See the Combined Notes to Consolidated Financial Statements

5854

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 generation, delivery and marketing of energy ~~generation~~through 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 to Note 4 - Mergers, Acquisitions~~businesses through ComEd, PECO, BGE, Pepco, DPL and ~~Dispositions for further information regarding the merger transaction.~~

~~The energy generation business includes:~~ACE.

~~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.



Name of Registrant	Business	Service Territories
Exelon Generation Company, LLC	Generation, physical delivery and marketing of power across multiple geographical regions through its customer-facing business, Constellation, which sells electricity to both wholesale and retail customers. Generation also sells natural gas, renewable energy and other energy-related products and services.	Five reportable segments: Mid-Atlantic, Midwest, New York, ERCOT and Other Power Regions

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

~~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.~~

Basis of Presentation (All Registrants)

As a result of the acquisition of PHI, Exelon’s financial reporting reflects PHI’s consolidated financial results subsequent 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 accounting to the consolidated financial statements of PHI such that the assets 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.~~

Each of the Registrant’s Consolidated Financial Statements includes the accounts of its subsidiaries. All intercompany transactions have been eliminated.

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

The accompanying consolidated financial statements as of ~~September 30, 2017~~March 31, 2020 and ~~2016~~2019 and for the three ~~and nine~~ months then ended 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 December 31, ~~2016~~2019 Consolidated Balance Sheets were derived from audited financial statements. 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

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Note 1 — Significant Accounting Policies

December 31, ~~2017.~~2020. 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.

COVID-19 (All Registrants)

2. The Registrants are responding to the global outbreak (pandemic) of the 2019 novel coronavirus (COVID-19) and have taken steps to mitigate the potential risks to the Registrants posed by its spread. The Registrants provide a critical service to their customers and have taken measures to keep employees who operate the business safe and minimize unnecessary risk of exposure to the virus, including extra precautions for employees who work in the field. The Registrants have implemented work from home policies where appropriate and imposed travel limitations on employees. In addition, the Registrants have updated their existing business continuity plans.

Management makes estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and accompanying notes, and the amounts of revenues and expenses reported during the periods covered by those financial statements and accompanying notes. We assessed certain accounting matters that require consideration of forecasted financial information, including, but not limited to, our allowance for credit losses, the carrying value of our goodwill and other long-lived assets, in context with the information reasonably available to us and the unknown future impacts of COVID-19 as of March 31, 2020 and through the date of this report. While there were no material increases in the Registrants’ allowance for credit losses and no material impairments resulting from these assessments as of and for the quarter ended March 31, 2020, our future assessment of our current expectations at that time of the magnitude and duration of COVID-19, as well as other factors, could result in material impacts to our consolidated financial statements in future reporting periods.

New Accounting Standards (All Registrants)

New Accounting Standards ~~Issued and Not Yet Adopted:~~ Adopted as of January 1, 2020: The following new authoritative accounting guidance issued by the FASB ~~has not yet been~~was adopted as of January 1, 2020 and will be 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 Cash Flows and disclosures, 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 with a customer. The new revenue recognition guidance, including subsequent amendments, is effective for annual reporting periods~~statements beginning ~~on or after December 15, 2017, with the option to early adopt the standard for annual periods beginning on or after December 15, 2016. Exelon has not early adopted this standard.~~

~~Table of Contents~~

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

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

The new standard replaces existing guidance on revenue recognition, including most industry specific guidance, with a five step model for recognizing and measuring revenue from contracts with customers. The objective of the new standard is to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability within industries, across industries, and across capital markets. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The guidance also requires 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 application of the guidance at the date of initial adoption (modified retrospective method).

The Registrants have assessed the revenue recognition standard and are executing a detailed implementation plan in preparation for adoption on January 1, 2018. The Registrants have also actively participated in the ~~AICPA Power and Utilities Industry Task Force (Industry Task Force) process to identify implementation issues and support the development~~first quarter of ~~related implementation guidance. In coordination with the Industry Task Force, the Registrants have reached conclusions on the following key accounting issues:~~2020.

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 the Presentation of Net Periodic Pension Cost 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

~~Table of Contents~~

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

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

Statements of Operations and Comprehensive Income. Additionally, service cost is the only component eligible for capitalization (whereas under current GAAP, all components of net benefit cost are eligible for capitalization).

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

The standard is effective January 1, 2018 and requires retrospective application for the presentation 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~~its current estimate of credit losses expected to be incurred over the life of the financial ~~instrument.~~instrument based on historical experience, current conditions and reasonable and supportable forecasts. 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~~was 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~~ This standard is primarily applicable to Generation's 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. TheUtility Registrants' Customer accounts receivables balances. This 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~~did not ~~currently expect~~have a significant impact ~~given~~on 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.~~Registrants’ consolidated financial statements.

Goodwill Impairment (Issued January 2017):. Simplifies the accounting for goodwill impairment by removing Step 2 of the current test, which requires calculation of a hypothetical purchase price allocation. Under the revised guidance, goodwill impairment will be measured as the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill (currently Step 1 of the ~~two step~~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 iswas effective January 1, 2020 ~~with early adoption permitted,~~ and must be applied on a prospective basis. Exelon, Generation, ComEd, PHI and DPL will apply the new guidance for their goodwill impairment assessments in 2020 and do not expect the updated guidance to have a material impact to their financial statements.

Allowance for Credit Losses on Accounts Receivables (All Registrants)

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

The allowance for credit losses for Generation’s retail customers is based on accounts receivable aging historical experience coupled with specific identification through a credit monitoring process, which considers current

6256

Table of Contents

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

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

Note 1 — Significant Accounting Policies

~~Clarifying~~

conditions and forward-looking information such as industry trends, macroeconomic factors, changes in the ~~Definition~~regulatory environment, external credit ratings, publicly available news, payment status, payment history, and the exercise of collateral calls. The allowance for credit losses for Generation wholesale customers is developed using a ~~Business (Issued January 2017):~~ ~~Clarifies the definition of~~credit monitoring process, similar to that used for retail customers. When a ~~business~~wholesale customer’s risk characteristics are no longer aligned with the ~~objective of addressing whether acquisitions (or dispositions) should be accounted~~pooled population, Generation uses specific identification to develop an allowance for as acquisitions/dispositions of assets or as acquisitions/dispositions of businesses. If substantially all the fair value of the assets acquired/disposed of is concentrated in a single identifiable asset or a group of similar identifiable assets, the set of transferred assets and activities is not a business. If the fair value of the assets acquired/disposed of is not concentrated in a single identifiable asset or a group of similar identifiable assets, then an entity must evaluate whether an input and a substantive process exist, which together significantly contributecredit losses. Adjustments to the ~~ability to produce outputs. The standard also revises the definition of outputs to focus~~allowance for credit losses are recorded in Operating and maintenance expense 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’Generation’s Consolidated Statements of ~~Cash Flows~~Operations and ~~disclosures.~~Comprehensive Income.

