 and for the fourth quarter of ~~2017~~2023 were as follows:

Period Declaration Date Shareholder of Record Date Dividend Payable Date
Cash per Share^(a)
First Quarter 2017 January 31, 2017 February 15, 2017 March 10, 2017 $ 0.3275
Second Quarter 2017 April 25, 2017 May 15, 2017 June 9, 2017 $ 0.3275
Third Quarter 2017 July 25, 2017 August 15, 2017 September 8, 2017 $ 0.3275
Fourth Quarter 2017 September 25, 2017 November 15, 2017 December 8, 2017 $ 0.3275

~~_________~~

~~(a)~~Period

~~Exelon's Board~~

Declaration Date

Shareholder of ~~Directors approved a revised dividend policy. The approved policy will raise the dividend 2.5% each year for the next three years, beginning with the~~ Record Date

Dividend Payable Date

Cash per Share(a)

First Quarter 2023

February 14, 2023

February 27, 2023

March 10, 2023

0.3600

Second Quarter 2023

April 25, 2023

May 15, 2023

June ~~2016 dividend and subject to Board approval.~~9, 2023

0.3600

~~Short-Term Borrowings~~

~~Short-term borrowings incurred (repaid) during the nine months ended September 30, 2017 and 2016 by Registrant were as follows:~~

Nine Months Ended
September 30,
2017 2016
Exelon $ (559 ) $ (1,271 )
Generation (609 ) 43
ComEd —
(284 )
BGE (45 ) (210 )
Pepco (23 ) (64 )
DPL 54
(88 )
ACE 65
(5 )

Successor Predecessor
Nine Months Ended September 30, 2017
March 24, 2016 to September 30, 2016
January 1, 2016 to March 23, 2016
PHI $ (404 ) $ (820 ) $ 379

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~~Table of Contents~~

~~Contributions from Parent/Member~~

~~Contributions received from Parent/Member for the nine months ended September 30, 2017 and 2016 by Registrant were as follows:~~

Nine Months Ended
September 30,
2017 2016
Generation $ 102
$ 142
ComEd ^(a)(b)
567
188
PECO ^(b)
16
18
BGE ^(b)
77
28
Pepco ^(c)
161
187
DPL ^(c)
—
113
ACE ^(c)
—
139

Successor Predecessor
Nine Months Ended September 30, 2017 March 24, 2016 to September 30, 2016 January 1, 2016 to March 23, 2016
PHI ^(b)
$ 758
$ 1,088
$ —

~~_________~~

Third Quarter 2023

July 25, 2023

August 15, 2023

September 8, 2023

0.3600

Fourth Quarter 2023

November 1, 2023

November 15, 2023

December 8, 2023

0.3600

~~(a)~~

Additional contributions from parent or external debt financing may be required as a result of increased capital investment in infrastructure improvements and modernization pursuant to EIMA and transmission upgrades.

~~(b)~~

~~Contribution paid by Exelon.~~

~~(c)~~

~~Contribution paid by PHI.~~

~~Other~~

~~For the nine months ended September 30, 2017, other financing activities primarily consist~~__________

(a)Exelon's Board of ~~debt issuance costs. See Note 11 — Debt and Credit Agreements of the Combined Notes to the Consolidated Financial Statements~~Directors approved an updated dividend policy for ~~further details of the Registrants’ debt issuances.~~2023. The 2023 quarterly dividend will be $0.36 per share.

Credit Matters and Cash Requirements

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 ~~$9.5~~$4.0 billion in aggregate total commitments of which ~~$8.3~~$3.2 billion was available to support additional commercial paper as of September 30, ~~2017,~~2023, and of which no financial institution has more than 7%6% of the aggregate commitments for the Registrants. The Registrants had access to the commercial paper ~~market~~markets and had availability under their revolving credit facilities during the ~~third quarter of 2017~~nine months ended September 30, 2023 to fund their short-term liquidity needs, when necessary. Exelon Corporate and the Utility Registrants each have a 5-year revolving credit facility. See Note 10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. 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 of the ~~Exelon 2016~~2022 Form 10-K for ~~further~~additional information regarding the effects of uncertainty in the capital and credit markets.

The Registrants believe their cash ~~flow~~flows from operating activities, access to credit markets, and their credit facilities provide sufficient ~~liquidity. If Generation lost~~liquidity to support the estimated future cash requirements.

On August 4, 2022, Exelon executed an equity distribution agreement (“Equity Distribution Agreement”) with certain sales agents and forward sellers and certain forward purchasers establishing an ATM equity distribution program under which it may offer and sell shares of its ~~investment grade credit rating as~~common stock, having an aggregate gross sales price of up to $1.0 billion. Exelon has no obligation to offer or sell any shares of common stock under the Equity Distribution Agreement and may at any time suspend or terminate offers and sales under the Equity Distribution Agreement. As of September 30, ~~2017, it would have been required to provide incremental collateral~~2023, Exelon has not issued any shares of ~~$1.8 billion to meet collateral obligations for derivatives, non-derivatives, normal purchase normal sales contracts~~common stock under the ATM program and ~~applicable payables and receivables, net of the contractual right of offset under master netting agreements, which is well within its current available credit facility capacities of $4.6 billion.~~

has not entered into any forward sale agreements.

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Table of Contents

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 September 30, ~~2017~~2023 and available credit facility capacity prior to any incremental collateral at September 30, ~~2017:~~2023:


	PJM Credit Policy Collateral		Other Incremental Collateral Required(a)		Available Credit Facility Capacity Prior to Any Incremental Collateral
ComEd	$	1	$	—	$	718
PECO	1		20		600
BGE	3		30		539

Pepco	4		—		300
DPL	4		9		300
ACE	2		—		127

__________

(a)Represents incremental collateral related to natural gas procurement contracts.

Capital Expenditure Spending

As of September 30, 2023, the most recent estimates of capital expenditures for plant additions and improvements for 2023 are as follows:


(In millions)	Transmission	Distribution	Gas	Total(a)
Exelon	N/A	N/A	N/A	$	7,300
ComEd	400	2,175	N/A	2,575
PECO	175	925	325	1,425
BGE	225	625	500	1,350
PHI	550	1,275	100	1,925
Pepco	250	675	N/A	925
DPL	175	300	100	575
ACE	125	300	N/A	425

__________

(a)Numbers rounded to the nearest $25M and may not sum due to rounding.

Projected capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors.

Retirement 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 reflect a funding strategy to make annual contributions with the objective of achieving 100% funded status on an ABO basis over time. This funding strategy helps minimize volatility of future period required pension contributions. Exelon’s estimated annual qualified pension contributions will be $20 million in 2023. 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 OPEB 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).

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Table of Contents

PJM Credit Policy Collateral
Other Incremental Collateral Required ^(a)
Available Credit Facility Capacity Prior to Any Incremental Collateral
ComEd $ 18
$ —
$ 998
PECO 3
20
599
BGE 3
28
600
Pepco 4
—
300
DPL 1
9
300
ACE —
—
300
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.

~~_________~~See Note 14 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements of the 2022 Form 10-K for additional information on pension and OPEB contributions.


~~(a)~~	~~Represents incremental collateral related to natural gas procurement contracts.~~

~~Exelon~~ Credit Facilities

Exelon ~~Pepco, DPL and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and short-term notes.~~Corporate, ComEd, and BGE meet their short-term liquidity requirements primarily through the issuance of commercial paper. ~~Generation and~~ PECO ~~meet their~~meets its 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.

~~The following table reflects~~See Note 10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ ~~commercial paper programs supported by the revolving credit agreements and bilateral credit agreements at September 30, 2017:~~

~~Commercial Paper Programs~~

Commercial Paper Issuer
Maximum Program Size ^(a)(b)
Outstanding Commercial Paper at
September 30, 2017 Average Interest Rate on Commercial Paper Borrowings for the Nine Months Ended September 30, 2017
Exelon Corporate $ 600
$ —
1.16 %
Generation 5,300
—
1.20 %
ComEd 1,000
—
1.24 %
PECO 600
—
1.13 %
BGE 600
—
1.15 %
Pepco 500
—
1.04 %
DPL 500
54
1.40 %
ACE 350
65
1.36 %

~~_________~~


~~(a)~~	~~Excludes $525 million bilateral credit facilities that do not back Generation's commercial paper program.~~

~~(b)~~

Excludes additional credit facility agreements for Generation, ComEd, PECO, BGE, Pepco, DPL and ACE with aggregate commitments of $49 million, $34 million, $34 million, $5 million, $2 million, $2 million and $2 million, respectively, arranged with minority and community banks located primarily within utilities' service territories. These facilities expire on October 12, 2018. These facilities are solely utilized to issue letters of credit. As of September 30, 2017, letters of credit issued under these agreements for Generation, ComEd, PECO and BGE totaled $5 million, $12 million, $21 million and $2 million, respectively.

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~~Table of Contents~~

~~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. While the amount of its commercial paper outstanding does not reduce available capacity under a Registrant’s credit facility, a Registrant does not issue commercial paper in an aggregate amount exceeding the then available capacity under its credit facility. At September 30, 2017, the Registrants had the following aggregate bank commitments, credit facility borrowings and ~~available capacity under their respective credit facilities:~~short term borrowing activity.

~~Credit Agreements~~

Borrower Facility Type
Aggregate Bank
Commitment^(a)(b)(c)

Facility
Draws

Outstanding
Letters of
Credit
Available Capacity at
September 30, 2017
Actual
To Support
Additional
Commercial
Paper^(b)(d)
Exelon Corporate Syndicated Revolver $ 600
$ —
$ 45
$ 555
$ 555
Generation^(e)
Syndicated Revolver 5,300
—
887
4,413
4,413
Generation Bilaterals 525
70
235
220
—
ComEd Syndicated Revolver 1,000
—
2
998
998
PECO Syndicated Revolver 600
—
1
599
599
BGE Syndicated Revolver 600
—
—
600
600
Pepco Syndicated Revolver 300
—
—
300
300
DPL Syndicated Revolver 300
—
—
300
246
ACE Syndicated Revolver 300
—
—
300
235

~~_________~~

~~(a)~~

Excludes $128 million of credit facility agreements arranged at minority and community banks at Generation, ComEd, PECO, BGE, Pepco, DPL and ACE. These facilities expire on October 12, 2018. These facilities are solely utilized to issue letters of credit. As of September 30, 2017, letters of credit issued under these agreements for Generation, ComEd, PECO and BGE totaled $5 million, $12 million, $21 million and $2 million, respectively.

~~(b)~~

Pepco, DPL and ACE's revolving credit facility is subject to available borrowing capacity. 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 $900 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


~~(c)~~	~~Excludes nonrecourse debt letters of credit, see Note 14 — Debt and Credit Agreements in the Exelon 2016 Form 10-K for further information on Continental Wind nonrecourse debt.~~


~~(d)~~	~~Excludes $525 million bilateral credit facilities that do not back Generation’s commercial paper program.~~


~~(e)~~	~~Excludes ExGen Texas Power Financing's $20 million of borrowed debt on its revolving credit facility.~~

~~As of September 30, 2017, there was $70 million of borrowings under Generation's bilateral credit facilities.~~

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:

Exelon Generation ComEd PECO BGE Pepco DPL ACE
Prime based borrowings 27.5 27.5 7.5 0.0 0.0 7.5
7.5
7.5
LIBOR-based borrowings 127.5 127.5 107.5 90.0 100.0 107.5
107.5
107.5

The maximum adders for prime rate borrowings and LIBOR-based rate borrowings are 90 basis points and 165 basis points, respectively. 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.

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Each revolving credit agreement for Exelon, Generation, ComEd, PECO, BGE, Pepco, DPL and ACE requires the affected borrower to maintain a minimum cash from operations to interest expense ratio for the twelve-month period ended on the last day of any quarter. The following table summarizes the minimum thresholds reflected in the credit agreements for the nine months ended September 30, 2017:

~~Exelon~~

~~Generation~~

~~ComEd~~

~~PECO~~

~~BGE~~

~~Pepco~~

~~DPL~~

~~ACE~~

~~Credit agreement threshold~~

~~2.50 to 1~~

~~3.00 to 1~~

~~2.00 to 1~~

~~At September 30, 2017, the interest coverage ratios at Exelon, Generation, ComEd, PECO, BGE, Pepco, DPL and ACE were as follows:~~

Exelon Generation ComEd PECO BGE Pepco DPL ACE
Interest coverage ratio 6.27
9.02
10.83
8.26
10.66
6.83 8.78 6.03

An event of default under Exelon, Generation, ComEd, PECO or BGE's indebtedness will not constitute an event of default under any of the others’ credit facilities, except that a bankruptcy or other event of default in the payment of principal, premium or indebtedness in principal amount in excess of $100 million in the aggregate by Generation will constitute an event of default under the Exelon Corporate credit facility. An event of default under Pepco, DPL or ACE's indebtedness will not constitute an event of default under any of the others’ credit facilities, except that a bankruptcy or other event of default in the payment of principal, premium or indebtedness in principal amount in excess of $50 million in the aggregate will constitute an event of default under the credit facility.

