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 and energy distribution and transmission businesses. Prior to March 23, 2016, Exelon's principal, wholly owned subsidiaries included Generation, 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, Pepco, DPL and ACE, in the energy distribution and transmission ~~businesses. Refer~~businesses through ComEd, PECO, BGE, Pepco, DPL, and ACE.

On February 21, 2021, Exelon's Board of Directors approved a plan to separate the Utility Registrants and 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, accounting, engineering, customer operations, distribution and transmission planning, asset management, system operations, and power procurement, to PHI operating companies. The costs of BSC and PHISCO are directly charged or allocated to the applicable subsidiaries. The results of Exelon’s corporate operations are presented as “Other” in the consolidated financial statements and include intercompany eliminations unless otherwise disclosed.

The accompanying consolidated financial statements as of ~~September 30, 2017 and 2016~~March 31, 2022 and for the three months ended March 31, 2022 and ~~nine months then ended~~2021 are unaudited but, in the opinion of the management of each Registrant 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

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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

December 31, ~~2016~~2021 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.~~2022. 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, meets 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 all periods presented. See Note 2 — Discontinued Operations for additional information.

Prior Period Adjustments and ~~disclosures,~~Reclassifications (Exelon, PHI, ACE)

In the first quarter of 2022, management identified an error related to an overstatement of the regulatory liability associated with ACE’s mechanism to recover the cost of Transition Bonds issued in 2002 and 2003 by ACE Funding. Management has concluded that the error was not material to previously issued financial statements for Exelon, PHI or ACE.

The error was corrected through a revision to ACE’s financial statements contained herein. The impact of the error correction was an $8 million increase to ACE’s opening Retained earnings as ~~well as the potential to early adopt where applicable. The Registrants have assessed other FASB issuances~~ of ~~new standards which are not listed below given the current expectation such standards will not significantly impact the Registrants' financial reporting.~~

~~Revenue from Contracts with Customers (Issued May 2014 and subsequently amended to address implementation questions):~~ ~~Changes the criteria for recognizing revenue from a contract~~January 1, 2021 with a ~~customer.~~corresponding reduction to Regulatory liabilities of $11 million and an increase to Deferred income taxes and unamortized investment tax credits of $3 million. The impact of the error to ACE’s Total operating revenues and Net income was less than $1 million for the three months ended March 31, 2021. The error did not impact net cash flows provided by operating activities, net cash flows used in investing activities or net cash flows provided by financing activities for the three months ended March 31, 2021.

The error was corrected in the Exelon and PHI financial statements for the three months ended March 31, 2022 as it was not material, resulting in an increase to Net income of $8 million.

2. Discontinued Operations (Exelon)

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, through the distribution of 326,663,937 common stock shares of Constellation, the new ~~revenue recognition guidance, including subsequent amendments,~~publicly traded company, to Exelon shareholders. Under the separation plan, Exelon shareholders retained their current shares of Exelon stock and received one share of Constellation common stock for every three shares of Exelon common stock held on January 20, 2022, the record date for the distribution, in a transaction that is ~~effective~~tax-free to Exelon and its shareholders for ~~annual reporting periods beginning~~U.S. federal income tax purposes.

Constellation was newly formed and incorporated in Pennsylvania on ~~or after December~~June 15, ~~2017, with~~2021 for the ~~option~~purposes of separation and holds Generation (including Generation's subsidiaries).

Pursuant to ~~early adopt~~ the ~~standard~~separation:

•Exelon entered into four term loans consisting of a 364-day term loan for ~~annual periods beginning~~$1.15 billion and three 18-month term loans for $300 million, $300 million and $250 million, respectively. Exelon issued these term loans primarily to fund the cash payment to Constellation and for general corporate purposes. See Note 10 — Debt and Credit Agreements for additional information.

•Exelon made a cash payment of $1.75 billion to Constellation on ~~or after December 15, 2016. Exelon has not early adopted this standard.~~

January 31, 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

~~The new standard replaces existing guidance~~•Exelon contributed its equity ownership interest in Generation to Constellation. Exelon no longer retains any equity ownership interest in Generation or Constellation.

•Exelon transferred certain corporate assets and employee-related obligations to Constellation.

•Exelon received cash from Generation of $258 million to settle the intercompany loan on ~~revenue recognition,~~January 31, 2022. See Note 10 — Debt and Credit Agreements 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 entered into several agreements, including ~~most industry specific guidance,~~the following:

•Separation Agreement – governs the rights and obligations between Exelon and Constellation regarding certain actions to be taken in connection with ~~a five step model for recognizing~~the separation, among others, including the allocation of assets and ~~measuring revenue from contracts with customers. The objective~~liabilities between Exelon and Constellation.

•Transition Services Agreement (TSA) – governs the terms and conditions of the ~~new standard is~~services that Exelon will provide to Constellation and Constellation will provide to Exelon for an expected period of two years, provided that certain services may be longer than the term and services may be extended with approval from both parties. The services include 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 period from February 1, 2022 to March 31, 2022, the amounts Exelon billed Constellation and Constellation billed Exelon for these services were $56 million recorded in Other income, net and $9 million recorded in Operating and maintenance expense, respectively.

•Tax Matters Agreement (TMA) – governs the respective rights, responsibilities and obligations of Exelon and Constellation with respect to all tax matters, including 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 Generation after the separation. Prior to the separation, such expenses were primarily recorded as Purchased power from affiliates and an immaterial amount recorded as Operating and maintenance expense from 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 Generation to provide a ~~single, comprehensive revenue recognition model for all~~portion of ComEd’s electric supply requirements. ComEd also purchased RECs and ZECs from Generation.

•PECO received electric supply from Generation under contracts executed through PECO’s competitive procurement process. In addition, PECO had a ten-year agreement with ~~customers~~Generation to ~~improve comparability within industries, across industries,~~sell solar AECs.

•BGE received a portion of its energy requirements from Generation under its MDPSC-approved market-based SOS and ~~across capital markets. The underlying principle is that an entity will recognize revenue to depict~~gas commodity programs.

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

•DPL received a portion of ~~goods or services to customers at an amount that~~its energy requirements from Generation under its MDPSC and DEPSC approved market-based SOS commodity programs.

•ACE received electric supply from Generation under contracts executed through ACE’s competitive procurement process approved by the ~~entity expects to be entitled to in exchange for those goods or services. The guidance~~NJBPU.

ComEd and PECO also ~~requires~~have receivables with Generation as a number of disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows. The guidance can be applied retrospectively to each prior reporting period presented (full retrospective method) or retrospectively with a cumulative effect adjustment to retained earnings for initial applicationresult of the ~~guidance~~nuclear decommissioning contractual construct whereby, to the extent NDT funds are greater than the underlying ARO at the ~~date~~end of ~~initial adoption (modified retrospective method).~~

~~The Registrants have assessed the revenue recognition standard~~decommissioning, such amounts are due back to ComEd and ~~are executing a detailed implementation plan in preparation~~PECO, as applicable, 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~~payment to ~~identify implementation issues and support the development~~their respective customers. See Note 10 — Asset Retirement Obligations 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) and the Utility Registrants expect to disclose disaggregated revenue by major customer class (i.e., residential and commercial & industrial) separately for electric and gas in the Combined Notes to Consolidated Financial ~~Statements.~~

~~Improving~~Statements of the ~~Presentation of Net Periodic Pension Cost~~Exelon 2021 Form 10-K 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 cost and other non-service cost components 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 operations and the components are disclosed in the Retirement Benefits footnote. Service cost will be presented as part of income from operations and the other non-service cost components will be classified outside of income from operations on the Consolidated

Note 15 — Related Party Transactions 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 2 — Discontinued Operations

Discontinued Operations

The separation represented a strategic shift that would have a major effect on Exelon’s operations and financial results. Accordingly, the separation meets the criteria for discontinued operations.

The 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. Additionally, service cost~~Income for the three months ended March 31, 2022 and March 31, 2021.

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 ~~only component eligible~~impact of transaction costs, certain BSC costs, including any transition costs, that were historically allocated and directly attributable to Generation, transactions between Generation and the Utility Registrants, and tax-related adjustments. Transaction costs include costs for ~~capitalization (whereas under current GAAP, all components~~external bankers, accountants, appraisers, lawyers, external counsels and other advisors, among others, who are involved in the negotiation, appraisal, due diligence and regulatory approval of ~~net benefit cost~~the separation. Transition costs are ~~eligible for capitalization).~~

primarily employee-related costs such as recruitment expenses, costs to establish certain stand-alone functions and information technology systems, professional services fees and other separation-related costs during the transition to separate Generation. For the purposes of reporting discontinued operations, these results also include transactions between Generation ~~ComEd, PECO, BGE,~~and the Utility Registrants that were historically eliminated within Exelon’s Consolidated Statements of Operations as these transactions will be ongoing after the separation. Certain BSC ~~PHI, Pepco, DPL, ACE and PHISCO participate~~costs that were historically allocated to Generation are presented as part of continuing operations in Exelon’s ~~single employer pension and OPEB plans and apply multi-employer accounting. Multi-employer accounting is~~Consolidated Statements of Operations as these costs do 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 reportedqualify 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 for the presentation~~expenses 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 liabilities 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 the 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~~discontinued operations per 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 goodwill as of September 30, 2017. This updated guidance is not currently expected to impact the Registrants’ financial reporting. The standard is effective January 1, 2020, with early adoption permitted, and must be applied on a prospective basis.rules.


	Three Months Ended March 31,
	2022		2021
Operating revenues
Competitive business revenues	$	1,855	$	5,265
Competitive business revenues from affiliates	161		294
Total operating revenues	2,016		5,559
Operating expenses
Competitive businesses purchased power and fuel	1,138		4,610

Operating and maintenance(a)	371		904

Depreciation and amortization	94		940
Taxes other than income taxes	44		121
Total operating expenses	1,647		6,575
Gain on sales of assets and businesses	10		71
Operating income (loss)	379		(945)
Other income and (deductions)
Interest expense, net	(20)		(68)

Other, net	(281)		167
Total other income and (deductions)	(301)		99
Income (loss) before income taxes	78		(846)
Income taxes	(40)		(58)
Equity in losses of unconsolidated affiliates	(1)		(1)
Net income (loss)	117		(789)
Net income attributable to noncontrolling interests	1		25
Net income (loss) from discontinued operations	$	116	$	(814)

Table of Contents

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__________

(a)Includes transaction 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.

~~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~~separation of ~~fair value changes~~$52 million and $3 million for the three months ended March 31, 2022 and 2021, respectively. $50 million and $2 million of ~~financial liabilities for which the fair value option has been elected, (iii) amends several disclosure requirements, including the methods~~transaction costs and ~~significant assumptions used to estimate fair value or a description~~$2 million and less than $1 million of ~~the changes~~transition costs are included in the ~~methods~~results of discontinued operations in the table presented above for the three months ended March 31, 2022 and ~~assumptions used to estimate fair value, and (iv) requires disclosure of the fair value of financial~~March 31, 2021, respectively. See discussion above for additional information.

There were no 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'~~discontinued operations included in Exelon’s Consolidated Balance ~~Sheets,~~Sheet as of March 31, 2022. Constellation had net assets of $11,573 million that separated on February 1, 2022 that resulted in a reduction to Exelon’s equity during the three months ended March 31, 2022. Refer to the Distribution of Constellation line in Exelon’s Consolidated ~~Statements~~Statement of ~~Operations~~Changes in Shareholders’ Equity for further information.

The following table presents the assets and ~~Comprehensive Income, and~~liabilities of discontinued operations in Exelon’s Consolidated ~~Statements~~Balance Sheet as of ~~Cash Flows.~~

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

A VIE is a legal entity that possesses any of the following characteristics: an insufficient amount of equity at risk to finance its activities, equity owners who do not have the power to direct 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.

~~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~~2021:


	December 31, 2021
ASSETS
Current assets
Cash and cash equivalents	$	510
Restricted cash and cash equivalents	72
Accounts receivable
Customer accounts receivable	1,724
Customer allowance for credit losses	(55)
Customer accounts receivable, net	1,669
Other accounts receivable	596
Other allowance for credit losses	(4)
Other accounts receivable, net	592
Mark-to-market derivative assets	2,169
Inventories, net
Fossil fuel and emission allowances	284
Materials and supplies	1,004
Renewable energy credits	529
Assets held for sale	13
Other	993
Total current assets of discontinued operations	7,835
Property, plant, and equipment (net of accumulated depreciation and amortization of $15,888)	19,661
Deferred debits and other assets
Nuclear decommissioning trust funds	15,938
Investments	193

Mark-to-market derivative assets	949
Other	1,768
Total property, plant, and equipment, deferred debits, and other assets of discontinued operations	38,509
Total assets of discontinued operations	$	46,344

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 2 — Discontinued Operations

~~Consolidated Variable Interest Entities below)~~. As of September 30, 2017 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)~~.


	December 31, 2021
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings	$	2,082
Long-term debt due within one year	1,220
Accounts payable	1,757
Accrued expenses	818
Mark-to-market derivative liabilities	981

Renewable energy credit obligation	779
Liabilities held for sale	3
Other	300
Total current liabilities of discontinued operations	7,940
Long-term debt	4,575
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	3,583
Asset retirement obligations	12,819
Pension obligations	939
Non-pension postretirement benefit obligations	876
Spent nuclear fuel obligation	1,210
Mark-to-market derivative liabilities	513

Other	1,161
Total long-term debt, deferred credits, and other liabilities of discontinued operations	25,676
Total liabilities of discontinued operations	$	33,616

~~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 million of~~The following table presents selected financial information regarding 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 supportflows of the ~~payment obligations related to~~discontinued operations that are included within Exelon’s Consolidated Statements of Cash Flows for the Engineering, Procurement and Construction (EPC) contract (see Note 14 - Debt and Credit Agreements for additional details on Albany Green Energy, LLC). During the third quarter of 2017, the ownership of the entity increased to 99%, all payment obligations related to the EPC contract were satisfied, and the parental guarantee provided by Generation was terminated. As a result, the entity is now sufficiently capitalized and no longer meets the definition of a VIE. The entity was previously disclosed in “a group of companies formed by Generation to build, own and operate other generating facilities” as of 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 quarter of 2017 the rate stabilization bonds were fully redeemed and BGE remitted its final payment to BondCo. During the ninethree months ended ~~September 30, 2017, BGE remitted $22 million to BondCo. During the three~~March 31, 2022 and nine months ended September 30, 2016, BGE remitted $27 million and $64 million to BondCo, 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.March 31, 2021.

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~~


	Three Months Ended March 31, 2022
	2022		2021
Non-cash items included in net income (loss) from discontinued operations:
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization	$	207	$	1,346

Gain on sales of assets and businesses	9		(71)
Deferred income taxes and amortization of investment tax credits	(143)		(234)
Net fair value changes related to derivatives	(59)		(178)
Net realized and unrealized losses (gains) on NDT fund investments	205		(118)
Net unrealized losses on equity investments	16		23
Other decommissioning-related activity	36		(332)
Cash flows from investing activities:
Capital expenditures	(227)		(394)
Collection of DPP	169		1,574
Supplemental cash flow information:
Decrease in capital expenditures not paid	(128)		(37)
Increase in DPP	348		1,339
Increase in PP&E related to ARO update	335		—

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 3 — Regulatory Matters

3. Regulatory Matters (All Registrants)

As ~~of September 30, 2017, Exelon's, PHI's and ACE's consolidated VIE consists of:~~

~~ATF~~, ~~a special purpose entity formed by ACE for the purpose of securitizing authorized portions of ACE’s recoverable stranded costs through the issuance and sale of transition bonds.~~

~~As of September 30, 2017 and 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 to the renewable energy project companies 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 million~~discussed in ~~credit support 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~~3 — Regulatory Matters of the Exelon ~~2016~~2021 Form 10-K, the Registrants are involved in rate and regulatory proceedings at FERC and their state commissions. The following discusses developments in 2022 and updates to the 2021 Form 10-K.

Distribution Base Rate Case Proceedings

The following tables show the completed and pending distribution base rate case proceedings in 2022.

Completed Distribution Base Rate Case Proceedings


Registrant/Jurisdiction	Filing Date	Service	Requested Revenue Requirement Increase		Approved Revenue Requirement Increase		Approved ROE		Approval Date	Rate Effective Date
ComEd - Illinois(a)	April 16, 2021	Electric	$	51	$	46	7.36	%	December 1, 2021	January 1, 2022
PECO - Pennsylvania	March 30, 2021	Electric	246		132		N/A(b)		November 18, 2021	January 1, 2022
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 - District of Columbia(d)	May 30, 2019 (amended June 1, 2020)	Electric	136		109		9.275	%	June 8, 2021	July 1, 2021
Pepco - Maryland(e)	October 26, 2020 (amended March 31, 2021)	Electric	104		52		9.55	%	June 28, 2021	June 28, 2021
DPL - Maryland(f)	September 1, 2021 (amended December 23, 2021)	Electric	27		13		9.60	%	March 2, 2022	March 2, 2022
ACE - New Jersey(g)	December 9, 2020 (amended February 26, 2021)	Electric	67		41		9.60	%	July 14, 2021	January 1, 2022

__________

(a)ComEd's 2022 approved revenue requirement reflects an increase of $37 million for ~~additional information regarding Generation's~~the initial year revenue requirement for 2022 and ~~Exelon’s transactions with CENG):~~

~~under the NOSA, Generation conducts all activities~~an increase of $9 million related to the ~~operation~~annual reconciliation for 2020. The revenue requirement for 2022 provides for a weighted average debt and equity return on distribution rate base of 5.72%, inclusive of an allowed ROE of 7.36%, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. The reconciliation revenue requirement for 2020 provides for a weighted average debt and equity return on distribution rate base of 5.69%, inclusive of an allowed ROE of 7.29%, reflecting the monthly yields on 30-year treasury bonds plus 580 basis points less a performance metrics penalty of 7 basis points.

(b)The PECO electric 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. The MDPSC awarded BGE electric revenue requirement increases of $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. BGE proposed to use certain tax benefits to fully offset the increases in 2021 and 2022 and partially offset the increase in 2023. However, the 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 ~~CENG nuclear generation fleet owned by CENG subsidiaries (the CENG fleet)~~cumulative 2021 and ~~provides corporate~~2022 electric revenue requirement increases and ~~administrative services for the remaining life and decommissioning~~50% of the ~~CENG nuclear plants as if they were~~cumulative gas revenue requirement increases. Whether certain tax benefits will be used to offset the customer rate increases in 2023 has not been decided, and BGE cannot predict the outcome.

(d)Reflects a ~~part~~cumulative multi-year plan with 18-months remaining in 2021 through 2022. The DCPSC awarded Pepco electric incremental revenue requirement increases of $42 million and $67 million, before offsets, for 2021 and 2022, respectively. However, the ~~Generation nuclear fleet, subject~~DCPSC utilized the acceleration of refunds for certain tax benefits along with other rate relief to partially offset the ~~CENG member rights of EDF,~~

~~under the Power Services Agency Agreement (PSAA), Generation provides scheduling, asset management~~customer rate increases by $22 million and ~~billing services to the CENG fleet~~$40 million for ~~the remaining operating life of the CENG nuclear plants,~~2021 and 2022, respectively.

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~~(e)Reflects a 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, ~~to support the operations of CENG as well as a $165~~$16 million, ~~guarantee of CENG’s cash pooling agreement with its subsidiaries.~~

~~As of September 30, 2017~~ and ~~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~~$15 million, before offsets, for the ~~transfer by ACE~~12-month periods ending March 31, 2022, 2023, and 2024, respectively. Pepco proposed to ~~ATF~~utilize certain tax benefits to fully offset the 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 ~~right to collect a non-bypassable Transition Bond Charge from ACE customers pursuant to bondable stranded costs rate orders issued by~~cumulative revenue requirement increase for 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~~12-month period ending March 31, 2023. Whether certain tax benefits will be used to ~~settle obligations~~offset the customer rate increases for the 12-month period ending March 31, 2024 has not been decided, and Pepco cannot predict the outcome.

(f)The approved settlement reflects a 9.60% ROE, which is solely for the purposes of calculating AFUDC and regulatory asset carrying costs.

(g)Requested and approved increases are before New Jersey sales and use tax. The order allows ACE to retain approximately $11 million of certain tax benefits which resulted in a decrease to income tax expense in Exelon's, PHI's, and ACE's Consolidated Statements of Operations and Comprehensive Income in the third quarter of 2021.

Pending Distribution Base Rate Case Proceedings

Registrant/Jurisdiction

Filing Date

Service

Requested Revenue Requirement Increase

Requested ROE

Expected Approval Timing

ComEd - Illinois(a)

April 15, 2022

Electric

199

7.85

Fourth quarter of 2022

PECO - Pennsylvania

March 31, 2022

Natural Gas

10.95

Fourth quarter of 2022

DPL - Delaware(b)

January 14, 2022 (amended February 28, 2022)

Natural Gas

10.30

First quarter of 2023

__________

(a)ComEd's 2023 requested revenue requirement reflects an increase of $144 million for the initial year revenue requirement for 2023 and an increase of $55 million related to the annual reconciliation for 2021. The revenue requirement for 2023 provides for a weighted average debt and equity return on distribution rate base of 5.94%, inclusive of an allowed ROE of 7.85%, reflecting the average monthly yields for 30-year treasury bonds plus 580 basis points. The reconciliation revenue requirement for 2021 provides for a weighted average debt and equity return on distribution rate base of 5.91%, inclusive of an allowed ROE of 7.78%, reflecting the average monthly yields for 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 update filing under EIMA as a result of the ~~respective VIE;~~law authorizing the rate setting process sunsetting at the end of 2022. See Note 3. - Regulatory Matters of the Exelon 2021 Form 10-K for additional information on ComEd's transition away from the electric distribution formula rate.

~~Exelon, Generation, PHI~~(b)The rates will go into effect on August 14, 2022, subject to refund.

Transmission Formula Rates

The Utility Registrants' transmission rates are each established based on a FERC-approved formula. ComEd, BGE, Pepco, DPL, and ACE ~~did not provide any additional material financial support~~are required to file an annual update to the ~~VIEs;~~FERC-approved formula on or before May 15, and PECO is required to file on or before May 31, with the resulting rates effective on June 1 of the 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 revenue requirement in effect beginning June 1 of the prior year and actual costs incurred for that year (annual reconciliation). The annual update for BGE is based on prior year actual costs and current year projected capital additions, accumulated depreciation, depreciation and amortization expense, and accumulated deferred income taxes. The update for BGE also reconciles any differences between the actual costs and actual revenues for the calendar year (annual reconciliation).

~~Exelon, Generation, PHI~~For 2022, the following total increases were included in ComEd’s and BGE's electric transmission formula rate update. PECO, Pepco, DPL, and ACE ~~did not have any material contractual commitments or obligations~~intend to ~~provide financial support to~~file by the ~~VIEs; and~~required deadline for the annual update.

~~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:


Registrant(a)	Initial Revenue Requirement Increase		Annual Reconciliation Decrease		Total Revenue Requirement Increase			Allowed Return on Rate Base(c)		Allowed ROE(d)
ComEd	$	24	$	(24)	$	—		8.11	%	11.50	%
BGE	25		(4)		16		(b)	7.30	%	10.50	%

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:

Note 3 — Regulatory Matters

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)All rates are effective June 1, 2022 - May 31, 2023, subject to review by interested parties pursuant to review protocols of ComEd's and BGE's tariff.

~~_________~~


~~(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~~(b)The increase in unconsolidated VIEs generally include equity investments and energy purchase and sale contracts. For the equity investments, the carrying amount of the investments is reflected 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 predominantlyBGE's transmission revenue requirement includes a $5 million reduction related to ~~working capital accounts~~a FERC-approved dedicated facilities charge to recover the costs of providing transmission service to specifically designated load by BGE.

~~Table of Contents~~

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

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

~~and generally represent~~(c)Represents 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 subordinatedweighted average 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.~~return on transmission rate bases.

~~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)~~

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. (d)As part of the ~~acquisition agreements, Generation provided nuclear fuel~~FERC-approved settlements of ComEd’s 2007 transmission rate case, the rate of return on common equity is 11.50%, inclusive of a 50-basis-point incentive adder for being a member of a RTO, and ~~reimbursed Entergy for incremental costs~~the common equity component of the ratio used to ~~prepare for~~calculate the weighted average debt and ~~conduct a plant refueling outage; and Generation reimbursed Entergy for incremental costs to operate and maintain the plant~~equity return 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.transmission formula rate is currently capped at 55%. 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, the MDPSC issued an order approving the amounts of the additional merger benefits for Maryland, but amending the proposed allocations of 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 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.

~~Table of Contents~~

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

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

~~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 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 recorded 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 Pepco, DPL and ACE are not permitted to reduce employment levels due to involuntary attrition associated 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 stay 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 of the January 27, 2017 decision by 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 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 review 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 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 for the Merger Transaction~~

The total purchase price consideration of approximately $7.1 billion for the PHI Merger consisted of cash paid to PHI shareholders, cash paid 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 units 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 of costs and a fair return on invested capital, or rate base, generally measured at historical cost. In applying the acquisition method of accounting, 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 orFERC-approved settlement of the ~~fair value adjustments, with no impact on reported net income. See Note 5 - Regulatory Matters for additional information regarding~~ROE complaint against BGE, the ~~fair value~~rate 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~~common equity 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 of Pepco, DPL and ACE do not reflect the revaluation of any assets 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 )

~~For 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 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. See Note 6 - Impairment of Long-Lived Assets for further information.

~~In July 2016, DPL completed the sale~~10.50%, inclusive of a 9~~acre land parcel located on South Madison Street in Wilmington, DE, resulting in~~50-basis-point incentive adder for being a ~~pre-tax gain~~member of approximately $4 million. 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. a RTO.

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

~~Distribution Formula Rate~~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 multi-year plan 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 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 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.

The ICC initiated a docket to accelerate and fully credit to customers TCJA unprotected property-related EDIT no later than December 31, 2025. On April 13, ~~2017, ComEd filed its annual distribution formula rate with~~2022, a stipulation and agreement on the ICC pursuant to EIMA. The filing establishes the revenue requirement used to set the rates that will take effect in January 2018 after the ICC’s review and approval, which is due by December 2017. The revenue requirement requested is based on 2016 actual costs plus projected 2017 capital additions as well as an annual reconciliation of the 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 millionschedule for the ~~initial revenue requirement for 2017~~acceleration of EDIT amortization was submitted by ComEd, the Illinois Attorney General's Office, and the Citizens Utility Board. At this time, ComEd cannot predict an ~~increase~~outcome 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 rate base 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 2016 provided for a weighted average debt and equity return on distribution rate base of 6.45% inclusive of an allowed ROE of 8.34%, reflecting the average rate on 30-year treasury notes plus 580 basis points less a performance metrics penalty of 6 basis points. these proceedings.