~~Recognition~~

The allowance for credit losses for the Utility Registrants’ customers is developed by applying loss rates for each Utility Registrant, based on historical loss experience, current conditions 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 relatedforward-looking risk factors, to the ~~presentation of fair value changes of financial liabilities~~outstanding receivable balance by customer risk segment. Utility Registrants' customer accounts are written off consistent with approved regulatory requirements. Adjustments to the allowance for ~~which the fair value option has been elected, (iii) amends several disclosure requirements, including the methods~~credit losses are primarily recorded to Operating and significant assumptions used to estimate fair value or a description of the changes in the methods and assumptions used to estimate fair value, and (iv) requires disclosure of the fair value of financial assets and liabilities measured at amortized cost at the amount that would be received to sell the asset or paid to transfer the liability. The standard is effective January 1, 2018 with early adoption permitted. The guidance requires a modified retrospective transition approach with a cumulative effect adjustment to retained earnings for initial application of the guidance at the date of adoption. The Registrants will not early adopt this standard. The Registrants do not expect that this guidance will have a significant impactmaintenance expense on the Utility Registrants' ~~Consolidated Balance Sheets,~~ Consolidated Statements of Operations and Comprehensive Income and Regulatory assets on ComEd, BGE and ACE’s Consolidated ~~Statements~~Balance Sheets. See Note 3 - Regulatory Matters of ~~Cash Flows.~~the 2019 Form 10-K for additional information regarding the regulatory recovery of credit losses on customer accounts receivable at ComEd, BGE and ACE.

The Registrants have certain non-customer receivables in Other Deferred debits and other assets which primarily are with governmental agencies and other high-quality counterparties with no history of default. As such, the allowance for credit losses related to these receivables is immaterial. The Registrants monitor these balances and will record an allowance if there are indicators of a decline in credit quality.

~~3. Variable Interest Entities~~2. Regulatory Matters (All Registrants)

~~A VIE is a legal entity that possesses any~~As discussed in Note 3 — Regulatory Matters of the Exelon 2019 Form 10-K, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The following ~~characteristics: an insufficient amount of equity at risk~~discusses developments in 2020 and updates to ~~finance its activities, equity owners who do not have~~ the ~~power to direct~~2019 Form 10-K.

Utility Regulatory Matters (Exelon and the ~~significant activities of~~Utility Registrants)

Distribution Base Rate Case Proceedings

The following tables show the entity (or have voting rights that are disproportionate to their ownership interest) or equity owners who do not have the obligation to absorb expected losses or the right to receive the expected residual returns of the entity. Companies are required to consolidate a VIE if they are its primary beneficiary, which is the enterprise that has the power to direct the activities that most significantly affect the entity’s economic performance.completed and pending distribution base rate case proceedings in 2020.

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~~

6357

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 2 — Regulatory Matters

~~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)~~.

~~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 cash plus immaterial working capital and other customary post-closing adjustments. The Renewable JV meets the definition of a VIE because the Renewable JV has a similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner. Additionally, under the VIE guidance Generation is the primary beneficiary because Generation maintains the controlling financial interest; therefore, Generation will continue to consolidate the Renewable JV.

Generation owned 90% of a biomass fueled, combined heat and power company. In the second quarter of 2015, the entity was deemed to be a VIE because the entity required additional subordinated financial support in the form of a parental guarantee provided by Generation for up to $275 million in support of the payment obligations related to the Engineering, Procurement 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 nine months ended September 30, 2017, BGE remitted $22 million to BondCo. During the three 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.

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~~

Completed Distribution Base Rate Case Proceedings



Registrant/Jurisdiction	Filing Date	Requested Revenue Requirement (Decrease) Increase			Approved Revenue Requirement (Decrease) Increase			Approved ROE		Approval Date	Rate Effective Date
ComEd - Illinois (Electric)^(a)	April 8, 2019	$	(6	)	$	(17	)	8.91	%	December 4, 2019	January 1, 2020

__________

(a)

Reflects an increase of $51 million for the initial revenue requirement for 2019 and a decrease of $68 million related to the annual reconciliation for 2018. The revenue requirement for 2019 and annual reconciliation for 2018 provides for a weighted average debt and equity return on distribution rate base of 6.51%, inclusive of an allowed ROE of 8.91%, reflecting the average rate on 30-year treasury notes plus 580 basis points.

Pending Distribution Base Rate Case Proceedings



Registrant/Jurisdiction	Filing Date	Requested Revenue Requirement (Decrease) Increase			Requested ROE		Expected Approval Timing
ComEd - Illinois (Electric)^(a)	April 16, 2020	$	(11	)	8.38	%	Fourth quarter of 2020
Pepco - District of Columbia (Electric)^(b)	May 30, 2019 (amended April 8, 2020)	147			10.3	%	Fourth quarter of 2020
DPL - Maryland (Electric)	December 5, 2019 (amended April 23, 2020)	17			10.3	%	Third quarter of 2020
DPL - Delaware (Gas)^(c)	February 21, 2020 (amended March 17, 2020)	9			10.3	%	First quarter of 2021
DPL - Delaware (Electric)^(d)	March 6, 2020 (amended April 16, 2020)	24			10.3	%	First quarter of 2021

__________

(a)

Reflects an increase of $51 million for the initial revenue requirement for 2020 and a decrease of $62 million related to the annual reconciliation for 2019. The revenue requirement for 2020 and annual reconciliation for 2019 provides for a weighted average debt and equity return on distribution rate base of 6.28%, inclusive of an allowed ROE of 8.38%, reflecting the average rate on 30-year treasury notes plus 580 basis points.


(b)	Reflects a three-year cumulative multi-year plan and total requested revenue requirement increases of $77 million, $37 million and $33 million for years 2020, 2021, and 2022, respectively, to recover capital investments made in 2018 and 2019 and planned capital investments from 2020 to 2022.


(c)	The rates will go into effect on September 21, 2020, subject to refund.


(d)	The rates will go into effect on October 6, 2020, subject to refund.

Other Federal Regulatory Matters

Transmission-Related Income Tax Regulatory Assets (Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE). On December 13, 2016 (and as amended on March 13, 2017), BGE filed with FERC to begin recovering certain existing and future transmission-related income tax regulatory assets through its transmission formula rate. BGE’s existing regulatory assets included (1) amounts that, if BGE’s transmission formula rate provided for recovery, would have been previously amortized and (2) amounts that would be amortized and recovered prospectively. On November 16, 2017, FERC issued an order rejecting BGE’s proposed revisions to its transmission formula rate to recover

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 2 — Regulatory Matters

these transmission-related income tax regulatory assets. In the fourth quarter of 2017, ComEd, BGE, Pepco, DPL, and ACE fully impaired their associated transmission-related income tax regulatory asset for the portion of the income tax regulatory asset that would have been previously amortized.