The absence of a material adverse change in Exelon's or PHI’s business, property, results of operations or financial condition is not a condition to the availability of credit under the credit agreement. The credit agreement does not include any rating triggers.

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 109 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral provisions.

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The credit ratings for Exelon Corporate, PECO, BGE, PHI, Pepco, DPL, and ACE did not change for the nine months ended September 30, 2023. On July 26, 2023, S&P raised ComEd's long-term issuer credit rating from 'BBB+' to a 'A-'. S&P also affirmed the current 'A' rating on ComEd's senior secured debt and 'A-2' short-term rating, which influences long and short-term borrowing cost.

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 ~~pools.~~pool. Maximum amounts contributed to and borrowed from the money pool by participant and the net contribution or borrowing as of September 30, ~~2017,~~2023, are presented in the following table:

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									During the Nine Months Ended September 30, 2023				At September 30, 2023
Exelon Intercompany Money Pool	During the Three Months Ended September 30, 2017				As of September 30, 2017			Exelon Intercompany Money Pool	Maximum Contributed		Maximum Borrowed		Contributed (Borrowed)
Contributed (borrowed)	Maximum Contributed		Maximum Borrowed		Contributed (Borrowed)
Exelon Corporate	$	579	n/a		$	280		Exelon Corporate	$	510	$	—	$	178
Generation	—		(417	)	(146		)
PECO	97		(10	)	57			PECO	305		(238)		51
BSC	—		(369	)	(245		)	BSC	—		(350)		(212)
PHI Corporate ^(a)	n/a		(33	)	(1		)
PCI ^(a)	54		—		54
PHI Corporate								PHI Corporate	—		(62)		(62)
PCI								PCI	45		—		45

~~_________~~


~~(a)~~	~~As a result of the merger, PHI Corporate and PCI began to participate in the Exelon Intercompany Money Pool effective March 24, 2016.~~

PHI Intercompany Money Pool During the Three Months Ended September 30, 2017 As of September 30, 2017
Contributed (borrowed)
Maximum
Contributed

Maximum
Borrowed

Contributed
(Borrowed)
PHI Corporate $ 51
$ (1 ) $ —
PHISCO 24
(25 ) —

~~Investments in Nuclear Decommissioning Trust Funds~~

Exelon, Generation and CENG maintain trust funds, as required by the NRC, to fund certain costs of decommissioning nuclear plants. The mix of securities in the trust funds is designed to provide returns to be used to fund decommissioning and to offset inflationary increases in decommissioning costs. Generation actively monitors the investment performance of the trust funds and periodically reviews asset allocations in accordance with Generation’s NDT fund investment policy. Generation’s and CENG’s investment policies establish limits on the concentration of holdings in any one company and also in any one industry. See Note 13 —Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements for further information regarding the trust funds, the NRC’s minimum funding requirements and related liquidity ramifications.


	During the Nine Months Ended September 30, 2023				At September 30, 2023
PHI Intercompany Money Pool	Maximum Contributed		Maximum Borrowed		(Borrowed) Contributed
Pepco	$	39	$	(55)	$	7
DPL	111		—		10
ACE	—		(95)		(17)

Shelf Registration Statements

Exelon ~~Generation, ComEd, PECO, BGE, Pepco, DPL~~ and ~~ACE~~the Utility Registrants have a currently effective combined shelf registration statement, unlimited in amount, ~~filed with the SEC,~~ that will expire in August ~~2019.~~2025. 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.

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Regulatory Authorizations

~~Generation, ComEd, PECO, BGE, Pepco, DPL and ACE~~The Utility Registrants are required to obtain short-term and long-term financing authority from Federal and State Commissions as follows:

At September 30, 2023

Short-term Financing Authority (e)

Remaining Long-term Financing Authority

Commission

Expiration Date

Amount

Commission

Expiration Date

Amount

ComEd(a)

FERC

December 31, 2023

2,500

ICC

January 1, 2025

368

PECO

FERC

December 31, 2023

1,500

PAPUC

December 31, 2024

550

BGE(b)

FERC

December 31, 2023

700

MDPSC

N/A

1,100

Pepco(c)

FERC

December 31, 2023

500

MDPSC / DCPSC

December 31, 2025

1,050

DPL(c)

FERC

December 31, 2023

500

MDPSC / DEPSC

December 31, 2025

1,075

ACE(d)

NJBPU

December 31, 2023

350

NJBPU

December 31, 2024

625

Short-term Financing Authority^(a)(b)

Long-term Financing Authority^(c)
Commission Expiration Date Amount (in millions) Commission Expiration Date Amount (in millions)
ComEd^(d)
FERC December 31, 2017 $ 2,500
ICC 2019 $ 1,383
PECO FERC December 31, 2017 1,500
PAPUC December 31, 2018 1,275
BGE FERC December 31, 2017 700
MDPSC N/A 700
Pepco FERC June 30, 2018 500
MDPSC / DCPSC September 25, 2017 —
DPL FERC June 30, 2018 500
MDPSC / DPSC December 31, 2017 125
ACE NJPU January 1, 2018 350
NJBPU December 31, 2017 300
__________

~~_________~~


~~(a)~~	~~Generation currently has blanket financing authority it received from FERC in connection with its market-based rate authority.~~


~~(b)~~	On October 31, 2017, ComEd, PECO, BGE, Pepco and DPL filed applications with FERC for renewal of their short-term financing authority through December 31, 2019. ComEd, PECO, BGE, Pepco and DPL expect approval of the applications before the end of the year.


~~(c)~~	~~Pepco, DPL, and ACE, are currently in the process renewing their long-term financing authority with their respective commissions and expect approvals before the end of the year.~~


~~(d)~~	ComEd had $1,140 million available in long-term debt refinancing authority and $243 million available in new money long term debt financing authority from the ICC as of September 30, 2017 and has an expiration date of June 1, 2019 and March 1, 2019, respectively.

(a)On June 29, 2023, ComEd filed an application for $2 billion in new money long-term debt financing authority from the ICC and expects approval by December 31, 2023.

~~Contractual Obligations~~(b)On December 21, 2022, BGE received approval from the MDPSC for $1.8 billion in new long-term financing authority with an effective date of January 4, 2023.

(c)The financing authority filed with MDPSC does not have an expiration date, while the financing authority filed with DCPSC and ~~Off-Balance Sheet Arrangements~~DEPSC have an expiration date of December 31, 2025.

~~Contractual obligations represent cash obligations that are considered to be firm commitments and commercial commitments triggered~~(d)On July 14, 2023, ACE filed an application with the NJBPU for renewal of their short-term financing authority through January 1, 2026. ACE expects approval of their application by ~~future events. See Note 24 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in the Exelon 2016 Form 10-K.~~December 31, 2023.

~~Generation,~~(e)On October 2, 2023, ComEd, PECO, BGE, Pepco, and DPL filed applications with FERC for renewal of their short-term financing authority through December 31, 2025. ComEd, PECO, BGE, Pepco, and ~~ACE have obligations related to contracts for the purchase~~DPL expect approval of ~~power~~their applications by December 31, 2023.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

The Registrants hold commodity and fuel supplies, and ComEd and PECO have obligations related to their financing trusts. The power and fuel purchase contracts and the financing trusts have been considered for consolidation in the Registrants’ respective financial ~~statements pursuant~~instruments that are exposed to the ~~authoritative guidance for VIEs.~~following market risks:

•Commodity price risk, which is discussed further below.

•Counterparty credit risk associated with non-performance by counterparties on executed derivative instruments and participation in all, or some of the established, wholesale spot energy markets that are administered by PJM. The credit policies of PJM 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. See Note 19 — ~~Basis of Presentation~~Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for ~~further information.~~

~~For an in-depth~~a detailed discussion of counterparty credit risk related to derivative instruments.

•Equity price and interest rate risk associated with Exelon’s pension and OPEB plan trusts. See Note 8 — Retirement Benefits of the Registrants' contractual obligations and off-balance sheet arrangements, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Contractual Obligations and Off-Balance Sheet Arrangements” in the Exelon 20162022 Form 10-K for additional information.

•Interest rate risk associated with changes in interest rates for the Registrants’ outstanding long-term debt. This risk is significantly reduced as substantially all of the Registrants’ outstanding debt has fixed interest rates. There is inherent interest rate risk related to refinancing maturing debt by issuing new long-term debt. The Registrants use a combination of fixed-rate and ~~"Management's Discussion~~variable-rate debt to manage interest rate exposure. See Note 10 — Debt and ~~Analysis~~Credit Agreements of the Combined Notes to Consolidated Financial ~~Condition~~Statements for additional information. In addition, Exelon may utilize interest rate derivatives to lock in rate levels in anticipation of future financings, which are typically designated as cash flow hedges, or to lock in rate levels on borrowings, which are typically designated as economic hedges. See Note 9 – Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.

•Electric operating revenues risk associated with ComEd's distribution formula rate. ComEd's ROE for its electric distribution service through 2023 is directly correlated to yields on U.S. Treasury bonds. Exelon Corporate may utilize interest rate derivatives to mitigate volatility and ~~Results~~manage risk to Exelon, which are typically accounted for as economic hedges. See Note 9 – Derivative Financial Instruments of ~~Operations - Contractual Obligations and Commercial Commitments."~~

~~Item 3. Quantitative and Qualitative Disclosures about Market Risk~~the Combined Notes to Consolidated Financial Statements for additional information.

The Registrants operate primarily under cost-based rate regulation limiting exposure to the effects of market risk. Hedging programs are ~~exposed~~utilized to ~~market~~reduce exposure to energy and natural gas price volatility and have no direct earnings impacts as the costs are fully recovered through regulatory-approved recovery mechanisms.

Exelon manages these risks ~~associated with adverse changes in commodity prices, counterparty credit, interest rates and equity prices. Exelon’s RMC approves~~through 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~~Risk management issues are reported to Exelon’s Executive Committee, the ~~chief executive officer~~Risk Management Committees of each Utility Registrant, 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 FinanceAudit and Risk Committee of ~~the Exelon~~Exelon’s Board of Directors on the scope of the risk management activities. The following discussion serves as an update to ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK of Exelon’s 2016 Annual Report on Form 10-K incorporated herein by reference.Directors.

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~~purchases differs from the amount of energy it has contracted to sell, Exelon ~~has price risk from~~is exposed to market fluctuations in commodity ~~price movements.~~prices. Exelon seeks to mitigate its commodity price risk through the sale and purchase of electricity ~~fossil fuel~~ and ~~other commodities.~~

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~~Generation~~

~~Normal Operations and Hedging Activities.~~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 price risk caused by market fluctuations, Generation enters into non-derivative contracts as well as derivative contracts, including forwards, futures, swaps and options, with approved counterparties to hedge anticipated exposures. Generation believes these instruments represent economic hedges that mitigate exposure to fluctuations in commodity prices. Generation expects the settlement of the majority of its economic hedges will occur during 2017 through 2019.

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 risk for Exelon's expected generation, typically on a ratable basis over a three-year period. As of September 30, 2017, the percentage of expected generation hedged is 98%-101%, 79%-82% and 45%-48% for 2017, 2018 and 2019, 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 generating facilities 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 the Utility Registrants 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 non-proprietary trading portfolio associated with a $5 reduction in the annual average around-the-clock energy price based on September 30, 2017 market conditions and hedged position would be an increase in pre-tax net income of approximately $10 million for 2017 and decreases of approximately $170 million and $500 million, respectively, for 2018~~and 2019.~~ Power price sensitivities are derived by adjusting power price assumptions while keeping all other price inputs constant. Generation expects to actively manage 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.

~~Proprietary Trading Activities.~~Generation also enters into certain energy-related derivatives for proprietary trading purposes. Proprietary trading includes all contracts entered into with the intent of benefiting from shifts or changes in market prices as opposed to those entered into with the intent of hedging or managing risk. Proprietary trading activities are subject to limits established by Exelon’s RMC. The proprietary trading portfolio is subject to a risk management policy that includes stringent risk management limits, including volume, stop loss and Value-at-Risk (VaR) limits to manage exposure to market risk. Additionally, the Exelon risk management group and Exelon’s RMC monitor the financial risks of the proprietary trading activities. The proprietary trading activities, which included physical volumes of 2,601 GWhs and 6,763 GWhs for the three and nine months ended September 30, 2017, respectively, and 1,506 GWhs and 4,015 GWhs and for the three and nine months September 30, 2016, respectively, are a complement to Generation’s energy marketing portfolio, but represent a small portion of Generation’s overall revenue from energy marketing activities. Proprietary trading portfolio activity for the nine months ended September 30, 2017 resulted in $11 million of pre-tax gains due to net mark-to-market gains of $3 million and realized gains of $8 million. Generation uses a 95% confidence interval, assuming standard normal distribution, one day holding period and a one-tailed statistical measure in calculating its VaR. The daily VaR on proprietary trading activity averaged $0.1 million of exposure during the quarter. Generation has not segregated proprietary trading activity within the following discussion because of the relative size of the proprietary trading portfolio in comparison to Generation’s total Revenue net of purchase power and fuel expense for the nine months ended September 30, 2017 of $6,526 million.