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 of the Exelon ~~2016~~2021 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 be based upon the current social cost 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~~10-K 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~~on CEJA (referred 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.

Clean Energy ~~Efficiency~~Law).

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.~~

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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~~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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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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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 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 to review the policy. In 2014, the NJBPU issued a decision which retained the CTA, but in a highly modified format that significantly reduced the impact of the CTA to ACE.

On September 18, 2017, the Appellate Division of the Superior Court of New Jersey reversed 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 (Exelon, PHI and ACE).~~ ~~On March 30, 2017,~~December 22, 2021, ACE filed ~~an application~~ with the NJBPU a petition to ~~increase its annual electric distribution rates~~terminate the 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 $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.

~~On September 8, 2017, ACE entered into a settlement agreement with~~ the NJBPU ~~staff,~~on March 23, 2022. Upon closing of the ~~New Jersey Division~~transaction on March 31, 2022, ACE recognized a liability of ~~Rate Counsel~~$203 million for the contract termination fee, which is to be paid by the end of 2024, and ~~Wal-Mart Stores, Inc.~~recognized a corresponding regulatory asset of $203 million.

As of March 31, 2022, the $203 million liability for the contract termination fee consists of $85 million and $118 million included in ~~its electric distribution rate proceeding, which provides~~Other current liabilities and Other deferred credits and other liabilities, respectively, in Exelon's Consolidated Balance Sheet. As of March 31, 2022, the current and noncurrent liability is included in PPA termination obligation and Other deferred credits and other liabilities, respectively, in PHI's and ACE's Consolidated Balance Sheets.

Regulatory Assets and Liabilities

The Utility Registrants' regulatory assets and liabilities have not changed materially since December 31, 2021, unless noted below. See Note 3 — Regulatory Matters of the Exelon 2021 Form 10-K for ~~an increase~~

additional information on the specific regulatory assets and liabilities.

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Note 3 — Regulatory Matters

~~in ACE annual electric distribution base rates~~PECO. Regulatory assets increased $66 million primarily due to an increase of ~~$43~~$60 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~~Deferred Income Taxes regulatory asset. Regulatory liabilities decreased by $112 million primarily due 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 ratea decrease of ~~approximately $29 million (revised to approximately $32~~$111 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~~Nuclear Decommissioning regulatory liability.

BGE. Regulatory assets decreased $50 million primarily due to a ~~stipulation of settlement entered into by the parties providing for an overall annual rate~~ decrease of ~~approximately $32~~$19 million ~~effective June 1, 2017. The rate decrease was placed into effect provisionally, subject~~in the Electric Energy and Natural Gas Costs regulatory asset and $16 million in the Energy Efficiency and Demand Response Programs regulatory asset. Regulatory liabilities decreased $53 million primarily due to a ~~review by NJBPU and~~decrease of $65 million in 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 underDeferred Income Taxes regulatory liability.

ACE. Regulatory assets increased $205 million primarily due to an ~~approved deferral mechanism. The matter is pending at the NJBPU.~~

~~New York Regulatory Matters~~

~~New York Clean Energy Standard (Exelon and Generation).~~ 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, subject to specified caps and minimum performance requirements. The price to be paid for the ZECs under each tranche will be administratively determined using a formula based on the social cost of carbon as determined in 2016 by the federal government, subject to pricing adjustments designed to lower the ZEC price based on increase in ~~underlying energy 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 toEnergy Costs 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 with FERC with revisions 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 adjustment 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 operationsasset as a result of the ~~noncontrolling interests in CENG.~~

~~The RSSA required Ginna~~PPA termination. Regulatory liabilities decreased $19 million primarily due to ~~continue operating through the RSSA term. On September 30, 2016, Ginna filed the required notice with the NYPSC~~a decrease 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$9 million in ~~June 2017. Additionally,~~ the ~~provisions of the RSSA provided for a one-time payment of $12~~Deferred Income Taxes regulatory liability and $5 million to be paid from RG&E to Ginna at the end of the contract. This $12 million was recognized in revenue as of March 31, 2017. RG&E paid the $12 million 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 information regarding the impacts of a decision to early retire one or more nuclear plants.

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~~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 Note 3 — Regulatory Matters of 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~~

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~~(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.

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~~(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 2016 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,Energy Costs 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.liability.

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, refer to Note 3 — Regulatory Matters 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 of Contents~~

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

~~(Dollars 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)~~

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.

~~(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.


	Exelon		ComEd(a)		PECO		BGE(b)		PHI		Pepco(c)		DPL(c)		ACE
March 31, 2022	$	49	$	2	$	—	$	34	$	13	$	11	$	2	$	—

December 31, 2021	43		1		—		37		5		3		2		—

__________

(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 authorized amounts capitalized for ratemaking purposes primarily relate to earnings on shareholder's investment on its 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 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)

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
$ —
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 Exelon 2021 Form 10-K for additional information regarding the primary sources of revenue for the Registrants.


~~(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.

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 liabilities in their Consolidated Balance Sheets.

For PHI, Pepco, DPL, and 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.

Revenues recognized were immaterial for Exelon, PHI, Pepco, DPL, and ACE for the three months ended March 31, 2022 and 2021. As of March 31, 2022 and December 31, 2021, ComEd's, PECO's, and BGE's contract liabilities were immaterial.

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

~~Purchase~~Transaction Price Allocated to Remaining Performance Obligations

The following table shows the amounts of ~~Receivables Programs (Exelon,~~future revenues expected to be recorded in each year for performance obligations that are unsatisfied or partially unsatisfied as of March 31, 2022. 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.


	2022		2023		2024		2025		2026 and thereafter		Total
Exelon	$	6	$	8	$	6	$	5	$	82	$	107
PHI	6		8		6		5		82		107
Pepco	4		6		5		5		65		85
DPL	1		1		—		—		9		11
ACE	1		1		1		—		8		11

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 Registrant's 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 6 reportable segments, which include ComEd, PECO, BGE, ~~PHI,~~and PHI's 3 reportable segments consisting of Pepco, DPL, and ~~ACE)~~

ACE. ComEd, PECO, BGE, Pepco, DPL, and ACE each represent a single reportable segment, and as such, no separate segment information is provided for these Registrants. Exelon, ComEd, PECO, BGE, Pepco, DPL, and ACE's CODMs evaluate the performance of and allocate resources to ComEd, PECO, BGE, Pepco, DPL, and ACE based on net income.

An analysis and reconciliation of the Registrants’ reportable segment information to the respective information in the consolidated financial statements for the three months ended March 31, 2022 and 2021 is as follows:

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 March 31, 2022 and 2021


	ComEd		PECO		BGE		PHI		Other(a)		Intersegment Eliminations		Exelon
Operating revenues(b):
2022
Electric revenues	$	1,734	$	741	$	736	$	1,318	$	—	$	(7)	$	4,522
Natural gas revenues	—		306		418		83		—		(2)		$	805
Shared service and other revenues	—		—		—		3		576		(579)		$	—
Total operating revenues	$	1,734	$	1,047	$	1,154	$	1,404	$	576	$	(588)	$	5,327
2021
Electric revenues	$	1,535	$	661	$	632	$	1,170	$	—	$	(7)	$	3,991
Natural gas revenues	—		228		342		71		—		—		641
Shared service and other revenues	—		—		—		3		491		(494)		—
Total operating revenues	$	1,535	$	889	$	974	$	1,244	$	491	$	(501)	$	4,632

Intersegment revenues(c):
2022	$	6	$	1	$	7	$	3	$	576	$	(587)	$	6
2021	6		2		6		3		487		(497)		7
Depreciation and amortization:
2022	$	321	$	92	$	171	$	218	$	15	$	—	$	817
2021	292		86		152		210		17		—		757
Operating expenses:
2022	$	1,406	$	793	$	919	$	1,215	$	625	$	(531)	$	4,427
2021	1,210		679		752		1,058		448		(339)		3,808
Interest expense, net:
2022	$	100	$	41	$	35	$	69	$	93	$	—	$	338
2021	96		38		34		67		83		—		318
Income (loss) from continuing operations before income taxes:
2022	$	240	$	220	$	207	$	137	$	(62)	$	(43)	$	699
2021	236		177		196		136		(32)		(149)		564
Income Taxes:
2022	$	52	$	14	$	9	$	7	$	146	$	(10)	$	218
2021	39		10		(13)		8		7		(12)		39
Net income (loss) from continuing operations:
2022	$	188	$	206	$	198	$	130	$	(208)	$	(33)	$	481
2021	197		167		209		128		(39)		(137)		525
Capital Expenditures:
2022	$	617	$	344	$	303	$	409	$	22	$	—	$	1,695
2021	613		295		336		456		46		—		1,746
Total assets:
March 31, 2022	$	37,013	$	14,113	$	12,509	$	25,636	$	7,583	$	(4,156)	$	92,698
December 31, 2021	36,470		13,824		12,324		24,744		7,634		(8,319)		86,677

__________

(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 expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 14 — Supplemental Financial Information for additional information on total utility taxes.

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 15 — Related Party Transactions for additional information on intersegment revenues.

PHI:


	Pepco		DPL		ACE		Other(a)		Intersegment Eliminations		PHI
Operating revenues(b):
2022
Electric revenues	$	614	$	348	$	349	$	—	$	7	$	1,318
Natural gas revenues	—		83		—		—		—		83
Shared service and other revenues	—		—		—		107		(104)		3
Total operating revenues	$	614	$	431	$	349	$	107	$	(97)	$	1,404
2021
Electric revenues	$	553	$	311	$	310	$	—	$	(4)	$	1,170
Natural gas revenues	—		71		—		—		—		71
Shared service and other revenues	—		—		—		95		(92)		3
Total operating revenues	$	553	$	382	$	310	$	95	$	(96)	$	1,244
Intersegment revenues(c):
2022	$	1	$	1	$	1	$	97	$	(97)	$	3
2021	1		2		1		95		(96)		3
Depreciation and amortization:
2022	$	108	$	57	$	47	$	6	$	—	$	218
2021	102		53		47		8		—		210
Operating expenses:
2022	$	547	$	357	$	311	$	97	$	(97)	$	1,215
2021	466		309		282		97		(96)		1,058
Interest expense, net:
2022	$	36	$	16	$	14	$	3	$	—	$	69
2021	34		15		15		3		—		67
Income (loss) before income taxes:
2022	$	44	$	60	$	27	$	6	$	—	$	137
2021	65		61		14		(4)		—		136
Income Taxes:
2022	$	(2)	$	4	$	1	$	4	$	—	$	7
2021	6		5		—		(3)		—		8
Net income (loss):
2022	$	46	$	56	$	26	$	2	$	—	$	130
2021	59		56		14		(1)		—		128
Capital Expenditures:
2022	$	218	$	103	$	87	$	1	$	—	$	409
2021	220		112		123		1		—		456
Total assets:
March 31, 2022	$	10,458	$	5,573	$	4,929	$	4,720	$	(44)	$	25,636
December 31, 2021	9,903		5,412		4,556		4,933		(60)		24,744

__________

(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

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 March 31, 2022
Revenues from contracts with customers	ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Electric revenues
Residential	$	857	$	487	$	417	$	652	$	275	$	207	$	170
Small commercial & industrial	423		111		81		141		38		56		47
Large commercial & industrial	153		64		131		323		253		26		44
Public authorities & electric railroads	14		8		7		16		8		4		4
Other(a)	239		62		97		193		46		56		81
Total electric revenues(b)	$	1,686	$	732	$	733	$	1,325	$	620	$	349	$	346
Natural gas revenues
Residential	$	—	$	218	$	282	$	51	$	—	$	51	$	—
Small commercial & industrial	—		76		45		21		—		21		—
Large commercial & industrial	—		—		65		3		—		3		—
Transportation	—		8		—		4		—		4		—
Other(c)	—		3		35		4		—		4		—
Total natural gas revenues(d)	$	—	$	305	$	427	$	83	$	—	$	83	$	—
Total revenues from contracts with customers	$	1,686	$	1,037	$	1,160	$	1,408	$	620	$	432	$	346

Other revenues
Revenues from alternative revenue programs	$	40	$	6	$	(12)	$	(5)	$	(7)	$	(1)	$	3
Other electric revenues(e)	8		3		4		1		1		—		—
Other natural gas revenues(e)	—		1		2		—		—		—		—

Total other revenues	$	48	$	10	$	(6)	$	(4)	$	(6)	$	(1)	$	3
Total revenues for reportable segments	$	1,734	$	1,047	$	1,154	$	1,404	$	614	$	431	$	349

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 March 31, 2021
Revenues from contracts with customers	ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Electric revenues
Residential	$	741	$	433	$	362	$	605	$	253	$	190	$	162
Small commercial & industrial	367		100		69		118		33		46		39
Large commercial & industrial	134		57		105		248		184		21		43
Public authorities & electric railroads	11		9		7		13		6		4		3
Other(a)	220		52		77		143		51		41		52
Total electric revenues(b)	$	1,473	$	651	$	620	$	1,127	$	527	$	302	$	299
Natural gas revenues
Residential	$	—	$	160	$	216	$	46	$	—	$	46	$	—
Small commercial & industrial	—		59		35		18		—		18		—
Large commercial & industrial	—		—		54		2		—		2		—
Transportation	—		7		—		4		—		4		—
Other(c)	—		2		31		1		—		1		—
Total natural gas revenues(d)	$	—	$	228	$	336	$	71	$	—	$	71	$	—
Total revenues from contracts with customers	$	1,473	$	879	$	956	$	1,198	$	527	$	373	$	299

Other revenues
Revenues from alternative revenue programs	$	54	$	10	$	18	$	46	$	26	$	9	$	11
Other electric revenues(e)	8		—		—		—		—		—		—


Total other revenues	$	62	$	10	$	18	$	46	$	26	$	9	$	11
Total revenues for reportable segments	$	1,535	$	889	$	974	$	1,244	$	553	$	382	$	310

__________

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

(b)Includes operating revenues from affiliates in 2022 and 2021 respectively of:

•$6 million, $6 million at ComEd

•$1 million, $1 million at PECO

•$2 million, $2 million at BGE

•$3 million, $3 million at PHI

•$1 million, $1 million at Pepco

•$2 million, $2 million at DPL

•$1 million, $1 million at ACE

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

(d)Includes operating revenues from affiliates in 2022 and 2021 respectively of:

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

•$6 million, $4 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 March 31, 2022
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance as of December 31, 2021	$	320	$	73	$	105	$	38	$	104	$	37	$	18	$	49
Plus: Current period provision for expected credit losses(a)	110		26		31		26		27		11		7		9
Less: Write-offs, net of recoveries(b)(c)	41		7		11		5		18		8		1		9
Balance as of March 31, 2022	$	389	$	92	$	125	$	59	$	113	$	40	$	24	$	49

	Three Months Ended March 31, 2021
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance as of December 31, 2020	$	334	$	97	$	116	$	35	$	86	$	32	$	22	$	32
Plus: Current period provision for expected credit losses(d)	70		21		20		9		20		11		6		3
Less: Write-offs, net of recoveries(b)	27		15		6		1		5		2		3		—
Balance as of March 31, 2021	$	377	$	103	$	130	$	43	$	101	$	41	$	25	$	35

__________

(a)For PECO, BGE and ACE, the increase is primarily as a result of increased receivable balances due to the increased aging of receivables. For BGE, also reflects increased receivable balance due to colder weather.

(b)Recoveries were not material to the Registrants.

(c)For ACE, the increase in 2022 is primarily related to the termination of the moratorium, which beginning in March 2020, prevented customer disconnections for non-payment. With disconnection activities restarting in January 2022, write-offs of aging accounts receivable increased throughout the year.

(d)The increase is primarily as a result of increased receivable balances due to the colder weather and the increased aging of receivables, the temporary suspension of customer disconnections for non-payment, temporary cessation of new late payment fees, and reconnection of service for customers previously disconnected due to COVID-19.

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
















	Three Months Ended March 31, 2022
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance as of December 31, 2021	$	72	$	17	$	7	$	9	$	39	$	16	$	8	$	15
Plus: Current period provision for expected credit losses	14		4		3		3		4		2		1		1
Less: Write-offs, net of recoveries(a)	5		1		1		1		2		—		—		2
Balance as of March 31, 2022	$	81	$	20	$	9	$	11	$	41	$	18	$	9	$	14

	Three Months Ended March 31, 2021
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance as of December 31, 2020	$	71	$	21	$	8	$	9	$	33	$	13	$	9	$	11
Plus: Current period provision for expected credit losses	10		1		4		1		4		2		1		1
Less: Write-offs, net of recoveries(a)	2		—		1		1		—		—		—		—
Balance as of March 31, 2021	$	79	$	22	$	11	$	9	$	37	$	15	$	10	$	12

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 6 — Accounts Receivable

__________

(a)Recoveries were not material to the Registrants.

Unbilled Customer Revenue

The following table provides additional information about unbilled customer revenues recorded in the Registrants' Consolidated Balance Sheets as of March 31, 2022 and December 31, 2021.


	Unbilled customer revenues(a)
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
March 31, 2022	$	629	$	189	$	127	$	139	$	174	$	89	$	50	$	35
December 31, 2021	747		240		161		171		175		82		53		40

__________

(a)Unbilled customer revenues are classified in Customer accounts receivables, 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~~present the total receivables purchased.


	Total receivables purchased
	Exelon(a)		ComEd		PECO		BGE(a)		PHI		Pepco		DPL		ACE
Three months ended March 31, 2022	$	1,044	$	248	$	292	$	222	$	282	$	174	$	57	$	51
Three months ended March 31, 2021	1,023		266		290		199		268		166		56		46

__________

(a)Includes $4 million and $12 million of receivables purchased ~~receivables of those companies as of September 30, 2017~~from Generation for the three months ended March 31, 2022 and ~~December 31, 2016.~~2021, respectively.

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 of~~ the ~~Upstream Assets. See Note 4 - Mergers, Acquisitions and Dispositions of~~following:


	Three Months Ended March 31, 2022(a)
	Exelon		ComEd		PECO(b)		BGE(b)		PHI		Pepco(b)		DPL		ACE(b)
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)	21.1		8.0		(0.1)		2.4		3.7		(4.5)		6.2		6.8
Plant basis differences	(3.6)		(0.6)		(11.3)		(0.9)		(1.6)		(2.6)		(0.7)		(1.3)
Excess deferred tax amortization	(11.5)		(6.3)		(3.2)		(17.6)		(17.7)		(17.4)		(19.4)		(22.2)
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(d)	1.7		(0.3)		—		(0.4)		(0.4)		(0.4)		(0.3)		(0.3)
Other(e)	2.6		—		—		(0.1)		0.2		(0.6)		0.1		(0.1)
Effective income tax rate	31.2	%	21.7	%	6.4	%	4.3	%	5.1	%	(4.5)	%	6.7	%	3.7	%


	Three Months Ended March 31, 2021(a)
	Exelon		ComEd		PECO(f)		BGE(f)		PHI		Pepco		DPL		ACE(f)
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	2.8		6.8		(1.6)		(10.1)		6.1		5.5		6.4		6.9
Plant basis differences	(3.4)		(0.6)		(10.5)		(1.4)		(1.5)		(2.1)		(0.7)		(0.9)
Excess deferred tax amortization	(12.0)		(6.9)		(3.2)		(15.5)		(19.3)		(15.1)		(18.5)		(28.7)
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	(0.3)		(0.2)		—		(0.4)		(0.2)		(0.2)		(0.1)		(0.3)
Other	(1.1)		(3.5)		(0.1)		(0.1)		(0.1)		0.1		0.3		2.2
Effective income tax rate	6.9	%	16.5	%	5.6	%	(6.6)	%	5.9	%	9.2	%	8.2	%	—	%

__________

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

(b)For PECO, the ~~Exelon 2016 Form 10-K for further information.~~

Inlower effective tax rate is primarily related to plant basis differences attributable to tax repair deductions. For BGE, the ~~second quarter of 2016, updates~~lower effective tax rate is primarily due to the ~~Company's~~Maryland multi-year plan which resulted in the acceleration of certain income tax benefits. For Pepco, the income tax benefit is primarily due to the Maryland and Washington, D.C. multi-year plans which resulted in the acceleration of certain income tax benefits. For ACE, the lower effective tax rate is primarily due to the acceleration of certain income tax benefits due to distribution rate case settlements.

(c)For Exelon, the higher state income taxes, net of federal income tax benefit, is primarily due to the long-term ~~view~~marginal state income tax rate change of ~~energy~~approximately $67 million and ~~capacity prices suggested that~~ the ~~carrying value~~recognition of a ~~group~~valuation allowance of ~~merchant wind assets, located in West Texas, may be impaired. Upon review,~~approximately $40 million against 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. Asnet deferred tax asset position for certain standalone state filing jurisdictions as a result of the ~~fair value analysis, long-lived assets held and used with a carrying amount~~separation.

(d)For Exelon, reflects the income tax expense related to the write-off of federal tax credits subject to recapture of approximately ~~$60~~$15 million ~~were written down to their fair value of $24 million and~~as 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 in the second quarter of 2016, updates to the Company's long-term view, as described above, in conjunction with the previous decision to early retire the Clinton and Quad Cities nuclear facilities in Illinois suggested that the carrying value of our Midwest asset group may be impaired. Generation completed a comprehensive reviewresult of the ~~estimated undiscounted future cash flows~~separation.

(e)For Exelon, primarily reflects the nondeductible transaction costs of ~~the Midwest asset group and no impairment charge was required.~~

~~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 MEAGapproximately $19 million arising as part of the ~~transactions (Leases).~~separation.

~~On March 31, 2016, UII and MEAG finalized an agreement~~(f)For PECO, the lower effective tax rate is primarily related to ~~terminate~~plant basis differences attributable to tax repair deductions. For BGE, the ~~MEAG Headleases,~~income tax benefit is primarily due to 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 investmentMaryland multi-year plan which resulted in the ~~MEAG Headleases and the Leases. The transaction resulted in a pre-tax gain~~acceleration 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

certain income tax benefits. For ACE, the lower effective tax rate is primarily due to the acceleration of ~~which Generation owns~~certain income tax benefits due to distribution rate case settlements.

Unrecognized Tax Benefits

Exelon, PHI and ACE have the following unrecognized tax benefits as of March 31, 2022 and December 31, 2021. ComEd's, PECO's, BGE's, Pepco's, and DPL's amounts are not material.


	Exelon		PHI		ACE
March 31, 2022	$	146	$	56	$	16
December 31, 2021	143		56		16

__________

(a)As of March 31, 2022, Exelon recorded a ~~42.59% ownership interest.~~ receivable of approximately $50 million in Noncurrent other assets in the Consolidated Balance Sheet for Constellation’s share of unrecognized tax benefits for periods prior to the separation.

Reasonably possible the total amount of unrecognized tax benefits could significantly increase or decrease within 12 months after the reporting date

As ~~previously disclosed,~~of March 31, 2022, ACE has approximately $14 million of unrecognized state tax benefits that could significantly decrease within the 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

Separation (Exelon)

In connection with the separation, Exelon recorded an income tax expense related to continuing operations of approximately $148 million primarily due to the long-term marginal state income tax rate change of approximately $67 million discussed further below, the recognition of valuation allowances of approximately $40 million against the net deferred tax assets positions for certain standalone state filing jurisdictions, the write-off of federal and state tax credits subject to recapture of approximately $17 million, and nondeductible transaction costs for federal and state taxes of approximately $24 million.

Tax Matters Agreement (Exelon)

In connection with the separation, Exelon entered into a TMA with Constellation. The TMA governs the respective rights, responsibilities, and obligations between Exelon and ~~Generation~~Constellation after the separation with respect to tax liabilities, refunds and attributes for open tax years that Constellation was part of 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 IRS and certain state jurisdictions relating to the taxable periods prior to the separation. The TMA specifies that Constellation is liable for their share of taxes required to be paid by Exelon with respect to taxable periods prior to the separation to the extent Constellation would have ~~committed to cease operation~~been responsible for such taxes under the existing Exelon tax sharing agreement. As of ~~the Oyster Creek nuclear plant by the end~~March 31, 2022, Exelon recorded a receivable of ~~2019.~~

~~The TMI nuclear plant did not clear~~approximately $55 million in Current other assets in the ~~May 2017 PJM capacity auction~~Consolidated Balance Sheet for ~~the 2020-2021 planning year and will not receive capacity revenue~~Constellation’s share of taxes 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.~~

~~Based on these capacity auction results, prolonged~~ periods of low wholesale power prices, and the absence of federal or state policies that place a value on nuclear energy for its ability to produce electricity without air pollution, 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 filing of a deactivation notice with PJM on May 30, 2017 and notificationprior to the ~~NRC on June 20, 2017. PJM has subsequently notified Generation~~separation.

Tax Refunds. The TMA specifies that ~~it has not identified~~Constellation is entitled to their share of any ~~reliability issues and has approved~~future tax refunds claimed by Exelon with respect to taxable periods prior to the ~~deactivation~~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 ~~TMI as proposed.~~

~~In 2017, as~~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 also provides that Exelon will reimburse Constellation when those allocated tax credit carryforwards are utilized. As of March 31, 2022, Exelon recorded a ~~result~~payable 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 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 $112approximately $11 million and ~~$149~~$484 million respectively, of pre-tax expense for these items. Please refer to Note 13 — Nuclear Decommissioning for additional detail on changes to the nuclear decommissioning ARO balances resulting from the early retirement of TMI.

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~~in Current other liabilities 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~~Noncurrent other liabilities, respectively, in the ~~table below.~~Consolidated Balance Sheet for tax credit carryforwards that are expected to be utilized and reimbursed to Constellation.

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

~~_________~~Long-Term Marginal State Income Tax Rate (All Registrants)


~~(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 the first quarter of 2022, Exelon updated its marginal state income tax rates for changes in state apportionment due to the separation, which resulted in an increase of approximately $67 million to the deferred tax liability at Exelon, and a corresponding adjustment to income tax expense, net of federal taxes.

8. Retirement Benefits (All Registrants)

Defined Benefit Pension and OPEB

Effective February 1, 2022, in connection with the separation, pension and OPEB obligations and assets for current and former employees of the Constellation business and certain other former employees of Exelon and its subsidiaries transferred to pension and OPEB plans and trusts maintained by Constellation or its subsidiaries. The Exelon New ~~York,~~England Union Employees Pension Plan and Constellation Mystic Power, LLC Union Employees Pension Plan Including Plan A and Plan B were transferred. The following OPEB plans were also transferred: Constellation Mystic Power, LLC Post-Employment Medical Account Savings Plan, Exelon New England Union Post-Employment Medical Savings Account Plan, and the ~~Ginna,~~ Nine Mile Point Nuclear Station, LLC Medical Care and ~~Generation’s recently acquired FitzPatrick nuclear plant also faced significant economic challenges~~Prescription Drug Plan for Retired Employees.