On February 23, 2018 (as amended on July 9, 2018), ComEd, Pepco, DPL, and ACE each filed with FERC to revise their transmission formula rate mechanisms to permit recovery of transmission-related income tax regulatory assets, including those amounts that would have been previously amortized and recovered through rates had the transmission formula rate provided for such recovery.

On September ~~30,~~7, 2018, FERC issued orders rejecting 1) BGE's rehearing request of FERC's November 16, 2017 ~~Exelon's, PHI's~~order; and ~~ACE's consolidated VIE consists of:~~

~~ATF~~, ~~a special purpose entity formed~~2) February 23, 2018 (as amended on July 9, 2018) filing by ComEd, Pepco, DPL and ACE for similar recovery.

On November 2, 2018, BGE filed an appeal of FERC’s September 7, 2018 order to the ~~purpose~~Court of ~~securitizing authorized portions~~Appeals for the D.C. Circuit. On March 27, 2020, the Court of Appeals denied BGE’s November 2, 2018 appeal.

On October 1, 2018, ComEd, BGE, Pepco, DPL, and ACE submitted filings to recover only ongoing non-TCJA amortization amounts and credit TCJA transmission-related income tax regulatory liabilities to customers for the prospective period starting on October 1, 2018. On April 26, 2019, FERC issued an order accepting ComEd’s, BGE’s, Pepco’s, DPL’s, and ACE’s October 1, 2018 filings, effective October 1, 2018, subject to refund and established hearing and settlement judge procedures. On April 24, 2020, ComEd, BGE, Pepco, DPL, ACE and other parties filed a settlement agreement with FERC. The settlement agreement provides for the recovery of ongoing transmission-related income tax regulatory assets and establishes the amount and amortization period for excess deferred income taxes resulting from TCJA. The accelerated amortization will result in a reduction to Operating revenues and an offsetting reduction to Income tax expense over the remaining amortization period.

While FERC has no deadline by which it must rule on the settlement, a final order from FERC is expected before the end of the third quarter of 2020. Exelon cannot predict the outcome of this proceeding. If FERC ultimately rules that the future, ongoing non-TCJA amortization amounts are not recoverable, ~~stranded costs through the issuance~~Exelon, ComEd, BGE, PHI, Pepco, DPL and ~~sale~~ACE would record additional charges to Income tax expense, which could be up to approximately $81 million, $51 million, $18 million, $12 million, $4 million, $6 million and $2 million, respectively, as of ~~transition bonds.~~

March 31, 2020.

~~As of September 30, 2017~~Regulatory Assets and Liabilities

The Utility Registrants' regulatory assets and liabilities have not changed materially since 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 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~~2019, unless noted below. See Note ~~5—Investment in Constellation Energy Nuclear Group, LLC and Note 27—Related Party Transactions~~3 — Regulatory Matters of the Exelon ~~2016~~2019 Form 10-K for additional information ~~regarding Generation's~~on the specific regulatory assets and ~~Exelon’s transactions with CENG):~~liabilities.

~~under the NOSA, Generation conducts all activities related~~ComEd. Regulatory assets increased $96 million primarily due to ~~the operation~~an increase of ~~the CENG nuclear generation fleet owned~~$45 million in Energy Efficiency Costs, $22 million in Electric Distribution Formula Rate Annual Reconciliations and $15 million due to increased Electric Energy Costs. Regulatory liabilities decreased $596 million primarily due to a decrease of $582 million in Nuclear Decommissioning.

PECO. Regulatory liabilities decreased $207 million primarily due to a decrease of $219 million in Nuclear Decommissioning offset by ~~CENG subsidiaries (the CENG fleet)~~a $16 million increase in Electric Energy and provides corporate and administrative services for the remaining life and decommissioning of the CENG nuclear plants as if they were a part of the Generation nuclear fleet, subject to the CENG member rights of EDF,Natural Gas Costs.

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

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~~

6559

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 2 — Regulatory Matters

~~Exelon has executed an agreement to provide up to $245 million to support~~

Capitalized Ratemaking Amounts Not Recognized (Exelon and the ~~operations of CENG as well as a $165 million guarantee of CENG’s cash pooling agreement with its subsidiaries.~~

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

In the case of ATF, proceeds from the sale of each series of transition bonds by ATF were transferred to ACE in exchange for the transfer by ACE to ATF of the right to collect a non-bypassable Transition Bond Charge from ACE customers pursuant to bondable stranded costs rate orders issued by the NJBPU in an amount sufficient to fund the principal and interest payments on transition bonds and related taxes, expenses and fees. During the three and nine months ended September 30, 2017, ACE transferred $11 million and $39 million to ATF, respectively. During the three and nine months ended September 30, 2016, ACE transferred $20 million and $47 million to ATF, respectively.

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

~~the assets of the VIEs are restricted and can only be used to settle obligations of the respective VIE;~~

~~Exelon, Generation, PHI and ACE did not provide any additional material financial support to the VIEs;~~

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

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

The ~~carrying~~following table presents authorized amounts capitalized for ratemaking purposes related to earnings on shareholders’ investment that are not recognized for financial reporting purposes in Exelon's and ~~classification of~~ the ~~consolidated VIEs’ assets and liabilities included~~Utility Registrant's Consolidated Balance Sheets. These amounts will be recognized as revenues in the ~~Registrants' consolidated financial statements at September 30, 2017~~related Consolidated Statements of Operations and ~~December 31, 2016~~Comprehensive Income in the periods they are ~~as follows:~~billable to our customers.

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



	Exelon		ComEd^(a)		PECO		BGE^(b)		PHI		Pepco^(c)		DPL^(c)		ACE
March 31, 2020	$	60	$	2	$	—	$	51	$	7	$	4	$	3	$	—
December 31, 2019	63		3		—		53		7		4		3		—

_________


(a)	~~Includes certain purchase accounting adjustments not pushed down to the ACE standalone entity.~~Reflects ComEd's unrecognized equity returns earned for ratemaking purposes on its electric distribution formula rate regulatory assets.


(b)	~~Includes certain purchase accounting adjustments not pushed down~~BGE's authorized amounts capitalized for ratemaking purposes primarily relate to ~~the BGE standalone entity.~~

~~Table of Contents~~

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

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

~~Assets and Liabilities of Consolidated VIEs~~

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

September 30, 2017 December 31, 2016
Successor Successor

Exelon ^(a)

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

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

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

618

13
9
908

870

23

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

8,859

30
22
7,985

7,947

3

35
23
Total assets $ 9,520

$ 9,477

$ 43
$ 31
$ 8,893

$ 8,817

$ 26

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

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

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

$ 143
$ 126

~~_________~~


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


~~(b)~~	~~Includes certain purchase accounting adjustments not pushed down to the BGE standalone entity.~~earnings on shareholders' investment on its AMI programs.

(c)

~~Includes the retail gas pension obligation, which is presented as a net asset balance within the Prepaid pension asset line item~~Pepco's and DPL's authorized amounts capitalized for ratemaking purposes relate to earnings on ~~Generation’s Consolidated Balance Sheets. See Note 14 - Retirement Benefits for additional details.~~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.