~~Fuel Procurement.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. 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

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from 2017 through 2021 are supplied by three producers. 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 Exelon’s and Generation’s results of operations, cash flows and financial positions.

~~ComEd~~gas.

ComEd entered into 20-year ~~contracts for~~floating-to-fixed renewable energy ~~and RECs~~swap contracts beginning in June ~~2012.~~2012, which are considered an economic hedge and have changes in fair value recorded to an offsetting regulatory asset or liability. ComEd ~~is permitted to recover its renewable~~has block energy and REC costs from retail customers with no mark-up. The annual commitments represent the maximum settlements with suppliers for renewable energy and RECs under the existing contract terms. Pursuant to the ICC’s Order on December 19, 2012, ComEd’s commitments under the existing long-term contracts were reduced for the June 2013 through May 2014 procurement period. In addition, the ICC’s December 18, 2013 Order approved the reduction of ComEd’s commitments under those contracts for the June 2014 through May 2015 procurement period, and the amount of the reduction was approved by the ICC in March 2014. See Note 5 — Regulatory Matters and Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding energy procurement and derivatives. ComEd does not enter into derivatives for speculative or proprietary trading purposes.

~~PECO~~

~~PECO has~~ contracts to procure electric supply that ~~were~~are executed through ~~the~~a competitive procurement process, outlined in its PAPUC-approved DSP Programs, which are further discussed in Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements. PECO has certain full requirements contracts which are considered derivatives and qualify for ~~the normal purchases and normal sales scope exception under current derivative authoritative guidance,~~NPNS, and as a result are accounted for on an accrual basis of accounting. ~~Under the DSP Programs,~~ PECO, ~~is permitted~~BGE, Pepco, DPL, and ACE have contracts to ~~recover its~~procure electric supply that are executed through a competitive procurement ~~costs from retail customers with no mark-up.~~

process. PECO, ~~has also entered into derivative natural gas contracts, which either qualify for the normal purchases~~BGE, Pepco, DPL, and ~~normal sales exception or~~ACE have no mark-to-market balances because the derivatives are index priced, to hedge its long-term price risk in the natural gas market. PECO’s hedging program for natural gas procurement has no direct impact on its financial position or results of operations as natural gas costs are fully recovered from customers under the PGC.

PECO does not enter into derivatives for speculative or proprietary trading purposes. For additional information on these contracts, see Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements.

~~BGE~~

~~BGE procures electric supply for default service customers through~~certain full requirements contracts, ~~pursuant to BGE’s MDPSC-approved SOS program. BGE’s full requirements contracts that~~which are considered derivatives and qualify for ~~the normal purchases and normal sales scope exception under current derivative authoritative guidance,~~NPNS, and as a result are accounted for on an accrual basis of accounting. ~~Under the SOS program,~~Other full requirements contracts are not derivatives.

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PECO, BGE, ~~is permitted to recover its electricity procurement costs from retail customers, plus an administrative fee which includes a shareholder return component~~ and ~~an incremental cost component.~~

~~BGE has~~DPL also ~~entered into~~have executed derivative natural gas contracts, which qualify for ~~the normal purchases and normal sales scope exception,~~NPNS, to hedge ~~its~~their long-term price risk in the natural gas market. The hedging ~~program~~programs for natural gas procurement ~~has~~have no direct impact on ~~BGE’s~~their financial position. However, under BGE’s market-based rates incentive mechanism, BGE’s actual cost of gas is compared to a market index (a measure of the market price of gas in a given period). The difference between BGE’s actual cost and the market index is shared equally between shareholders and customers.statements.

~~BGE does not enter into derivatives for speculative or proprietary trading purposes.~~ For additional information on these contracts, see Note 109 — Derivative Financial Instruments and Note 11 — Fair Value of Financial Assets and Liabilities of the Combined Notes to Consolidated Financial Statements.

~~Pepco~~

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~~Table of Contents~~

include an administrative fee. The administrative fee includes an incremental cost component and a shareholder return component for residential and commercial rate classes. Pepco’s price risk related to electric supply procurement is limited. Pepco locks in fixed prices for all of its SOS requirements through full requirements contracts. Certain of Pepco’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other Pepco full requirements contracts are not derivatives.

Pepco does not enter into derivatives for speculative or proprietary trading purposes. For additional information on these contracts, see Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements.

~~DPL~~

DPL provides natural gas to its customers under a GCR mechanism approved by the DPSC. The demand portion of the GCR is based upon DPL’s firm transportation and storage contracts. DPL has firm deliverability of swing and seasonal storage; a liquefied natural gas facility and firm transportation capacity to meet customer demand and provide a reserve margin. The commodity portion of the GCR includes a commission approved hedging program which is intended to reduce gas commodity price volatility while limiting the firm natural gas customers’ exposure to adverse changes in the market price of natural gas.

DPL does not enter into derivatives for speculative or proprietary trading purposes. See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding energy procurement and derivatives.

~~ACE~~

ACE has contracts to procure BGS electric supply that are executed through a competitive procurement process approved by the NJBPU. The BGS rates charged recover ACE's wholesale power supply costs. ACE does not make any profit or incur any loss on the supply component of the BGS it supplies to customers. ACE’s price risk related to electric supply procurement is limited. ACE locks in fixed prices for all of its BGS requirements through full requirements contracts. ACE’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other ACE full requirements contracts are not derivatives.

ACE does not enter into derivatives for speculative or proprietary trading purposes. For additional information on these contracts, see Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements.

~~Trading and Non-Trading Marketing Activities.~~ The following detailed presentation of Exelon’s, Generation’s, ComEd’s, PHI's and DPL's trading and non-trading marketing activities is included to address the recommended disclosures by the energy industry’s Committee of Chief Risk Officers (CCRO).

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The following table provides detail on changes in Exelon’s, Generation’s, ComEd’s, PHI's and DPL's commodity mark-to-market net asset or liability balance sheet position from December 31, 2016 to September 30, 2017. It indicatespresents 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 normal purchase and normal sales contracts and does not segregate proprietary trading activity. See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on the balance sheet classification of the mark-to-market energy contract net assets (liabilities) recorded as of September 30, 2017 and December 31, 2016.

Exelon Generation ComEd PHI DPL
Total mark-to-market energy contract net assets (liabilities) at December 31, 2016^(a)
$ 719
$ 977
$ (258 ) $ —
$ —
Total change in fair value during 2017 of contracts recorded in results of operations (13 ) (13 ) —
—
—
Reclassification to realized of contracts recorded in results of operations (138 ) (138 ) —
—
—
Contracts received at acquisition date —
—
—
—
—
Changes in fair value — recorded through regulatory assets and liabilities^(b)
(21 ) —
(19 ) (2 ) (2 )
Changes in allocated collateral 88
86
—
2
2
Changes in net option premium paid/(received) (35 ) (35 ) —
—
—
Option premium amortization (15 ) (15 ) —
—
—
Upfront payments and amortizations^(c)
(54 ) (54 ) —
—
—
Total mark-to-market energy contract net assets (liabilities) at September 30, 2017^(a)
$ 531
$ 808
$ (277 ) $ —
$ —

~~_________~~


~~(a)~~	~~Amounts are shown net of collateral paid to and received from counterparties.~~

~~(b)~~

For ComEd and DPL, the changes in fair value are recorded as a change in regulatory assets or liabilities. As of September 30, 2017, ComEd recorded a regulatory liability of $277 million related to its mark-to-market derivative liabilities with Generation and unaffiliated suppliers. For the nine months ended September 30, 2017, ComEd also recorded $32 million of decreases in fair value and an increase for realized losses due to settlements of $13 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers.


~~(c)~~	~~Includes derivative contracts acquired or sold by Generation through upfront payments or receipts of cash, excluding option premiums, and the associated amortization.~~

~~Fair Values.~~ ~~The following tables present~~ maturity and source of fair value for ~~Exelon, Generation~~Exelon’s and ~~ComEd~~ComEd’s mark-to-market commodity contract net ~~assets (liabilities).~~liabilities. These net liabilities are associated with ComEd’s floating-to-fixed energy swap contracts with unaffiliated suppliers. The ~~tables provide~~table provides two fundamental pieces of information. First, the ~~tables provide~~table provides the source of fair value used in determining the carrying amount of ~~the Registrants’~~Exelon's and ComEd's total mark-to-market net ~~assets (liabilities), net of allocated collateral.~~liabilities. Second, the ~~tables show~~table shows the maturity, by year, of ~~the Registrants’~~Exelon's and ComEd's commodity contract net ~~assets (liabilities), net of allocated collateral,~~liabilities giving an indication of when these mark-to-market amounts will settle and either generate or require cash. See Note 911 — 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.

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~~Exelon~~

Maturities Within Total Fair
Value
2017 2018 2019 2020 2021 2022 and Beyond
Normal Operations, Commodity derivative contracts^(a)(b):

Actively quoted prices (Level 1) $ 27
$ 1
$ (29 ) $ (13 ) $ 2
$ (2 ) $ (14 )
Prices provided by external sources (Level 2) 112
109
7
(6 ) 5
—
227
Prices based on model or other valuation methods (Level 3)^(c)
47
339
111
18
(32 ) (165 ) 318
Total $ 186
$ 449
$ 89
$ (1 ) $ (25 ) $ (167 ) $ 531


	Maturities Within												Total Fair Value
Commodity derivative contracts(a):	2023		2024		2025		2026		2027		2028 and Beyond		Total Fair Value
Prices based on model or other valuation methods (Level 3)	$	(10)	$	(18)	$	(17)	$	(17)	$	(17)	$	(55)	$	(134)

_________


~~(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 $415 million at September 30, 2017.~~


~~(c)~~	~~Includes ComEd’s~~ (a)Represents ComEd's net liabilities associated ~~with the floating-to-fixed energy swap contracts with unaffiliated suppliers.~~

~~Generation~~

Maturities Within Total Fair
Value
2017 2018 2019 2020 2021 2022 and Beyond
Normal Operations, Commodity derivative contracts^(a)(b):

Actively quoted prices (Level 1) $ 27
$ 1
$ (29 ) $ (13 ) $ 2
$ (2 ) $ (14 )
Prices provided by external sources (Level 2) 112
109
7
(6 ) 5
—
227
Prices based on model or other valuation methods (Level 3) 53
360
133
40
(11 ) 20
595
Total $ 192
$ 470
$ 111
$ 21
$ (4 ) $ 18
$ 808

~~_________~~


~~(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 $415 million at September 30, 2017.~~

~~ComEd~~

Maturities Within Total Fair
Value
2017 2018 2019 2020 2021 2022 and Beyond
Commodity derivative contracts^(a):

Prices based on model or other valuation methods (Level 3) $ (6 ) $ (21 ) $ (22 ) $ (22 ) $ (21 ) $ (185 ) $ (277 )

~~_________~~


~~(a)~~	~~Represents ComEd’s net liabilities associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.~~

~~Credit Risk, Collateral and Contingent Related Features (All Registrants)~~

The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties that enter into derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date. See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for a detailed discussion of credit risk, collateral and contingent related features.

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~~Table of Contents~~

~~Generation~~

The following tables provide information on Generation’s credit exposure for all derivative instruments, normal purchase normal sales agreements, and applicable payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of September 30, 2017. 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 tables below exclude credit risk exposure from individual retail customers, uranium procurement contracts, and exposure through RTOs, ISOs, NYMEX, ICE, NASDAQ, NGX and Nodal commodity exchanges, which are discussed below. Additionally, the figures in the tables below exclude exposures with affiliates, including net receivables with ComEd, PECO, BGE, Pepco, DPL and ACE of $18 million, $22 million, ~~$22 million, $34 million, $12 million, and $7 million as of September 30, 2017, respectively.~~

Rating as of September 30, 2017 Total Exposure Before Credit Collateral
Credit
Collateral^(a)

Net
Exposure

Number of
Counterparties
Greater than 10%
of Net Exposure

Net Exposure of
Counterparties
Greater than
10% of Net
Exposure
Investment grade $ 828
$ 9
$ 819
1
$ 278
Non-investment grade 44
4
40

No external ratings
Internally rated — investment grade 316
—
316

Internally rated — non-investment grade 100
18
82

Total $ 1,288
$ 31
$ 1,257
1
$ 278

Maturity of Credit Risk Exposure
Rating as of September 30, 2017
Less than
2 Years
2-5 Years
Exposure
Greater than
5 Years

Total Exposure
Before Credit
Collateral
Investment grade $ 682
$ 139
$ 7
$ 828
Non-investment grade 36
8
—
44
No external ratings
Internally rated — investment grade 249
35
32
316
Internally rated — non-investment grade 87
13
—
100
Total $ 1,054
$ 195
$ 39
$ 1,288

~~_________~~


~~(a)~~	~~As of September 30, 2017, credit collateral held from counterparties where Generation had credit exposure included $19 million of cash and $12 million of letters of credit.~~

~~ComEd, PECO, BGE, PHI, Pepco, DPL and ACE~~

There have been no significant changes or additions to ComEd’s, PECO's, BGE's, PHI's, Pepco's, DPL's or ACE's exposures to credit risk that are described in ITEM 1A. RISK FACTORS of Exelon’s 2016 Annual Report on Form 10-K.