As a result of the separation, Exelon restructured certain of its qualified pension plans. Pension obligations and ~~risk~~assets for current and former employees continuing with Exelon and who are participants in the Exelon Employee Pension Plan for Clinton, TMI, and Oyster Creek, Pension Plan of ~~retirement before the end of each unit’s respective operating license period (2029 for Ginna~~Constellation Energy Nuclear Group, LLC, and Nine Mile Point ~~Unit 1, 2046 for Nine Mile Point Unit 2, and 2034 for FitzPatrick)~~Pension Plan were merged into the Pension Plan of Constellation Energy Group, Inc, which was subsequently renamed, Exelon Pension Plan (EPP). ~~On August 1, 2016,~~Exelon employees who participated in these plans prior to the ~~NYPSC issued an order adopting~~separation now participate in 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~~EPP. The merging of the ~~program (March 31, 2029). The assumed useful life for depreciation purposes for each facility is through~~plans did not change 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,benefits offered to the extent either the Illinois ZES or 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 materialplan participants and, thus, had no impact on ~~Exelon’s and Generation’s future results of operations, cash flows and financial position.~~

~~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 has recorded the sponsorship agreement as a finite-lived intangible asset with a $25 million carrying amount. Because no specific sponsorship agreements have yet been entered into with the District of Columbia, amortization of the finite-lived intangible asset has yet to commence. In the third quarter of 2017, PHI continued discussions with the District of Columbia regarding the nature and timing of available sponsorship opportunities, and based on these ongoing discussions, will continue to evaluate any potential impact on 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) as of September 30, 2017 and December 31, 2016:

~~Exelon~~Exelon's pension obligations.

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 8 — Retirement Benefits

The tables below show the pension and OPEB plans in which employees of each operating company participated as of March 31, 2022:

Operating Company(a)

Name of Plan:

ComEd

PECO

BGE

PHI

Pepco

DPL

ACE

Qualified Pension Plans:

Exelon Corporation Retirement Program

Exelon Corporation Pension Plan for Bargaining Unit Employees

Exelon Pension Plan

Pepco Holdings LLC Retirement Plan

Non-Qualified Pension Plans:

Exelon Corporation Supplemental Pension Benefit Plan and 2000 Excess Benefit Plan

Exelon Corporation Supplemental Management Retirement Plan

Constellation Energy Group, Inc. Senior Executive Supplemental Plan

Constellation Energy Group, Inc. Supplemental Pension Plan

Constellation Energy Group, Inc. Benefits Restoration Plan

Baltimore Gas & Electric Company Executive Benefit Plan

Baltimore Gas & Electric Company Manager Benefit Plan

Pepco Holdings LLC 2011 Supplemental Executive Retirement Plan

Conectiv Supplemental Executive Retirement Plan

Pepco Holdings LLC Combined Executive Retirement Plan

Atlantic City Electric Director Retirement Plan

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

Operating Company(a)

Name of Plan:

ComEd

PECO

BGE

PHI

Pepco

DPL

ACE

OPEB Plans:

PECO Energy Company Retiree Medical Plan

Exelon Corporation Health Care Program

Exelon Corporation Employees’ Life Insurance Plan

Exelon Corporation Health Reimbursement Arrangement Plan

BGE Retiree Medical Plan

BGE Retiree Dental Plan

Exelon Employee Life Insurance Plan and Family Life Insurance Plan

Exelon Retiree Medical Plan of Constellation Energy Nuclear Group, LLC

Exelon Retiree Dental Plan of Constellation Energy Nuclear Group, LLC

Pepco Holdings LLC Welfare Plan for Retirees

__________

(a)Employees generally remain in their legacy benefit plans when transferring between operating companies.

As of February 1, 2022, in connection with the separation, Exelon's pension and OPEB plans were remeasured. The remeasurement and separation resulted in a decrease to the pension obligation, net of plan assets, of $921 million and a decrease to the OPEB obligation of $893 million. Additionally, accumulated other comprehensive loss, decreased by $1,994 million (after-tax) and regulatory assets and liabilities increased by $14 million and $5 million respectively. Key assumptions were held consistent with the year end December 31, 2021 assumptions with the exception of the discount rate.

The majority of the 2022 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 3.24%. The majority of the 2022 OPEB cost is calculated using an expected long-term rate of return on plan assets of 6.44% for funded plans and a discount rate of 3.20%.

During the first quarter of 2022, Exelon received an updated valuation of its pension and OPEB to reflect actual census data as of February 1, 2022. This valuation resulted in a decrease to the pension obligation of $24 million and an increase to the OPEB obligation of $5 million. Additionally, accumulated other comprehensive loss increased by $5 million (after-tax) and regulatory assets and liabilities decreased by $30 million and $3 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 months ended March 31, 2022 and 2021.

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



	Pension Benefits				OPEB
	Three Months Ended March 31,				Three Months Ended March 31,
	2022		2021		2022		2021
Components of net periodic benefit cost:
Service cost	$	61	$	74	$	10	$	14
Interest cost	110		102		19		17
Expected return on assets	(209)		(213)		(25)		(26)
Amortization of:
Prior service cost (credit)	1		1		(5)		(6)
Actuarial loss	76		100		4		7
Curtailment benefits	—		—		—		(1)


Net periodic benefit cost	$	39	$	64	$	3	$	5

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~~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 ~~tables above~~non-service cost components are ~~comprised of dividends payable (included~~included in ~~other current liabilities) (Level 1)~~Other, net and ~~short-term borrowings (Level 2).~~ Regulatory assets. For the Utility Registrants, 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.


	Three Months Ended March 31,
Pension and OPEB Costs		2022		2021
Exelon		$	42	$	69
ComEd		16		32
PECO		(2)		2
BGE		11		15
PHI		13		12
Pepco		2		2
DPL		1		1
ACE		3		3

Defined Contribution Savings Plan

The ~~Registrants’ carrying amounts~~Registrants participate in a 401(k) defined contribution savings plan that is sponsored by Exelon. The plan is qualified under applicable sections of the ~~short-term liabilities are representative~~IRC and allow employees to contribute a portion of ~~fair value because~~their pre-tax and/or after-tax income in accordance with specified guidelines. All Registrants match a percentage of the ~~short-term nature of these instruments.~~

~~Long-Term Debt.~~ employee contributions up to certain limits. 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 incorporatefollowing table presents 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 addedmatching contributions to the ~~appropriate benchmark U.S. Treasury rates in order to determine the current market yields~~savings plans 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 or note. Due to low trading volume of private placement debt, qualitative factors such as market conditions, low volume of investorsthree months ended March 31, 2022 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.~~2021, respectively.

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


	Three Months Ended March 31,
Savings Plans Matching Contributions		2022		2021
Exelon		$	20	$	20
ComEd		8		8
PECO		3		3
BGE		2		2
PHI		3		3
Pepco		1		1
DPL		1		1
ACE		—		—

~~100~~

Table of Contents

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 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~~9 — ~~quoted prices (unadjusted) in active markets for identical assets or liabilities that the Registrants have the ability to liquidate as of the reporting date.~~

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

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

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~~

~~Table of Contents~~

~~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.

The following tables present assets 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 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~~

~~Table of Contents~~

~~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~~

~~Table of Contents~~

~~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 amounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do not represent the amount of the company's exposure to credit or market loss.

~~(d)~~

Excludes net liabilities of $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

~~107~~

~~Table of Contents~~

~~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 and 2016:

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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~~(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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~~(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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~~(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

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~~(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

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~~(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

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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 or non-derivatives, mitigate exposure to fluctuations in commodity prices.

~~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 economic hedges in the following tables. The Registrants have applied the NPNS scope exception to certain derivative contracts for the forward sale of generation, power procurement agreements, and natural gas supply agreements. Generation has also entered into bilateral long-term contractual obligations for sales of energy 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 focus on the resale of energy products for delivery. These non-derivative contracts are accounted for primarily under the accrual method of accounting. Additionally, Generation is exposed to certain market risks through its proprietary trading activities. The proprietary trading activities areoffset by 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

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

in supply and demand, fuel costs, market liquidity, weather conditions, governmental regulatory and environmental policies, and other factors. Within Exelon, Generation has the most exposure to commodity price risk. As such, Generation uses a variety of derivative and non-derivative instruments to manage the commodity price risk of its electric generation facilities, including power and gas sales, fuel and energy purchases, natural gas transportation 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 hedge the variability in future cash flows from forecasted sales of energy and gas and purchases of fuel and energy. The objectives for entering into such hedges include fixing the price for 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 portion of the long-term commodity price risk resulting from the renewable energy resource procurement requirements in the Illinois Settlement Legislation. ComEd has not elected hedge 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 acorresponding regulatory asset or liability. ~~See Note 3 — Regulatory Matters of the Exelon 2016 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 theFor all 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,instruments, accounts receivable 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. 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 andaccounts payable are recorded ~~by DPL as regulatory assets~~when derivatives settle and revenue 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 currentlyexpense is recognized 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 are 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 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 revenue from energy marketing activities. ComEd, PECO, BGE, PHI, Pepco, DPL and ACE do not enter into derivatives for proprietary trading purposes.

~~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 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. 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. Below is a summary of the interest rate and foreign exchange hedge balances as of September 30, 2017:

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)~~

~~The following table provides a summary of the interest rate and foreign exchange hedge balances recorded by the Registrants as of December 31, 2016:~~

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

~~__________~~

~~(a)~~

~~(b)~~

~~Fair Value Hedges. For derivative instruments that are designated and qualify as fair value hedges, the gain or loss on the derivative as well~~earnings as the ~~offsetting loss~~underlying physical commodity is sold or gain on the hedged item attributable to the hedged risk are recognized in current earnings. Exelon includes 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 )

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 December 31, 2016, Exelon had total outstanding fixed-to-floating fair value hedges related to interest rate swaps of $800 million, with a derivative asset of $16 million. 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 fair value hedges 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 million and $100 million 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 swaps and $3 million of AOCI will be amortized into Other, net in Exelon's Consolidated Statement

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

~~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 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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~~(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.consumed.

ComEd’s use of cash collateral is generally unrestricted unless ComEd is downgraded below investment ~~grade (i.e., to BB+ or Ba1).~~

grade. Cash collateral held by PECO, BGE, Pepco, DPL, and ~~BGE~~ACE must be deposited in ~~a non affiliate~~an unaffiliated major U.S. commercial bank or foreign bank with a U.S. branch office that meet certain qualifications.

~~In the table below, DPL's~~Commodity Price Risk

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, which are either determined to be non-derivative or classified as economic ~~hedges are shown gross.~~hedges. The ~~impact~~Utility Registrants procure electric and natural gas supply through a competitive procurement process approved by each of the ~~netting of fair value balances with~~respective state utility commissions. The Utility Registrants’ hedging programs are intended to reduce exposure to energy and natural gas price volatility and have no direct earnings impact as the ~~same counterparty that~~costs 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:~~fully recovered from customers through

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

Note 9 — Derivative Financial Instruments

regulatory-approved recovery mechanisms. The following table provides a summary of the Utility Registrants’ primary derivative ~~fair value balances recorded~~hedging instruments, listed by ~~the Registrants as of December 31, 2016:~~commodity and accounting treatment.

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)~~Registrant	~~Exelon, Generation, PHI and DPL net~~Commodity	Accounting Treatment	Hedging Instrument
ComEd	Electricity	NPNS	Fixed price contracts based on 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 reflectedrequirements in the ~~table above.~~

	IPA procurement plans.
~~(b)~~Electricity			~~Current and noncurrent assets are shown net~~ Changes in fair value 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.

economic hedge recorded to an offsetting regulatory asset or liability(a)
~~(c)~~	~~Includes current and noncurrent liabilities relating to~~20-year floating-to-fixed energy swap contracts ~~with unaffiliated suppliers.~~

	beginning June 2012 based on the renewable energy resource procurement requirements in the Illinois Settlement Legislation of approximately 1.3 million MWhs per year.
~~(d)~~PECO		~~Represents~~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 ~~futures purchased by DPL as part~~purchases in support of ~~a natural gas hedging program approved by the DPSC.~~

	projected firm sales.
~~(e)~~BGE		OfElectricity	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 ~~collateral posted/(received), $(158) million represents variation margin on the exchanges.~~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.
			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.

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~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ (a)See Note 3 — ~~(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 Regulatory Matters of the ~~hedged transactions, result in the ultimate recognition of net revenues or expenses at the contractual price.~~2021 Form 10-K for additional information.

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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~~(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, but for which the fair value or cash flow hedge elections were not made. Additionally, Generation enters into interest rate derivative contracts and foreign exchange currency swaps ("treasury") to manage the exposure related to the interest rate component of commodity positions and international purchases of commodities in currencies other than U.S. Dollars. For the three and nine months ended September 30, 2017 and 2016, the following net pre-tax mark-to-market gains (losses) of certain purchase and sale contracts were reported 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 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(b)The 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.DPL economic hedge is not material as of March 31, 2022 and December 31, 2021.

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

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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 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 inThe fair value of ~~the~~ derivative ~~contracts held at the reporting date. The “Reclassification to realized” represents the recognized change~~economic hedges is presented in ~~fair value that was reclassified to realized due to settlement of the~~current and noncurrent Mark-to-market derivative ~~during the period.~~

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
liabilities in Exelon's and ComEd's Consolidated Balance Sheets.

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. As of March 31, 2022, the amount of cash collateral held with external counterparties by Exelon, ComEd, PHI, and ~~their affiliates, both on an individual~~DPL was $192 million, $72 million, $86 million, and ~~an aggregate basis.~~

$73 million, respectively, which is recorded in Other current liabilities in Exelon's, ComEd's, PHI's, and DPL's Consolidated Balance Sheets. The amounts for PECO, BGE, Pepco, and ACE were not material as of March 31, 2022. As of December 31, 2021, the amounts for ComEd and DPL were $41 million and $43 million, respectively. The amounts for Exelon, PECO, BGE, PHI, Pepco, and ACE were not material as of December 31, 2021.

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

The following tables provide information on Generation’s credit exposure for all derivative instruments, NPNS 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. The figures in the tables below exclude credit risk exposure from individual retail counterparties, Nuclear fuel procurement contracts and exposure through RTOs, ISOs, NYMEX, ICE, NASDAQ, NGX and Nodal commodity exchanges. 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

Note 9 — Derivative Financial Instruments

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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~~(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,~~March 31, 2022, 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~~March 31, 2022, they could have been required to post ~~approximately $20 million of~~ collateral to ~~its counterparties.~~their counterparties of $39 million, $62 million, and $16 million, respectively.

~~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 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.

~~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~~meets their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the Exelon intercompany money pool. Pepco, DPL, and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the PHI intercompany money pool. PHI Corporate meets its short-term liquidity ~~requirement~~requirements primarily through the issuance of short-term notes and borrowings from the Exelon intercompany money pool. The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit.

Commercial Paper

The following table reflects the Registrants' commercial paper programs as of March 31, 2022 and December 31, 2021. PECO and ComEd had no commercial paper borrowings as of March 31, 2022 and December 31, 2021.


	Outstanding Commercial Paper as of				Average Interest Rate on Commercial Paper Borrowings as of
Commercial Paper Issuer	March 31, 2022		December 31, 2021		March 31, 2022		December 31, 2021
Exelon(a)	$	250	$	599	0.87	%	0.35	%


BGE	250		130		0.87	%	0.37	%
PHI(b)	—		469		—	%	0.35	%

Pepco	—		175		—	%	0.33	%
DPL	—		149		—	%	0.36	%
ACE	—		145		—	%	0.35	%

__________

(a)Exelon Corporate had no outstanding commercial paper borrowings as of March 31, 2022 and December 31, 2021.

(b)Represents the consolidated amounts of Pepco, DPL, and ACE.

Revolving Credit Agreements

On February 1, 2022, Exelon Corporate and the Utility Registrants' each entered into a new 5-year revolving credit facility that replaced its existing syndicated 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	%

See Note 17 — Debt and Credit Agreements of the Exelon 2021 Form 10-K for additional information on the Registrants' credit facilities.

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

~~Commercial Paper~~

~~The Registrants had the following amounts of commercial paper borrowings outstanding as ofSeptember 30, 2017~~Note 10 — Debt and ~~December 31, 2016:~~Credit Agreements

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
—

Short-Term Loan Agreements

On January 13, 2016, PHI entered into a $500 million term loan agreement, which was amended on March 28, 2016. The net proceeds of the loan were used to repay PHI's outstanding commercial paper, and for general corporate purposes. Pursuant to the loan agreement, as amended, loans made thereunder bear interest at a variable rate equal to LIBOR 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 agreement for $500 ~~million which expires~~million. The loan agreement was renewed on March ~~22, 2018.~~14, 2022 and will expire on March 16, 2023. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to ~~LIBOR~~SOFR plus 1%0.65% 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~~March 31, 2021, Exelon Corporate entered into a 364-day term loan agreement for ~~Generation's $75~~$150 million ~~bilateral credit facility was amended~~with a variable interest rate of LIBOR plus 0.65% and ~~restated to increase the facility size to $100 million and extend the maturity to January 2019. This facility will solely be used by Generation to issue letters~~an expiration date of ~~credit.~~

~~On May 26, 2016,~~March 30, 2022. Exelon Corporate ~~Generation, ComEd, PECO and BGE~~repaid the term loan on March 30, 2022.

In connection with the separation, on January 24, 2022, Exelon Corporate entered into ~~amendments~~a 364-day term loan agreement for $1.15 billion. The loan agreement will expire on January 23, 2023. Pursuant to ~~each~~the loan agreement, loans made thereunder bear interest at a variable rate equal to SOFR plus 0.75% with a 22.5 basis point increase commencing on July 24, 2022. All indebtedness pursuant to the loan agreement is unsecured.

Long-Term Debt

Issuance of their respective syndicated revolving credit facilities, which extended the maturity of each of the facilities to May 26, 2021. Exelon Corporate also increased the size of its facility from $500 million to $600 million. On May 26, 2016, PHI, Pepco, DPL and ACE entered into an amendment to their Second Amended and Restated Credit Agreement dated as of August 1, 2011, which (i) extended the maturity date of the facility to May 26, 2021, (ii) removed PHI as a borrower under the facility, (iii) decreased the size of the facility from $1.5 billion to $900 million and (iv) 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.

Long-Term Debt

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(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~~three months ended ~~September 30, 2017,~~March 31, 2022, the following long-term debt was issued:

Company

Type

Interest Rate

Maturity

Amount

Use of Proceeds

Exelon

SMBC Term Loan Agreement

SOFR plus 0.65%

July 21, 2023

$300

Fund a cash payment to Constellation and for general corporate purposes.

Exelon

U.S. Bank Term Loan Agreement

SOFR plus 0.65%

July 21, 2023

300

Fund a cash payment to Constellation and for general corporate purposes.

Exelon

PNC Term Loan Agreement

SOFR plus 0.65%

July 24, 2023

250

Fund a cash payment to Constellation and for general corporate purposes.

Exelon

Notes

2.75%

March 15, 2027

650

Repay existing indebtedness and for general corporate purposes.

Exelon

Notes

3.35%

March 15, 2032

650

Repay existing indebtedness and for general corporate purposes.

Exelon

Notes

4.10%

March 15, 2052

700

Repay existing indebtedness and for general corporate purposes.

ComEd

First Mortgage Bonds, Series 132

3.15%

March 15, 2032

300

Repay outstanding commercial paper obligations and to fund other general corporate purposes.

ComEd

First Mortgage Bonds, Series 133

3.85%

March 15, 2052

450

Repay outstanding commercial paper obligations and to fund other general corporate purposes.

Pepco(a)

First Mortgage Bonds

3.97%

March 24, 2052

400

Repay existing indebtedness and for general corporate purposes.

DPL

First Mortgage Bonds

3.06%

February 15, 2052

125

Repay existing indebtedness and for general corporate purposes.

ACE

First Mortgage Bonds

2.27%

February 15, 2032

Repay existing indebtedness and for general corporate purposes.

ACE

First Mortgage Bonds

3.06%

February 15, 2052

150

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~~

~~In September 2014, EGTP, an indirect subsidiary~~(a)On March 24, 2022, Pepco entered into a purchase agreement of ~~Exelon and Generation, issued $675~~First Mortgage Bonds of $225 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~~at 3.35% due on September ~~18, 2021.~~15, 2032. The ~~term loan bears interest at a variable rate equal~~closing date of the issuance is expected to ~~LIBOR plus 4.75%, subject~~occur in September 2022.

Long-Term Debt to ~~a 1% LIBOR floor with interest payable quarterly.~~ Affiliates

As of ~~September 30,~~December 31, 2021, Exelon Corporate had $319 million recorded to intercompany notes receivable from Generation. See Note 17 — Debt and Credit Agreements of the Exelon 2021 Form 10-K for additional information. In connection with the separation, on January 31, 2022, Exelon Corporate received cash from Generation of $258 million to settle the intercompany loan.

Debt Covenants

As of March 31, 2022, the Registrants are in compliance with debt covenants.

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(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~~asset or liability or indirectly observable through corroboration with observable market data.

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

Fair Value of ~~$20 million available through,~~Financial Liabilities Recorded at Amortized Cost

The following tables present the carrying amounts and scheduled to mature on September 18, 2019. In addition to 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 portionfair values of the ~~interest rate exposure in connection with this~~Registrants’ short-term liabilities, long-term debt, and trust preferred securities (long-term debt to financing trusts or junior subordinated debentures) 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 in the outstanding debt balance being~~of March 31, 2022 and December 31, 2021. The Registrants have no financial liabilities classified as ~~Long-term debt due within one year on Exelon's and Generation's~~Level 1.

The carrying amounts of the Registrants’ short-term liabilities as presented in their Consolidated Balance ~~Sheets. See Note 4 - Mergers, Acquisitions and Dispositions and Note 6 - Impairment~~Sheets are representative of ~~Long-Lived Assets for more information.~~

~~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 remarketingtheir fair value (Level 2) because of the ~~2024 notes into $1.15 billion~~short-term nature of ~~3.497% junior subordinated notes due in 2022 (“Remarketing”). Exelon conducted the Remarketing on behalf of the holders of equity units~~these instruments.


	March 31, 2022								December 31, 2021
	Carrying Amount		Fair Value						Carrying Amount		Fair Value
			Level 2		Level 3		Total				Level 2		Level 3		Total
Long-Term Debt, including amounts due within one year(a)
Exelon	$	37,162	$	35,174	$	2,645	$	37,819	$	32,902	$	34,897	$	2,217	$	37,114
ComEd	10,515		10,894		—		10,894		9,773		11,305		—		11,305
PECO	4,198		4,244		50		4,294		4,197		4,740		50		4,790
BGE	3,961		3,969		—		3,969		3,961		4,406		—		4,406
PHI	8,233		5,453		2,595		8,048		7,547		5,970		2,167		8,137
Pepco	3,841		2,901		1,272		4,173		3,445		3,201		975		4,176
DPL	1,935		1,300		592		1,892		1,810		1,426		552		1,978
ACE	1,757		1,007		732		1,739		1,582		1,091		641		1,732
Long-Term Debt to Financing Trusts
Exelon	$	390	$	—	$	435	$	435	$	390	$	—	$	470	$	470
ComEd	205		—		228		228		205		—		248		248
PECO	184		—		207		207		184		—		222		222

__________

(a)Includes unamortized debt issuance costs, unamortized debt discount and ~~did~~premium, net, purchase accounting fair value adjustments, and finance lease liabilities which are 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 paidfair valued. Refer 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~~Debt and ~~Equity for further information on the issuance of common stock.~~

~~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~~Credit Agreements of the ~~outstanding shares of BGE Capital Trust II 6.20% Preferred Securities (“Securities”), pursuant to the optional redemption provisions~~Exelon 2021 Form 10-K for unamortized debt issuance costs, unamortized debt discount and premium, net, and purchase accounting fair value adjustments and Note 11 - Leases of the Indenture under which the Securities were issued. The redemption price per share was $25.19, which equaled 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.Exelon 2021 Form 10-K for finance lease liabilities.

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(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 as of March 31, 2022 and December 31, 2021:

Exelon


	As of March 31, 2022						As of December 31, 2021
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Cash equivalents(a)	$	2,418	$	—	$	—	$	2,418	$	524	$	—	$	—	$	524
Rabbi trust investments
Cash equivalents	65		—		—		65		60		—		—		60
Mutual funds	55		—		—		55		60		—		—		60
Fixed income	—		9		—		9		—		10		—		10
Life insurance contracts	—		63		37		100		—		61		37		98
Rabbi trust investments subtotal	120		72		37		229		120		71		37		228
Total assets	2,538		72		37		2,647		644		71		37		752
Liabilities
Mark-to-market derivative liabilities	—		—		(144)		(144)		—		—		(219)		(219)
Deferred compensation obligation	—		(84)		—		(84)		—		(131)		—		(131)
Total liabilities	—		(84)		(144)		(228)		—		(131)		(219)		(350)
Total net assets (liabilities)	$	2,538	$	(12)	$	(107)	$	2,419	$	644	$	(60)	$	(182)	$	402

__________

(a)Exelon excludes cash of $470 million and $464 million as of March 31, 2022 and December 31, 2021, respectively, and restricted cash of $110 million and $49 million as of March 31, 2022 and December 31, 2021, respectively, and includes long-term restricted cash of $92 million and $44 million as of March 31, 2022 and December 31, 2021, respectively, which is reported in Other deferred debits 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%

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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

ComEd, PECO, and BGE


	ComEd								PECO								BGE
As of March 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)	$	537	$	—	$	—	$	537	$	9	$	—	$	—	$	9	$	—	$	—	$	—	$	—
Rabbi trust investments
Cash equivalents	—		—		—		—		1		—		—		1		—		—		—		—
Mutual funds	—		—		—		—		9		—		—		9		7		—		—		7
Life insurance contracts	—		—		—		—		—		17		—		17		—		—		—		—
Rabbi trust investments subtotal	—		—		—		—		10		17		—		27		7		—		—		7
Total assets	537		—		—		537		19		17		—		36		7		—		—		7
Liabilities
Mark-to-market derivative liabilities(b)	—		—		(144)		(144)		—		—		—		—		—		—		—		—
Deferred compensation obligation	—		(9)		—		(9)		—		(8)		—		(8)		—		(5)		—		(5)
Total liabilities	—		(9)		(144)		(153)		—		(8)		—		(8)		—		(5)		—		(5)
Total net assets (liabilities)	$	537	$	(9)	$	(144)	$	384	$	19	$	9	$	—	$	28	$	7	$	(5)	$	—	$	2


	ComEd								PECO								BGE
As of December 31, 2021	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)	$	237	$	—	$	—	$	237	$	9	$	—	$	—	$	9	$	—	$	—	$	—	$	—
Rabbi trust investments
Mutual funds	—		—		—		—		11		—		—		11		14		—		—		14
Life insurance contracts	—		—		—		—		—		16		—		16		—		—		—		—
Rabbi trust investments subtotal	—		—		—		—		11		16		—		27		14		—		—		14
Total assets	237		—		—		237		20		16		—		36		14		—		—		14
Liabilities
Mark-to-market derivative liabilities(b)	—		—		(219)		(219)		—		—		—		—		—		—		—		—
Deferred compensation obligation	—		(10)		—		(10)		—		(9)		—		(9)		—		(7)		—		(7)
Total liabilities	—		(10)		(219)		(229)		—		(9)		—		(9)		—		(7)		—		(7)
Total net assets (liabilities)	$	237	$	(10)	$	(219)	$	8	$	20	$	7	$	—	$	27	$	14	$	(7)	$	—	$	7

__________

(a)ComEd excludes cash of $71 million and $105 million as of March 31, 2022 and December 31, 2021, respectively, and restricted cash of $73 million and $42 million as of March 31, 2022 and December 31, 2021, respectively, and includes long-term restricted cash of $92 million and $43 million as of March 31, 2022 and December 31, 2021, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. PECO excludes cash of $25 million and $35 million as of March 31, 2022 and December 31, 2021, respectively. BGE excludes cash of $41 million and $51 million as of March 31, 2022 and December 31, 2021, respectively, and restricted cash of $34 million and $4 million as of March 31, 2022 and December 31, 2021, respectively.