~~Unconsolidated Variable Interest Entities~~

Exelon’s and Generation’s variable interests in unconsolidated VIEs generally include equity investments and energy purchase and sale contracts. For the equity investments, the carrying amount of the investments is reflected on Exelon’s and Generation’s Consolidated Balance Sheets in Investments. For the energy purchase and sale contracts (commercial agreements), the carrying amount of assets and liabilities in Exelon’s and Generation’s Consolidated Balance Sheets that relate to their involvement with the VIEs are predominantly related to working capital accounts

~~Table of Contents~~

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

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

~~and generally represent the amounts owed by, or owed to, Exelon and~~ Generation for the deliveries associated with the current billing cycles under the commercial agreements. Further, Exelon and Generation have not provided material debt or equity support, liquidity arrangements or performance guarantees associated with these commercial agreements.

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

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

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

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

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

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

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

~~Table of Contents~~

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

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

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

September 30, 2017
Commercial
Agreement
VIEs

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

December 31, 2016
Commercial
Agreement
VIEs

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

~~_________~~


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

~~(b)~~

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

For each of the unconsolidated VIEs, Exelon and Generation have assessed the risk of a loss equal to their maximum exposure to be remote and, accordingly, Exelon and Generation have not recognized a liability associated with any portion of the maximum exposure to loss. In addition, there are no material agreements with, or commitments by, third parties that would affect the fair value or risk of their variable interests in these VIEs.

~~BGE~~

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

~~Table of Contents~~

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

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

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

~~Acquisition of James A. FitzPatrick Nuclear Generating Station~~Regulatory Matters (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. As part of the acquisition agreements, Generation provided nuclear fuel and reimbursed Entergy for incremental costs to prepare for and conduct a plant refueling outage; and Generation reimbursed Entergy for incremental costs to operate and maintain the plant for the period after the refueling outage through the acquisition closing date. These reimbursements covered costs that Entergy otherwise would have avoided had it shut down the plant as originally intended in January 2017. The amounts reimbursed by Generation were offset by FitzPatrick's electricity and capacity sales revenues for this same post-outage period. As part of the transaction, Generation received the FitzPatrick NDT fund assets and assumed the obligation to decommission FitzPatrick. The NRC license for FitzPatrick expires in 2034. As of September 30, 2017, Generation had remitted purchase price consideration of $289 million (including $235 million of cash and $54 million of nuclear fuel) to and on behalf of Entergy.

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

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

~~Table of Contents~~

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

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

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

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

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

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

Bargain purchase gain (after-tax) $ 233

~~_________~~


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

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

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

On September 1, 2016, Generation acquired the competitive retail electricity and natural gas business of Consolidated Edison Solutions, Inc. (ConEdison Solutions), a subsidiary of Consolidated Edison, Inc. for a purchase price of $257 million including net working capital of $204 million. The renewable energy, sustainable services and energy efficiency businesses of ConEdison Solutions are excluded from the transaction.

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

~~Table of Contents~~

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

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

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

Total consideration transferred $ 257

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

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

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

~~Description of Transaction~~

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

~~Regulatory Matters~~

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

During the third and fourth quarters of 2016, Exelon and PHI filed proposals in Delaware, New Jersey and Maryland for amounts and allocations reflecting the application of the most favored nation provision, resulting in a total nominal cost of commitments of $513 million, excluding renewable generation commitments (approximately $444 million on a net present value basis amount, excluding renewable generation commitments and charitable contributions). These filings reflected agreements reached with certain parties to the merger proceedings in these jurisdictions. In 2016, the DPSC and NJBPU approved the amounts and allocations of the additional merger benefits for Delaware and New Jersey, respectively. On April 12, 2017, 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 or settlement of the fair value adjustments, with no impact on reported net income. See Note 5 - Regulatory Matters for additional information regarding the fair value of regulatory assets and liabilities established by Exelon and PHI.

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

As mentioned, under cost-of-service rate regulation, rates charged to customers are established by a regulator to provide for recovery of costs and a fair return on invested capital, or rate base, generally measured at historical cost. Historical cost information therefore is the most relevant presentation for the financial statements of PHI’s rate regulated utility subsidiary registrants, Pepco, DPL and ACE. As such, Exelon and PHI did not push-down the application of acquisition accounting to PHI's utility registrants, and therefore the financial statements 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 of a 9~~acre land parcel located on South Madison Street in Wilmington, DE, resulting in a pre-tax gain 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.

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.

~~Table of Contents~~

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

~~(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. 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 (Exelon and ComEd).~~ On April 13, 2017, ComEd filed its annual distribution formula rate with 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 million for the initial revenue requirement for 2017 and an increase of $18 million related to the annual reconciliation for 2016. The revenue requirement for 2017 provides for a weighted average debt and equity return on distribution 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. 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 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

~~Table of Contents~~

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

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

- May 31, 2018, the ZEC annual cost cap, is set at $235 million (ComEd’s share is approximately $170 million). For subsequent delivery years, the IPA-approved targeted ZEC procurement amounts will change based on forward energy and capacity prices. ZECs delivered to Illinois utilities in excess of the annual cost cap will be paid in subsequent years if the payments do not exceed the prescribed annual cost cap for that year.

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

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

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

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

~~ComEd Electric Distribution Rates~~

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

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

~~Energy Efficiency~~

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

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

~~Table of Contents~~

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

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

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

~~Table of Contents~~

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

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

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

~~Table of Contents~~

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

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

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.

~~Table of Contents~~

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

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

~~Maryland Regulatory Matters~~

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

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

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

~~Cash Working Capital Order (Exelon and BGE).~~ On November 17, 2016, the MDPSC rendered a decision in the proceeding to review BGE’s request to recover its cash working capital (CWC) requirement for its Provider of Last Resort service, also known as Standard Offer Service (SOS), as well as other components that make up the Administrative Charge, the mechanism that enables BGE to recover all of its SOS-related costs. The Administrative Charge is now comprised of five components: CWC, uncollectibles, incremental costs, return, and an administrative adjustment, which is an adder to the utility’s SOS rate to act as a proxy for retail suppliers’ costs. The Commission accepted BGE's positions on recovery of CWC and pass-through recovery of BGE’s actual uncollectibles and incremental costs. The order also grants BGE a return on the SOS. The Commission ruled that the level of the administrative adjustment will be determined in BGE’s next rate case. On December 16, 2016, MDPSC Staff requested clarification concerning the amount of return on the SOS awarded to BGE and on December 19, 2016, the residential consumer advocate sought rehearing of the return awarded. On January 24, 2017, the MDPSC issued an order denying the MDPSC Staff request for clarification and the residential consumer advocate request for rehearing. On February 22, 2017, the residential consumer advocate filed an appeal of the MDPSC's orders with the Circuit Court for Baltimore City. The residential consumer advocate filed its Memorandum on Appeal on June 5, 2017 and subsequent Reply Memoranda were filed by BGE and the MDPSC on July 7, 2017 and July 12, 2017, respectively. On August 7, 2017, following oral argument by the parties, a decision was issued from the Circuit Court affirming the decision of the MDPSC. On September 5, 2017, the residential consumer advocate filed an appeal of the Circuit Court's decision to the Maryland Court of Special Appeals. BGE cannot predict the outcome of this appeal.