~~See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for information regarding credit exposure to suppliers.~~

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~~Table of Contents~~

~~Collateral (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. These contracts either contain express provisions or otherwise permit Generation and its counterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the floating-to-fixed energy swap 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. 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. See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for information regarding collateral requirements.unaffiliated suppliers.

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 results of operations, cash flows and financial position. 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. In order to post collateral, Generation depends on access to bank credit facilities, which serve as liquidity sources to fund collateral requirements. See Liquidity and Capital Resources — Credit Matters — Exelon Credit Facilities for additional information.

As of September 30, 2017, Generation had cash collateral of $460 million posted and cash collateral held of $49 million for external counterparties with derivative positions, of which $415 million amount in net cash collateral deposits and $1 million amount in net cash collateral receipts were offset against energy derivative and interest rate and foreign exchange derivative related to underlying energy contracts, respectively. As of September 30, 2017, $3 million of cash collateral held was not offset against net derivative positions because it was not associated with energy-related derivatives or as of the balance sheet date there were no positions to offset. See Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for information regarding the letters of credit supporting the cash collateral.

~~ComEd~~

As of September 30, 2017, ComEd held $10 million in collateral from suppliers in association with energy procurement contracts and held approximately $21 million in the form of cash and letters of credit for both annual and long-term renewable energy contracts. See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements in this report and Note 3 — Regulatory Matters of the 2016 Exelon Form 10-K for additional information.

~~PECO~~

As of September 30, 2017, PECO was not required to post collateral under its energy and natural gas procurement contracts. See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.

~~BGE~~

BGE is not required to post collateral under its electric supply contracts nor was it holding collateral under its electric supply procurement contracts as of September 30, 2017. As of September 30, 2017, BGE was not required to post collateral under its natural gas procurement contracts but was holding an immaterial amount of collateral under its natural gas procurement contracts. See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.

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~~Table of Contents~~

~~Pepco~~

Pepco is not required to post collateral under its energy procurement contracts. See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.

~~DPL~~

DPL is not required to post collateral under its energy procurement contracts. As of September 30, 2017, DPL was not required to post collateral under its natural gas procurement contracts. See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.

~~ACE~~

ACE is not required to post collateral under its energy procurement contracts. See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.

~~RTOs and ISOs (All Registrants)~~

Generation, ComEd, PECO, BGE, Pepco, DPL and ACE participate in all, or some, of the established wholesale spot energy markets that are administered by PJM, ISO-NE, ISO-NY, CAISO, MISO, SPP, AESO, OIESO and ERCOT. 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 are no spot energy markets, electricity is purchased and sold solely through bilateral agreements. For sales into the spot energy 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’ results of operations, cash flows and financial positions.

~~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 the Exchanges are significantly collateralized and have limited counterparty credit risk.

~~Interest Rate and Foreign Exchange Risk (All Registrants)~~

The Registrants use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. The Registrants may also utilize fixed-to-floating interest rate swaps, which are typically designated as fair value hedges, as a means to manage their interest rate exposure. In addition, the Registrants may utilize interest rate derivatives to lock in rate levels in anticipation of future financings, which are typically designated as cash flow hedges. These strategies are employed to manage interest rate risks. At September 30, 2017, Exelon had $800 million of notional amounts of fixed-to-floating hedges outstanding and Exelon and Generation had $491 million of notional amounts of floating-to-fixed hedges outstanding. Assuming the interest rate hedges are 100% effective, a hypothetical 50 bps increase in the interest rates associated with unhedged variable-rate debt (excluding Commercial Paper) and fixed-to-floating swaps would result in approximately a $4 million decrease in Exelon Consolidated pre-tax income for the nine months ended September 30, 2017. 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.

~~Equity Price Risk (Exelon and Generation)~~

Generation maintains trust funds, as required by the NRC, to fund certain costs of decommissioning its nuclear plants. As of September 30, 2017, Generation’s decommissioning trust funds are reflected at fair value on 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.

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~~Table of Contents~~

A hypothetical 10% increase in interest rates and decrease in equity prices would result in a $626 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 ITEM ~~2. MANAGEMENT'S DISCUSSION~~4. CONTROLS AND ~~ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for further discussion of equity price risk as a result of the current capital and credit market conditions.~~

~~Item 4. Controls and Procedures~~PROCEDURES

During the third quarter of ~~2017,~~2023, each of ~~Exelon’s, Generation’s, ComEd’s, PECO’s, BGE’s, PHI's, Pepco's, DPL's and ACE's~~the Registrants' management, including its principal executive officer and principal financial officer, evaluated its disclosure controls and procedures related to the recording, processing, summarizing, and reporting of information in its periodic reports that it files with the SEC. These disclosure controls and procedures have been designed by ~~all~~the Registrants to ensure that (a) material information relating to that Registrant, including its consolidated subsidiaries, is accumulated and made known to ~~Exelon’s~~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 September 30, ~~2017,~~2023, the principal executive officer and principal financial officer of each of ~~Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE~~the Registrants concluded that such Registrant’s disclosure controls and procedures were effective to accomplish its objectives. ~~All~~The Registrants continually strive to improve their disclosure controls and procedures to enhance the quality of its financial reporting and to maintain dynamic systems that change as conditions warrant. There ~~have been~~were no changes in internal control over financial reporting ~~that occurred~~ during the third quarter of ~~2017~~2023 that ~~have~~ materially affected, or are reasonably likely to materially affect, any of ~~Exelon’s, Generation’s, ComEd’s, PECO’s, BGE’s, PHI’s, Pepco’s, DPL’s and ACE’s~~the Registrants' internal control over financial reporting.

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~~Table of Contents~~

PART II — OTHER INFORMATION

~~Item~~ITEM 1. ~~Legal Proceedings~~LEGAL PROCEEDINGS

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 (a) ITEM 3. LEGAL PROCEEDINGS of ~~Exelon’s 2016~~the 2022 Form 10-K, (b) Notes 3 — Regulatory Matters and 18 — Commitments and Contingencies of the 2022 Form 10-K, and ~~(b)~~(c) Notes 53 —Regulatory Matters and 1812 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in PART I, ITEM 1. FINANCIAL STATEMENTS of this Report. Such descriptions are incorporated herein by these references.

149

~~Item~~

Table of Contents

ITEM 1A. ~~Risk Factors~~RISK FACTORS

Risks Related to ~~Exelon~~All Registrants

At September 30, ~~2017,~~2023, the Registrants' risk factors were consistent with the risk factors described in the Registrants' combined ~~2016~~2022 Form 10-K in ITEM 1A. RISK ~~FACTORS.~~FACTORS, except for the following risk factor, which was amended.

The activities associated with the past Deferred Prosecution Agreement and the now resolved associated SEC investigation could have a material adverse effect on Exelon’s and ComEd’s reputation and relationship with legislators, regulators and customers that could affect their ability to achieve actions and approvals (Exelon and ComEd).

~~Item 4. Mine Safety Disclosures~~On July 17, 2020, ComEd entered into a Deferred Prosecution Agreement with the U.S. Attorney’s Office for the Northern District of Illinois (USAO) to resolve the USAO’s investigation into Exelon’s and ComEd’s lobbying activities in the State of Illinois. Exelon was not made a party to the DPA and no charges were brought against Exelon. Under the DPA, the USAO filed a single charge alleging that ComEd improperly gave and offered to give jobs, vendor subcontracts, and payments associated with those jobs and subcontracts for the benefit of the Speaker of the Illinois House of Representatives and the Speaker’s associates, with the intent to influence the Speaker’s action regarding legislation affecting ComEd’s interests. The DPA provided that the USAO would defer any prosecution of such charge and any other criminal or civil case against ComEd in connection with the matters identified therein for a three-year period, which expired, and the pending charge was dismissed in July 2023. In October 2019, the SEC notified Exelon and ComEd that it had opened an investigation into their lobbying activities in the state of Illinois. On September 28, 2023, Exelon and ComEd reached a settlement with the SEC to fully resolve the matter.

The DPA and the settlement with the SEC could have a material adverse impact on Exelon’s and ComEd’s reputation or relationships with regulatory and legislative authorities, customers, and other stakeholders. Those impacts could affect, or make more difficult, their efforts to achieve actions or approvals associated with operations. See Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for more information regarding the DPA and SEC settlement.

ITEM 5. OTHER INFORMATION

All Registrants

~~Not applicable to the Registrants.~~None.

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Table of Contents

ITEM 6. ~~Exhibits~~EXHIBITS

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~~Registrant and its subsidiaries on a consolidated basis and the ~~relevant registrant~~relevant. Registrant agrees to furnish a copy of any such instrument to the Commission upon request.



~~Exhibit~~ ~~No.~~	~~Description~~
~~4.1~~	Supplemental Indenture dated as of August 9, 2017, from ComEd to BNY Mellon Trust Company of Illinois, as trustee, and D. G. Donovan, as co-trustee (File No. 001-01839, Form 8-K dated August 23, 2017, Exhibit 4.1)

~~4.2~~	~~BGE Form of 3.750% notes due 2047 (File No. 001-01910, Form 8-K dated August 24, 2017, Exhibit 4.1)~~

~~4.3~~	One Hundred and Fourteenth Supplemental Indenture dated as of September 1, 2017, from PECO to U.S. Bank National Association, as trustee (File No. 000-16844, Form 8-K dated September 18, 2017, Exhibit 4.1)

~~101.INS~~	~~XBRL Instance~~

~~101.SCH~~	~~XBRL Taxonomy Extension Schema~~

~~101.CAL~~	~~XBRL Taxonomy Extension Calculation~~
��
~~101.DEF~~	~~XBRL Taxonomy Extension Definition~~

~~101.LAB~~	~~XBRL Taxonomy Extension Labels~~

~~101.PRE~~	~~XBRL Taxonomy Extension Presentation~~

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Certifications Pursuant to Rule 13a-14(a) and 15d-14(a) of the Securities and Exchange Act of 1934 as to the Quarterly Report on Form 10-Q for the quarterly period ended September 30, ~~2017~~2023 filed by the following officers for the following companies:



~~31-1~~			~~— Filed by Christopher M. Crane for~~ Exelon Corporation
Exhibit No.		Description
~~31-2~~31-1		~~— Filed by Jonathan W. Thayer 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~~

~~31-5~~	~~— Filed by Anne R. Pramaggiore for Commonwealth Edison Company~~

~~31-6~~	~~— Filed by Joseph R. Trpik, Jr. for Commonwealth Edison Company~~

~~31-7~~	~~— Filed by Craig L. Adams for PECO Energy Company~~

~~31-8~~	~~— Filed by Phillip S. Barnett for PECO Energy Company~~

~~31-9~~	— Filed by Calvin G. Butler, Jr. for Exelon Corporation

31-2		Filed by Jeanne M. Jones for Exelon Corporation

Commonwealth Edison Company
Exhibit No.		Description
31-3		Filed by Gil C. Quiniones for Commonwealth Edison Company

31-4		Filed by Joshua S. Levin for Commonwealth Edison Company

PECO Energy Company
Exhibit No.		Description
31-5		Filed by Michael A. Innocenzo for PECO Energy Company

31-6		Filed by Marissa Humphrey for PECO Energy Company

Baltimore Gas and Electric Company
Exhibit No.		Description
31-7		Filed by Carim V. Khouzami for Baltimore Gas and Electric Company

~~31-10~~31-8		— Filed by David M. Vahos for Baltimore Gas and Electric Company

Pepco Holdings LLC
Exhibit No.		Description
~~31-11~~31-9		— Filed by ~~David M. Velazquez~~J. Tyler Anthony for Pepco Holdings LLC

~~31-12~~31-10		— Filed by ~~Donna J. Kinzel~~Phillip S. Barnett for Pepco Holdings LLC

Potomac Electric Power Company
Exhibit No.		Description
~~31-13~~31-11		— Filed by ~~David M. Velazquez~~J. Tyler Anthony for Potomac Electric Power Company

~~31-14~~31-12		— Filed by ~~Donna J. Kinzel~~Phillip S. Barnett for Potomac Electric Power Company

Delmarva Power & Light Company
Exhibit No.		Description
~~31-15~~31-13		— Filed by ~~David M. Velazquez~~J. Tyler Anthony for Delmarva Power & Light Company

~~31-16~~31-14		— Filed by ~~Donna J. Kinzel~~Phillip S. Barnett for Delmarva Power & Light Company

Atlantic City Electric Company
Exhibit No.		Description
~~31-17~~31-15		— Filed by ~~David M. Velazquez~~J. Tyler Anthony for Atlantic City Electric Company

~~31-18~~31-16		— Filed by ~~Donna J. Kinzel~~Phillip S. Barnett for Atlantic City Electric Company

151

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Table of Contents

Certifications Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code ~~(Sarbanes — Oxley~~(Sarbanes-Oxley Act of 2002) as to the Quarterly Report on Form 10-Q for the quarterly period ended September 30, ~~2017~~2023 filed by the following officers for the following companies:

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Table of Contents



Exelon Corporation
Exhibit No.		Description
32-1		~~— Filed by Christopher M. Crane for Exelon Corporation~~

~~32-2~~	~~— Filed by Jonathan W. Thayer for Exelon Corporation~~

~~32-3~~	~~— Filed by Kenneth W. Cornew for Exelon Generation Company, LLC~~

~~32-4~~	~~— Filed by Bryan P. Wright for Exelon Generation Company, LLC~~

~~32-5~~	~~— Filed by Anne R. Pramaggiore for Commonwealth Edison Company~~

~~32-6~~	~~— Filed by Joseph R. Trpik, Jr. for Commonwealth Edison Company~~

~~32-7~~	~~— Filed by Craig L. Adams for PECO Energy Company~~

~~32-8~~	~~— Filed by Phillip S. Barnett for PECO Energy Company~~

~~32-9~~	— Filed by Calvin G. Butler, Jr. for Exelon Corporation

32-2		Filed by Jeanne M. Jones for Exelon Corporation

Commonwealth Edison Company
Exhibit No.		Description
32-3		Filed by Gil C. Quiniones for Commonwealth Edison Company

32-4		Filed by Joshua S. Levin for Commonwealth Edison Company

PECO Energy Company
Exhibit No.		Description
32-5		Filed by Michael A. Innocenzo for PECO Energy Company

32-6		Filed by Marissa Humphrey for PECO Energy Company

Baltimore Gas and Electric Company
Exhibit No.		Description
32-7		Filed by Carim V. Khouzami for Baltimore Gas and Electric Company

~~32-10~~32-8		— Filed by David M. Vahos for Baltimore Gas and Electric Company

Pepco Holdings LLC
Exhibit No.		Description
~~32-11~~32-9		— Filed by ~~David M. Velazquez~~J. Tyler Anthony for Pepco Holdings LLC

~~32-12~~32-10		— Filed by ~~Donna J. Kinzel~~Phillip S. Barnett for Pepco Holdings LLC

Potomac Electric Power Company
Exhibit No.		Description
~~32-13~~32-11		— Filed by ~~David M. Velazquez~~J. Tyler Anthony for Potomac Electric Power Company

~~32-14~~32-12		— Filed by ~~Donna J. Kinzel~~Phillip S. Barnett for Potomac Electric Power Company

Delmarva Power & Light Company
Exhibit No.		Description
~~32-15~~32-13		— Filed by ~~David M. Velazquez~~J. Tyler Anthony for Delmarva Power & Light Company

~~32-16~~32-14		— Filed by ~~Donna J. Kinzel~~Phillip S. Barnett for Delmarva Power & Light Company

Atlantic City Electric Company
Exhibit No.		Description
~~32-17~~32-15		— Filed by ~~David M. Velazquez~~J. Tyler Anthony for Atlantic City Electric Company

~~32-18~~32-16		— Filed by ~~Donna J. Kinzel~~Phillip S. Barnett for Atlantic City Electric Company

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)

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SIGNATURES

Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

EXELON CORPORATION



/s/ C~~HRISTOPHER~~CALVIN G. BUTLER, JR.	/s/ JEANNE M. C~~RANE~~	~~/s/ JONATHAN~~ ~~W. THAYER~~ JONES
~~Christopher~~Calvin G. Butler, Jr.	Jeanne M. ~~Crane~~	~~Jonathan W. Thayer~~Jones
President, ~~and~~ Chief Executive Officer (Principal Executive Officer) and Director	~~Senior~~ Executive Vice President and Chief Financial Officer (Principal Financial Officer)

~~/s/ DUANE~~ ~~M. DESPARTE~~
~~Duane M. DesParte~~
~~Senior Vice President and Corporate Controller~~ ~~(Principal Accounting Officer)~~

~~November 2, 2017~~

~~279~~

~~Table of Contents~~

~~Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.~~

~~EXELON GENERATION COMPANY, LLC~~



/s/ K~~ENNETH~~ ~~W. CORNEW~~ ROBERT A. KLECZYNSKI		~~/s/ BRYAN~~ ~~P. WRIGHT~~
~~Kenneth W. Cornew~~Robert A. Kleczynski		~~Bryan P. Wright~~
~~President and Chief Executive Officer~~ ~~(Principal Executive Officer)~~	Senior Vice President, Corporate Controller and ~~Chief Financial Officer~~ ~~(Principal Financial Officer)~~

~~/s/ MATTHEW~~ ~~N. BAUER~~
~~Matthew N. Bauer~~
~~Vice President and Controller~~ Tax (Principal Accounting Officer)

November 2, ~~2017~~

2023

~~280~~

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Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

COMMONWEALTH EDISON COMPANY



/s/ A~~NNE~~ ~~R. PRAMAGGIORE~~ GIL C. QUINIONES						/s/ J~~OSEPH~~ ~~R. TRPIK, J~~R. JOSHUA S. LEVIN
~~Anne R. Pramaggiore~~Gil C. Quiniones						~~Joseph R. Trpik, Jr.~~Joshua S. Levin
~~President and~~ Chief Executive Officer (Principal Executive Officer) and Director						Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)

/s/ G~~ERALD~~STEVEN J. K~~OZEL~~ CICHOCKI
~~Gerald~~Steven J. ~~Kozel~~Cichocki
~~Vice President and Controller~~ Director, Accounting (Principal Accounting Officer)

November 2, ~~2017~~

2023

~~281~~

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Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

PECO ENERGY COMPANY



/s/ C~~RAIG~~ ~~L. ADAMS~~ MICHAEL A. INNOCENZO						/s/ P~~HILLIP~~ ~~S. BARNETT~~ MARISSA HUMPHREY
~~Craig L. Adams~~Michael A. Innocenzo						~~Phillip S. Barnett~~Marissa Humphrey
President, ~~and~~ Chief Executive Officer (Principal Executive Officer) and Director						Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)

/s/ S~~COTT~~ ~~A. BAILEY~~ CAROLINE FULGINITI
~~Scott A. Bailey~~Caroline Fulginiti
~~Vice President and Controller~~ Director, Accounting (Principal Accounting Officer)

November 2, ~~2017~~2023

~~282~~

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Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

BALTIMORE GAS AND ELECTRIC COMPANY



/s/ C~~ALVIN~~ ~~G. BUTLER, J~~R. CARIM V. KHOUZAMI						/s/ D~~AVID~~DAVID M. V~~AHOS~~ VAHOS
~~Calvin G. Butler, Jr.~~Carim V. Khouzami						David M. Vahos
President, Chief Executive Officer (Principal Executive Officer) and Director						Senior Vice President, Chief Financial Officer and Treasurer ~~(Principal~~ (Principal Financial Officer)

/s/ A~~NDREW~~ ~~W. HOLMES~~ JASON T. JONES
~~Andrew W. Holmes~~Jason T. Jones
~~Vice President and Controller~~ Director, Accounting (Principal Accounting Officer)

November 2, ~~2017~~2023

~~283~~

157

Table of Contents

Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

PEPCO HOLDINGS LLC



/s/ D~~AVID~~ ~~M. VELAZQUEZ~~ J. TYLER ANTHONY						/s/ D~~ONNA~~ ~~J. KINZEL~~ PHILLIP S. BARNETT
~~David M. Velazquez~~J. Tyler Anthony						~~Donna J. Kinzel~~Phillip S. Barnett
President, ~~and~~ Chief Executive Officer (Principal Executive Officer) and Director						Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)

/s/ R~~OBERT~~ ~~M. AIKEN~~ JULIE E. GIESE
~~Robert M. Aiken~~Julie E. Giese
~~Vice President and Controller~~ Director, Accounting (Principal Accounting Officer)

November 2, ~~2017~~2023

~~284~~

158

Table of Contents

Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

POTOMAC ELECTRIC POWER COMPANY


/s/ J. TYLER ANTHONY		/s/ PHILLIP S. BARNETT
J. Tyler Anthony		Phillip S. Barnett
President, Chief Executive Officer (Principal Executive Officer) and Director		Senior Vice President, Chief Financial Officer, Treasurer (Principal Financial Officer) and Director

/s/ D~~AVID~~ ~~M. VELAZQUEZ~~ JULIE E. GIESE		~~/s/ DONNA~~ ~~J. KINZEL~~
~~David M. Velazquez~~Julie E. Giese		~~Donna J. Kinzel~~
~~President and Chief Executive Officer~~ ~~(Principal Executive Officer)~~	~~Senior Vice President, Chief Financial Officer and Treasurer~~ ~~(Principal Financial Officer)~~

~~/s/ ROBERT~~ ~~M. AIKEN~~
~~Robert M. Aiken~~
~~Vice President and Controller~~ Director, Accounting (Principal Accounting Officer)

November 2, ~~2017~~2023

~~285~~

159

Table of Contents

Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

DELMARVA POWER & LIGHT COMPANY



/s/ D~~AVID~~ ~~M. VELAZQUEZ~~ J. TYLER ANTHONY						/s/ D~~ONNA~~ ~~J. KINZEL~~ PHILLIP S. BARNETT
~~David M. Velazquez~~J. Tyler Anthony						~~Donna J. Kinzel~~Phillip S. Barnett
President, ~~and~~ Chief Executive Officer (Principal Executive Officer) and Director						Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)

/s/ R~~OBERT~~ ~~M. AIKEN~~ JULIE E. GIESE
~~Robert M. Aiken~~Julie E. Giese
~~Vice President and Controller~~ Director, Accounting (Principal Accounting Officer)

November 2, ~~2017~~2023

~~286~~

160

Table of Contents

Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

ATLANTIC CITY ELECTRIC COMPANY



/s/ D~~AVID~~ ~~M. VELAZQUEZ~~ J. TYLER ANTHONY						/s/ D~~ONNA~~ ~~J. KINZEL~~ PHILLIP S. BARNETT
~~David M. Velazquez~~J. Tyler Anthony						~~Donna J. Kinzel~~Phillip S. Barnett
President, ~~and~~ Chief Executive Officer (Principal Executive Officer) and Director						Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)

/s/ R~~OBERT~~ ~~M. AIKEN~~ JULIE E. GIESE
~~Robert M. Aiken~~Julie E. Giese
~~Vice President and Controller~~ Director, Accounting (Principal Accounting Officer)

November 2, ~~2017~~

2023

~~287~~

161



Exelon Corporation Common Stock, without par value		~~960,852,473~~995,437,416
~~Exelon Generation Company, LLC~~		~~not applicable~~
Commonwealth Edison Company Common Stock, $12.50 par value	~~127,021,214~~127,021,396
PECO Energy Company Common Stock, without par value		170,478,507
Baltimore Gas and Electric Company Common Stock, without par value		1,000
Pepco Holdings LLC		not applicable
Potomac Electric Power Company Common Stock, ~~$.01~~$0.01 par value		100
Delmarva Power & Light Company Common Stock, $2.25 par value		1,000
Atlantic City Electric Company Common Stock, $3.00 par value		8,546,017


				Page No.


			~~Page No.~~
~~GLOSSARY OF TERMS AND ABBREVIATIONS~~ ITEM 2.		6
~~FILING FORMAT~~		12
~~CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION~~		12
~~WHERE TO FIND MORE INFORMATION~~		12
~~PART I.~~	~~FINANCIAL INFORMATION~~	13
~~ITEM 1.~~	~~FINANCIAL STATEMENTS~~	13
	~~Exelon Corporation~~
	~~Consolidated Statements of Operations and Comprehensive Income~~	14
	~~Consolidated Statements of Cash Flows~~	15
	~~Consolidated Balance Sheets~~	16
	~~Consolidated Statement of Changes in Shareholders’ Equity~~	18
	~~Exelon Generation Company, LLC~~
	~~Consolidated Statements of Operations and Comprehensive Income~~	19
	~~Consolidated Statements of Cash Flows~~	20
	~~Consolidated Balance Sheets~~	21
	~~Consolidated Statement of Changes in Equity~~	23
	~~Commonwealth Edison Company~~
	~~Consolidated Statements of Operations and Comprehensive Income~~	24
	~~Consolidated Statements of Cash Flows~~	25
	~~Consolidated Balance Sheets~~	26
	~~Consolidated Statement of Changes in Shareholders' Equity~~	28
	~~PECO Energy Company~~
	~~Consolidated Statements of Operations and Comprehensive Income~~	29
	~~Consolidated Statements of Cash Flows~~	30
	~~Consolidated Balance Sheets~~	31
	~~Consolidated Statement of Changes in Shareholder's Equity~~	33
	~~Baltimore Gas and Electric Company~~
	~~Consolidated Statements of Operations and Comprehensive Income~~	34
	~~Consolidated Statements of Cash Flows~~	35
	~~Consolidated Balance Sheets~~	36
	~~Consolidated Statement of Changes in Shareholders’ Equity~~	38
	~~Pepco Holdings LLC~~
	~~Consolidated Statements of Operations and Comprehensive Income~~	39
	~~Consolidated Statements of Cash Flows~~	40
	~~Consolidated Balance Sheets~~	41
	~~Consolidated Statement of Changes in Equity~~	43