(b)The Level 3 balance consists of the current and noncurrent liability of none and $144 million, respectively, as of March 31, 2022 and $18 million and $201 million, respectively, as of December 31, 2021 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%

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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

PHI, Pepco, DPL, and ACE



	As of March 31, 2022								As of December 31, 2021
PHI	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Cash equivalents(a)	$	599	$	—	$	—	$	599	$	110	$	—	$	—	$	110
Rabbi trust investments
Cash equivalents	61		—		—		61		59		—		—		59
Mutual funds	12		—		—		12		14		—		—		14
Fixed income	—		9		—		9		—		10		—		10
Life insurance contracts	—		24		36		60		—		27		35		62
Rabbi trust investments subtotal	73		33		36		142		73		37		35		145
Total assets	672		33		36		741		183		37		35		255
Liabilities
Deferred compensation obligation	—		(17)		—		(17)		—		(18)		—		(18)



Total liabilities	—		(17)		—		(17)		—		(18)		—		(18)
Total net assets	$	672	$	16	$	36	$	724	$	183	$	19	$	35	$	237


	Pepco								DPL								ACE
As of March 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)	$	294	$	—	$	—	$	294	$	152	$	—	$	—	$	152	$	153	$	—	$	—	$	153




Rabbi trust investments
Cash equivalents	59		—		—		59		—		—		—		—		—		—		—		—

Life insurance contracts	—		24		36		60		—		—		—		—		—		—		—		—
Rabbi trust investments subtotal	59		24		36		119		—		—		—		—		—		—		—		—
Total assets	353		24		36		413		152		—		—		152		153		—		—		153
Liabilities
Deferred compensation obligation	—		(2)		—		(2)		—		—		—		—		—		—		—		—



Total liabilities	—		(2)		—		(2)		—		—		—		—		—		—		—		—
Total net assets	$	353	$	22	$	36	$	411	$	152	$	—	$	—	$	152	$	153	$	—	$	—	$	153

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

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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

~~first quarter 2017, as a part~~


	Pepco								DPL								ACE
As of December 31, 2021	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)	$	31	$	—	$	—	$	31	$	43	$	—	$	—	$	43	$	—	$	—	$	—	$	—
Rabbi trust investments
Cash equivalents	58		—		—		58		—		—		—		—		—		—		—		—


Life insurance contracts	—		27		35		62		—		—		—		—		—		—		—		—
Rabbi trust investments subtotal	58		27		35		120		—		—		—		—		—		—		—		—
Total assets	89		27		35		151		43		—		—		43		—		—		—		—
Liabilities
Deferred compensation obligation	—		(2)		—		(2)		—		—		—		—		—		—		—		—



Total liabilities	—		(2)		—		(2)		—		—		—		—		—		—		—		—
Total net assets	$	89	$	25	$	35	$	149	$	43	$	—	$	—	$	43	$	—	$	—	$	—	$	—

__________

(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$300 million and ~~$22~~$100 million ~~respectively,~~ as of ~~September 30, 2017, resulting in a benefit to Income taxes on Exelon’s, Generation’s, PHI’s, Pepco’s, DPL’s~~March 31, 2022 and ~~ACE’s Consolidated Statements~~December 31, 2021, respectively, and restricted cash of ~~Operations~~$3 million as of both March 31, 2022 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~~December 31, 2021. Pepco excludes cash 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 September 30, 2017, Exelon and ComEd have approximately $39~~$239 million and $2$34 million as of March 31, 2022 and December 31, 2021, respectively, and restricted cash of ~~unrecognized federal~~$3 million as of both March 31, 2022 and ~~state income tax benefits that could significantly decrease within the 12 months after the reporting date due to a final resolution~~December 31, 2021. DPL excludes cash 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 September 30, 2017, Exelon, Generation, BGE, PHI, Pepco, DPL, and ACE have approximately $676 million, $469 million, $120 million, $88 million, $59 million, $21~~$41 million and $8$28 million as of ~~unrecognized federal~~March 31, 2022 and ~~state tax benefits that could significantly decrease within the 12 months after the reporting date~~December 31, 2021, respectively. ACE excludes cash of $15 million and $29 million as ~~a result~~ of ~~completing audits, potential settlements,~~March 31, 2022 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.

~~On September 30, 2013, the IRS issued a notice of deficiency to Exelon for the like-kind exchange position. Exelon filed a petition on~~ December 13, 2013 to initiate litigation in the United States Tax Court (Tax Court) 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.

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.

31, 2021, respectively.

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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

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 months ended March 31, 2022 and ~~recorded charges to earnings representing the amount of interest~~2021:


	Exelon		ComEd			PHI and Pepco
Three months ended March 31, 2022	Total		Mark-to-Market Derivatives			Life Insurance Contracts
Balance as of January 1, 2022	$	(182)	$	(219)		$	35
Total realized / unrealized gains
Included in net income(a)	1		—			1


Included in regulatory assets	75		75		(b)	—







Transfers out of Level 3	(1)		—			—
Balance as of March 31, 2022	$	(107)	$	(144)		$	36
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities as of March 31, 2022	$	1	$	—		$	1


	Exelon		ComEd			PHI and Pepco
Three Months Ended March 31, 2021	Total		Mark-to-Market Derivatives			Life Insurance Contracts
Balance as of January 1, 2021	$	(267)	$	(301)		$	34
Total realized / unrealized gains
Included in net income(a)	1		—			1


Included in regulatory assets	6		6		(b)	—








Balance as of March 31, 2021	$	(260)	$	(295)		$	35
The amount of total gains included in income attributed to the change in unrealized gain related to assets and liabilities as of March 31, 2021	$	1	$	—		$	1

__________

(a)Classified in Operating and maintenance 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~~Operations and Comprehensive Income.

(b)Includes $69 million of increases in fair value and an increase for realized losses due to settlements of $6 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended March 31, 2022. Includes $2 million of decreases in fair value and an increase for realized losses due to settlements of $8 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended March 31, 2021.

Valuation Techniques Used to Determine Fair Value

Exelon’s ~~agreement~~valuation techniques used to ~~continue to hold ComEd harmless from any unfavorable impact on its equity from~~measure the ~~like-kind exchange position, ComEd recorded on its Consolidated Balance Sheets as of September 30, 2016, an additional $150 million receivable and non-cash equity contributions from Exelon.~~

~~As a result~~fair value of the ~~IRS’s finalization of its computation~~assets and liabilities shown in the ~~second quarter 2017, Exelon recorded a benefit to earnings~~tables below are in accordance with the policies discussed in Note 18 — Fair Value of ~~approximately $26 million, consisting of an income tax benefit of $50 million~~Financial Assets 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.

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 resultLiabilities 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 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.

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

2021 Form 10-K.

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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

~~and/or~~Mark-to-Market Derivatives (Exelon and ComEd)

The table below discloses the significant ~~operational changes. Exelon's, PHI's and Pepco's long-term marginal state income tax rate were revised in~~inputs to 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~~forward curve used to ~~Deferred income tax liability of $28 million, $8 million, and $8 million, respectively, on their Consolidated Balance Sheets. Because income taxes~~value mark-to-market derivatives.


Type of trade	Fair Value as of March 31, 2022		Fair Value as of December 31, 2021		Valuation Technique	Unobservable Input	2022 Range & Arithmetic Average				2021 Range & Arithmetic Average
Mark-to-market derivatives	$	(144)	$	(219)	Discounted Cash Flow	Forward heat rate(a)	8.90x	-	9.10x	9.00x	9x	-	10x	9.13x
						Marketability reserve	4%	-	5%	4.35%	3%	-	7%	4.77%
						Renewable factor	92%	-	120%	98%	92%	-	120%	97%

__________

(a)Quoted forward natural gas rates are ~~recovered through customer rates, Exelon, PHI and Pepco recorded a corresponding regulatory liability of $8 million, in~~utilized to project the ~~Consolidated Balance Sheets. In addition, Exelon recorded a decrease to Income tax expense of $20 million, net of federal taxes, in the Consolidated Statements of Operations and Comprehensive Income~~forward power curve for the ~~three months ended March 31, 2017.~~delivery of energy at specified future dates.

In the third quarter 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,The inputs listed above, which ~~increased the total corporate income tax rate from 7.75% to 9.5% effective July 1, 2017. As a result~~are as of the rate changes, 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 tobalance sheet date, would have a ~~material ongoing~~direct 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 decreasesabove instruments if they 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 anadjusted. An increase to the ~~pension obligation of $92 million and an~~marketability reserves would decrease the fair value. An increase to the other postretirement benefit obligation of $57 million. Additionally, accumulated other comprehensive loss increased by approximately $59 million (after tax), regulatory assets increased by approximately $57 million and regulatory liabilities increased by approximately $4 million.

~~The majority of~~forward heat rate or renewable factor would increase 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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~~(Dollars 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 maintenance 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~~accordingly.

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~~(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 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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~~(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, the PHI Merger severance costs were immaterial. For the nine months ended September 30, 2016, the Registrants recorded the following severance costs 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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~~(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 for the nine months ended September 30, 2017 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

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~~(Dollars 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 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 and 2016. The following tables present amounts reclassified out of AOCI to Net income for Exelon, Generation and PHI during the three and nine months ended September 30, 2017 and 2016.

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

~~The following table presents income tax expense (benefit) allocated to each component of other comprehensive income (loss) during 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 related to the PHI Merger not included in the calculation of diluted common shares outstanding due to their antidilutive effect for the three and nine months ended September 30, 2017. The number of equity units related to the PHI Merger not included in 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.

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 -19 — Commitments and Contingencies of the ~~Combined Notes~~Exelon 2021 Form 10-K.

Commitments

PHI Merger Commitments (Exelon, PHI, Pepco, DPL, and ACE). Approval of the PHI Merger in Delaware, New Jersey, Maryland, and the District of Columbia was conditioned upon Exelon and PHI agreeing to certain commitments. The following amounts represent total commitment costs that have been recorded since the ~~Consolidated Financial Statements~~acquisition date and the total remaining obligations for Exelon, PHI, Pepco, DPL, and ACE as of March 31, 2022:


Description	Exelon		PHI		Pepco		DPL		ACE
Total commitments	$	513	$	320	$	120	$	89	$	111
Remaining commitments(a)	65		55		46		6		3

__________

(a)Remaining commitments extend through 2026 and include rate credits, energy efficiency programs and delivery system modernization.

In addition, Exelon has committed to purchase 100 MWs of wind energy in PJM. DPL has committed to conducting three RFPs to procure up to a total of 120 MWs of wind RECs for the purpose of meeting Delaware's renewable portfolio standards. DPL has conducted two of the three wind REC RFPs. The first 40 MW wind REC tranche was conducted in 2017 and did not result in a purchase agreement. The second 40 MW wind REC tranche was conducted in 2018 and resulted in a proposed REC purchase agreement that was approved by the DEPSC in 2019. The RFP for the third and final 40 MW wind REC tranche will be conducted in the ~~Exelon 2016 Form 10-K for additional information regarding Generation’s future minimum lease payments.~~second half of 2022.

The direct investment commitment also includes $450 million to $500 million relating to Exelon and Generation’s development or assistance in 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 to date and an additional 10 MW commitment satisfied 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 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, Exelon 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.~~

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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 ~~September 30, 2017,~~March 31, 2022, representing commitments potentially triggered by future events were as follows:


			Expiration within
	Total		2022		2023		2024		2025		2026		2027 and beyond
Exelon
Letters of credit	$	14	$	12	$	2	$	—	$	—	$	—	$	—
Surety bonds(a)	201		188		11		2		—		—		—
Financing trust guarantees	378		—		—		—		—		—		378
Guaranteed lease residual values(b)	30		1		3		6		5		5		10
Total commercial commitments	$	623	$	201	$	16	$	8	$	5	$	5	$	388

ComEd
Letters of credit	$	7	$	7	$	—	$	—	$	—	$	—	$	—
Surety bonds(a)	17		12		3		2		—		—		—
Financing trust guarantees	200		—		—		—		—		—		200
Total commercial commitments	$	224	$	19	$	3	$	2	$	—	$	—	$	200

PECO
Letters of credit	$	1	$	1	$	—	$	—	$	—	$	—	$	—
Surety bonds(a)	3		2		1		—		—		—		—
Financing trust guarantees	178		—		—		—		—		—		178
Total commercial commitments	$	182	$	3	$	1	$	—	$	—	$	—	$	178

BGE
Letters of credit	$	2	$	2	$	—	$	—	$	—	$	—	$	—
Surety bonds(a)	4		3		1		—		—		—		—
Total commercial commitments	$	6	$	5	$	1	$	—	$	—	$	—	$	—

PHI

Surety bonds(a)	$	94	$	91	$	3	$	—	$	—	$	—	$	—
Guaranteed lease residual values(b)	30		1		3		6		5		5		10
Total commercial commitments	$	124	$	92	$	6	$	6	$	5	$	5	$	10

Pepco

Surety bonds(a)	$	84	$	84	$	—	$	—	$	—	$	—	$	—
Guaranteed lease residual values(b)	10		—		1		2		2		2		3
Total commercial commitments	$	94	$	84	$	1	$	2	$	2	$	2	$	3

DPL

Surety bonds(a)	$	6	$	3	$	3	$	—	$	—	$	—	$	—
Guaranteed lease residual values(b)	13		1		1		3		2		2		4
Total commercial commitments	$	19	$	4	$	4	$	3	$	2	$	2	$	4

ACE
Surety bonds(a)	$	4	$	4	$	—	$	—	$	—	$	—	$	—
Guaranteed lease residual values(b)	7		—		1		1		1		1		3
Total commercial commitments	$	11	$	4	$	1	$	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 8 years. The maximum potential obligation at the end of the minimum lease term would be $73 million guaranteed by Exelon and PHI, of which ~~Generation~~$25 million, $30 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 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 sites, there are additional PRPs that may share responsibility for the ultimate remediation of each location.

•ComEd has ~~identified 42~~21 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.~~2023.

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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 2023.

•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.

~~During the third quarter~~ComEd, pursuant to an ICC order, and PECO, pursuant to a PAPUC order, are currently recovering environmental remediation costs of ~~2017, ComEd, PECO,~~former MGP facility sites through customer rates. While BGE and ~~PHI completed an annual study~~DPL do not have riders for MGP clean-up costs, they have historically received recovery of ~~their future estimated MGP remediation requirements. The study resulted~~actual clean-up costs in ~~a $13 million and $2 million increase to environmental liabilities and related regulatory assets for ComEd and PECO, respectively, and no 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 Cotter for any liability arising in connection with the West Lake Landfill. In connection with Exelon’s 2001 corporate restructuring, this responsibility to indemnify Cotter was transferred to Generation. 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.

distribution rates.

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~~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

As of March 31, 2022 and December 31, 2021, the Registrants had accrued the following undiscounted amounts for environmental liabilities in Other current liabilities and Other deferred credits and other liabilities in their respective Consolidated Balance Sheets:

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. On September 30, 2013, EPA issued the Record of Decision identifying its preferred remedial alternative 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 and EPA finalized the terms of a Consent Decree which has been executed by the Parties and lodged with the U.S. District Court. After publication 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.


	March 31, 2022				December 31, 2021
	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	$	354	$	305	$	352	$	303
ComEd	279		279		279		279
PECO	21		20		22		20
BGE	7		6		6		4
PHI	42		—		42		—
Pepco	40		—		40		—
DPL	1		—		1		—
ACE	1		—		1		—

~~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.

~~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~~which became a part of Generation, following the 2016 merger between PHI and Exelon. This generating facility was deactivated

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

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 developing a FS to evaluate possible remedial alternatives for submission to DOEE. The Court has established a schedule for completion of the ~~RI and~~ FS, and approval by the DOEE, by ~~June 2018.~~

~~Upon DOEE’s~~September 16, 2022. After completion and approval of the ~~final RI and~~ FS, ~~Reports, Pepco and Generation will have satisfied their obligations under the consent decree. At that point,~~ DOEE will prepare 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 actions determined to be necessary.

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~~National Park Service ("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 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. In April 2018, DOEE ~~asked~~released a draft RI report for public review and comment. Pepco ~~along with parties responsible for other sites along~~submitted written comments to the ~~river, to participate~~draft RI and participated in a ~~“Consultative Working Group” to provide input into the process for future remedial actions addressing the entire tidal reach of the river~~public hearing.

Exelon, PHI, and ~~to ensure proper coordination with the other river cleanup efforts currently underway, including cleanup of the river segment adjacent to the Benning Road site resulting from the Benning Road RI/FS.~~ Pepco ~~responded~~have determined that it is probable that costs for remediation will ~~participate~~be incurred and recorded a liability in the ~~Consultative Working Group but~~third quarter 2019 for management’s best estimate of its ~~participation is not~~share of those costs. On September 30, 2020, DOEE released its Interim ROD. The Interim ROD reflects 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 section of the river is expected to be released for public comment 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 those associated with the Benning RI/FS component of the river-wide initiative. It is possible, however, that resolution of this matter could have a material, unfavorable impact on Exelon's and Pepco’s future results of operations and cash flows.

adaptive management

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Note 12 — Commitments and Contingencies

~~Conectiv Energy Wholesale Power Generation Sites.~~ ~~In July 2010, PHI sold~~approach which will require several identified “hot spots” in the ~~wholesale power generation business of Conectiv Energy Holdings, Inc.~~river to be addressed first while continuing to conduct studies and ~~substantially all of its subsidiaries (Conectiv Energy)~~ to ~~Calpine Corporation (Calpine). Under New Jersey’s Industrial Site Recovery Act (ISRA),~~monitor the ~~transfer of ownership~~river to ~~Calpine triggered an obligation on~~evaluate improvements and determine potential future remediation plans. The adaptive management process chosen by DOEE is less intrusive, provides more long-term environmental certainty, is less costly, and allows for site specific remediation plans already underway, including the 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 remediation andplan for the ~~payment of all related ISRA compliance costs up~~Benning Road site to ~~$10 million. Predecessor PHI was obligated~~proceed 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 theconclusion. Pepco concluded that incremental exposure remains reasonably possible, but management cannot reasonably estimate a range of ~~approximately $7 million to $18 million~~, ~~and predecessor PHI established an appropriate accrual for its share of~~loss 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 recorded, which are included in the table above.

On July 12, 2021, DOEE and NPS held a virtual meeting with the PRP's in response to a General Notice Letter sent by each agency inviting the PRP's to participate in discussions, which Pepco attended.

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 ~~liability~~result of ~~Generation.~~the contamination that is being remediated. The ~~responsibility to indemnify Calpine is shared by PHI and Generation. The ultimate resolution~~Trustees can seek compensation from responsible parties for such damages, including restoration costs. During the second quarter of ~~this matter is currently not expected to have a material financial impact on PHI and Generation.~~

~~Rock Creek Mineral Oil Release.~~ ~~In late August 2015, a~~2018, Pepco ~~underground transmission line~~became aware that the Trustees are in the ~~District~~beginning stages of ~~Columbia suffered~~ a ~~breach, resulting in~~Natural Resources Damages (NRD) assessment, a process that often takes many years beyond the ~~release~~remedial decision to complete. Pepco has entered into negotiations with the Trustees to evaluate possible incorporation of ~~non-toxic mineral oil surrounding~~NRD assessment and restoration as part of its remedial activities associated with the ~~transmission line into~~Benning site to accelerate 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 estimatesNRD benefits for that ~~approximately 6,100 gallons of mineral oil were released and that its remediation efforts recovered approximately 80%~~portion 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~~Anacostia River Sediment Project ("ARSP") assessment. 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~~has concluded that a loss associated with the eventual NRD assessment is reasonably possible. Due to the very early stage of the assessment process, Pepco cannot reasonably estimate the final range of loss potentially resulting from this ~~matter is probable and have estimated that the costs for implementation of a closure plan and cap on the site are~~process.

As noted in the ~~range~~Benning Road Site disclosure above, as part of ~~approximately $3 million~~the separation of Exelon and Constellation in February 2022, an assumption agreement was executed transferring any potential future remediation liabilities associated with the Benning Site remediation to ~~$6 million, for which an appropriate reserve has been established and is included in~~a non-utility subsidiary of Exelon. Similarly, any potential future liability associated with the ~~table above. Exelon, PHI and Pepco believe that the costs incurred in~~ARSP was also assumed by this ~~matter will be recoverable from NRG under the 2000 sale agreement.~~entity.

Litigation and Regulatory Matters

~~Asbestos Personal Injury Claims~~Deferred Prosecution Agreement (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~~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 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 provides that the USAO will 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 that are currently owned~~obligations of ComEd, including payment to the U.S. Treasury of $200 million, which was paid in November 2020. Exelon was not made party to the DPA, and therefore the investigation by ~~Generation or~~the USAO into Exelon’s activities ended with no charges being brought against Exelon. The SEC’s investigation remains ongoing and Exelon and ComEd have cooperated fully and intend to continue to cooperate fully with the SEC. Exelon and ComEd cannot predict the outcome of the SEC investigation. No loss contingency has been reflected in Exelon's and ComEd's consolidated financial statements with respect to the SEC investigation, as this contingency is neither probable nor reasonably estimable at this time.

Subsequent to Exelon announcing the receipt of the subpoenas, various lawsuits were ~~previously owned by~~filed, and various demand letters were received related to the subject of the subpoenas, the conduct described in the DPA and the SEC's investigation, including:

•Four putative class action lawsuits against ComEd and ~~PECO. The reserve is recorded~~Exelon were filed in federal court on ~~an undiscounted basis and excludes~~behalf of ComEd customers in the ~~estimated legal costs associated with handling~~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 ~~matters, which could be material.~~

At September 30, 2017 and December 31, 2016, Generation had reserved approximately $80 million and $83 million, respectively, in total for asbestos-related bodily injury claims. As of September 30, 2017, approximately $22 million of this amount related to 227 open claims presented to Generation, while the remaining $58 million of the reserve is for estimated future asbestos-related bodily injury claims anticipated to arise through 2050, based on actuarial

cases

~~163~~

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

Note 12 — Commitments and Contingencies

~~assumptions~~on October 22, 2020 which was granted on December 23, 2020. On December 2, 2020, the court appointed interim lead plaintiffs in the federal cases which consisted of counsel for three of the four federal cases. These plaintiffs filed a consolidated complaint on January 5, 2021. CUB also filed its own complaint against ComEd only on the same day. The remaining federal case, Potter, et al. v. Exelon et al, differed from the other lawsuits as it named additional individual defendants not named in the consolidated complaint. However, the Potter plaintiffs voluntarily dismissed their complaint without prejudice on April 5, 2021. ComEd and ~~analyses, which are updated~~Exelon moved to dismiss the consolidated class action complaint and CUB’s complaint on ~~an annual basis.~~February 4, 2021 and briefing was completed on March 22, 2021. On March 25, 2021, the parties agreed, along with state court plaintiffs, discussed below, to jointly engage in mediation. The parties participated in a ~~quarterly basis, Generation monitors actual experience against~~one-day mediation on June 7, 2021 but no settlement was reached. On September 9, 2021, the ~~number~~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 ~~forecasted claims to be received and expected~~the federal law claim ~~payments and evaluates whether an adjustment~~ to the ~~reserve is necessary.~~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. Plaintiffs' opening appeal brief in the Seventh Circuit was filed on January 14, 2022. Exelon and ComEd filed their response brief on March 7, 2022, and plaintiffs filed their reply brief on April 6, 2022. The court has scheduled oral argument for May 17, 2022.

•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 intervene in the cases pursuant to an Illinois statute allowing CUB to intervene as a party or otherwise participate on behalf of utility consumers in any proceeding which affects the interest of utility consumers. On November ~~22, 2013,~~23, 2020, the ~~Supreme~~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 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 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 January 21, 2022. Plaintiffs have appealed the court's ruling dismissing their complaint to the First District Court of ~~Pennsylvania held~~Appeals. On February 15, 2022, Exelon and ComEd moved to dismiss the federal plaintiffs' refiled state law claims, seeking dismissal on the same legal grounds asserted in their motion to dismiss the original state court plaintiffs' complaint. The court granted dismissal of the refiled state claims on February 16, 2022. The original federal plaintiffs appealed that ~~the Pennsylvania Workers Compensation Act does not apply to an employee’s disability or death resulting from occupational disease, such as diseases~~dismissal on February 18, 2022. The two state appeals were consolidated on March 21, 2022. Plaintiffs' opening appellate briefs are currently due June 3, 2022.