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

~~Table of Contents~~

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

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

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

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

~~Delaware Regulatory Matters~~

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

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

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

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

~~District of Columbia Regulatory Matters~~

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

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

~~Table of Contents~~

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

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

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

~~District of Columbia Power Line Undergrounding Initiative (Exelon, PHI and Pepco).~~ The District of Columbia government enacted on an emergency basis (effective May 17, 2017) and thereafter on a permanent basis (effective July 11, 2017) legislation to amend the Electric Company Infrastructure Improvement Financing Act of 2014 (as amended) (the Infrastructure Improvement Financing Act) to authorize the District of Columbia Power Line Undergrounding (DC PLUG) initiative, a projected six year, $500 million project to place underground some of the District of Columbia’s most outage-prone power lines with $250 million of the project costs funded by Pepco and $250 million funded by the District of Columbia.

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

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

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

New Jersey Regulatory Matters

New Jersey ~~Consolidated Tax Adjustment (Exelon, PHI and ACE).~~ ~~The Consolidated Tax Adjustment (CTA) is a~~Clean Energy Legislation. On May 23, 2018, New Jersey ~~ratemaking policy~~enacted legislation that ~~requires utilities~~established a ZEC program that ~~are part of a consolidated tax group~~provides compensation for nuclear plants that demonstrate 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~~that they meet certain requirements, including that they make a ~~generic proceeding~~significant contribution to ~~review~~air quality in the ~~policy. In 2014,~~state and that their revenues are insufficient to cover their costs and risks. Under the legislation, the NJBPU ~~issued a decision which retained~~will issue ZECs to qualifying nuclear power plants and the ~~CTA, but~~electric distribution utilities in ~~a highly modified format that significantly reduced~~New Jersey, including ACE, will be required to purchase those ZECs. On April 18, 2019, the ~~impact~~NJBPU approved the award of ZECs to Salem 1 and Salem 2. Upon approval, Generation began recognizing revenue for the ~~CTA to ACE. On September 18, 2017, the Appellate Division of the Superior Court~~sale of New Jersey ~~reversed~~ZECs in the ~~NJBPU’s decision in adopting~~month they are generated and has recognized $18 million for 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).~~ three months ended March 31, 2020. On ~~March 30, 2017, ACE filed an application with the NJBPU to increase its annual electric distribution rates by $70 million (before~~May 15, 2019, New Jersey ~~sales and use tax), which was updated~~Rate Counsel appealed the NJBPU's decision 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,~~ the New Jersey ~~Division of Rate Counsel~~Superior Court. Exelon and ~~Wal-Mart Stores, Inc. in its electric distribution rate proceeding, which provides for an increase~~

~~Table of Contents~~

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

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

~~in ACE annual electric distribution base rates of $43 million (before New Jersey sales and use tax) reflecting a ROE of 9.6%. In addition, pursuant to~~Generation cannot predict 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 IIoutcome of the rate proceeding and decided at a later date. PowerAhead includes capital investments to enhance the resiliency of the system through improvements focused on improving the distribution system's ability to withstand major storm events. A stipulation of settlement with respect to the PowerAhead program (the PowerAhead Stipulation) was approved by the NJBPU on May 31, 2017. As adopted, the PowerAhead program includes an approved investment level of $79 million to be recovered through the cost recovery mechanism described in the PowerAhead Stipulation. The NJBPU order adopting the PowerAhead Stipulation was effective on June 10, 2017.

~~Update and Reconciliation of Certain Under-Recovered Balances (Exelon, PHI and ACE).~~ ~~On February 1, 2017, ACE submitted its 2017 annual petition with the NJBPU seeking to reconcile and update (i) charges~~appeal. See Note 6 — Early Plant Retirements for additional information related to the recovery of above-market costs associated with ACE’s long-term power purchase contracts with the non-utility generators and (ii) costs related to surcharges for the New Jersey Societal Benefit Program (a statewide public interest program that is intended to benefit low income customers and address other public policy goals) and ACE’s uncollectible accounts. As filed, the net impact of adjusting the charges as proposed would have been an overall annual rate decrease of approximately $29 million (revised to approximately $32 million in April 2017, based upon an update for actuals through March 2017), including New Jersey sales and use tax. On May 31, 2017, the NJBPU approved a stipulation of settlement entered into by the parties providing for an overall annual rate decrease of approximately $32 million, effective June 1, 2017. The rate decrease was placed into effect provisionally, subject to a review by NJBPU and the Division of Rate Counsel of the final underlying costs for reasonableness and prudence. This rate decrease will have no effect on ACE’s operating income, since these revenues provide for recovery of deferred costs under an approved deferral mechanism. The matter is pending at the NJBPU.Salem.

New York Regulatory Matters

New York Clean Energy ~~Standard (Exelon and Generation).~~ Standard.On August 1, 2016, the ~~New York Public Service Commission (NYPSC)~~NYPSC issued an order establishing the New York CES, a component of which is ~~the~~a Tier 3 ZEC program targeted at preserving the environmental attributes of zero-emissions nuclear-powered generating facilities that meet the criteria demonstrating public necessity as determined by the ~~NYPSC. The New York State Energy Research and Development Authority (NYSERDA) will centrally procure the ZECs from eligible plants through a 12-year contract,~~NYPSC 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~~Generation's 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,~~30, 2016 ~~the required contracts with NYSERDA were executed for Ginna and Nine Mile Point, in addition to Entergy’s execution~~(as amended on January 13, 2017), a group 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~~Petition 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~~

~~Table of Contents~~

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

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

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~~which argued that the NYPSC did not have authority to establish the program, that it violated state environmental law and that it violated certain technical provisions of the State Administrative Procedures Act ~~(SAPA)~~ when adopting the ZEC program. On ~~February 15, 2017, Generation~~January 22, 2018, the court dismissed the environmental claims 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,~~majority of the plaintiffs ~~filed a memorandum of law opposing~~from the case but denied the motions to dismiss with respect to the remaining five plaintiffs and ~~Generation and CENG~~claims, without commenting on the merits of the case. On October 8, 2019, the court dismissed all remaining claims. The petitioners filed a ~~reply brief~~notice of appeal on ~~April 28, 2017. Oral argument was held on June 19, 2017. The motions~~November 4, 2019 and originally had until May 4, 2020 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 heldfile their brief. However, on March ~~29, 2017. On July 25, 2017,~~17, 2020, the court ~~granted both motions~~suspended all filing deadlines indefinitely due to ~~dismiss. On August 24, 2017, plaintiffs appealed~~COVID-19, so the ~~decision to~~new deadline will not be known until 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.~~court lifts the suspension.