		~~Page No.~~
	~~Potomac Electric Power Company~~
	~~Statements of Operations and Comprehensive Income~~	44
	~~Statements of Cash Flows~~	45
	~~Balance Sheets~~	46
	~~Statement of Changes in Shareholder's Equity~~	48
	~~Delmarva Power & Light Company~~
	~~Statements of Operations and Comprehensive Income~~	49
	~~Statements of Cash Flows~~	50
	~~Balance Sheets~~	51
	~~Statement of Changes in Shareholder’s Equity~~	53
	~~Atlantic City Electric Company~~
	~~Consolidated Statements of Operations and Comprehensive Income~~	54
	~~Consolidated Statements of Cash Flows~~	55
	~~Consolidated Balance Sheets~~	56
	~~Consolidated Statement of Changes in Shareholder’s Equity~~	58
	~~Combined Notes to Consolidated Financial Statements~~	59
	~~1. Basis of Presentation~~	59
	~~2. New Accounting Standards~~	60
	~~3. Variable Interest Entities~~	63
	~~4. Mergers, Acquisitions and Dispositions~~	70
	~~5. Regulatory Matters~~	78
	~~6. Impairment of Long-Lived Assets~~	94
	~~7. Early Nuclear Plant Retirements~~	95
	~~8. Intangible Assets~~	97
	~~9. Fair Value of Financial Assets and Liabilities~~	97
	~~10. Derivative Financial Instruments~~	~~118~~
	~~11. Debt and Credit Agreements~~	~~132~~
	~~12. Income Taxes~~	~~136~~
	~~13. Nuclear Decommissioning~~	~~141~~
	~~14. Retirement Benefits~~	~~144~~
	~~15. Severance~~	~~146~~
	~~16. Changes in Accumulated Other Comprehensive Income~~	~~149~~
	~~17. Earnings Per Share and Equity~~	~~154~~
	~~18. Commitments and Contingencies~~	~~155~~
	~~19. Supplemental Financial Information~~	~~166~~
	~~20. Segment Information~~	~~173~~



		~~Page No.~~
~~ITEM 2.~~	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	~~180~~110
			Exelon Corporation		~~180~~110
			Executive Overview		~~180~~110
			Financial Results of Operations		~~181~~110
			Significant ~~2017~~2023 Transactions and Developments		~~189~~113
			~~Exelon's Strategy and Outlook for 2017 and Beyond~~		~~194~~
			~~Liquidity Considerations~~		~~195~~
			Other Key Business Drivers and Management Strategies		~~196~~116
			Critical Accounting Policies and Estimates		~~202~~118
			Results of Operations By Registrant		~~203~~119
			~~Exelon Generation Company, LLC~~	~~204~~Commonwealth Edison Company		119
			~~Commonwealth Edison Company~~	~~212~~PECO Energy Company		122
			~~PECO Energy Company~~	~~218~~
	Baltimore Gas and Electric Company	~~224~~126
			Pepco Holdings LLC		~~231~~129
			Potomac Electric Power Company		~~234~~130
			Delmarva Power & Light Company		~~240~~133
			Atlantic City Electric Company		~~248~~137
			Liquidity and Capital Resources		~~253~~140
			~~Contractual Obligations and Off-Balance Sheet Arrangements~~		~~266~~
ITEM 3.			QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		~~266~~148
ITEM 4.			CONTROLS AND PROCEDURES		~~275~~149
PART II.			OTHER INFORMATION		~~276~~149
ITEM 1.			LEGAL PROCEEDINGS		~~276~~149
ITEM 1A.			RISK FACTORS		~~276~~150

ITEM 4.			~~MINE SAFETY DISCLOSURES~~5.	~~276~~OTHER INFORMATION		150
ITEM 6.			~~EXHIBITS~~	~~276~~EXHIBITS		151
SIGNATURES					~~279~~154
			Exelon Corporation		~~279~~154
			~~Exelon Generation Company, LLC~~	~~280~~Commonwealth Edison Company		155
			~~Commonwealth Edison Company~~	~~281~~PECO Energy Company		156
			~~PECO Energy Company~~	~~282~~
	Baltimore Gas and Electric Company	~~283~~157
			Pepco Holdings LLC		~~284~~158
			Potomac Electric Power Company		~~285~~159
			Delmarva Power & Light Company		~~286~~160
			Atlantic City Electric Company		~~287~~161


GLOSSARY OF TERMS AND ABBREVIATIONS
Exelon Corporation and Related Entities
Exelon			Exelon Corporation
ComEd			Commonwealth Edison Company
PECO			PECO Energy Company
BGE			Baltimore Gas and Electric Company
Pepco Holdings or PHI			Pepco Holdings LLC
Pepco			Potomac Electric Power Company
DPL			Delmarva Power & Light Company
ACE			Atlantic City Electric Company
Registrants			Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE, collectively
Utility Registrants			ComEd, PECO, BGE, Pepco, DPL, and ACE, collectively


~~GLOSSARY OF TERMS AND ABBREVIATIONS~~
~~Exelon Corporation and Related Entities~~
~~Exelon~~BSC		~~Exelon Corporation~~
~~Generation~~	~~Exelon Generation Company, LLC~~
~~ComEd~~	~~Commonwealth Edison Company~~
~~PECO~~	~~PECO Energy Company~~
~~BGE~~	~~Baltimore Gas and Electric Company~~
~~Pepco Holdings or PHI~~	~~Pepco Holdings LLC (formerly Pepco Holdings, Inc.)~~
~~Pepco~~	~~Potomac Electric Power Company~~
~~Pepco Energy Services or PES~~	~~Pepco Energy Services, Inc. and its subsidiaries~~
~~PCI~~	~~Potomac Capital Investment Corporation and its subsidiaries~~
~~DPL~~	~~Delmarva Power & Light Company~~
~~ACE~~	~~Atlantic City Electric Company~~
~~ACE Funding or ATF~~	~~Atlantic City Electric Transition Funding LLC~~
~~BSC~~	Exelon Business Services Company, LLC
~~PHISCO~~		~~PHI Service Company~~
Exelon Corporate		Exelon in its corporate capacity as a holding company
PCI			Potomac Capital Investment Corporation and its subsidiaries
PECO Trust III			PECO Energy Capital Trust III
PECO Trust IV			PECO Energy Capital Trust IV

PHI Corporate			PHI in its corporate capacity as a holding company
~~Registrants~~PHISCO			PHI Service Company
Former Related Entities
Constellation			Constellation Energy Corporation
Generation			Constellation Energy Generation, LLC (formerly Exelon Generation ~~ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, collectively~~
~~Utility Registrants~~	~~ComEd, PECO, BGE, Pepco, DPL and ACE, collectively~~
~~AmerGen~~	~~AmerGen Energy~~ Company, LLC,
~~Antelope Valley~~	~~Antelope Valley Solar Ranch One~~
~~BondCo~~	~~RSB BondCo LLC~~
~~CENG~~	~~Constellation Energy Nuclear Group, LLC~~
~~ConEdison Solutions~~	~~The competitive retail electricity and natural gas business of Consolidated Edison Solutions, Inc.,~~ a subsidiary of ~~Consolidated Edison, Inc.~~
~~Constellation~~	~~Constellation Energy Group, Inc.~~
~~EGTP~~	~~ExGen Texas Power, LLC~~
~~EGR~~	~~ExGen Renewables I, LLC~~
~~Entergy~~	~~Entergy Nuclear FitzPatrick, LLC~~
Exelon ~~Transmission Company~~	~~Exelon Transmission Company, LLC~~
~~Exelon Wind~~	~~Exelon Wind, LLC and Exelon Generation Acquisition Company, LLC~~
~~FitzPatrick~~	~~James A. FitzPatrick nuclear generating station~~
~~Legacy PHI~~	~~PHI, Pepco, DPL and ACE, collectively~~
~~PEC L.P.~~	~~PECO Energy Capital, L.P.~~
~~PECO Trust III~~	~~PECO Capital Trust III~~
~~PECO Trust IV~~	~~PECO Energy Capital Trust IV~~
~~PETT~~	~~PECO Energy Transition Trust~~
~~RPG~~	~~Renewable Power Generation~~
~~SolGen~~	~~SolGen, LLC~~
~~TMI~~	~~Three Mile Island nuclear facility~~
~~UII~~	~~Unicom Investments, Inc.~~
~~Ventures~~	~~Exelon Ventures Company, LLC~~



x			☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934



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


		Page No.
GLOSSARY OF TERMS AND ABBREVIATIONS		4
FILING FORMAT		7
CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION		7
WHERE TO FIND MORE INFORMATION		7
PART I.	FINANCIAL INFORMATION	8
ITEM 1.	FINANCIAL STATEMENTS	8
	Exelon Corporation
	Consolidated Statements of Operations and Comprehensive Income	9
	Consolidated Statements of Cash Flows	10
	Consolidated Balance Sheets	11
	Consolidated Statements of Changes in Shareholders’ Equity	13
	Commonwealth Edison Company
	Consolidated Statements of Operations and Comprehensive Income	15
	Consolidated Statements of Cash Flows	16
	Consolidated Balance Sheets	17
	Consolidated Statements of Changes in Shareholders' Equity	19
	PECO Energy Company
	Consolidated Statements of Operations and Comprehensive Income	20
	Consolidated Statements of Cash Flows	21
	Consolidated Balance Sheets	22
	Consolidated Statements of Changes in Shareholder's Equity	24
	Baltimore Gas and Electric Company
	Statements of Operations and Comprehensive Income	25
	Statements of Cash Flows	26
	Balance Sheets	27
	Statements of Changes in Shareholder's Equity	29
	Pepco Holdings LLC
	Consolidated Statements of Operations and Comprehensive Income	30
	Consolidated Statements of Cash Flows	31
	Consolidated Balance Sheets	32
	Consolidated Statements of Changes in Member's Equity	34


GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
Note ~~“—”~~- of the ~~Exelon 2016~~2022 Form 10-K			Reference to specific Combined Note to Consolidated Financial Statements within ~~Exelon’s 2016~~Exelon's 2022 Annual Report on Form 10-K
~~Act 11~~ABO			~~Pennsylvania Act 11 of 2012~~Accumulated Benefit Obligation
~~Act 129~~AECs			~~Pennsylvania Act 129 of 2008~~
~~AEC~~	Alternative Energy ~~Credit~~Credits that isare issued for each megawatt hour of generation from a qualified alternative energy source
~~AEPS~~AFUDC			~~Pennsylvania Alternative Energy Portfolio Standards~~
~~AEPS Act~~	~~Pennsylvania Alternative Energy Portfolio Standards Act of 2004, as amended~~
~~AESO~~	~~Alberta Electric Systems Operator~~
~~AFUDC~~	Allowance for Funds Used During Construction
~~AGE~~AMI			~~Albany Green Energy Project~~
~~AMI~~	Advanced Metering Infrastructure
AOCI			Accumulated Other Comprehensive Income (Loss)
~~ARC~~ARO			~~Asset Retirement Cost~~
~~ARO~~	Asset Retirement Obligation
~~ASC~~ATM			~~Accounting Standards Codification~~At the market
BGS			Basic Generation Service
~~Block Contracts~~BSA			~~Forward Purchase Energy Block Contracts~~Bill Stabilization Adjustment
~~CAIR~~CEJA			~~Clean Air Interstate Rule~~Climate and Equitable Jobs Act; Illinois Public Act 102-0662 signed into law on September 15, 2021
~~CAISO~~CERCLA			~~California ISO~~
~~CAMR~~	~~Federal Clean Air Mercury Rule~~
~~CAP~~	~~Customer Assistance Program~~
~~CERCLA~~	Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended
~~CES~~CIP			~~Clean Energy Standard~~Conservation Incentive Program
~~CFL~~CMC			~~Compact Fluorescent Light~~Carbon Mitigation Credit
~~Clean Air Act~~CODMs			~~Clean Air Act of 1963, as amended~~Chief Operating Decision Makers
~~Clean Water Act~~		~~Federal Water Pollution Control Amendments of 1972, as amended~~
~~Competition Act~~	~~Pennsylvania Electricity Generation Customer Choice and Competition Act of 1996~~
~~Conectiv~~	~~Conectiv, LLC, a wholly owned subsidiary of PHI and the parent of DPL and ACE~~
~~Conectiv Energy~~	~~Conectiv Energy Holdings, Inc. and substantially all of its subsidiaries, which were sold to Calpine in July 2010~~
~~CPUC~~	~~California Public Utilities Commission~~
~~CSAPR~~	~~Cross-State Air Pollution Rule~~
~~D.C. Circuit Court~~	~~United States Court of Appeals for the District of Columbia Circuit~~
~~DCPSC~~	~~District of Columbia Public Service Commission~~
DC PLUG		District of Columbia Power Line Undergrounding Initiative
~~Default Electricity Supply~~DCPSC			~~The supply~~Public Service Commission of ~~electricity by PHI’s electric utility subsidiaries at regulated rates to retail customers who do not elect to purchase electricity from a competitive supplier, and which, depending on~~ the ~~jurisdiction, is also known as Standard Offer Service or BGS~~District of Columbia
~~DOE~~DEPSC			~~United States Department of Energy~~
~~DOJ~~	~~United States Department of Justice~~
~~DPSC~~	Delaware Public Service Commission