•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 ~~asbestos exposure, which manifests more than 300 weeks after~~ComEd’s lobbying activities and the ~~employee’s last employment-based exposure, and that therefore the exclusivity provision~~related investigations. The complaint was amended on September 16, 2020, to dismiss two of the ~~Act does not preclude such employee from suing his or her employer in court. The Supreme Court’s ruling reverses previous rulings by the Pennsylvania Superior Court precluding current~~original defendants and former employees from suing their employers in court, despite 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 exposureadd other defendants, including ComEd. Defendants filed a motion to ~~asbestos. Since the Pennsylvania Supreme Court's ruling~~dismiss in November ~~2013, Exelon, Generation,~~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. 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 ~~PECO have experienced~~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 ~~increase in asbestos-related personal injury claims brought by former PECO employees, all of which have been reserved for~~amendment to their protective order that would prohibit the parties from requesting discovery into certain matters, including communications with the U.S. government. The court ordered said amendment to the protective order on ~~a claim by claim basis. Those additional claims are taken into account in projecting estimates of future asbestos-related bodily injury claims.~~

November 15, 2021 and discovery resumed. On ~~November 4, 2015,~~February 10, 2022, the ~~Illinois Supreme Court found that the provisions~~court granted an extension of the ~~Illinois' Workers' Compensation Act~~amendment to the protective order, at the U.S. government's request, to May 15, 2022 and directed the ~~Workers' Occupational Diseases Act barred an employee from bringing~~parties to submit a ~~direct civil action against an employer~~proposed joint schedule 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~~additional case proceedings by the Illinois Court of Appeals, which initially ruled that the Illinois Worker's Compensation law should 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 customers as a result of the interruption and may be responsible for reimbursement of local governmental emergency and contingency expenses incurred in connection with the interruption. Recovery of consequential damages is barred. The affected utility may seek from the ICC a waiver of these liabilities when the utility can show that the cause of the interruption was unpreventable damage due to weather events or conditions, customer tampering, or certain other causes enumerated in the law. As of September 30, 2017 and December 31, 2016, ComEd did not have any material liabilities recorded for these storm events.

~~Baltimore City Franchise Taxes (Exelon and BGE)~~

The City of Baltimore claims that BGE has maintained electric facilities 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.

May 13, 2022.

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

Note 12 — Commitments and Contingencies

~~Conduit Lease with City of Baltimore (Exelon and BGE~~)

~~On September 23, 2015,~~•Several shareholders have sent letters to the ~~Baltimore City~~Exelon Board of ~~Estimates approved an increase in annual rental fees for access~~Directors from 2020 through May 2022 demanding, among other things, that the 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 ~~Baltimore City underground conduit system effective November 1, 2015, from $12 million~~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 ~~$42 million, subject~~investigate and address these shareholders’ allegations and make recommendations to ~~an annual increase thereafter~~the Exelon Board of Directors based on the ~~Consumer Price Index. BGE subsequently entered~~outcome of the 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 the derivative action filed an agreed motion to stay that litigation for 120 days in order to allow the SLC to continue its investigation, which the court granted. On January 31, 2022, the parties jointly moved the court to extend the stay an additional 120 days.

•Two separate shareholder requests seeking review of certain Exelon books and records were received in August 2021 and January 2022. Exelon responded to both requests and both shareholders have since sent formal shareholder demands to the Exelon Board, as discussed above.

No loss contingencies have been reflected in Exelon’s and ComEd’s consolidated financial statements with respect to these matters, as such contingencies are neither probable nor reasonably estimable at this time.

The ICC continues to conduct an investigation into ~~litigation~~rate impacts of conduct admitted in the DPA initiated on August 12, 2021. On December 16, 2021, ComEd filed direct testimony addressing the costs recovered from customers related to the DPA and Exelon's funding of the fine paid by ComEd. In that testimony, ComEd proposed to voluntarily refund to customers compensation costs of the former officers charged with wrongdoing in connection with events described in the DPA for the period during which those events occurred as well as costs, previously proposed to be returned, of individuals and entities specifically identified in the DPA, as well as individuals and entities who were referred to ComEd as part of the conduct described in the DPA and who failed, during their tenure at ComEd, to perform work to management expectations. The testimony supports the calculation of the refund amount and proposes a refund mechanism (one-time bill credit in April 2023) and also addresses other topics outlined by statute and the ICC orders initiating the investigation. On April 14, 2022, in response to rebuttal testimony from ICC staff and the Illinois Attorney General, City ~~regarding~~of Chicago, and CUB, ComEd filed surrebuttal testimony, in which ComEd proposed to increase its voluntary customer refund to $38 million of ICC and FERC jurisdictional amounts, and estimated interest to resolve the issue of the potential expenditure of customer monies on activities identified in the DPA in this matter. An accrual for the amount of the voluntary customer refund has been recorded in Other deferred credits and ~~basis for establishing the conduit fee. On November 30, 2016, the Baltimore City Board~~other liabilities in Exelon’s and ComEd’s Consolidated Balance Sheets as of ~~Estimates approved a settlement agreement entered into between BGE~~March 31, 2022. The voluntary customer refund will not be recovered in rates or charged to customers and the City to resolve the disputes 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 million in the first three years and caps the annual expense in the last three years toComEd will not ~~more~~seek or accept reimbursement or indemnification from any source other 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 decision with the Supreme Court of Delaware. Generation has accrued an amount to cover its potential liability.

~~City of Everett Tax Increment Financing Agreement (Exelon)~~

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 administrativeevidentiary hearing on the ~~City’s petition. Generation has reviewed~~remaining contested issue was held on April 28, 2022. A final order is expected by September 9, 2022.

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 the ~~City’s claim~~Northern District of Illinois against Exelon, its Board of Directors, the former Board Investment Oversight Committee, the Corporate Investment Committee, individual defendants, and ~~believes~~other unnamed fiduciaries of the Exelon Corporation Employee Savings Plan (“Plan”). The complaint alleges that ~~it lacks merit. Generation has not recorded~~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 ~~accrual~~investment adviser to charge excessive fees for ~~payment resulting from~~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. The plaintiffs filed their response brief on March 28, 2022 and the defendants filed their reply on April 11, 2022. On March 4, 2022, the Chamber of Commerce filed a brief of amicus curiae in support of the defendants' motion to dismiss. No loss contingencies have been reflected in Exelon’s consolidated financial statements with respect to this matter, as such ~~a revocation because the range of loss, if any, cannot be~~contingencies are neither probable nor reasonably ~~estimated~~estimable 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 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

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 12 — Commitments and Contingencies

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.

13. Changes in Accumulated Other Comprehensive Income ~~Taxes (Exelon, Generation, ComEd, PECO~~(Exelon)

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


Three Months Ended March 31, 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)


Three Months Ended March 31, 2021	Losses on Cash Flow Hedges		Pension and Non-Pension Postretirement Benefit Plan Items(a)		Foreign Currency Items		Total
Balance at December 31, 2020	$	(5)	$	(3,372)	$	(23)	$	(3,400)
OCI before reclassifications	—		(2)		1		(1)
Amounts reclassified from AOCI	—		55		—		55
Net current-period OCI	—		53		1		54
Balance at March 31, 2021	$	(5)	$	(3,319)	$	(22)	$	(3,346)

______

(a)This AOCI component is included in the computation of net periodic pension and ~~BGE)~~

OPEB cost. Additionally, as of February 1, 2022, in connection with the separation, Exelon's pension and OPEB plans were remeasured. See Note 128 — Retirement Benefits for additional information. See Exelon's Statements of Operations and Comprehensive Income ~~Taxes~~ for ~~information regarding the Registrants’~~individual components of AOCI.

The following table presents income tax ~~refund claims and certain tax positions, including the 1999 sale~~benefit (expense) allocated to each component of ~~fossil generating assets.~~Exelon's other comprehensive income (loss):


	Three Months Ended March 31,
		2022		2021
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost		$	—	$	1
Actuarial loss reclassified to periodic benefit cost		(5)		(19)

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

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

~~19.~~14. 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:

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

Note 14 — Supplemental Financial Information

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

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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 )


	Taxes other than income taxes
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE










Three Months Ended March 31, 2022
Utility taxes(a)	$	221	$	78	$	38	$	27	$	78	$	70	$	7	$	1
Property	94		10		4		46		34		23		10		1
Payroll	37		7		4		4		7		2		1		1

Three Months Ended March 31, 2021
Utility taxes(a)	$	193	$	59	$	35	$	25	$	74	$	67	$	6	$	1
Property	86		8		4		42		32		21		10		1
Payroll	33		7		4		5		7		2		1		—

_________


~~(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.

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~~

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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
Utility taxes $ 255

$ 35

$ 67

$ 40

$ 21
$ 92
$ 87

$ 5

$ —


	Other, net
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Three Months Ended March 31, 2022

AFUDC — Equity	$	36	$	8	$	7	$	6	$	15	$	11	$	2	$	2
Non-service net periodic benefit cost	17		—		—		—		—		—		—		—

Three Months Ended March 31, 2021

AFUDC — Equity	$	28	$	4	$	6	$	7	$	11	$	9	$	1	$	1
Non-service net periodic benefit cost	20		—		—		—		—		—		—		—

Supplemental Cash Flow Information

The following tables provide additional information ~~regarding~~about material items recorded in the ~~Registrants’~~Registrants' Consolidated Statements of Cash ~~Flows for the nine months ended September 30, 2017 and 2016.~~Flows.

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~~

Table of Contents

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.~~

~~171~~

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

~~(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.

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, 2017 and 2016 is as follows:

~~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

~~174~~

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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 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~~

~~Table of Contents~~

~~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~~

~~Table of Contents~~

~~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~~

~~Table of Contents~~

~~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~~

~~Table of Contents~~

~~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 14 — Supplemental Financial Information


	Depreciation and amortization
	Exelon(a)		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Three Months Ended March 31, 2022
Property, plant, and equipment(b)	$	726	$	254	$	88	$	117	$	164	$	72	$	45	$	41
Amortization of regulatory assets(b)	179		67		4		54		54		36		12		6
Amortization of intangible assets, net(b)	6		—		—		—		—		—		—		—
Amortization of energy contract assets and liabilities(c)	3		—		—		—		—		—		—		—
Nuclear fuel(d)	66		—		—		—		—		—		—		—
ARO accretion(e)	44		—		—		—		—		—		—		—
Total depreciation, amortization, and accretion	$	1,024	$	321	$	92	$	171	$	218	$	108	$	57	$	47

Three Months Ended March 31, 2021
Property, plant, and equipment(b)	$	1,522	$	239	$	82	$	106	$	154	$	67	$	42	$	37
Amortization of regulatory assets(b)	160		53		4		46		56		35		11		10
Amortization of intangible assets, net(b)	15		—		—		—		—		—		—		—
Amortization of energy contract assets and liabilities(c)	4		—		—		—		—		—		—		—
Nuclear fuel(d)	276		—		—		—		—		—		—		—
ARO accretion(e)	127		—		—		—		—		—		—		—
Total depreciation, amortization, and accretion	$	2,104	$	292	$	86	$	152	$	210	$	102	$	53	$	47

__________

(a)Exelon's 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 Operating revenues or Purchased power and fuel expense in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.

(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.

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 14 — Supplemental Financial Information


	Other non-cash operating activities
	Exelon(a)		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Three Months Ended March 31, 2022
Pension and non-pension postretirement benefit costs	$	44	$	16	$	(2)	$	12	$	13	$	2	$	1	$	3
Allowance for credit losses	78		17		27		18		18		9		6		3
Other decommissioning-related activity	36		—		—		—		—		—		—		—
Energy-related options	60		—		—		—		—		—		—		—
True-up adjustments to decoupling mechanisms and formula rates(b)	(29)		(40)		(6)		12		5		7		1		(3)


Long-term incentive plan	25		—		—		—		—		—		—		—


Amortization of operating ROU asset	23		1		—		7		7		2		2		1


AFUDC — Equity	(36)		(8)		(7)		(6)		(15)		(11)		(2)		(2)

Three Months Ended March 31, 2021
Pension and non-pension postretirement benefit costs	$	95	$	32	$	2	$	14	$	12	$	2	$	1	$	3
Allowance for credit losses	85		13		24		4		10		5		4		1
Other decommissioning-related activity	(322)		—		—		—		—		—		—		—
Energy-related options	17		—		—		—		—		—		—		—
True-up adjustments to decoupling mechanisms and formula rates(b)	(129)		(54)		(10)		(18)		(46)		(26)		(9)		(11)


Long-term incentive plan	32		—		—		—		—		—		—		—


Amortization of operating ROU asset	37		—		—		7		7		1		3		1


AFUDC — Equity	(28)		(4)		(6)		(7)		(11)		(9)		(1)		(1)

__________

(a)Exelon's 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 BGE, Pepco, DPL, and ACE, reflects the change in regulatory assets and liabilities associated with their decoupling mechanisms and transmission formula rates. For PECO, reflects the change in regulatory assets and liabilities associated with its transmission formula rates. See Note 3 — Regulatory Matters of the Exelon 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)

Note 14 — 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.


	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
March 31, 2022
Cash and cash equivalents	$	2,476	$	343	$	26	$	41	$	796	$	502	$	120	$	168
Restricted cash and cash equivalents	430		246		8		34		106		34		73		—
Restricted cash included in other long-term assets	92		92		—		—		—		—		—		—
Total cash, restricted cash, and cash equivalents	$	2,998	$	681	$	34	$	75	$	902	$	536	$	193	$	168

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 long-term 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

March 31, 2021
Cash and cash equivalents	$	1,908	$	86	$	48	$	21	$	558	$	134	$	64	$	353
Restricted cash and cash equivalents	374		270		7		1		37		33		—		4
Restricted cash included in other long-term assets	52		43		—		—		9		—		—		9
Total cash, restricted cash, and cash equivalents(a)	$	2,334	$	399	$	55	$	22	$	604	$	167	$	64	$	366

December 31, 2020
Cash and cash equivalents	$	663	$	83	$	19	$	144	$	111	$	30	$	15	$	17
Restricted cash and cash equivalents	438		279		7		1		39		35		—		3
Restricted cash included in other long-term assets	53		43		—		—		10		—		—		10
Cash, restricted cash, and cash equivalents - Held for Sale	12		—		—		—		—		—		—		—
Total cash, restricted cash, and cash equivalents(a)	$	1,166	$	405	$	26	$	145	$	160	$	65	$	15	$	30

__________

(a)Exelon's amounts include amounts related to Generation prior to the separation. See Note 2 — Discontinued Operations for additional information.

For additional information on restricted cash see Note 1 — Significant Accounting Policies of the Exelon 2021 Form 10-K.

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 14 — Supplemental Financial Information

Supplemental Balance Sheet Information

The following table provides additional information about material items recorded in the Registrants' Consolidated Balance Sheets.


	Accrued expenses
	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
March 31, 2022
Compensation-related accruals(a)	$	370	$	95	$	51	$	48	$	73	$	26	$	15	$	12
Taxes accrued	258		95		15		78		94		85		10		9
Interest accrued	346		66		36		39		77		37		21		17

December 31, 2021
Compensation-related accruals(a)	$	596	$	155	$	77	$	78	$	113	$	35	$	20	$	17
Taxes accrued	253		94		14		53		96		88		9		11
Interest accrued	297		116		41		44		52		28		8		11

__________

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

15. 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 affiliates and an immaterial amount recorded as Operating and maintenance expense from affiliates at the Utility Registrants:


	Three Months Ended March 31,
	2022		2021
ComEd(a)	$	59	$	85
PECO(b)	33		42
BGE(c)	18		72
PHI	51		100
Pepco(d)	39		75
DPL(e)	10		21
ACE(f)	2		4

__________

(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.

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 15 — 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 March 31,					Three Months Ended March 31,
		2022		2021			2022		2021
Exelon
BSC							$	205	$	114
PHISCO							19		17
ComEd
BSC		$	85	$	71		85		45
PECO
BSC		49		39			36		17
BGE
BSC		51		43			38		20
PHI
BSC		50		39			46		32
PHISCO							19		17
Pepco
BSC		29		22			17		13
PHISCO		29		30			8		7

DPL
BSC		18		14			14		10
PHISCO		24		25			6		5

ACE
BSC		15		12			15		8
PHISCO		21		22			5		5

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 15 — Related Party Transactions

Current Receivables from/Payables to affiliates

The following tables present current receivables from affiliates and current payables to affiliates:

March 31, 2022


				Receivables from affiliates:
	Payables to affiliates:			ComEd			PECO			BGE			Pepco			DPL			ACE			BSC			PHISCO			Other			Total
ComEd					$	—		$	—		$	—		$	—		$	—		$	64		$	—		$	2		$	66
PECO		$	—					—			—			—			—			33			—			5			38
BGE		—			—						—			—			—			35			—			2			37
PHI		—			—			—			—			—			—			7			1			10			18
Pepco		—			—			—						—			—			19			15			—			34
DPL		—			—			—			—						—			3			12			—			15
ACE		—			—			—			—			—						12			11			—			23
Other		3			—			—			—			—			—			—			—						3
Total		$	3		$	—		$	—		$	—		$	—		$	—		$	173		$	39		$	19		$	234

December 31, 2021


				Receivables from affiliates:
	Payables to affiliates:			ComEd			PECO			BGE			Pepco			DPL			ACE			Generation			BSC			PHISCO			Other			Total
ComEd					$	—		$	—		$	—		$	—		$	—		41			$	71		$	—		$	9		$	121
PECO		$	—					—			—			—			—			30			36			—			4			70
BGE		—			—						—			—			—			4			41			—			3			48
PHI		—			1			—			—			—			1			—			5			—			9			16
Pepco		—			—			1						1			1			20			21			12			3			59
DPL		—			—			—			—						—			4			17			11			1			33
ACE		—			—			—			—			—						7			13			9			2			31
Generation		13			—			—			—			—			—						102			—			16			131
Other		3			—			—			—			—			—			11			—			—						14
Total		$	16		$	1		$	1		$	—		$	1		$	2		$	117		$	306		$	32		$	47		$	523

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. ComEd, PECO, and PHI Corporate participate in the Exelon money pool. Pepco, DPL, and ACE participate in the PHI intercompany money pool.

Noncurrent Receivables from affiliates

ComEd and PECO have noncurrent receivables with Generation as a result of the nuclear decommissioning contractual construct whereby, to the extent NDT funds are greater than the underlying ARO at the end of decommissioning, such amounts are due back to ComEd and PECO, as applicable, for payment to their respective customers. The receivables are recorded in Receivable related to Regulatory Agreement Units as of March 31, 2022 and in noncurrent Receivables from affiliates as of December 31, 2021. See Note 10 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements of the Exelon 2021 Form 10-K for additional information.

Long-term debt to financing trusts

The following table presents Long-term debt to financing trusts:

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 15 — Related Party Transactions


	March 31, 2022						December 31, 2021
	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

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)

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 distribution and ~~a wholly owned subsidiary of Exelon.~~transmission businesses through ComEd, PECO, BGE, Pepco, DPL, and ACE.

Exelon has ~~twelve~~six reportable segments consisting of ~~Generation’s six reportable segments (Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions in Generation),~~ 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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~~Table of Contents~~

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 and the Utility Registrants' Net income for the three ~~and nine~~ months ended ~~September 30, 2017~~March 31, 2022 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 for2021. 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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~~Table of Contents~~

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~~March 31, 2022 and ~~fuel expense,~~2021 see the discussions of Results of Operations by ~~Segment~~Registrant.


	Three Months Ended March 31,					(Unfavorable) Favorable Variance
		2022			2021
Exelon			$	481		$	525	$	(44)
ComEd			188			197		(9)
PECO			206			167		39
BGE			198			209		(11)
PHI			130			128		2
Pepco			46			59		(13)
DPL			56			56		—
ACE			26			14		12
Other(a)			(241)			(176)		(65)

__________

(a)Primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities and other financing and investing 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 all periods presented.

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. See further discussion below.

~~Adjusted (non-GAAP) Operating Earnings~~Three Months Ended March 31, 2022 Compared to Three Months Ended March 31, 2021. Net income attributable to common shareholders from continuing operations decreased by $44 million and diluted

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earnings per average common share from continuing operations decreased to $0.49 in 2022 from $0.53 in 2021 primarily due to:

•An income tax expense recorded in connection with the separation 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;

•Higher depreciation expense at BGE and PHI; and

•Higher storm costs at PHI.

The decreases were partially offset by:

•Higher electric distribution earnings from higher rate base and higher allowed electric distribution ROE due to an increase in treasury rates at ComEd;

•The favorable impacts of regulatory rate increases at PECO, BGE, and PHI; and

•Lower BSC costs presented in Exelon’s ~~adjusted (non-GAAP) operating earnings~~continuing operations, which were previously allocated to Generation but do not qualify as expenses of the discontinued operation per the accounting rules. Such costs, on a pre-tax basis, were $28 million for the period in 2022 prior to the separation on February 1, 2022 (January 1, 2022 to January 31, 2022) and $106 million for the three months ended ~~September 30, 2017 were $821 million, or $0.85 per diluted share, compared with adjusted~~March 31, 2021.

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. Operating Earnings. In addition to 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-to-year operating results and provide an indication of Exelon’s baseline operating performance excluding items that are considered by management to be not directly related to the ongoing operations of the business. In addition, this information is among the primary indicators management uses as a basis for evaluating performance, allocating resources, setting incentive compensation targets, and planning and forecasting of future periods. Adjusted (non-GAAP) operating earnings is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.

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The following ~~tables provide~~table provides a reconciliation between net income attributable to common shareholders from continuing operations as determined in accordance with GAAP and adjusted (non-GAAP) operating earnings for the three ~~and nine~~ months ended ~~September 30, 2017 as~~March 31, 2022 compared to the same period in ~~2016.~~2021.

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


	Three Months Ended March 31,
	2022				2021
(In millions, except per share data)			Earnings per Diluted Share				Earnings per Diluted Share
Net Income Attributable to Common Shareholders from Continuing Operations	$	481	$	0.49	$	525	$	0.53
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $1)	—		—		(1)		—
COVID-19 Direct Costs (net of taxes of $1)(a)	—		—		2		—
Acquisition Related Costs (net of taxes of $2)(b)	—		—		6		0.01
ERP System Implementation Costs (net of taxes of $0 and $2, respectively)(c)	1		—		5		0.01
Separation Costs (net of taxes of $7 and $1, respectively)(d)	17		0.02		5		0.01
Income Tax-Related Adjustments (entire amount represents tax expense)(e)	134		0.14		—		—
Adjusted (non-GAAP) Operating Earnings	$	634	$	0.64	$	542	$	0.55

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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 from Continuing Operations and Adjusted (non-GAAP) Operating Earnings is based on the marginal statutory federal and state income tax rates for each Registrant, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part. ~~For all items except the unrealized gains and losses related to NDT fund investments, the~~The marginal statutory income tax rates for 2022 and 2021 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)Represents direct costs related to ~~NDT Fund investments~~COVID-19 consisting primarily of costs to acquire personal protective equipment, costs for cleaning supplies and services, and costs to hire healthcare professionals to monitor the health of employees, which are recorded in Operating and maintenance expense.

(b)Reflects certain BSC costs related to the acquisition of Electricite de France SA's (EDF's) interest in CENG, which was completed in the third quarter of 2021, that were ~~43.2 percent~~historically allocated to Generation but are presented as part of continuing operations in Exelon’s results as these costs do not qualify as expenses of the discontinued operations per the accounting rules.

(c)Reflects costs related to a multi-year Enterprise Resource Program (ERP) system implementation, which are recorded in Operating and ~~46.2 percent~~maintenance expense.

(d)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.

(e)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.

Significant 2022 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 meets 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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~~Table of Contents~~

~~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.~~

~~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.

discontinued operations.

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Table of Contents

~~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 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 million, $21 million, $16$24 million and ~~$22~~$4 million on a pre-tax basis for the three months ended March 31, 2022 and March 31, 2021, respectively, aswhich are recorded in Operating and maintenance expense. Total separation costs impacting continuing operations for the remainder of ~~September 30, 2017, resulting in a benefit~~2022 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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~~Table of Contents~~

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.

2022. 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~~these and ~~Smart Grid Initiatives and infrastructure development and enhancement programs.~~other regulatory proceedings.

~~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.Completed Distribution Base Rate Case Proceedings

~~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.~~


Registrant/Jurisdiction	Filing Date	Service	Requested Revenue Requirement Increase		Approved Revenue Requirement Increase		Approved ROE		Approval Date	Rate Effective Date
ComEd - Illinois	April 16, 2021	Electric	$	51	$	46	7.36	%	December 1, 2021	January 1, 2022
PECO - Pennsylvania	March 30, 2021	Electric	246		132		N/A		November 18, 2021	January 1, 2022
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 - District of Columbia	May 30, 2019 (amended June 1, 2020)	Electric	136		109		9.28	%	June 8, 2021	July 1, 2021
Pepco - Maryland	October 26, 2020 (amended March 31, 2021)	Electric	104		52		9.55	%	June 28, 2021	June 28, 2021
DPL - Maryland	September 1, 2021 (amended December 23, 2021)	Electric	27		13		9.60	%	March 2, 2022	March 2, 2022
ACE - New Jersey	December 9, 2020 (amended February 26, 2021)	Electric	67		41		9.60	%	July 14, 2021	January 1, 2022

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Pending Distribution Base Rate Case Proceedings

~~Project Financing~~

Registrant/Jurisdiction

Filing Date

Service

Requested Revenue Requirement Increase

Requested ROE

Expected Approval Timing

ComEd - Illinois

April 15, 2022

Electric

199

7.85

Fourth quarter of 2022

PECO - Pennsylvania

March 31, 2022

Natural Gas

10.95

Fourth quarter of 2022

DPL - Delaware

January 14, 2022 (amended February 28, 2022)

Natural Gas

10.30

First quarter of 2023

~~Generation utilizes individual project financings as a means to finance~~Transmission Formula Rates

For 2022, the ~~construction of various generating asset projects. Project financing is based upon a nonrecourse financial structure,~~following total increases were included in ~~which project debt~~ComEd’s 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 Generation in the event of a default. If a specific project financing entity does not maintain compliance with its specific debt financing covenants, there could be a requirement to accelerate repayment of the associated debt or other project-related borrowings earlier than the stated maturity dates. In these instances, if such repayment was not satisfied, or restructured, the lenders or security holders would generally have rights to foreclose against the project-specific assets and related collateral. The potential requirement to satisfy its associated debt or other borrowings earlier than otherwise anticipated could lead to impairments due to a higher likelihood of disposing of the respective project-specific assets significantly before the end of their useful lives.BGE's electric transmission formula rate update. 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 on ~~nonrecourse debt.~~these and other regulatory proceedings.