~~Other legal challenges remain possible, the outcomes of which remain uncertain.~~ See Note ~~7 -~~6 — Early ~~Nuclear~~ Plant Retirements for additional information ~~relative~~related to Ginna and Nine Mile Point. ~~See Note 4 - Mergers, Acquisitions and Dispositions for additional information on Generation's acquisition of FitzPatrick.~~

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

On March 22, 2016, Ginna submitted a compliance filing 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 operations as a result of the noncontrolling interests in CENG.

The RSSA required Ginna to continue operating through the RSSA term. On September 30, 2016, Ginna filed the required notice with the NYPSC of its intent to continue operating beyond the March 31, 2017 expiry of the RSSA, conditioned upon successful execution of an agreement between Ginna and NYSERDA for the sale of ZECs under the New York CES. As stated previously, on November 18, 2016 the required contract with NYSERDA was executed by Generation and CENG for Ginna. Upon the expiry of the RSSA on March 31, 2017, Ginna was required to make refund payments of $20 million to RG&E related to capital expenditures. Ginna paid RG&E the $20 million in June 2017. Additionally, the provisions of the RSSA provided for a one-time payment of $12 million to be paid from RG&E to Ginna at the end of the contract. This $12 million was recognized in 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.

8760

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 2 — Regulatory Matters

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~~

~~Table of Contents~~

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

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

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

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

~~DOE Notice of Proposed Rulemaking (Exelon and Generation).~~ On August 23, 2017, the DOE released its report on the reliability of the electric grid. One aspect of the wide-ranging report is the DOE’s recognition that the electricity markets do not currently value the resiliency provided by baseload generation, such as nuclear plants. On September, 28, 2017, the DOE issued a Notice of Proposed Rulemaking (NOPR) that would entitle certain eligible resilient generating units (i.e., those located in organized markets, with a 90-day supply of fuel on site, not already subject to state cost of service regulation and satisfying certain other requirements) to recover fully allocated costs and earn a fair return on equity on their investment. The DOE issued the NOPR under an infrequently-used section of the DOE Organization Act under which the FERC has exclusive jurisdiction to consider and take any final action related to NOPRs proposed by the DOE. The DOE NOPR recommended that the FERC take comments for 45 days after publication in the Federal Register and issue a final order 60 days after such publication. On October 2, 2017, the FERC issued a notice inviting comments regarding the DOE NOPR within 21 days and established a new docket wherein the FERC will consider the matter. On October 23, 2017, Exelon filed comments with the FERC, supporting the goals of the NOPR and urging the agency to take swift action to protect customers from power supply interruptions and ensure resiliency in a way that appropriately balances the value and cost to customers. Exelon cannot predict the final outcome of the proceeding or its potential impact, if any, on Exelon or Generation.

~~Complaints at FERC Seeking to Mitigate Illinois and New York Programs Providing ZECs (Exelon and Generation).~~ NYISO MOPR Proceedings. 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 effectively 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. Prior to December 19, 2019, the MOPR in PJM applied only to certain new gas-fired resources. Currently, the ~~MOPRs~~MOPR in NYISO applies only to certain resources in downstate New York.

For Generation’s facilities 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 resourcesare currently 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~~would require exclusion of ZEC compensation when bidding into future capacity auctions, ~~such that these facilities would have~~resulting in an increased risk of these facilities not ~~clearing in those auctions and thus no longer~~ receiving capacity revenues ~~during~~in future auctions. While FERC issued a set of orders on MOPR in NYISO on February 20, 2020, it did not expand mitigation to include Generation's nuclear assets in upstate New York. However, FERC has taken action to expand the ~~respective~~MOPR in PJM.

Specifically, on December 19, 2019, FERC issued an order in the PJM MOPR proceeding that broadly applies the MOPR to all new and existing resources including nuclear, renewables, demand response, energy efficiency, storage and all resources owned by vertically-integrated utilities, greatly expanding the breadth and scope of PJM’s MOPR, effective as of PJM’s next capacity auction. While FERC included some limited exemptions (generally available to existing renewable, energy efficiency, demand response, storage and existing vertically-integrated utility resources) in its order, no exemptions were available to state-supported nuclear resources. In addition, FERC provided no new mechanism for accommodating state-supported resources other than the existing FRR mechanism under which an entire utility zone would be removed from PJM’s capacity auction along with sufficient resources to support the load in such zone. FERC directed PJM to make a compliance filing within 90 days, which was filed on March 18, 2020. In that filing, PJM proposes tariff language interpreting and implementing FERC's directives and proposes a schedule for resuming capacity auctions that is contingent on the timing of FERC's action on the compliance filing. FERC has no deadline for such action, and FERC could accept, reject or direct further revisions to all or part of PJM's proposed tariff revisions and auction schedule. In addition, on April 16, 2020, FERC issued orders largely denying requests for rehearing of FERC's December 2019 order and another order in this proceeding. In those orders, FERC also granted a few clarifications that will require an additional PJM compliance filing that could also delay the timing for FERC to issue its compliance order(s) and PJM to resume its capacity auctions.

Unless Illinois and New Jersey can implement an FRR program in their PJM zones, the MOPR will apply to Generation's owned or jointly owned nuclear plants in those states receiving a benefit under the Illinois ZES or the New Jersey ZEC ~~programs. Any~~program, as applicable, increasing the risk that those units may not clear the capacity market.

Exelon is currently working with PJM and other stakeholders to pursue the FRR option prior to the next capacity auction in PJM. If Illinois implements the FRR option, Generation’s Illinois nuclear plants could be removed from PJM’s capacity auction and instead supply capacity and be compensated under the FRR program, which has the potential to mitigate the current economic distress being experienced by Generation's nuclear plants in Illinois, as discussed in Note 6 - Early Plant Retirements. Implementing the FRR program in Illinois will require both legislative and regulatory changes. Legislation may be introduced in New Jersey as well. Exelon cannot predict whether such ~~mitigation of these generating resources~~legislative and regulatory changes can be implemented prior to the next capacity auction in PJM.

If Generation’s state-supported nuclear plants in PJM are subjected to the MOPR or equivalent without compensation under an FRR or similar program, it could have a material ~~effect~~adverse impact on ~~Exelon’s~~Exelon's and ~~Generation’s future cash flows~~Generation's financial statements, which Exelon 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.Generation cannot reasonably estimate at this time.

~~Table of Contents~~

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

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

Operating License Renewals ~~(Exelon and Generation).~~

Conowingo Hydroelectric Project. On August 29, 2012, Generation submitted a hydroelectric license application to FERC for a ~~46-year~~new license for the Conowingo Hydroelectric Project (Conowingo). In connection with Generation’s efforts to obtain a water quality certification pursuant to Section 401 of the Clean Water Act ~~with Maryland Department of the Environment (MDE)~~(401 Certification) from MDE for Conowingo, Generation ~~continues to work~~has been working 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, regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent the excess recovery of costs or accrued credits that have been deferred because it is probable such amounts will be returned to customers through future regulated rates or represent billings in advance of expenditures for approved regulatory programs.