DOEE			District of Columbia Department of Energy & Environment
~~GLOSSARY OF TERMS AND ABBREVIATIONS~~DPA			Deferred Prosecution Agreement
~~Other Terms and Abbreviations~~DPP			Deferred Purchase Price
~~DRP~~DSIC			~~Direct Stock Purchase and Dividend Reinvestment Plan~~Distribution System Improvement Charge
~~DSP~~EIMA			~~Default Service Provider~~
~~DSP Program~~	~~Default Service Provider Program~~
~~EDCs~~	~~Electric distribution companies~~
~~EDF~~	~~Electricite de France SA and its subsidiaries~~
~~EE&C~~	~~Energy Efficiency and Conservation/Demand Response~~
~~EGS~~	~~Electric Generation Supplier~~
~~EIMA~~	Energy Infrastructure Modernization Act (Illinois Senate Bill 1652 and Illinois House Bill 3036)
~~EmPower Maryland~~EPA			~~A Maryland demand-side management program for Pepco and DPL~~
~~EPA~~	United States Environmental Protection Agency
~~EPSA~~ERCOT			~~Electric Power Supply Association~~
~~ERCOT~~	Electric Reliability Council of Texas
ERISA			Employee Retirement Income Security Act of 1974, as amended
~~EROA~~ERP			~~Expected Rate of Return on Assets~~Enterprise Resource Program
~~FASB~~ETAC			~~Financial Accounting Standards Board~~Energy Transition Assistance Charge
FEJA			Illinois Public Act 99-0906 or Future Energy Jobs Act
FERC			Federal Energy Regulatory Commission
~~FRCC~~GAAP			~~Florida Reliability Coordinating Council~~
~~GAAP~~	Generally Accepted Accounting Principles in the United States
GCR			Gas Cost Rate
~~GHG~~GSA			~~Greenhouse Gas~~
~~GSA~~	Generation Supply Adjustment
~~GWh~~GWhs			Gigawatt ~~hour~~hours
~~Health Care Reform Acts~~ICC			~~Patient Protection and Affordable Care Act and Health Care and Education Reconciliation Act of 2010~~
~~HSR Act~~	~~The Hart-Scott-Rodino Antitrust Improvements Act of 1976~~
~~IBEW~~	~~International Brotherhood of Electrical Workers~~
~~ICC~~	Illinois Commerce Commission
~~ICE~~IIJA			~~Intercontinental Exchange~~Infrastructure Investment and Jobs Act
~~Illinois Act~~IIP			~~Illinois Electric Service Customer Choice and Rate Relief Law of 1997~~Infrastructure Investment Program
~~Illinois EPA~~		~~Illinois Environmental Protection Agency~~
Illinois Settlement Legislation		Legislation enacted in 2007 affecting electric utilities in Illinois
~~Integrys~~IPA			~~Integrys Energy Services, Inc.~~
~~IPA~~	Illinois Power Agency
~~IRC~~IRA			Inflation Reduction Act
IRC			Internal Revenue Code
IRS			Internal Revenue Service
~~ISO~~	~~Independent System Operator~~
~~ISO-NE~~	~~Independent System Operator New England Inc.~~
~~ISO-NY~~	~~Independent System Operator New York~~
kV	~~Kilovolt~~
kW	~~Kilowatt~~
~~kWh~~	~~Kilowatt-hour~~
~~LIBOR~~	~~London Interbank Offered Rate~~


GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
~~LLRW~~MDPSC		~~Low-Level Radioactive Waste~~
~~LT Plan~~	~~Long-term renewable resources procurement plan~~
~~LTIP~~	~~Long-Term Incentive Plan~~
~~MAPP~~	~~Mid-Atlantic Power Pathway~~
~~MATS~~	~~U.S. EPA Mercury and Air Toxics Rule~~
~~MBR~~	~~Market Based Rates Incentive~~
~~MDE~~	~~Maryland Department of the Environment~~
~~MDPSC~~	Maryland Public Service Commission
MGP		Manufactured Gas Plant
~~MISO~~mmcf		~~Midcontinent Independent System Operator, Inc.~~
~~mmcf~~	Million Cubic Feet
~~Moody’s~~MMG		~~Moody’s Investor Service~~Middle Mile Grant
~~MOPR~~MRP		~~Minimum Offer Price Rule~~Multi-Year Rate Plan
~~MRV~~MW		~~Market-Related Value~~Megawatt
MWMWh		Megawatt hour
~~MWh~~N/A		~~Megawatt hour~~Not applicable
~~NAAQS~~NAV		~~National Ambient Air Quality Standards~~
~~n.m.~~	~~not meaningful~~
~~NAV~~	Net Asset Value
NDT		Nuclear Decommissioning Trust
~~NEIL~~NJBPU		~~Nuclear Electric Insurance Limited~~
~~NERC~~	~~North American Electric Reliability Corporation~~
~~NGS~~	~~Natural Gas Supplier~~
~~NJBPU~~	New Jersey Board of Public Utilities
~~NJDEP~~NPNS		~~New Jersey Department of Environmental Protection~~Normal Purchase Normal Sale scope exception
~~Non-Regulatory Agreements Units~~NPS		~~Nuclear generating units or portions thereof whose decommissioning-related activities are not subject to contractual elimination under regulatory accounting~~National Park Service
~~NOSA~~NRD		~~Nuclear Operating Services Agreement~~Natural Resources Damages
~~NPDES~~OCI		~~National Pollutant Discharge Elimination System~~
~~NRC~~	~~Nuclear Regulatory Commission~~
~~NSPS~~	~~New Source Performance Standards~~
~~NUGs~~	~~Non-utility generators~~
~~NWPA~~	~~Nuclear Waste Policy Act of 1982~~
~~NYMEX~~	~~New York Mercantile Exchange~~
~~NYPSC~~	~~New York Public Service Commission~~
~~OCI~~	Other Comprehensive Income
~~OIESO~~OPEB		~~Ontario Independent Electricity System Operator~~
~~OPC~~	~~Office of People’s Counsel~~
~~OPEB~~	Other Postretirement Employee Benefits
~~PA DEP~~PAPUC		~~Pennsylvania Department of Environmental Protection~~
~~PAPUC~~	Pennsylvania Public Utility Commission
PGC		Purchased Gas Cost Clause
PJM		PJM Interconnection, LLC


POLR
~~GLOSSARY OF TERMS AND ABBREVIATIONS~~
~~Other Terms and Abbreviations~~
~~POLR~~	Provider of Last Resort
~~POR~~PPA		~~Purchase of Receivables~~
~~PPA~~	Power Purchase Agreement
~~Price-Anderson Act~~PP&E		~~Price-Anderson Nuclear Industries Indemnity Act of 1957~~Property, plant, and equipment
~~Preferred Stock~~PRPs		~~Originally issued shares of non-voting, non-convertible and non-transferable Series A preferred stock, par value $0.01 per share~~
~~PRP~~	Potentially Responsible Parties
~~PSEG~~REC		~~Public Service Enterprise Group Incorporated~~
~~PURTA~~	~~Pennsylvania Public Realty Tax Act~~
PV	~~Photovoltaic~~
~~RCRA~~	~~Resource Conservation and Recovery Act of 1976, as amended~~
~~REC~~	Renewable Energy Credit which is issued for each megawatt hour of generation from a qualified renewable energy source
Regulatory Agreement Units		Nuclear generating units or portions thereof whose decommissioning-related activities are subject to contractual elimination under regulatory accounting
~~RES~~RFP		~~Retail Electric Suppliers~~
~~RFP~~	Request for Proposal
Rider		Reconcilable Surcharge Recovery Mechanism
~~RGGI~~ROE		~~Regional Greenhouse Gas Initiative~~
~~RMC~~	~~Risk Management Committee~~
~~ROE~~	Return on equity
~~RPM~~ROU		~~PJM Reliability Pricing Model~~Right-of-use
RPS		Renewable Energy Portfolio Standards
~~RSSA~~RTO		~~Reliability Support Services Agreement~~
~~RTEP~~	~~Regional Transmission Expansion Plan~~
~~RTO~~	Regional Transmission Organization
~~S&P~~SEC		~~Standard & Poor’s Ratings Services~~
~~SEC~~	United States Securities and Exchange Commission
~~Senate Bill 1~~SOFR		~~Maryland Senate Bill 1~~Secured Overnight Financing Rate
~~SERC~~SOS		~~SERC Reliability Corporation (formerly Southeast Electric Reliability Council)~~
~~SGIG~~	~~Smart Grid Investment Grant from DOE~~
~~SILO~~	~~Sale-In, Lease-Out~~
~~SMPIP~~	~~Smart Meter Procurement and Installation Plan~~
~~SNF~~	~~Spent Nuclear Fuel~~
~~SOS~~	Standard Offer Service
~~SPFPA~~STRIDE		~~Security, Police~~Maryland Strategic Infrastructure Development and ~~Fire Professionals of America~~Enhancement Program
~~SPP~~TCJA		~~Southwest Power Pool~~Tax Cuts and Jobs Act
~~Transition Bond Charge~~ZEC		~~Revenue ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds and related taxes, expenses and fees~~
~~Transition Bonds~~	~~Transition Bonds issued by ACE Funding~~
~~UGSOA~~	~~United Government Security Officers of America~~
~~Upstream~~	~~Natural gas exploration and production activities~~
~~VIE~~	~~Variable Interest Entity~~Zero Emission Credit or Zero Emission Certificate



~~GLOSSARY OF TERMS AND ABBREVIATIONS~~
~~Other Terms and Abbreviations~~
~~WECC~~		~~Western Electric Coordinating Council~~
~~ZEC~~		~~Zero Emission Credit~~
~~ZES~~		~~Zero Emission Standard~~



	Nine Months Ended September 30,
(In millions)	2017			2016
Cash flows from operating activities
Net income	$	1,911		$	956
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization	3,999			4,009
Impairment of long-lived assets and losses on regulatory assets	488			274
Gain on sales of assets	(5		)	(41		)
Bargain purchase gain	(233		)	—
Deferred income taxes and amortization of investment tax credits	439			623
Net fair value changes related to derivatives	149			100
Net realized and unrealized gains on nuclear decommissioning trust fund investments	(429		)	(243		)
Other non-cash operating activities	603			1,224
Changes in assets and liabilities:
Accounts receivable	224			(296		)
Inventories	(87		)	21
Accounts payable and accrued expenses	(593		)	296
Option premiums received (paid), net	35			(24		)
Collateral (posted) received, net	(100		)	757
Income taxes	167			527
Pension and non-pension postretirement benefit contributions	(344		)	(283		)
Other assets and liabilities	(547		)	(537		)
Net cash flows provided by operating activities	5,677			7,363
Cash flows from investing activities
Capital expenditures	(5,556		)	(6,368		)
Proceeds from nuclear decommissioning trust fund sales	6,848			7,914
Investment in nuclear decommissioning trust funds	(7,044		)	(8,093		)
Acquisition of businesses, net	(208		)	(6,896		)
Proceeds from sales of long-lived assets	219			49
Proceeds from termination of direct financing lease investment	—			360
Changes in restricted cash	(67		)	(75		)
Other investing activities	(2		)	(110		)
Net cash flows used in investing activities	(5,810		)	(13,219		)
Cash flows from financing activities
Changes in short-term borrowings	(570		)	(1,014		)
Proceeds from short-term borrowings with maturities greater than 90 days	621			195
Repayments on short-term borrowings with maturities greater than 90 days	(610		)	(452		)
Issuance of long-term debt	2,616			4,488
Retirement of long-term debt	(1,728		)	(944		)
Retirement of long-term debt to financing trust	(250		)	—
Restricted proceeds from issuance of long-term debt	—			(30		)
Redemption of preference stock	—			(190		)
Sale of noncontrolling interest	396			—
Dividends paid on common stock	(921		)	(873		)
Common stock issued from treasury stock	1,150			—
Proceeds from employee stock plans	61			36
Other financing activities	(64		)	35
Net cash flows provided by financing activities	701			1,251
Increase (Decrease) in cash and cash equivalents	568			(4,605		)
Cash and cash equivalents at beginning of period	635			6,502
Cash and cash equivalents at end of period	$	1,203		$	1,897



(In millions)	September 30, 2017		December 31, 2016
ASSETS
Current assets
Cash and cash equivalents	$	1,203	$	635
Restricted cash and cash equivalents	320		253
Deposit with IRS	1,250		1,250
Accounts receivable, net
Customer	3,854		4,158
Other	950		1,201
Mark-to-market derivative assets	699		917
Unamortized energy contract assets	81		88
Inventories, net
Fossil fuel and emission allowances	387		364
Materials and supplies	1,281		1,274
Regulatory assets	1,264		1,342
Other	1,435		930
Total current assets	12,724		12,412
Property, plant and equipment, net	73,067		71,555
Deferred debits and other assets
Regulatory assets	10,238		10,046
Nuclear decommissioning trust funds	12,966		11,061
Investments	634		629
Goodwill	6,677		6,677
Mark-to-market derivative assets	426		492
Unamortized energy contract assets	407		447
Pledged assets for Zion Station decommissioning	57		113
Other	1,277		1,472
Total deferred debits and other assets	32,682		30,937
Total assets^(a)	$	118,473	$	114,904