Registrant	Initial Revenue Requirement Increase		Annual Reconciliation Decrease		Total Revenue Requirement Increase		Allowed Return on Rate Base		Allowed ROE
ComEd	$	24	$	(24)	$	—	8.11	%	11.50	%
BGE	25		(4)		16		7.30	%	10.50	%

Other Key Business Drivers and Management Strategies

~~Power Markets~~

~~Price~~The following discussion of ~~Fuels~~

~~The use~~other key business driver 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~~issues arising during the period that may impact future financial statements. This section should be read in conjunction with ITEM 1. Business and ~~reserves, which places downward pressure on natural gas prices~~ITEM 7. Management's Discussion and ~~therefore, on wholesale~~Analysis of Financial Condition and retail power prices, which results in a reduction in Exelon’s revenues. Forward natural gas prices have declined significantly over the last several years; in part reflecting an increase in supply due to strong natural gas production (due to shale gas development).

~~Capacity Market Changes in PJM~~

~~In the wake~~Results of ~~the January 2014 Polar Vortex that blanketed much of the Eastern~~Operations — Other Key Business Drivers 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 participatedManagement Strategies 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 result of this and several related orders, PJM hosted its 2018/2019 Base Residual Auction (results posted on August 21, 2015) 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 selected 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 MWRegistrants' 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~~ 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 on Fukushima Daiichi Accident (Exelon~~Infrastructure Investment and ~~Generation).~~Jobs Act

~~In July 2011, an NRC Task Force formed~~On November 15, 2021, President Biden signed the $1.2 trillion Infrastructure Investment and Jobs Act (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 in the ~~aftermath~~process of 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 ~~March 11, 2011, 9.0 magnitude earthquake~~first quarter of 2022. The Registrants are analyzing the legislation and ~~ensuing tsunami, that seriously damaged the nuclear units at the Fukushima Daiichi Nuclear Power Station, issued a report of its review of the accident, including tiered recommendations~~considering possible opportunities to apply for ~~future regulatory action by the NRC to be taken~~funding, either directly or in ~~the near~~potential collaborations with state and/or local agencies and ~~longer term.~~key stakeholders. The Task Force’s report concluded that nuclear reactors in the United States are operating safely and do not present an imminent risk 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 review by the NRC staff, both from an operational 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 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 managementRegistrants cannot predict the ~~outcome~~ultimate timing and success of such negotiations. In April 2017, Exelon Nuclear Security successfully ratified its CBA with the SPFPA Local 238 at Quad Cities to an extension of three years. In June 2017, Exelon Nuclear Security successfully ratified its CBA with the UGSOA Local 12 at Limerick to an extension of three years.securing funding from programs under IIJA.

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. At March 31, 2022, the Registrants’ critical accounting policies and estimates had not changed significantly from December 31, 2021 except for critical accounting policies and estimates that relate to Generation, which are no longer applicable to the Registrants. 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 Registrants' 2021 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.

~~202~~

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Table of Contents

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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~~Table of Contents~~

Results of Operations — ~~Generation~~ComEd


	Three Months Ended March 31,					Favorable (Unfavorable) Variance
		2022			2021
Operating revenues			$	1,734		$	1,535	$	199
Operating expenses
Purchased power			638			527		(111)
Operating and maintenance			351			316		(35)
Depreciation and amortization			321			292		(29)
Taxes other than income taxes			96			75		(21)
Total operating expenses			1,406			1,210		(196)

Operating income			328			325		3
Other income and (deductions)
Interest expense, net			(100)			(96)		(4)
Other, net			12			7		5
Total other income and (deductions)			(88)			(89)		1
Income before income taxes			240			236		4
Income taxes			52			39		(13)
Net income			$	188		$	197	$	(9)

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~~March 31, 2022 Compared to Three Months Ended ~~September 30, 2016.~~ ~~Generation’s~~ March 31, 2021. 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 offsetdecreased 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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~~Table of Contents~~

~~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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~~Table of Contents~~

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 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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~~Table of Contents~~

~~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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~~Table of Contents~~

~~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 primarily due to more non-refueling outage days and was partially offset by fewer refueling outage days, excluding Salem outages, during the three months ended September 30, 2017 compared to the same period in 2016.

~~Nine Months Ended September 30, 2017 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 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 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.

~~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 decreased2021, 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,voluntary customer refund related to the ~~contractual elimination~~ICC investigation 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 changematters identified 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 providedDeferred Prosecution Agreement, partially offset by increases 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 the impacts of ~~increased capital investment~~higher rate base and higher allowed electric distribution ~~ROE)~~ROE due to an increase in treasury rates). ~~The higher Net income was partially offset by~~See Note 12 - Commitments and Contingencies of the ~~impact of weather conditions in the third quarter of 2016. See Revenue Decoupling discussion below~~Combined Notes to Consolidated Financial Statements 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 penalty related to the ~~Tax Court's decision on Exelon's like-kind exchange tax position~~Deferred Prosecution Agreement.

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, 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.						Three Months Ended March 31, 2022

		Increase
Distribution		$	45
Transmission		21
Energy efficiency		7
Other		3

~~(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.


		76
Regulatory required programs		123
Total increase		$	199

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 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~~March 31, 2022 as compared to the

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same period in 2021, due to ~~increased capital investment, increased Depreciation expense, and~~the impact of higher rate base, higher allowed ROE due to an increase in treasury rates, ~~as compared to the same period in 2016~~ 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~~Transmission revenue increased 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~~March 31, 2022 as compared to the same ~~period~~periods in ~~2016. See Operating~~2021 primarily due to the impact of higher rate base and ~~maintenance expense below and Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.~~higher fully recoverable costs.

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 months ended March 31, 2022 as compared to the same period in 2021, 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 remained relatively the ~~annual average rate on 30-year treasury notes plus 580 basis points. Beginning January 1, 2018, ComEd’s allowed ROE is subject~~same for the three months ended March 31, 2022 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 2021.

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~~savings goal. See Depreciation and amortization expense discussions below, and Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.~~

Regulatory Required ~~Programs.~~ ~~This~~ Programs represents ~~the change in Operating~~ revenues collected under approved ~~rate~~ riders to recover costs incurred for regulatory programs such as ~~ComEd’s purchased power administrative~~recoveries under the credit loss expense tariff, environmental costs associated with MGP sites, Energy Transition Assistance Charge ("ETAC"), and costs related to electricity, ZEC and REC procurement. ETAC is a retail customer surcharge collected by electric utilities operating in Illinois established by CEJA and remitted to an Illinois state agency for programs to support clean energy ~~efficiency~~jobs 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, 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 ~~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 and maintenance expense~~of $111 million for the three ~~and nine~~ months ended ~~September 30, 2017~~March 31, 2022 compared to the same period in ~~2016,~~2021, in Purchased power expense is 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, 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.						Three Months Ended March 31, 2022

		Increase (Decrease)

~~(b)~~Storm-related costs	~~For the three~~	$	1
Pension and ~~nine months ended September 30, 2017, includes the $8 million write-off of a regulatory asset related to Constellation merger~~non-pension postretirement benefits expense		(7)
Labor, other benefits, contracting and ~~integration costs for which recovery is no longer expected.~~materials		2


~~(c)~~BSC costs	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.	14

Other(a)		21
		31
Regulatory required programs(b)		4
Total increase		$	35

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~~Depreciation and Amortization Expense~~

(a)The increase is primarily due to the voluntary customer refund related to the ICC investigation of matters identified in the Deferred Prosecution Agreement. See Note 12 - Commitments and Contingenciesof the Combined Notes to Consolidated Financial Statements for additional information related to the Deferred Prosecution Agreement.

(b)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.

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


	Three Months Ended March 31, 2022
	Increase
Depreciation and amortization(a)	$	15
Regulatory asset amortization(b)	14

Total increase	$	29

__________

(a)Reflects ongoing capital expenditures.

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

Taxes other than income taxes increased by $21 million for the three ~~and nine~~ months ended ~~September 30, 2017,~~March 31, 2022 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)
$ 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~~

Taxes other than income, which can vary year to year, include municipal and state utility taxes, real estate taxes and payroll taxes. Taxes other than income taxes remained relatively consistent for the three and nine months ended September 30, 2017, 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~~2021, primarily due to ~~the sale of land during March 2016.~~

~~Interest Expense, Net~~

~~The changes in interest expense, net, 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)
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 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~~taxes related to ~~the Tax Court's decision on Exelon's like-kind exchange tax position in the third quarter of 2016.~~ETAC, which is recovered through Operating revenues.

Effective ~~Income Tax Rate~~

~~ComEd's effective~~ income tax ~~rate was 40.9%~~rates were 21.7% and ~~67.0%~~16.5% for the three months ended ~~September 30, 2017~~March 31, 2022 and ~~2016,~~2021, respectively. ComEd's effective income tax rate was 42.3% and 45.1% for the nine months ended September 30, 2017 and 2016, 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.

~~216~~

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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 March 31,					Favorable (Unfavorable) Variance
		2022			2021
Operating revenues			$	1,047		$	889	$	158
Operating expenses
Purchased power and fuel			407			316		(91)
Operating and maintenance			247			234		(13)
Depreciation and amortization			92			86		(6)
Taxes other than income taxes			47			43		(4)
Total operating expenses			793			679		(114)

Operating income			254			210		44
Other income and (deductions)
Interest expense, net			(41)			(38)		(3)
Other, net			7			5		2
Total other income and (deductions)			(34)			(33)		(1)
Income before income taxes			220			177		43
Income taxes			14			10		(4)


Net income			$	206		$	167	$	39

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~~March 31, 2022 Compared to Three Months Ended ~~September 30, 2016.~~ ~~PECO's~~ March 31, 2021. Net income ~~decreased from the same period in 2016,~~ increased by $39 million, 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 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, fluctuationsincreases in electric ~~supply~~ and ~~natural~~ gas ~~procurement costs have no impact on electric~~distribution rates, and ~~natural gas revenue net of purchased power and fuel expense.~~volume.

~~Electric and natural gas revenue and purchased power and fuel expense are also affected by fluctuations~~The changes 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,Operating revenues consisted of the following:


	Three Months Ended March 31, 2022
	(Decrease) Increase
		Electric		Gas		Total
Weather		$	(4)	$	(5)	$	(9)
Volume		7		7		14
Pricing		33		17		50
Transmission		5		—		5
Other		5		3		8
		46		22		68
Regulatory required programs		36		54		90
Total increase		$	82	$	76	$	158

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 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 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 months ended ~~September 30, 2017~~March 31, 2022 compared to the same period in ~~2016,~~2021, 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.~~

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~~Table of Contents~~

conditions in PECO's service territory.

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

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PECO

PECO’s service territory for the three ~~and nine~~ months ended ~~September 30, 2017~~March 31, 2022 compared to the same ~~periods~~period in ~~2016~~2021 and normal weather consisted of the following:


	Three Months Ended March 31,			% Change
PECO Service Territory	2022	2021	Normal	2022 vs. 2021		2022 vs. Normal




Heating Degree-Days	2,228	2,302	2,416	(3.2)	%	(7.8)	%
Cooling Degree-Days	1	5	1	(80.0)	%	—	%

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 ~~nine~~three months ended ~~September 30, 2017~~March 31, 2022, compared to the same period in ~~2016, primarily reflects the impacts of energy efficiency initiatives~~2021, increased on a net basis due to an increase in overall usage for customers further increased by customer ~~usage partially offset by moderate economic and customer growth, as well as a shift in the~~growth. Natural gas 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~~three months ended ~~September 30, 2017~~March 31, 2022 compared to the same period in ~~2016~~2021, increased due to ~~strong customer growth~~retail load growth.


Electric Retail Deliveries to Customers (in GWhs)		Three Months Ended March 31,			% Change	Weather - Normal % Change(b)
	2022		2021
Residential				3,758	3,767	(0.2)	%	1.1	%
Small commercial & industrial				1,937	1,881	3.0	%	3.4	%
Large commercial & industrial				3,332	3,272	1.8	%	1.9	%
Public authorities & electric railroads				182	149	22.1	%	22.4	%
Total electric retail deliveries(a)				9,209	9,069	1.5	%	2.2	%


	As of March 31,
Number of Electric Customers	2022	2021
Residential	1,521,255	1,512,255
Small commercial & industrial	155,485	154,637
Large commercial & industrial	3,102	3,109
Public authorities & electric railroads	10,342	10,237
Total	1,690,184	1,680,238

__________

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

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


Natural Gas Deliveries to Customers (in mmcf)		Three Months Ended March 31,			% Change	Weather - Normal % Change(b)
	2022		2021
Residential				20,837	20,674	0.8	%	4.3	%
Small commercial & industrial				10,546	10,170	3.7	%	5.8	%
Large commercial & industrial				10	7	42.9	%	10.2	%
Transportation				7,639	7,650	(0.1)	%	0.7	%
Total natural gas retail deliveries(a)				39,032	38,501	1.4	%	4.0	%


	As of March 31,
Number of Natural Gas Customers	2022	2021
Residential	499,188	493,857
Small commercial & industrial	44,959	44,604
Large commercial & industrial	5	5
Transportation	664	685
Total	544,816	539,151

__________

(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.

108

Table of ~~purchased power as a result of pricing~~ Contents

PECO

Pricing for the three ~~and nine~~ months ended ~~September 30, 2017~~March 31, 2022 compared to the same period in ~~2016~~2021 increased primarily due to ~~higher overall effective~~an increase in electric and gas distribution rates ~~due~~charged to ~~decreased usage across~~customers.

Transmission Revenue. Under a FERC approved formula, transmission revenue varies from year to year based upon fluctuations in the ~~major customer classes. Operating~~underlying costs and capital investments being recovered.

Other revenue primarily includes revenue related to late payment charges. Other revenues ~~net of fuel expense~~ for the three ~~and nine~~ months ended ~~September 30, 2017~~March 31, 2022 compared to the same period in ~~2016~~2021, 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

~~221~~

~~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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~~Table of Contents~~

~~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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~~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 does affect revenue collected from~~as PECO remains the distribution service provider for all customers ~~related~~and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to ~~supplied energy and natural gas.~~

~~Retail deliveries purchased from competitive~~purchase 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 60 % 58 % 60 % 59 %
Natural Gas 74 % 80 % 57 % 59 %

~~The number of retail customers purchasing electric generation and~~or natural gas from competitive ~~electric generation~~suppliers, PECO either acts as the billing agent or the competitive supplier separately bills its own customers 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 339,300
27 % 334,100
26 %
Natural Gas 148,600
22 % 150,000
23 %

~~The changes in BGE’s~~therefore PECO does not record Operating revenues ~~net of purchased~~or Purchased power and fuel expense ~~for the three and nine months ended September 30, 2017, compared~~related to the ~~same period~~electricity and/or natural gas. For customers that choose to purchase electric generation or natural gas 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 ~~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 increase in distribution~~Operating revenues ~~for the nine months ended September 30, 2017, compared~~and Purchased power and fuel expense related to the ~~same period in 2016, was primarily due to the impact of the electric and~~electricity, 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.~~ RECs.

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

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~~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$91 million for the three ~~and nine~~ months ended ~~September 30, 2017~~March 31, 2022 compared to the same period in ~~2016~~2021, respectively, in Purchased power and fuelexpense is offset in Operating revenues as part of regulatory required programs.

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


	Three Months Ended March 31, 2022
	Increase (Decrease)
BSC costs	$	10
Credit loss expense	3
Storm-related costs	2
Labor, other benefits, contracting and materials	(2)
Pension and non-pension post retirement benefit expense	(1)
Other	(2)
	10
Regulatory required programs	3









Total increase	$	13

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 returnThe changes in ~~certain instances. The costs of these programs are included in Operating and maintenance expense,~~ Depreciation and amortization expense consisted of the following:


	Three Months Ended March 31, 2022
	Increase
Depreciation and amortization(a)	$	6
Regulatory asset amortization	—

Total increase	$	6

__________

(a)Depreciation and ~~Taxes other than income in BGE's Consolidated Statements~~amortization increased primarily due to ongoing capital expenditures.

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Table of ~~Operations and Comprehensive Income.~~Contents

~~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 revenuePECO

Interest expense, net increased $3 million for the three ~~and nine~~ months ended ~~September 30, 2017,~~March 31, 2022 compared to the same period in ~~2016, was~~2021, primarily due to ~~increases~~the issuance of debt 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.2021.

~~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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~~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%~~rates were 6.4% and ~~39.1%~~5.6% for the three months ended ~~September 30, 2017~~March 31, 2022 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,~~2021 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.

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~~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 March 31,					Favorable (Unfavorable) Variance
		2022			2021
Operating revenues			$	1,154		$	974	$	180
Operating expenses
Purchased power and fuel			454			331		(123)
Operating and maintenance			218			197		(21)
Depreciation and amortization			171			152		(19)
Taxes other than income taxes			76			72		(4)
Total operating expenses			919			752		(167)

Operating income			235			222		13
Other income and (deductions)
Interest expense, net			(35)			(34)		(1)
Other, net			7			8		(1)
Total other income and (deductions)			(28)			(26)		(2)
Income before income taxes			207			196		11
Income taxes			9			(13)		(22)
Net income			$	198		$	209	$	(11)

Three Months Ended March 31, 2022 Compared to Three Months Ended March 31, 2021. Net income decreased $11 million primarily due to an increase in depreciation expense and credit loss expense, partially offset by favorable impacts of ~~operations include~~ the ~~results~~multi-year plans. 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.

The changes in Operating revenues consisted of the following:


	Three Months Ended March 31, 2022
	Increase
		Electric		Gas		Total
Distribution		$	14	$	10	$	24
Transmission		5		—		5
Other		8		2		10
		27		12		39
Regulatory required programs		78		63		141
Total increase		$	105	$	75	$	180

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.


	As of March 31,
Number of Electric Customers	2022	2021
Residential	1,199,272	1,192,470
Small commercial & industrial	115,363	114,819
Large commercial & industrial	12,674	12,505
Public authorities & electric railroads	268	266
Total	1,327,577	1,320,060

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BGE


	As of March 31,
Number of Natural Gas Customers	2022	2021
Residential	653,397	648,824
Small commercial & industrial	38,356	38,318
Large commercial & industrial	6,193	6,120
Total	697,946	693,262

Distribution Revenue increased for the three ~~reportable segments, Pepco, DPL~~months ended March 31, 2022,compared to the same period in 2021, 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 ~~ACE~~capital investments being recovered. Transmission revenue increased for the three months ended March 31, 2022, compared to the same period in 2021, primarily due to the 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 increased for the three months ended March 31, 2022, compared to the same period in 2021, primarily due to an increase in late fees charged to customers.

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 and transactions have been eliminated in consolidation. A separate specific discussion~~the presentation of ~~the results~~BGE's revenue disaggregation.

The increase of ~~operations~~$123 million 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 for the three and nine months ended September 30, 2017, the three months ended ~~September 30, 2016~~March 31, 2022 compared to the same period in 2021, in Purchased power and ~~for~~fuel expense is fully offset in Operating revenues as part of regulatory required programs.

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BGE

The changes in Operating and maintenance expense consisted of the ~~period from March 24, 2016 to September 30, 2016. All amounts presented below are before the impact of income taxes, except as noted.~~following:

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~~	Three Months Ended March 31, 2022
		Increase (Decrease)
Labor, other benefits, contracting, and ~~fuel~~materials		$	4

Pension and non-pension postretirement benefits expense ~~for electric and natural gas sales. PHI believes revenue net of purchased power and fuel~~		(3)
BSC costs		8
Credit loss 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.		14
Other		(3)
		20
Regulatory required programs		1

Total increase		$	21

~~Successor Period Three Months Ended September 30, 2017 Compared~~The changes in Depreciation and amortization expense consisted of the following:


	Three Months Ended March 31, 2022
	Increase
Depreciation and amortization(a)	$	9
Regulatory required programs	7
Regulatory asset amortization	3

Total increase	$	19

__________

(a)Depreciation and amortization increased primarily due to ~~Successor Period Three Months Ended September 30, 2016~~ongoing capital expenditures.

~~Net Income~~

~~PHI's Net~~Effective income for the Successor period of three months ended September 30, 2017 was $153 million compared to $166 million for the Successor period of three months ended September 30, 2016. The decrease in Net income reflects the September 2016 pre-tax recording of a $50 million reallocation of merger-related commitments from Pepco, DPLtax rateswere 4.3% 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~~(6.6)% for the three months ended ~~September 30, 2017~~March 31, 2022 and 2021, respectively. The change is primarily due to decreases in the multi-year plans' accelerated income tax benefits in 2022 as compared to ~~the three 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~~2021. See Note 3 — Regulatory Matters of the ~~new~~Combined Notes to Consolidated Financial Statements for additional information on the three-year electric ~~distribution~~ and natural gas ~~rates charged to Delaware customers that became effective in July 2016~~distribution multi-year plans 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, 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 Nine~~

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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 months ended March 31, 2022 compared to the same period in 2021. See the Results of Operations for Pepco, DPL, and ACE for additional information.


	Three Months Ended March 31,					Favorable (Unfavorable) Variance
		2022			2021
PHI			$	130		$	128	$	2
Pepco			46			59		(13)
DPL			56			56		—
ACE			26			14		12
Other(a)			2			(1)		3

_________

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

Three Months Ended ~~September 30, 2017~~

~~PHI's~~ March 31, 2022 Compared to Three Months Ended March 31, 2021. Net ~~income for the Successor period~~Income increased by $2 million primarily due to favorable impacts as a result of ~~nine months ended September 30, 2017 was $359 million. Therewere no significant changes in the underlying trends affecting PHI's operations during the Successor period~~Pepco's Maryland and District of ~~nine months ended September 30, 2017 except for the impact of increases in electric distribution~~Columbia multi-year plans and ~~natural gas rates within Revenue net of purchased power expense (Pepco~~higher electric distribution rates ~~effective November 2016~~at DPL and ACE, partially offset by an increase in storm costs and depreciation expense.

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Pepco

Results of Operations — Pepco


	Three Months Ended March 31,					Favorable (Unfavorable) Variance
		2022			2021
Operating revenues			$	614		$	553	$	61


Operating expenses
Purchased power			213			166		(47)
Operating and maintenance			131			108		(23)
Depreciation and amortization			108			102		(6)
Taxes other than income taxes			95			90		(5)
Total operating expenses			547			466		(81)

Operating income			67			87		(20)
Other income and (deductions)
Interest expense, net			(36)			(34)		(2)
Other, net			13			12		1
Total other income and (deductions)			(23)			(22)		(1)
Income before income taxes			44			65		(21)
Income taxes			(2)			6		8
Net income			$	46		$	59	$	(13)

Three Months Ended March 31, 2022 Compared to Three Months Ended March 31, 2021.Net income decreased $13 million primarily due to an increase in storm costs, depreciation expense, and credit loss expense, partially offset by the favorable impacts of the Maryland ~~Pepco~~and District of Columbia multi-year plans.

The changes in Operating revenues consisted of the following:


	Three Months Ended March 31, 2022
	Increase (Decrease)
Distribution	$	6
Transmission	3
Other	(3)
	6
Regulatory required programs	55
Total increase	$	61

Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution ~~rates effective August 2017~~ in both Maryland and the District of Columbia ~~DPL electric~~are not impacted by abnormal weather or usage per customer as a result of a bill stabilization adjustment (BSA) that provides for a fixed distribution ~~rates effective February 2017~~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.


	As of March 31,
Number of Electric Customers	2022	2021
Residential	846,258	835,415
Small commercial & industrial	54,509	53,738
Large commercial & industrial	22,620	22,492
Public authorities & electric railroads	184	174
Total	923,571	911,819

Distribution Revenue increased for the three months ended March 31, 2022 compared to the same period in 2021 primarily due to favorable impacts of the Maryland ~~DPL electric distribution~~ and ~~natural gas rates effective July 2016~~District of Columbia multi-year plans.

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Pepco

Transmission Revenue Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and ~~December 2016~~capital investments being recovered. Transmission revenue increased for the three months ended March 31, 2022, compared to the same period in ~~Delaware,~~2021, primarily due to increases in underlying costs.

Other Revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues, and ~~ACE electric distribution rates effective August 2016~~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, 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 ~~New Jersey).~~certain instances. The ~~deferral~~costs of ~~merger-related, rate case, and customer billing system costs to a regulatory asset and lower uncollectible accounts~~these programs are included in Purchased power 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 the Combined Notes to Consolidated Financial Statements for the presentation of Pepco's revenue disaggregation.

The increase of $47 million for the three months ended March 31, 2022 compared to the same period in 2021, in Purchased power 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 March 31, 2022
	Increase
Storm-related costs	$	6
BSC and PHISCO Costs	6
Credit loss expense	4
Labor, other benefits, contracting and materials	4



Other	3
	23

Regulatory required programs	—
Total increase	$	23

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Pepco

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


	Three Months Ended March 31, 2022
	Increase (Decrease)
Depreciation and amortization(a)	$	5
Regulatory asset amortization	(4)
Regulatory required programs	5
Total increase	$	6

_________

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

Effective income tax rates were (4.5)% and 9.2% for the three months ended March 31, 2022 and 2021, respectively. The change is primarily due to the acceleration of certain ~~merger commitments in the first quarter of 2017.~~

~~PHI's effective~~ income tax ~~rate for~~benefits as a result of the ~~Successor period~~Maryland and District of ~~nine months ended September 30, 2017 was 23.3%.~~Columbia multi-year plans. See Note ~~12 -~~3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statement for additional information on the three-year electric distribution multi-year plans and Note 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 March 31,					Favorable (Unfavorable) Variance
		2022			2021
Operating revenues			$	431		$	382	$	49
Operating expenses
Purchased power and fuel			189			156		(33)
Operating and maintenance			93			83		(10)
Depreciation and amortization			57			53		(4)
Taxes other than income taxes			18			17		(1)
Total operating expenses			357			309		(48)

Operating income			74			73		1
Other income and (deductions)
Interest expense, net			(16)			(15)		(1)
Other, net			2			3		(1)
Total other income and (deductions)			(14)			(12)		(2)
Income before income taxes			60			61		(1)
Income taxes			4			5		1
Net income			$	56		$	56	$	—

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~~March 31, 2022 Compared to Three Months Ended ~~September 30, 2016.~~ ~~Pepco's~~ March 31, 2021. Net income remained consistent.

The changes in Operating revenues consisted of the following:


	Three Months Ended March 31, 2022
	Increase
		Electric		Gas		Total

Volume		$	5	$	1	$	6
Distribution		6		2		8
Transmission		2		—		2

		13		3		16
Regulatory required programs		25		8		33
Total increase		$	38	$	11	$	49

Revenue Decoupling. The demand for ~~the three months ended September 30, 2017, was higher than the same period in 2016, primarily due to an increase in Revenue net of purchased power expense resulting~~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.~~

~~Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016.~~ Pepco's Net income for the nine months ended September 30, 2017, was higher than the same period in 2016, primarily due to an increase in Revenue net of purchased power expense resulting from higher electric distribution revenues 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 implemented~~ 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 and changes in the approved distribution charge per customer. 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.customers.

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 to the amount by which revenue from Maryland 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.