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

9061

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 32 — Regulatory Matters

On October 29, 2019, Generation and MDE filed with FERC a Joint Offer of Settlement (Offer of Settlement) that would resolve all outstanding issues relating to the 401 Certification. Pursuant to the Offer of Settlement, the parties submitted Proposed License Articles to FERC to be incorporated by FERC into the new license in accordance with FERC’s discretionary authority under the Federal Power Act. Among the Proposed License Articles are modifications to river flows to improve aquatic habitat, eel passage improvements and initiatives to support rare, threatened and endangered wildlife. If FERC approves the Offer of Settlement and incorporates the Proposed License Articles into the new license without modification, then MDE would waive its rights to issue a 401 Certification and Generation would agree, pursuant to a separate agreement with MDE (MDE Settlement), to implement additional environmental protection, mitigation and enhancement measures over the anticipated 50-year term of the new license. These measures address mussel restoration and other ecological and water quality matters, among other commitments. Exelon’s commitments under the various provisions of the Offer of Settlement and MDE Settlement are not effective unless and until FERC approves the Offer of Settlement and issues the new license with the Proposed License Articles. Generation cannot currently predict when FERC will issue the new license.

Peach Bottom Units 2 and 3. On July 10, 2018, Generation submitted a second 20-year license renewal application with the NRC for Peach Bottom Units 2 and 3, which was approved on March 6, 2020. Peach Bottom Units 2 and 3 are now licensed to operate through 2053 and 2054, respectively.

3. Revenue from Contracts with Customers (All Registrants)

The Registrants recognize revenue from contracts with customers to depict the transfer of goods or services to customers at an amount that the entities expect to be entitled to in exchange for those goods or services. Generation’s primary sources of revenue include competitive sales of power, natural gas, and other energy-related products and services. The Utility Registrants’ primary sources of revenue include regulated electric and gas tariff sales, distribution and transmission services.

See Note 4 — Revenue from Contracts with Customers of the Exelon ~~2016~~2019 Form ~~10-K.~~10-K for additional information regarding the primary sources of revenue for the Registrants.

Contract Balances (All Registrants)

Contract Assets and Liabilities

Generation records contract assets for the revenue recognized on the construction and installation of energy efficiency assets and new power generating facilities before Generation has an unconditional right to bill for and receive the consideration from the customer. These contract assets are subsequently reclassified to receivables when the right to payment becomes unconditional. Generation records contract assets and contract receivables within Other current assets and Customer accounts receivable, net, respectively, within Exelon’s and Generation’s Consolidated Balance Sheets.

Generation records contract liabilities when consideration is received or due prior to the satisfaction of the performance obligations. These contract liabilities primarily relate to upfront consideration received or due for equipment service plans, solar panel leases and the Illinois ZEC program that introduces a cap on the total consideration to be received by Generation. Generation records contract liabilities within Other current liabilities and Other noncurrent liabilities within Exelon's and Generation's Consolidated Balance Sheets.

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
$ —

9162

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 3 — Revenue from Contracts with Customers

The following table provides a rollforward of the contract assets and liabilities reflected in Exelon's and Generation's Consolidated Balance Sheets for the three months ended March 31, 2019 and March 31, 2020

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



	Contract Assets						Contract Liabilities
	Exelon			Generation			Exelon			Generation
Balance as of December 31, 2018	$	187		$	187		$	27		$	42
Consideration received or due	(26		)	(26		)	21			63
Revenues recognized ^(a)	26			26			(23		)	(66		)
Balance at March 31, 2019	$	187		$	187		$	25		$	39

Balance as of December 31, 2019	$	174		$	174		$	33		$	71
Consideration received or due	(19		)	(19		)	20			55
Revenues recognized ^(b)	17			17			(24		)	(70		)
Balance at March 31, 2020	$	172		$	172		$	29		$	56

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~~Revenues recognized in the three months ended March 31, 2019, which were included in contract liabilities at December 31, ~~2016, the pension~~2018, were approximately $5 million for both Exelon 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.Generation.

(b)

~~As of September 30, 2017, includes transmission-related income tax regulatory assets that require FERC approval separate from~~Revenues recognized in 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~~three months ended March 31, 2020, which were included in contract liabilities at 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~~2019, were approximately $9 million and $19 million for ~~ComEd, BGE, Pepco, DPL~~Exelon and ~~ACE,~~Generation, 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

The Utility Registrants do not have any contract assets. The Utility Registrants also record contract liabilities when consideration is received prior to the satisfaction of the performance obligations. As of March 31, 2020 and December 31, 2019, the Utility Registrants' contract liabilities were immaterial.

Transaction Price Allocated to Remaining Performance Obligations (All Registrants)

The following table shows the amounts of future revenues expected to be recorded in each year for performance obligations that are unsatisfied or partially unsatisfied as of March 31, 2020. This disclosure only includes contracts for which the total consideration is fixed and determinable at contract inception. The average contract term varies by customer type and commodity but ranges from one month to several years.

This disclosure excludes Generation's power and gas sales contracts as they contain variable volumes and/or variable pricing. This disclosure also excludes the Utility Registrants' gas and electric tariff sales contracts and transmission revenue contracts as they generally have an original expected duration of one year or less and, therefore, do not contain any future, unsatisfied performance obligations to be included in this disclosure.



	2020		2021		2022		2023		2024 and thereafter		Total
Exelon	$	273	$	144	$	64	$	45	$	198	$	724
Generation	330		200		79		45		198		852

Revenue Disaggregation (All Registrants)

The Registrants disaggregate revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. See Note 4 — Segment Information for the presentation of the Registrant's revenue disaggregation.

4. Segment Information (All Registrants)

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

Exelon has 11 reportable segments, which include Generation's 5 reportable segments consisting of the Mid-Atlantic, Midwest, New York, ERCOT and all other power regions referred to collectively as “Other Power Regions”

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 4 — Segment Information

and ~~made effective BGE’s proposed modifications to its transmission formula rate, subject to refund~~ComEd, PECO, BGE, and ~~further Commission order.~~PHI's 3 reportable segments consisting of Pepco, DPL and ACE. ComEd, PECO, BGE, Pepco, DPL and ACE each represent a single reportable segment, and as such, no separate segment information is provided for these Registrants. Exelon, ComEd, PECO, BGE, Pepco, DPL and ACE's CODMs evaluate the performance of and allocate resources to ComEd, PECO, BGE, Pepco, DPL and ACE based on net income.