	Nine Months Ended September 30, 2023
(In millions, shares in thousands)	Issued Shares	Common Stock		Treasury Stock		Retained Earnings		Accumulated Other Comprehensive Loss, net		Noncontrolling Interests		Total Shareholders' Equity
Balance at December 31, 2022	995,830	$	20,908	$	(123)	$	4,597	$	(638)	$	—	$	24,744
Net income	—	—		—		669		—		—		669
Long-term incentive plan activity	306	1		—		—		—		—		1
Employee stock purchase plan issuances	266	12		—		—		—		—		12




Common stock dividends ($0.36/common share)	—	—		—		(359)				—		(359)
Other comprehensive loss, net of income taxes	—	—		—		—		(1)		—		(1)

Balance at March 31, 2023	996,402	$	20,921	$	(123)	$	4,907	$	(639)	$	—	$	25,066
Net income	—	—		—		343		—		—		343
Long-term incentive plan activity	372	9		—		—		—		—		9
Employee stock purchase plan issuances	278	11		—		—		—		—		11




Common stock dividends ($0.36/common share)	—	—		—		(359)		—		—		(359)
Other comprehensive income, net of income taxes	—	—		—		—		9		—		9

Balance at June 30, 2023	997,052	$	20,941	$	(123)	$	4,891	$	(630)	$	—	$	25,079
Net income	—	—		—		700		—		—		700
Long-term incentive plan activity	(84)	3		—		—		—		—		3
Employee stock purchase plan issuances	302	12		—		—		—		—		12



Common stock dividends ($0.36/common share)	—	—		—		(358)		—		—		(358)
Other comprehensive income, net of income taxes	—	—		—		—		34		—		34
Balance at September 30, 2023	997,270	$	20,956	$	(123)	$	5,233	$	(596)	$	—	$	25,470



	Member’s Equity
(In millions)	Membership Interest			Undistributed Earnings			Accumulated Other Comprehensive Loss, net			Noncontrolling Interests			Total Equity
Balance, December 31, 2016	$	9,261		$	2,275		$	(54	)	$	1,774		$	13,256
Net income	—			479			—			12			491
Changes in equity of noncontrolling interests	—			—			—			(11		)	(11		)
Sale of noncontrolling interest	(36		)	—			—			443			407
Distribution of net retirement benefit obligation to member	33			—			—			—			33
Allocation of tax benefit from member	99			—			—			—			99
Distributions to member	—			(494		)	—			—			(494		)
Other comprehensive income (loss), net of income taxes	—			—			18			(2		)	16
Balance, September 30, 2017	$	9,357		$	2,260		$	(36	)	$	2,216		$	13,797



(In millions)	Common Stock		Other Paid-In Capital		Retained Deficit Unappropriated			Retained Earnings Appropriated			Total Shareholders’ Equity
Balance, December 31, 2016	$	1,588	$	6,150	$	(1,639	)	$	2,626		$	8,725
Net income	—		—		447			—			447
Appropriation of retained earnings for future dividends	—		—		(447		)	447			—
Common stock dividends	—		—		—			(316		)	(316		)
Contributions from parent	—		567		—			—			567
Parent tax matter indemnification	—		21		—			—			21
Balance, September 30, 2017	$	1,588	$	6,738	$	(1,639	)	$	2,757		$	9,444



	Successor												Predecessor
	Three Months Ended September 30,						Nine Months Ended September 30,			March 24 to September 30,			January 1 to March 23,
(In millions)	2017			2016			2017			2016			2016
Operating revenues
Electric operating revenues	$	1,280		$	1,366		$	3,417		$	2,485		$	1,096
Natural gas operating revenues	18			17			105			46			57
Operating revenues from affiliates	12			11			35			34			—
Total operating revenues	1,310			1,394			3,557			2,565			1,153
Operating expenses
Purchased power	354			370			901			658			471
Purchased fuel	7			6			46			17			26
Purchased power and fuel from affiliates	112			207			371			362			—
Operating and maintenance	214			200			666			870			294
Operating and maintenance from affiliates	37			26			108			51			—
Depreciation and amortization	179			182			511			355			152
Taxes other than income	122			124			344			248			105
Total operating expenses	1,025			1,115			2,947			2,561			1,048
Gain on sales of assets	—			—			1			—			—
Operating income	285			279			611			4			105
Other income and (deductions)
Interest expense, net	(62		)	(64		)	(183		)	(135		)	(65		)
Other, net	13			19			40			31			(4		)
Total other income and (deductions)	(49		)	(45		)	(143		)	(104		)	(69		)
Income (loss) before income taxes	236			234			468			(100		)	36
Income taxes	83			68			109			(9		)	17
Net income (loss)	$	153		$	166		$	359		$	(91	)	$	19
Comprehensive income (loss), net of income taxes
Net income (loss)	$	153		$	166		$	359		$	(91	)	$	19
Other comprehensive income, net of income taxes
Pension and non-pension postretirement benefit plans:
Actuarial loss reclassified to periodic cost	—			—			—			—			1
Other comprehensive income	—			—			—			—			1
Comprehensive income (loss)	$	153		$	166		$	359		$	(91	)	$	20


	Nine Months Ended September 30, 2023
(In millions)	Membership Interest		Undistributed (Losses)/Gains		Total Member's Equity
Balance at December 31, 2022	$	11,582	$	(352)	$	11,230
Net income	—		155		155
Distributions to member	—		(112)		(112)
Contributions from member	405		—		405
Balance at March 31, 2023	$	11,987	$	(309)	$	11,678
Net income	—		103		103
Distributions to member	—		(100)		(100)

Balance at June 30, 2023	$	11,987	$	(306)	$	11,681
Net income	—		232		232
Distributions to member	—		(198)		(198)
Contributions from member	70		—		70

Balance at September 30, 2023	$	12,057	$	(272)	$	11,785



(In millions)	Membership Interest		Undistributed Earnings (Losses)			Member's Equity
Successor
Balance, December 31, 2016	$	8,077	$	(61	)	$	8,016
Net income	—		359			359
Distribution to member	—		(267		)	(267		)
Contribution from member	751		—			751
Allocation of tax benefit from member	7		—			7
Balance, September 30, 2017	$	8,835	$	31		$	8,866


	Nine Months Ended September 30, 2023
(In millions)	Common Stock		Retained Earnings		Total Shareholder's Equity
Balance at December 31, 2022	$	2,767	$	1,015	$	3,782
Net income	—		65		65
Common stock dividends	—		(48)		(48)
Contributions from parent	243		—		243
Balance at March 31, 2023	$	3,010	$	1,032	$	4,042
Net income	—		64		64



Common stock dividends	—		(67)		(67)

Balance at June 30, 2023	$	3,010	$	1,029	$	4,039
Net income	—		120		120



Common stock dividends	—		(85)		(85)
Contributions from parent	65		—		65
Balance at September 30, 2023	$	3,075	$	1,064	$	4,139



Registrant	1	2	3	4	5	6	7	8	9	10	11	12	13	14	15	16	17	18	19	20
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	.	.	.		.				.	.	.	.		.	.			.	.	.



September 30, 2017	Commercial Agreement VIEs		Equity Investment VIEs		Total
Total assets^(a)	$	635	$	519	$	1,154
Total liabilities^(a)	39		229		268
Exelon's ownership interest in VIE^(a)	—		259		259
Other ownership interests in VIE^(a)	596		31		627
Registrants’ maximum exposure to loss:
Carrying amount of equity method investments	—		259		259
Contract intangible asset	9		—		9
Debt and payment guarantees	—		—		—
Net assets pledged for Zion Station decommissioning^(b)	4		—		4



Cash paid for purchase price	$	110
Cash paid for net cost reimbursement	125
Nuclear fuel transfer	54
Total consideration transferred	$	289

Identifiable assets acquired and liabilities assumed
Current assets	$	60
Property, plant and equipment	298
Nuclear decommissioning trust funds	807
Other assets^(a)	114
Total assets	$	1,279

Current liabilities	$	6
Nuclear decommissioning ARO	444
Pension and OPEB obligations	33
Deferred income taxes	149
Spent nuclear fuel obligation	110
Other liabilities	15
Total liabilities	$	757
Total net identifiable assets, at fair value	$	522

Bargain purchase gain (after-tax)	$	233



Total consideration transferred	$	257

Identifiable assets acquired and liabilities assumed
Working capital assets	$	204
Property, plant and equipment	2
Mark-to-market derivative assets	6
Unamortized energy contract assets	100
Customer relationships	9
Other assets	1
Total assets	$	322

Mark-to-market derivative liabilities	$	65
Total liabilities	$	65
Total net identifiable assets, at fair value	$	257



	Expected Payment Period							Successor
Description	Expected Payment Period	Pepco		DPL		ACE		PHI		Exelon
Rate credits	2016 - 2017	$	91	$	67	$	101	$	259	$	259
Energy efficiency	2016 - 2021	—		—		—		—		122
Charitable contributions	2016 - 2026	28		12		10		50		50
Delivery system modernization	Q2 2017	—		—		—		—		22
Green sustainability fund	Q2 2017	—		—		—		—		14
Workforce development	2016 - 2020	—		—		—		—		17
Other		1		5		—		6		29
Total		$	120	$	84	$	111	$	315	$	513



(In millions of dollars, except per share data)	Total Consideration
Cash paid to PHI shareholders at $27.25 per share (254 million shares outstanding at March 23, 2016)	$	6,933
Cash paid for PHI preferred stock	180
Cash paid for PHI stock-based compensation equity awards^(a)	29
Total purchase price	$	7,142



Purchase Price Allocation^(a)
Current assets	$	1,441
Property, plant and equipment	11,088
Regulatory assets	5,015
Other assets	248
Goodwill	4,005
Total assets	$	21,797

Current liabilities	$	2,752
Unamortized energy contracts	1,515
Regulatory liabilities	297
Long-term debt, including current maturities	5,636
Deferred income taxes	3,447
Pension and OPEB obligations	821
Other liabilities	187
Total liabilities	$	14,655
Total purchase price	$	7,142



	Three Months Ended September 30,					Nine Months Ended September 30,
Acquisition, Integration and Financing Costs^(a)	2017			2016		2017			2016
Exelon	$	(8	)	$	20	$	10		$	123
Generation	5			9		18			29
ComEd^(b)	—			—		1			(6		)
PECO	1			1		3			3
BGE^(c)	1			1		3			(3		)
Pepco^(d)	(8		)	3		(6		)	26
DPL^(e)	1			2		(6		)	18
ACE^(f)	(8		)	2		(6		)	17



	Three Months Ended September 30,		Nine Months Ended September 30,		Year Ended December 31,
	2016^(a)		2016^(a)		2016^(b)
Total operating revenues	$	9,002	$	24,468	$	32,342
Net income attributable to common shareholders	501		1,346		1,562

Basic earnings per share	$	0.54	$	1.46	$	1.69
Diluted earnings per share	0.54		1.45		1.69



	2017
Annual Transmission Filings^(a)	ComEd			BGE			Pepco			DPL			ACE
Initial revenue requirement increase	$	44		$	31		$	5		$	6		$	20
Annual reconciliation (decrease) increase	(33		)	3			15			8			22
Dedicated facilities decrease^(b)	—			(8		)	—			—			—
Total revenue requirement increase	$	11		$	26		$	20		$	14		$	42

Allowed return on rate base^(c)	8.43		%	7.47		%	7.92		%	7.16		%	8.02		%
Allowed ROE^(d)	11.50		%	10.50		%	10.50		%	10.50		%	10.50		%



	Exelon		ComEd^(a)		PECO		BGE^(b)		PHI		Pepco^(c)		DPL^(c)		ACE
September 30, 2017	$	71	$	7	$	—	$	54	$	10	$	6	$	4	$	—

	Exelon		ComEd^(a)		PECO		BGE^(b)		PHI		Pepco^(c)		DPL^(c)		ACE
December 31, 2016	$	72	$	5	$	—	$	57	$	10	$	6	$	4	$	—



													Successor
As of December 31, 2016	Exelon			ComEd			PECO			BGE			PHI			Pepco			DPL			ACE
Purchased receivables	$	313		$	87		$	72		$	59		$	95		$	63		$	10		$	22
Allowance for uncollectible accounts^(a)	(37		)	(14		)	(6		)	(4		)	(13		)	(7		)	(2		)	(4		)
Purchased receivables, net	$	276		$	73		$	66		$	55		$	82		$	56		$	8		$	18



Income statement expense (pre-tax)	Q3 2017		YTD 2017
Depreciation and amortization
Accelerated depreciation^(a)	$	106	$	141
Accelerated nuclear fuel amortization	6		8
Total	$	112	$	149