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 service territory. The changes in heating and cooling degree days in Pepco’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:

% 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 %

~~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 Pepco's Consolidated Statements of Operations and Comprehensive Income. Refer to the Operating and maintenance expense and Depreciation and amortization expense discussion below 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 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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~~Table of Contents~~

Weather. The demand for electricity and natural gas in ~~areas not subject to the BSA~~Delaware is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as ~~“favorable~~"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~~March 31, 2022 compared to the same ~~periods~~period in ~~2016, operating revenue net~~2021, Operating revenues related to weather remained consistent.

118

Table of ~~purchased power and fuel expense was lower due to the impact of unfavorable weather conditions in DPL's service territory.~~Contents

DPL

Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 20-year period in DPL's Delaware electric service territory and a 30-year period in DPL's Delaware natural gas service territory. The changes in heating and cooling degree days in DPL’s Delaware service territory for the three ~~and nine~~ months ended ~~September 30, 2017~~March 31, 2022 compared to ~~the~~ same ~~periods~~period in ~~2016~~2021 and normal weather consisted of the following:


	Three Months Ended March 31,			% Change
Delaware Electric Service Territory	2022	2021	Normal	2022 vs. 2021		2022 vs. Normal





Heating Degree-Days	2,355	2,358	2,480	(0.1)	%	(5.0)	%
Cooling Degree-Days	3	3	—	—	%	—	%

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 %


	Three Months Ended March 31,			% Change
Delaware Natural Gas Service Territory	2022	2021	Normal	2022 vs. 2021		2022 vs. Normal




Heating Degree-Days	2,355	2,358	2,500	(0.1)	%	(5.8)	%

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 revenue net of purchased power and fuel expense related to delivery volume,~~ Volume, exclusive of the effects of weather, increased for the three ~~and nine~~ months ended ~~September 30, 2017~~March 31, 2022 compared to the same ~~periods~~period in ~~2016,~~2021 primarily ~~reflects~~due to customer growth and usage.


Electric Retail Deliveries to Delaware Customers (in GWhs)	Three Months Ended March 31,		% Change	Weather - Normal % Change(b)
	2022	2021
Residential		895	854	4.8	%	4.2	%
Small commercial & industrial		370	342	8.2	%	7.7	%
Large commercial & industrial		765	689	11.0	%	11.0	%
Public authorities & electric railroads		9	9	—	%	5.3	%
Total electric retail deliveries(a)		2,039	1,894	7.7	%	7.3	%


	As of March 31,
Number of Total Electric Customers (Maryland and Delaware)	2022	2021
Residential	478,009	473,917
Small commercial & industrial	63,296	62,647
Large commercial & industrial	1,221	1,208
Public authorities & electric railroads	603	608
Total	543,129	538,380

_________

(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 ~~impact~~change in delivery volumes assuming normalized weather based on the historical 20-year average.


Natural Gas Retail Deliveries to Delaware Customers (in mmcf)	Three Months Ended March 31,		% Change	Weather - Normal % Change(b)
	2022	2021
Residential		4,453	4,394	1.3	%	0.3	%
Small commercial & industrial		1,983	1,868	6.2	%	6.0	%
Large commercial & industrial		457	457	—	%	0.1	%
Transportation		2,207	2,224	(0.8)	%	(0.7)	%
Total natural gas deliveries(a)		9,100	8,943	1.8	%	1.3	%

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Table of ~~increased~~Contents

DPL


	As of March 31,
Number of Delaware Natural Gas Customers	2022	2021
Residential	128,695	127,522
Small commercial & industrial	10,097	10,043
Large commercial & industrial	17	19
Transportation	159	160
Total	138,968	137,744

__________

(a)Reflects delivery volumes from customers purchasing natural gas ~~average customer usage~~directly from DPL and ~~customer growth.~~customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges.

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

Distribution ~~Revenues.~~ ~~The increase in electric operating revenues net of purchased power expense as a result of pricing~~Revenue increased for the three ~~and nine~~ months ended ~~September 30, 2017~~March 31, 2022 compared to the same ~~periods~~period in ~~2016 was~~2021 primarily due to ~~the impact of~~ higher electric distribution ~~and natural gas~~ rates ~~charged to Delaware customers~~in Maryland that became effective in ~~July and December 2016 and the impact of~~March 2022, higher ~~electric distribution~~Distribution System Improvement Charge (DSIC) rates ~~charged to Maryland customers~~in Delaware that became effective in ~~February 2017. See Note 5—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.~~January 2022, and higher approved electric distribution rates in Delaware that became effective in September 2021.

~~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 DPL's Consolidated Statements of Operations and Comprehensive Income. Refer to the Operating and maintenance expense and Depreciation and amortization expense discussion below 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 and capital investments being ~~recovered and other billing adjustments. The increase in~~recovered. Transmission revenue ~~net of purchased power expense~~increased for the three months ended ~~September 30, 2017~~March 31, 2022, compared to the same period in ~~2016 is a result of higher rates effective June 1, 2017 related~~2021,primarily due to increases in ~~transmission plant investment and operating expenses. The increase in revenue net of purchased power expense for the nine months~~underlying costs.

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~~Table of Contents~~

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.

~~Other.~~ Other ~~revenue, which can vary period to period,~~Revenue includes rental revenue, revenue related to late payment charges, ~~assistance provided to other utilities through~~ mutual assistance ~~programs,~~revenues, and recoveries of other taxes.

~~Operating~~Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, DE Renewable Portfolio Standards, SOS procurement 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.

administrative costs, and GCR costs. The ~~changes~~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, ~~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 $ 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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~~Table of Contents~~

~~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:~~

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 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 deliveries as DPL 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, DPL either acts as the billing agent or the competitive supplier separately bills its own customers, and 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 DPL, DPL is permitted to recover the electricity, natural gas, and REC procurement costs from customers and therefore records the amounts related to the electricity, natural gas, and RECs in Operating revenues and 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 ~~three and nine months ended September 30, 2017 compared to the same periods in 2016 remained relatively constant.~~presentation of DPL's revenue disaggregation.

~~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% and 30.2%~~The increase of $33 million for the three months ended ~~September 30, 2017~~March 31, 2022, compared to the same period in 2021, respectively, in Purchased power and ~~2016, respectively. DPL's effective~~fuel expense is fully offset in Operating revenues as part of regulatory required programs.

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Table of Contents

DPL

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


	Three Months Ended March 31, 2022
	Increase
BSC and PHISCO costs	$	3
Storm-related costs	3
Credit loss expense	2

Labor, other benefits, contracting and materials	(2)
Other	3
	9
Regulatory required programs	1
Total increase	$	10

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


	Three Months Ended March 31, 2022
	Increase
Depreciation and amortization(a)	$	3
Regulatory asset amortization	—
Regulatory required programs	1
Total increase	$	4

_________

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

Effective income tax ~~rate was 28.7%~~rateswere 6.7% and ~~900.0%~~8.2% for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2022 and ~~2016,~~2021, 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~~

121

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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Table of Contents

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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~~Table of Contents~~

Results of Operations -— ACE


	Three Months Ended March 31,					Favorable (Unfavorable) Variance
		2022			2021
Operating revenues			$	349		$	310	$	39


Operating expenses
Purchased power			178			157		(21)
Operating and maintenance			84			76		(8)
Depreciation and amortization			47			47		—
Taxes other than income taxes			2			2		—
Total operating expenses			311			282		(29)

Operating income			38			28		10
Other income and (deductions)
Interest expense, net			(14)			(15)		1
Other, net			3			1		2
Total other income and (deductions)			(11)			(14)		3
Income before income taxes			27			14		13
Income taxes			1			—		(1)
Net income			$	26		$	14	$	12

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~~March 31, 2022 Compared to Three Months Ended ~~September 30, 2016.~~ ~~ACE's~~ March 31, 2021. Net income ~~for the three months ended September 30, 2017, was lower than the same period in 2016,~~increased $12 million primarily due to ~~a decrease~~increases in distribution rates.

The changes in Operating revenues consisted of the following:


	Three Months Ended March 31, 2022
	Increase
Weather	$	1
Volume	2
Distribution	11
Transmission	5

	19




Regulatory required programs	20
Total increase	$	39

Revenue ~~net of purchased power expense resulting~~Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues 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.

~~Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016.~~ ACE's Net income (loss) for the nine months ended September 30, 2017, was higher than the same period in 2016, primarily due to an increase in Revenue net of purchased power expense resulting 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~~Conservation Incentive Program (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 approved target revenues established in ACE’s most recent distribution base rate case. The CIP is calculated annually, and recovery is subject to certain conditions, including an earnings test and ceilings on customer rate increases. While Operating revenues are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers. See Note 3 — Regulatory Matters of the Combined Notes to the ~~deductibility of certain merger commitments.~~Consolidated Financial Statements for additional information.

~~Revenues Net of Purchased Power Expense~~

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 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 ACE customers have the choice to purchase electricity from competitive electric generation suppliers. The customer's choice of supplier does not impact the volume of deliveries, but affects revenue collected from customers related to supplied energy service.

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~~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~~Weather. Prior to the ~~same periods in 2016, consisted~~third quarter of 2021, 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 iswas 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~~March 31, 2022 compared to the same ~~periods~~period in ~~2016, operating revenue net of purchased power and fuel expense was lower~~2021, Operating revenues related to weather increased due to the ~~impact~~absence of ~~unfavorable weather conditions~~impacts in ~~ACE's service territory.~~

~~For retail customers~~the first quarter of ~~ACE, distribution revenues are not decoupled from~~2022 as a result of 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.

CIP.

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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~~March 31, 2022 compared to ~~the~~ same ~~periods~~period in ~~2016~~2021 and normal weather consisted of the following:


	Three Months Ended March 31,		Normal	% Change
Heating and Cooling Degree-Days	2022	2021		2022 vs. 2021		2022 vs. Normal





Heating Degree-Days	2,436	2,348	2,454	3.7	%	(0.7)	%
Cooling Degree-Days	2	4	1	(50.0)	%	100.0	%

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~~Volume,exclusive of the effects of weather, increased for the three months ended ~~September 30, 2017,~~March 31, 2022 compared to the same period in ~~2016,~~2021, due to the ~~decrease~~absence of impacts in ~~operating revenue net~~the first quarter of ~~purchased power expense related to delivery volume, exclusive~~2022 as a result of the ~~effects of~~CIP.


Electric Retail Deliveries to Customers (in GWhs)	Three Months Ended March 31,		% Change	Weather - Normal % Change(b)
	2022	2021
Residential		918	928	(1.1)	%	(2.3)	%
Small commercial & industrial		339	305	11.1	%	9.7	%
Large commercial & industrial		703	716	(1.8)	%	(2.4)	%
Public authorities & electric railroads		14	13	7.7	%	6.2	%
Total electric retail deliveries(a)		1,974	1,962	0.6	%	(0.4)	%


	As of March 31,
Number of Electric Customers	2022	2021
Residential	500,511	498,396
Small commercial & industrial	62,124	61,771
Large commercial & industrial	3,124	3,267
Public authorities & electric railroads	724	704
Total	566,483	564,138

_________

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

(b)Reflects the change in delivery volumes assuming normalized weather ~~is primarily due to lower average customer usage. During~~based on the ~~nine~~historical 20-year average.

Distribution Revenue increased for the three months ended ~~September 30, 2017~~March 31, 2022 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 primarily~~2021 due to ~~the impact of~~ higher ~~electric~~ distribution ~~base~~ rates ~~charged to customers~~ that ~~became~~become effective in ~~August 2016. See Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.~~January 2022.

~~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. Refer to the Operating and maintenance expense and Depreciation and amortization expense discussion below 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 and capital investments being ~~recovered and other billing adjustments. The increase in~~recovered. Transmission revenue ~~net of purchased power expense~~increased for the three months ended ~~September 30, 2017~~March 31, 2022, compared to the same period in ~~2016 is a result of higher rates effective June 1, 2017 and related~~2021, primarily due to increases in ~~transmission plant~~capital investment and ~~operating expenses.~~ underlying costs.

Other Revenue includes rental revenue, service connection fees, and mutual assistance revenues.

Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, Societal Benefits Charge, Transition Bonds, and BGS 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, 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

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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 ~~in revenue net~~ of ~~purchased power expense~~$21 million for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2022 compared to the same period in ~~2016~~2021, respectively, in Purchased power expense is ~~a result~~fully offset in Operating revenues as part of ~~higher rates effective June 1, 2017 and June 1, 2016 related to increases~~regulatory required programs.

The changes in ~~transmission plant investment and operating expenses.~~

Operating and ~~Maintenance Expense~~maintenance expense consisted of the following:

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~~	Three Months Ended March 31, 2022
		Increase
BSC and ~~maintenance expenses for regulatory~~PHISCO costs		$	2
Labor, other benefits, contracting and materials		1

Storm-related costs		1


		4

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.(a)		4
Total increase		$	8

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(a)ACE 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 the Societal Benefits Charge.

The changes in ~~Operating~~Depreciation and ~~maintenance~~ amortizationexpense ~~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 $ 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~~	Three Months Ended March 31, 2022
		Increase (Decrease)
Depreciation and ~~compensation costs recognized in 2016.~~amortization(a)

		$	3
~~(b)~~Regulatory asset amortization	~~Primarily related to merger-related commitments for customer rate credits and charitable contributions recognized in 2016.~~			1
Regulatory required programs				(4)
Total				$	—

~~Depreciation and Amortization Expense~~

~~The changes in~~ _________

(a)Depreciation and amortization ~~expense for the three and nine months ended September 30, 2017 compared~~increased primarily due to ~~the same periods in 2016 consisted of the following:~~ongoing capital expenditures.

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 3.7% and ~~32.9%~~0.0% for the three months ended ~~September 30, 2017~~March 31, 2022 and ~~2016,~~2021, respectively. ACE's effective income tax rate was 13.5% and 13.8% for the nine months ended September 30, 2017 and 2016, 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~~

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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 Constellation 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 all periods presented. 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 onthree months ended March 31, ~~2017 and demonstrated adequate funding assurance for all nuclear units currently operating. As~~2022 includes one month of ~~September 30, 2017, across the four alternative decommissioning approaches available, Generation estimates a parental guarantee~~cash flows from Generation. The Exelon Consolidated Statement of up to $115 million 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.

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~~Cash Flows for the ~~plant’s owner(s) to utilize~~three months ended March 31, 2021 includes three months of cash flows from Generation. This is the ~~NDT fund to pay~~primary reason 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~~changes in cash flows as shown 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.tables unless otherwise noted below.

Cash Flows from Operating Activities

~~General~~

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

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

See ~~Notes~~Note 3 — Regulatory Matters of the Exelon 2021 Form 10-K and 24Note 12 — 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 cash flows from operations for the nine months ended September 30, 2017 and 2016:~~

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, equitychange 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~~

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~~three months ended ~~September 30, 2017~~March 31, 2022 and ~~2016~~2021 by ~~Registrant were as follows:~~Registrant:


Increase (decrease) in cash flows from operating activities	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Net income (loss)	$	862	$	(9)	$	39	$	(11)	$	2	$	(13)	$	—	$	12
Adjustments to reconcile net income to cash:
Non-cash operating activities	69		20		17		70		66		37		17		11
Option premiums (paid), net	(55)		—		—		—		—		—		—		—
Collateral received, net	869		38		—		—		—		—		—		—
Income taxes	(36)		21		(3)		13		2		(1)		(4)		(1)
Pension and non-pension postretirement benefit contributions	(37)		(5)		4		9		(31)		—		(1)		(4)
Changes in working capital and other noncurrent assets and liabilities	1,371		53		(41)		67		(16)		—		31		(28)
Increase (decrease) in cash flows from operating activities	$	3,043	$	118	$	16	$	148	$	23	$	23	$	43	$	(10)

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~~three months ended ~~September 30, 2017~~March 31, 2022 and ~~2016~~2021 were as follows:

~~Generation~~•See Note 14 — 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 iswas 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 the nine months ended September 30, 2017 and 2016, Generation had net (payments)/collections of counterparty cash collateral of $(77) million and $759 million, respectively, primarily due to market conditions that resulted in changes to Generation’s net mark-to-market position.

During the nine months ended September 30, 2017 and 2016, Generation had net (payments) collections of approximately $(35) million and $24 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 nine months ended September 30, 2017 and 2016, ComEd posted approximately $24 million and $2 million 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 of September 30, 2017 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~~•See Note ~~19 - Supplemental Financial Information~~7 — Income Taxes of the Combined Notes to Consolidated Financial Statements and the ~~Financial Statements.~~Registrants' Consolidated Statements of Cash Flows for additional information on income taxes.

•Changes in working capital and other noncurrent assets and liabilities for the Utility Registrants and Exelon Corporate total $88 million and for Generation total $1,283 million. The change for Generation primarily relates to the revolving accounts receivable financing arrangement. See Note 6 — Accounts Receivable of the Exelon 2021 Form 10-K and the Collection of DPP discussion below for additional information.

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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~~three months ended ~~September 30, 2017~~March 31, 2022 and ~~2016~~2021 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) increase in cash flows from investing activities	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Capital expenditures	$	218	$	(4)	$	(49)	$	33	$	47	$	2	$	9	$	36

Investment in NDT fund sales, net	3		—		—		—		—		—		—		—
Collection of DPP	(1,405)		—		—		—		—		—		—		—
Proceeds from sales of assets and businesses	(664)		—		—		—		—		—		—		—
Changes in intercompany money pool	—		—		48		—		—		—		—		—

Other investing activities	(66)		—		1		1		1		—		1		—
(Decrease) increase in cash flows from investing activities	$	(1,914)	$	(4)	$	—	$	34	$	48	$	2	$	10	$	36

Significant investing cash flow impacts for the Registrants for ~~nine~~three months ended ~~September 30, 2017~~March 31, 2022 and ~~2016~~2021 were as follows:

~~Exelon~~

~~During the nine months ended September 30, 2017, Exelon had~~•Variances 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 ~~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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~~fund anticipated planned~~Cash Requirements" section below for additional information on projected capital ~~and operating needs of the associated companies.~~expenditure spending. 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 the revolving accounts receivable financing agreement which Generation entered into in ~~2017.~~

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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 in2020. See Note 56 — ~~Regulatory Matters~~Accounts Receivable of the ~~Combined Notes~~Exelon 2021 Form 10-K for additional information on the transaction and the DPP, including the $400 million of additional funding received in February and March of 2021.

•Proceeds from sales of assets and businesses decreased primarily due to ~~Consolidated Financial Statements.~~the sale of a significant portion of Generation's solar business in 2021. See Note 2 — Mergers, Acquisitions, and Dispositions of the Exelon 2021 Form 10-K 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.

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~~three months ended ~~September 30, 2017~~March 31, 2022 and ~~2016~~2021 by ~~Registrant~~Registrant:

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Increase (decrease) in cash flows from financing activities	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Changes in short-term borrowings, net	$	(997)	$	188	$	—	$	(36)	$	(100)	$	(140)	$	(3)	$	43
Long-term debt, net	2,669		50		(375)		—		119		250		—		(131)
Changes in intercompany money pool	—		—		105		—		36		—		—		—

Dividends paid on common stock	42		(17)		(15)		(2)		—		(14)		(1)		(5)
Distributions to member	—		—		—		—		(21)		—		—		—
Contributions from(to) parent/member	—		(31)		227		—		144		249		24		(130)
Transfer of cash, restricted cash, and cash equivalents to Constellation	(2,594)		—		—		—		—		—		—		—
Other financing activities	(38)		(1)		3		(1)		(4)		(4)		—		—
Increase (decrease) in cash flows from financing activities	$	(918)	$	189	$	(55)	$	(39)	$	174	$	341	$	20	$	(223)

Significant financing cash flow impacts for the Registrants for the three months ended March 31, 2022 and 2021 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~~

~~See~~•Changes in short-term borrowings, net, is driven by repayments on and issuances of notes due in less than 365 days. Refer to 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. These changes also included repayments of $552 million in commercial paper and term loans by Generation prior to the separation.

•Long-term debt, net, varies due to debt issuances and redemptions each year. Refer to 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 19 — Commitments and Contingenciesof the Exelon 2021 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.

•For the three months ended March 31, 2022, other financing activities primarily consists of debt issuance costs. See Note 10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants’ debt issuances.

~~Dividends~~Debt

~~Cash dividend payments~~See Note 10 — Debt and ~~distributions during~~Credit Agreements of the ~~nine~~Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt issuances.

During the three months ended ~~September 30, 2017 and 2016 by Registrant~~March 31, 2022, there were no long-term debt retirements or redemptions. However, as ~~follows:~~of May 9, 2022, 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

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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

Pepco

First Mortgage Bonds

3.05

April 1, 2022

200

Exelon

Junior Subordinated Notes

3.50

May 2, 2022

1,150

Dividends

Quarterly dividends declared by the Exelon Board of Directors during the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2022 and for the ~~fourth~~second quarter of ~~2017~~2022 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 2022

February 8, 2022

February 25, 2022

March 10, 2022

0.3375

Second Quarter 2022

April 26, 2022

May 13, 2022

June ~~2016 dividend and subject to Board approval.~~10, 2022

0.3375

~~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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~~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
$ —

~~_________~~

~~(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.~~2022. The 2022 quarterly dividend will be $0.3375 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~~$3.7 billion was available to support additional commercial paper as of ~~September 30, 2017,~~March 31, 2022, and of which no financial institution has more than 7% of the aggregate commitments for the Registrants. The Registrants had access to the commercial paper ~~market~~markets and had availability under their revolving credit facilities during the ~~third quarter of 2017~~three months ended March 31, 2022 to fund their short-term liquidity needs, when necessary. On February 1, 2022, Exelon Corporate and the Utility Registrants each entered into a new 5-year revolving credit facility that replaced its existing syndicated 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~~2021 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 its investment grade credit rating as~~liquidity to support the estimated future cash requirements.

Pursuant to the Separation Agreement between Exelon and Constellation, Exelon made a cash payment of ~~September 30, 2017, it would have been required to provide incremental collateral of $1.8~~$1.75 billion to ~~meet collateral obligations for derivatives, non-derivatives, normal purchase normal sales contracts and applicable payables and receivables, net~~Generation on January 31, 2022. See Note 2 — Discontinued Operations of the ~~contractual right of offset under master netting agreements, which is well within its current available credit facility capacities of $4.6 billion.~~

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Combined Notes to Consolidated Financial Statements for additional information on the separation.

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~~March 31, 2022 and available credit facility capacity prior to any incremental collateral at ~~September 30, 2017:~~March 31, 2022:

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	PJM Credit Policy Collateral		Other Incremental Collateral Required ^(a)		Available Credit Facility Capacity Prior to Any Incremental Collateral			PJM Credit Policy Collateral		Other Incremental Collateral Required(a)		Available Credit Facility Capacity Prior to Any Incremental Collateral
ComEd	$	18	$	—	$	998	ComEd	$	40	$	—	$	998
PECO	3		20		599		PECO	2		39		600
BGE	3		28		600		BGE	2		62		350

Pepco	4		—		300		Pepco	2		—		300
DPL	1		9		300		DPL	2		16		300
ACE	—		—		300		ACE	1		—		300

_________


~~(a)~~	~~Represents incremental collateral related to natural gas procurement contracts.~~

(a)Represents incremental collateral related to natural gas procurement contracts.

Capital Expenditure Spending

As of March 31, 2022, the most recent estimates of capital expenditures for plant additions and improvements for 2022 are as follows:


(In millions)	Transmission	Distribution	Gas	Total(a)
Exelon	N/A	N/A	N/A	$	6,900
ComEd	475	2,000	N/A	2,475
PECO	200	800	325	1,325
BGE	250	500	475	1,225
PHI	575	1,200	75	1,850
Pepco	275	675	N/A	950
DPL	125	250	75	450
ACE	175	275	N/A	450

__________

(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.

Pension and Other Postretirement Benefits

Management considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006 (the Act), management of the pension obligation, and regulatory implications. The Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification). The projected contributions reflect a funding strategy to make levelized annual contributions with the objective of achieving 100% funded status on an ABO basis over time. This level funding strategy helps minimize volatility of future period required pension contributions. Post-separation, Exelon's estimated annual qualified pension contributions will be approximately $313 million in 2022. In connection with the separation, additional qualified pension contributions of $207 million and $33 million were completed on February 1, 2022 and March 2, 2022, respectively. 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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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 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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~~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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~~Table~~The credit ratings for ComEd, PECO, BGE, and DPL did not change for the three months ended March 31, 2022. On January 14, 2022, Fitch lowered Exelon Corporate's long-term and senior unsecured ratings from BBB+ to BBB and affirmed the short-term rating of ~~Contents~~

F2. In addition, Fitch upgraded Pepco, ACE, and PHI's long-term rating from BBB to BBB+ and upgraded Pepco and ACE's senior secured rating from A- to A.

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,~~March 31, 2022, are presented in the following ~~table:~~table. Pepco, ACE, and DPL had no activity within the PHI intercompany money pool during the three months ended March 31, 2022.

Exelon Intercompany Money Pool During the Three Months Ended September 30, 2017 As of September 30, 2017
Contributed (borrowed)
Maximum
Contributed

Maximum
Borrowed

Contributed
(Borrowed)
Exelon Corporate $ 579
n/a
$ 280
Generation —
(417 ) (146 )
PECO 97
(10 ) 57
BSC —
(369 ) (245 )
PHI Corporate ^(a)

n/a
(33 ) (1 )
PCI ^(a)
54
—
54

~~_________~~


~~(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 Three Months Ended March 31, 2022				As of March 31, 2022
Exelon Intercompany Money Pool	Maximum Contributed		Maximum Borrowed		Contributed (Borrowed)
Exelon Corporate	$	396	$	—	$	312
PECO	—		(95)		(65)
BSC	—		(377)		(246)
PHI Corporate	—		(54)		(46)
PCI	50		—		45

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.~~2022. The ability of each Registrant to sell securities off the

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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:

As of March 31, 2022

Short-term Financing Authority^(a)(b)

Long-term Financing Authority^(c)

Short-term Financing Authority

Remaining Long-term Financing Authority

Commission

Expiration Date

Amount (in millions)

Commission

Expiration Date

Amount (in millions)

Commission

Expiration Date

Amount

Commission

Expiration Date

Amount

ComEd^(d)(a)

FERC

December 31, 2017

2,500

ICC

2019

1,383

FERC

December 31, 2023

2,500

ICC

January 1, 2025

1,343

PECO(b)

FERC

December 31, 2017

1,500

PAPUC

December 31, 2018

1,275

FERC

December 31, 2023

1,500

PAPUC

December 31, 2024

1,900

BGE

FERC

December 31, 2017

700

MDPSC

N/A

700

BGE

FERC

December 31, 2023

700

MDPSC

N/A

500

Pepco

FERC

June 30, 2018

500

MDPSC / DCPSC

September 25, 2017

—

Pepco

FERC

December 31, 2023

500

MDPSC / DCPSC

December 31, 2022

225

DPL

FERC

June 30, 2018

500

MDPSC / DPSC

December 31, 2017

125

DPL

FERC

December 31, 2023

500

MDPSC / DEPSC

December 31, 2022

ACE(c)

NJPU

January 1, 2018

350

NJBPU

December 31, 2017

300

NJBPU

December 31, 2023

350

NJBPU

December 31, 2022

—

_________


~~(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 November 18, 2021, ComEd received approval from the ICC for $2 billion in new money long-term debt financing authority with an effective date of January 1, 2022.

~~Contractual Obligations~~(b)On December 2, 2021, PECO received approval from the PAPUC for $2.5 billion in new long-term debt financing authority with an effective date of January 1, 2022.

(c)ACE is currently in the process of renewing its long-term financing authority with the NJBPU and ~~Off-Balance Sheet Arrangements~~expects approval by August 1, 2022.

~~Contractual obligations represent cash obligations~~

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

The Registrants hold commodity and financial instruments that are ~~considered~~exposed to the 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 ~~firm commitments and commercial commitments triggered~~shared by ~~future events.~~the remaining participants. See Note 249 — ~~Commitments and Contingencies of the Combined Notes to Consolidated~~Derivative Financial ~~Statements in the Exelon 2016 Form 10-K.~~

Generation, ComEd, PECO, BGE, Pepco, DPL and ACE have obligations related to contracts for the purchase of power 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 to the authoritative guidance for VIEs. See Note 1 — Basis of PresentationInstruments of the Combined Notes to Consolidated Financial Statements for ~~further information.~~

~~For an in-depth~~a detailed discussion of ~~the Registrants' contractual obligations~~counterparty credit risk related to derivative instruments.

•Equity price and ~~off-balance sheet arrangements, see “Management’s Discussion~~interest rate risk associated with Exelon’s pension and ~~Analysis~~OPEB plan trusts. See Note 15 — Retirement Benefits of ~~Financial Condition and Results of Operations — Contractual Obligations and Off-Balance Sheet Arrangements” in~~ the Exelon ~~2016~~2021 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 and Results of Operations - Contractual Obligations and Commercial Commitments."~~

~~Item 3. Quantitative and Qualitative Disclosures about Market Risk~~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. BGE, Pepco, DPL, and ACE have certain full requirements contracts, which are considered derivatives and qualify for NPNS, and as a result are accounted for on an accrual basis of accounting. Other full requirements contracts are not derivatives.

PECO, ~~has~~BGE, and DPL also ~~entered into~~have executed derivative natural gas contracts, which either qualify for ~~the normal purchases and normal sales exception~~NPNS or have no mark-to-market balances because the derivatives are index priced, to hedge ~~its~~their 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 full requirements contracts pursuant to BGE’s MDPSC-approved SOS program. BGE’s full requirements contracts that are considered derivatives qualify for the normal purchases and normal sales scope exception under current derivative authoritative guidance, and as a result, are accounted for on an accrual basis of accounting. Under the SOS program, 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 also entered into natural gas contracts, which qualify for the normal purchases and normal sales scope exception, to hedge its~~ 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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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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~~Table of Contents~~

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 liabilities are associated with ComEd’s floating-to-fixed energy swap

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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.


	Maturities Within												Total Fair Value
	2022		2023		2024		2025		2026		2027 and Beyond		Total Fair Value
Prices based on model or other valuation methods (Level 3)	$	(1)	$	(8)	$	(18)	$	(18)	$	(18)	$	(81)	$	(144)

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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

~~_________~~


~~(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 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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~~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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~~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 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.

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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~~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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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 DISCUSSION4. 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~~first quarter of ~~2017,~~2022, 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,~~March 31, 2022, 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~~first quarter of ~~2017~~2022 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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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~~2021 Form 10-K and (b) 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.

~~Item~~ITEM 1A. ~~Risk Factors~~RISK FACTORS

Risks Related to ~~Exelon~~All Registrants

At ~~September 30, 2017,~~March 31, 2022, the Registrants' risk factors were consistent with the risk factors described in the Registrants' combined ~~2016~~2021 Form 10-K in ITEM 1A. RISK FACTORS.

~~Item~~ITEM 4. ~~Mine Safety Disclosures~~MINE SAFETY DISCLOSURES

All Registrants

Not applicable to the Registrants.

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Table of Contents

ITEM 5. OTHER INFORMATION

All Registrants

None.

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~~Registrant agrees to furnish a copy of any such instrument to the Commission upon request.


Exhibit No.			Description

4.1*			One Hundred and Thirtieth Supplemental Indenture dated as of January 1, 2022, among Delmarva Power & Light Company and The Bank of New York Mellon Company, as trustee*

4.2			Fifth Supplemental Indenture dated as of March 7, 2022, among Exelon Corporation and The Bank of New York Mellon Trust Company, N.A., as trustee (File 001-16169, Form 8-K dated March 7, 2022, Exhibit 4.2)

4.3			Supplement Indenture dated as of February 23, 2022, to Commonwealth Edison Company Mortgage (File 001-01839, Form 8-K/A dated March 15, 2022, Exhibit 4.1)

4.4			Supplemental Indenture dated as of March 1, 2022, to Potomac Electric Power Company Mortgage and Deed of Trust (File No. 001-01072, Form 8-K dated March 24, 2022, Exhibit 4.2)


~~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~~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)

*Filed herewith

~~276~~

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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~~March 31, 2022 filed by the following officers for the following companies:



Exhibit No.		Description
31-1		— Filed by Christopher M. Crane for Exelon Corporation

31-2		— Filed by ~~Jonathan W. Thayer~~Joseph Nigro for Exelon Corporation

31-3		— Filed by ~~Kenneth W. Cornew for Exelon Generation Company, LLC~~

~~31-4~~Gil C. Quiniones	~~— Filed by Bryan P. Wright for Exelon Generation Company, LLC~~

~~31-5~~	~~— Filed by Anne R. Pramaggiore~~ for Commonwealth Edison Company

~~31-6~~31-4		— Filed by ~~Joseph R. Trpik, Jr.~~Elisabeth J. Graham for Commonwealth Edison Company

~~31-7~~31-5		— Filed by ~~Craig L. Adams~~Michael A. Innocenzo for PECO Energy Company

~~31-8~~31-6		— Filed by ~~Phillip S. Barnett~~Robert J. Stefani for PECO Energy Company

~~31-9~~31-7		— Filed by ~~Calvin G. Butler, Jr.~~Carim V. Khouzami for Baltimore Gas and Electric Company

~~31-10~~31-8		— Filed by David M. Vahos for Baltimore Gas and Electric Company

~~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

~~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

~~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

~~31-17~~31-15		— Filed by ~~David M. Velazquez~~J. Tyler An thony for Atlantic City Electric Company

~~31-18~~31-16		— Filed by ~~Donna J. Kinzel~~Phillip S. Barnett for Atlantic City Electric Company

136

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Certifications Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code (Sarbanes — Oxley Act of 2002) as to the Quarterly Report on Form 10-Q for the quarterly period ended ~~September 30, 2017~~March 31, 2022 filed by the following officers for the following companies:



Exhibit No.		Description
32-1		— Filed by Christopher M. Crane for Exelon Corporation

32-2		— Filed by ~~Jonathan W. Thayer~~Joseph Nigro for Exelon Corporation

32-3		— Filed by ~~Kenneth W. Cornew for Exelon Generation Company, LLC~~

~~32-4~~Gil C. Quiniones	~~— Filed by Bryan P. Wright for Exelon Generation Company, LLC~~

~~32-5~~	~~— Filed by Anne R. Pramaggiore~~ for Commonwealth Edison Company

~~32-6~~32-4		— Filed by ~~Joseph R. Trpik, Jr.~~Elisabeth J. Graham for Commonwealth Edison Company

~~32-7~~32-5		— Filed by ~~Craig L. Adams~~Michael A. Innocenzo for PECO Energy Company

~~32-8~~32-6		— Filed by ~~Phillip S. Barnett~~Robert J. Stefani for PECO Energy Company

~~32-9~~32-7		— Filed by ~~Calvin G. Butler, Jr.~~Carim V. Khouzami for Baltimore Gas and Electric Company

~~32-10~~32-8		— Filed by David M. Vahos for Baltimore Gas and Electric Company

~~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

~~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

~~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

~~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

137

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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~~CHRISTOPHER M. C~~RANE~~ CRANE						/s/ J~~ONATHAN~~ ~~W. THAYER~~ JOSEPH NIGRO
Christopher M. Crane						~~Jonathan W. Thayer~~Joseph Nigro
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~~

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~~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~~ FABIAN E. SOUZA		~~/s/ BRYAN~~ ~~P. WRIGHT~~
~~Kenneth W. Cornew~~Fabian E. Souza		~~Bryan P. Wright~~
~~President and Chief Executive Officer~~ ~~(Principal Executive Officer)~~	Senior Vice President and ~~Chief Financial Officer~~ ~~(Principal Financial Officer)~~

~~/s/ MATTHEW~~ ~~N. BAUER~~
~~Matthew N. Bauer~~
~~Vice President and~~Corporate Controller (Principal Accounting Officer)

~~November 2, 2017~~

May 9, 2022

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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. ELISABETH J. GRAHAM
~~Anne R. Pramaggiore~~Gil C. Quiniones						~~Joseph R. Trpik, Jr.~~Elisabeth J. Graham
~~President and~~ Chief Executive Officer (Principal Executive Officer)						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~~

May 9, 2022

~~281~~

139

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.

PECO ENERGY COMPANY



/s/ C~~RAIG~~ ~~L. ADAMS~~ MICHAEL A. INNOCENZO						/s/ P~~HILLIP~~ ~~S. BARNETT~~ ROBERT J. STEFANI
~~Craig L. Adams~~Michael A. Innocenzo						~~Phillip S. Barnett~~Robert J. Stefani
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~~May 9, 2022

~~282~~

140

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.

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
Chief Executive Officer (Principal Executive Officer)						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~~May 9, 2022

~~283~~

141

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)						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~~May 9, 2022

~~284~~

142

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/ 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)						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~~May 9, 2022

~~285~~

143

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)						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~~May 9, 2022

~~286~~

144

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)						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~~

May 9, 2022

~~287~~

145



Exelon Corporation Common Stock, without par value		~~960,852,473~~980,209,605
~~Exelon Generation Company, LLC~~		~~not applicable~~
Commonwealth Edison Company Common Stock, $12.50 par value	~~127,021,214~~127,021,391
PECO Energy Company Common Stock, without par value		170,478,507
Baltimore Gas and Electric Company Common Stock, without par value		1,000
Pepco Holdings LLC		not applicable
Potomac Electric Power Company Common Stock, ~~$.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~~99
			Exelon Corporation		~~180~~99
			Executive Overview		~~180~~99
			Financial Results of Operations		~~181~~99
			Significant ~~2017~~2022 Transactions and Developments		~~189~~101
			~~Exelon's Strategy and Outlook for 2017 and Beyond~~		~~194~~
			~~Liquidity Considerations~~		~~195~~
			Other Key Business Drivers and Management Strategies		~~196~~103
			Critical Accounting Policies and Estimates		~~202~~103
			Results of Operations By Registrant		~~203~~104
			~~Exelon Generation Company, LLC~~	~~204~~Commonwealth Edison Company		104
			~~Commonwealth Edison Company~~	~~212~~PECO Energy Company		107
			~~PECO Energy Company~~	~~218~~
	Baltimore Gas and Electric Company	~~224~~111
			Pepco Holdings LLC		~~231~~114
			Potomac Electric Power Company		~~234~~115
			Delmarva Power & Light Company		~~240~~118
			Atlantic City Electric Company		~~248~~122
			Liquidity and Capital Resources		~~253~~125
			~~Contractual Obligations and Off-Balance Sheet Arrangements~~		~~266~~
ITEM 3.			QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		~~266~~133
ITEM 4.			CONTROLS AND PROCEDURES		~~275~~134
PART II.			OTHER INFORMATION		~~276~~134
ITEM 1.			LEGAL PROCEEDINGS		~~276~~134
ITEM 1A.			RISK FACTORS		~~276~~134
ITEM 4.			MINE SAFETY DISCLOSURES		~~276~~134
ITEM 6.			~~EXHIBITS~~5.	~~276~~OTHER INFORMATION		135
~~SIGNATURES~~ ITEM 6.			~~279~~EXHIBITS		135
					~~Exelon Corporation~~ SIGNATURES	~~279~~138
			~~Exelon Generation Company, LLC~~	~~280~~Exelon Corporation		138
			Commonwealth Edison Company		~~281~~139
			PECO Energy Company		~~282~~140
			Baltimore Gas and Electric Company		~~283~~141
			Pepco Holdings LLC		~~284~~142
			Potomac Electric Power Company		~~285~~143
			Delmarva Power & Light Company		~~286~~144
			Atlantic City Electric Company		~~287~~145


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
ACE Funding or ATF			Atlantic City Electric Transition Funding LLC

~~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	14
	Consolidated Statements of Cash Flows	15
	Consolidated Balance Sheets	16
	Consolidated Statements of Changes in Shareholders' Equity	18
	PECO Energy Company
	Consolidated Statements of Operations and Comprehensive Income	19
	Consolidated Statements of Cash Flows	20
	Consolidated Balance Sheets	21
	Consolidated Statements of Changes in Shareholder's Equity	23
	Baltimore Gas and Electric Company
	Statements of Operations and Comprehensive Income	24
	Statements of Cash Flows	25
	Balance Sheets	26
	Statements of Changes in Shareholder's Equity	28
	Pepco Holdings LLC
	Consolidated Statements of Operations and Comprehensive Income	29
	Consolidated Statements of Cash Flows	30
	Consolidated Balance Sheets	31
	Consolidated Statements of Changes in Member's Equity	33


GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
Note ~~“—”~~- of the ~~Exelon 2016~~2021 Form 10-K			Reference to specific Combined Note to Consolidated Financial Statements within ~~Exelon’s 2016~~Exelon's 2021 Annual Report on Form 10-K
~~Act 11~~AEC			~~Pennsylvania Act 11 of 2012~~
~~Act 129~~	~~Pennsylvania Act 129 of 2008~~
~~AEC~~	Alternative Energy Credit that is 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~~BGS			~~Accounting Standards Codification~~
~~BGS~~	Basic Generation Service
~~Block Contracts~~CEJA (formerly Clean Energy Law in the Exelon 2021 Form 10-K)			~~Forward Purchase Energy Block Contracts~~Climate and Equitable Jobs Act; Illinois Public Act 102-0662 signed into law on September 15, 2021
~~CAIR~~CERCLA			~~Clean Air Interstate Rule~~
~~CAISO~~	~~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~~CMC			~~Clean Energy Standard~~Carbon Mitigation Credit
~~CFL~~CODM			~~Compact Fluorescent Light~~Chief Operating Decision Maker(s)
~~Clean Air Act~~		~~Clean Air Act of 1963, as amended~~
~~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



~~GLOSSARY OF TERMS AND ABBREVIATIONS~~DOEE			District of Columbia Department of Energy & Environment
~~Other Terms and Abbreviations~~DPP			Deferred Purchase Price
~~DRP~~EIMA			~~Direct Stock Purchase and Dividend Reinvestment Plan~~
~~DSP~~	~~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~~ETAC			~~Expected Rate of Return on Assets~~Energy Transition Assistance Charge
~~FASB~~FEJA			~~Financial Accounting Standards Board~~
~~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			Gigawatt hour
~~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~~		~~Intercontinental Exchange~~
~~Illinois Act~~	~~Illinois Electric Service Customer Choice and Rate Relief Law of 1997~~
~~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			Internal Revenue Code
IRS			Internal Revenue Service
~~ISO~~LIBOR			~~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~~MDPSC
~~LLRW~~	~~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~~MW			~~Moody’s Investor Service~~Megawatt
~~MOPR~~MWh			~~Minimum Offer Price Rule~~Megawatt hour
~~MRV~~N/A			~~Market-Related Value~~Not applicable
MWNDT			~~Megawatt~~
~~MWh~~	~~Megawatt hour~~
~~NAAQS~~	~~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~~
~~Non-Regulatory Agreements Units~~Normal Purchase Normal Sale scope exception		~~Nuclear generating units or portions thereof whose decommissioning-related activities are not subject to contractual elimination under regulatory accounting~~
~~NOSA~~	~~Nuclear Operating Services Agreement~~
~~NPDES~~	~~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~~	~~Ontario Independent Electricity System Operator~~
~~OPC~~	~~Office of People’s Counsel~~
~~OPEB~~	~~Other Postretirement Employee Benefits~~
~~PA DEP~~	~~Pennsylvania Department of Environmental Protection~~
~~PAPUC~~	~~Pennsylvania Public Utility Commission~~
~~PGC~~	~~Purchased Gas Cost Clause~~
~~PJM~~	~~PJM Interconnection, LLC~~



GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
~~POLR~~NPS			National Park Service
OCI			Other Comprehensive Income
OPEB			Other Postretirement Employee Benefits
PAPUC			Pennsylvania Public Utility Commission
PGC			Purchased Gas Cost Clause
PJM			PJM Interconnection, LLC
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~~PRP			~~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~~		~~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~~ZEC			~~United Government Security Officers of America~~
~~Upstream~~Zero Emission Credit or Zero Emission Certificate		~~Natural gas exploration and production activities~~
~~VIE~~	~~Variable Interest Entity~~



~~GLOSSARY OF TERMS AND ABBREVIATIONS~~
~~Other Terms and Abbreviations~~
~~WECC~~		~~Western Electric Coordinating Council~~
~~ZEC~~		~~Zero Emission Credit~~
~~ZES~~		~~Zero Emission Standard~~


	Three Months Ended September 30,						Nine Months Ended September 30,							Three Months Ended March 31,
(In millions, except per share data)	2017			2016			2017			2016			(In millions, except per share data)		2022		2021
Operating revenues													Operating revenues
Competitive businesses revenues	$	4,456		$	4,535		$	12,924		$	12,243
Rate-regulated utility revenues	4,313			4,467			12,225			11,243
Electric operating revenues													Electric operating revenues		$	4,481	$	3,870
Natural gas operating revenues													Natural gas operating revenues		817		633
Revenues from alternative revenue programs													Revenues from alternative revenue programs		29		129
Total operating revenues	8,769			9,002			25,149			23,486			Total operating revenues		5,327		4,632
Operating expenses													Operating expenses
Competitive businesses purchased power and fuel	2,316			2,584			7,268			6,599
Rate-regulated utility purchased power and fuel	1,226			1,170			3,259			2,863
Purchased power													Purchased power		1,581		1,140
Purchased fuel													Purchased fuel		338		218
Purchased power and fuel from affiliates													Purchased power and fuel from affiliates		159		293
Operating and maintenance	2,300			2,338			7,732			7,677			Operating and maintenance		1,178		1,083
Depreciation and amortization	1,002			1,195			2,814			2,821			Depreciation and amortization		817		757
Taxes other than income	456			449			1,313			1,168
Taxes other than income taxes													Taxes other than income taxes		354		317
Total operating expenses	7,300			7,736			22,386			21,128			Total operating expenses		4,427		3,808
(Loss) Gain on sales of assets	(1		)	1			4			41
Bargain purchase gain	7			—			233			—

Operating income	1,475			1,267			3,000			2,399			Operating income		900		824
Other income and (deductions)													Other income and (deductions)
Interest expense, net	(377		)	(506		)	(1,165		)	(1,148		)	Interest expense, net		(332)		(312)
Interest expense to affiliates	(9		)	(10		)	(29		)	(31		)	Interest expense to affiliates		(6)		(6)
Other, net	237			120			725			377			Other, net		137		58
Total other income and (deductions)	(149		)	(396		)	(469		)	(802		)
Income before income taxes	1,326			871			2,531			1,597
Total other deductions													Total other deductions		(201)		(260)
Income from continuing operations before income taxes													Income from continuing operations before income taxes		699		564
Income taxes	452			340			595			625			Income taxes		218		39
Equity in losses of unconsolidated affiliates	(7		)	(5		)	(25		)	(16		)
Net income	867			526			1,911			956
Net income attributable to noncontrolling interests and preference stock dividends	43			36			12			26
Net income attributable to common shareholders	$	824		$	490		$	1,899		$	930
Comprehensive income, net of income taxes
Net income	$	867		$	526		$	1,911		$	956

Net income from continuing operations after income taxes													Net income from continuing operations after income taxes		481		525
Net income (loss) from discontinued operations after income taxes (Note 2)													Net income (loss) from discontinued operations after income taxes (Note 2)		117		(789)
Net income (loss)													Net income (loss)		598		(264)
Net income attributable to noncontrolling interests													Net income attributable to noncontrolling interests		1		25
Net income (loss) attributable to common shareholders													Net income (loss) attributable to common shareholders		$	597	$	(289)

Amounts attributable to common shareholders:													Amounts attributable to common shareholders:
Net income from continuing operations													Net income from continuing operations		481		525
Net income (loss) from discontinued operations													Net income (loss) from discontinued operations		116		(814)
Net income (loss) attributable to common shareholders													Net income (loss) attributable to common shareholders		$	597	$	(289)

Comprehensive income (loss), net of income taxes													Comprehensive income (loss), net of income taxes
Net income (loss)													Net income (loss)		$	598	$	(264)
Other comprehensive income (loss), net of income taxes													Other comprehensive income (loss), net of income taxes
Pension and non-pension postretirement benefit plans:													Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	(14		)	(12		)	(42		)	(35		)	Prior service benefit reclassified to periodic benefit cost		—		(1)
Actuarial loss reclassified to periodic benefit cost	49			47			147			140			Actuarial loss reclassified to periodic benefit cost		14		56
Pension and non-pension postretirement benefit plan valuation adjustment	3			—			(55		)	(3		)	Pension and non-pension postretirement benefit plan valuation adjustment		—		(2)
Unrealized gain (loss) on cash flow hedges	—			3			5			(4		)
Unrealized gain (loss) on equity investments	1			(4		)	5			(10		)

Unrealized gain on foreign currency translation	4			2			7			8			Unrealized gain on foreign currency translation		—		1
Unrealized gain on marketable securities	1			—			2			—

Other comprehensive income	44			36			69			96			Other comprehensive income		14		54
Comprehensive income	911			562			1,980			1,052
Comprehensive income attributable to noncontrolling interests and preference stock dividends	43			31			10			21
Comprehensive income attributable to common shareholders	$	868		$	531		$	1,970		$	1,031
Comprehensive income (loss)													Comprehensive income (loss)		612		(210)
Comprehensive income attributable to noncontrolling interests													Comprehensive income attributable to noncontrolling interests		1		25
Comprehensive income (loss) attributable to common shareholders													Comprehensive income (loss) attributable to common shareholders		$	611	$	(235)

Average shares of common stock outstanding:													Average shares of common stock outstanding:
Basic	962			925			941			924			Basic		981		977
Diluted	965			927			943			926
Earnings per average common share:
Assumed exercise and/or distributions of stock-based awards													Assumed exercise and/or distributions of stock-based awards		—		1
Diluted(a)													Diluted(a)		981		978

Earnings per average common share from continuing operations													Earnings per average common share from continuing operations
Basic	$	0.86		$	0.53		$	2.02		$	1.01		Basic		$	0.49	$	0.53
Diluted	$	0.85		$	0.53		$	2.01		$	1.00		Diluted		$	0.49	$	0.53
Dividends declared per common share	$	0.33		$	0.32		$	0.98		$	0.95

Earnings (losses) per average common share from discontinued operations													Earnings (losses) per average common share from discontinued operations
Basic													Basic		$	0.12	$	(0.83)
Diluted													Diluted		$	0.12	$	(0.83)



(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


	Three Months Ended March 31, 2022
(In millions, shares in thousands)	Issued Shares	Common Stock		Treasury Stock		Retained Earnings		Accumulated Other Comprehensive Loss, net		Noncontrolling Interests		Total Shareholders' Equity
Balance, December 31, 2021	981,291	$	20,324	$	(123)	$	16,942	$	(2,750)	$	402	$	34,795
Net income	—	—		—		597		—		1		598
Long-term incentive plan activity	540	(13)		—		—		—		—		(13)
Employee stock purchase plan issuances	211	9		—		—		—		—		9


Changes in equity of noncontrolling interests	—	—		—		—		—		(7)		(7)

Distribution of Constellation (Note 2)	—	(21)		—		(13,179)		2,023		(396)		(11,573)
Common stock dividends ($0.34/common share)	—	—		—		(332)		—		—		(332)
Other comprehensive income, net of income taxes	—	—		—		—		14		—		14

Balance, March 31, 2022	982,042	$	20,299	$	(123)	$	4,028	$	(713)	$	—	$	23,491



	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


	Three Months Ended March 31, 2022
(In millions)	Membership Interest		Undistributed (Losses)/Earnings		Total Member's Equity
Balance, December 31, 2021	$	10,795	$	(210)	$	10,585
Net income	—		130		130
Distributions to member	—		(102)		(102)
Contributions from member	704		—		704
Balance, March 31, 2022	$	11,499	$	(182)	$	11,317



(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



	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2017			2016			2017			2016
Operating revenues
Electric operating revenues	$	603		$	634		$	1,645		$	1,692
Operating revenues from affiliates	1			1			4			3
Total operating revenues	604			635			1,649			1,695
Operating expenses
Purchased power	111			84			268			340
Purchased power from affiliates	57			129			210			223
Operating and maintenance	89			100			296			488
Operating and maintenance from affiliates	14			9			40			20
Depreciation and amortization	82			76			242			221
Taxes other than income	102			105			282			287
Total operating expenses	455			503			1,338			1,579
Gain on sales of assets	—			—			1			8
Operating income	149			132			312			124
Other income and (deductions)
Interest expense, net	(31		)	(30		)	(89		)	(98		)
Other, net	7			12			22			28
Total other income and (deductions)	(24		)	(18		)	(67		)	(70		)
Income before income taxes	125			114			245			54
Income taxes	38			35			57			34
Net income	$	87		$	79		$	188		$	20
Comprehensive income	$	87		$	79		$	188		$	20


	Three Months Ended March 31, 2022
(In millions)	Common Stock		Retained Earnings		Total Shareholder's Equity
Balance, December 31, 2021	$	2,302	$	1,173	$	3,475
Net income	—		46		46
Common stock dividends	—		(42)		(42)
Contributions from parent	387		—		387
Balance, March 31, 2022	$	2,689	$	1,177	$	3,866



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 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