The basis for Generation's reportable segments is the integrated management of its electricity business that is located in different geographic regions, and largely representative of the footprints of ISO/RTO and/or NERC regions, which utilize multiple supply sources to provide electricity through various distribution channels (wholesale and retail). Generation's hedging strategies and risk metrics are ~~expected~~also aligned to ~~make similar filings with FERC and other parties in subsequent periods.~~these same geographic regions. Descriptions of each of Generation’s 5 reportable segments are as follows:

~~(c)~~•

Mid-Atlantic represents operations in the eastern half of ~~September 30, 2017, ComEd’s regulatory asset~~PJM, which includes New Jersey, Maryland, Virginia, West Virginia, Delaware, the District of ~~$256 million was comprised~~Columbia and parts of ~~$200 million for the 2015 - 2017 annual reconciliations~~Pennsylvania 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.North Carolina.

~~(d)~~•

Midwest represents operations in the western half of ~~September 30, 2017, ComEd’s regulatory liability~~PJM and the United States footprint 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.MISO, excluding MISO’s Southern Region.

~~(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.

New York represents operations within NYISO.

~~(f)~~•

ERCOT represents operations within Electric Reliability Council 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.Texas.

Other Power Regions:


•	New England represents the operations within ISO-NE.

~~(g)~~•

South represents operations in the FRCC, MISO’s Southern Region, and the remaining portions of ~~September 30, 2017, Pepco's regulatory asset of $6 million~~the SERC not 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.within MISO or PJM.

~~(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.

West represents operations in the WECC, which includes California ISO.

~~(i)~~•

Canada represents operations across the entire country of ~~September 30, 2017, ACE's regulatory asset~~Canada and includes AESO, OIESO and the Canadian portion 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.MISO.

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

Generation evaluate the performance of Generation’s electric business activities and allocate resources based on RNF. Generation believes that RNF is a useful measurement of operational performance. RNF is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report. Generation’s operating revenues include all sales to third parties and affiliated sales to the Utility Registrants. Purchased power costs include all costs associated with the procurement and supply of electricity including capacity, energy and ancillary services. Fuel expense includes the fuel costs for Generation’s owned generation and fuel costs associated with tolling agreements. The ~~following table illustrates our authorized amounts capitalized for ratemaking purposes related to earnings on shareholders’ investment~~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 ~~recognized for financial reporting purposes~~significant to Generation's overall operating revenues or results of operations. Further, Generation’s unrealized mark-to-market gains and losses on ~~our Consolidated Balance Sheets. These amounts will be recognized as revenues~~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 ~~our Consolidated Statements~~making decisions regarding allocating resources to or assessing the performance of ~~Operations~~these reportable segments.

An analysis and ~~Comprehensive Income~~reconciliation of the Registrants’ reportable segment information to the respective information in the ~~periods they are billable to our customers.~~consolidated financial statements for the three months ended March 31, 2020 and 2019 is as follows:

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

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

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

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

~~_________~~


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


~~(b)~~	~~BGE's authorized amounts capitalized for ratemaking purposes primarily relate to earnings on shareholders' investment on its AMI Programs.~~


~~(c)~~	Pepco's and DPL's authorized amounts capitalized for ratemaking purposes relate to earnings on shareholders' investment on their respective AMI Programs and Energy Efficiency and Demand Response Programs. The earnings on energy efficiency are on Pepco DC and DPL DE programs only.

9364

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 4 — Segment Information

~~Purchase~~

Three Months Ended March 31, 2020 and 2019



	Generation^(a)		ComEd		PECO		BGE		PHI		Other^(b)		Intersegment Eliminations			Exelon
Operating revenues^(c):
2020
Competitive businesses electric revenues	$	3,752	$	—	$	—	$	—	$	—	$	—	$	(326	)	$	3,426
Competitive businesses natural gas revenues	672		—		—		—		—		—		(3		)	669
Competitive businesses other revenues	309		—		—		—		—		—		(1		)	308
Rate-regulated electric revenues	—		1,439		604		613		1,104		—		(12		)	3,748
Rate-regulated natural gas revenues	—		—		209		324		64		—		(2		)	595
Shared service and other revenues	—		—		—		—		3		480		(482		)	1
Total operating revenues	$	4,733	$	1,439	$	813	$	937	$	1,171	$	480	$	(826	)	$	8,747
2019
Competitive businesses electric revenues	$	4,337	$	—	$	—	$	—	$	—	$	—	$	(315	)	$	4,022
Competitive businesses natural gas revenues	879		—		—		—		—		—		(1		)	878
Competitive businesses other revenues	80		—		—		—		—		—		(1		)	79
Rate-regulated electric revenues	—		1,408		620		658		1,153		—		(8		)	3,831
Rate-regulated natural gas revenues	—		—		280		318		71		—		(4		)	665
Shared service and other revenues	—		—		—		—		4		455		(457		)	2
Total operating revenues	$	5,296	$	1,408	$	900	$	976	$	1,228	$	455	$	(786	)	$	9,477
Intersegment revenues^(d):
2020	$	330	$	5	$	2	$	6	$	3	$	479	$	(824	)	$	1
2019	317		4		1		6		4		453		(785		)	—
Depreciation and amortization:
2020	$	304	$	273	$	86	$	143	$	194	$	21	$	—		$	1,021
2019	405		251		81		136		180		22		—			1,075
Operating expenses:
2020	$	4,400	$	1,151	$	625	$	688	$	1,000	$	481	$	(816	)	$	7,529
2019	4,963		1,135		678		756		1,054		459		(783		)	8,262
Interest expense, net:
2020	$	109	$	94	$	36	$	32	$	67	$	72	$	—		$	410
2019	111		87		33		29		65		78		—			403

Table of ~~Receivables Programs (Exelon,~~Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 4 — Segment Information



	Generation^(a)			ComEd		PECO		BGE		PHI		Other^(b)			Intersegment Eliminations			Exelon
Income (loss) before income taxes:
2020	$	(547	)	$	204	$	155	$	222	$	119	$	(69	)	$	1		$	85
2019	652			197		193		196		122		(78		)	—			1,282
Income Taxes:
2020	$	(389	)	$	36	$	15	$	41	$	11	$	(8	)	$	—		$	(294	)
2019	224			40		25		36		5		(20		)	—			310
Net income (loss):
2020	$	(161	)	$	168	$	140	$	181	$	108	$	(61	)	$	1		$	376
2019	422			157		168		160		117		(58		)	—			966
Capital Expenditures
2020	$	558		$	506	$	259	$	283	$	376	$	34		$	—		$	2,016
2019	511			503		222		258		358		21			—			1,873
Total assets:
March 31, 2020	$	47,882		$	33,146	$	11,535	$	10,789	$	22,753	$	8,337		$	(9,765	)	$	124,677
December 31, 2019	48,995			32,765		11,469		10,634		22,719		8,484			(10,089		)	124,977

__________


(a)	See Note 18 — Related Party Transactions for additional information on intersegment revenues.


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


(c)	Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 17 — Supplemental Financial Information for additional information on total utility taxes.

(d)

Intersegment revenues exclude sales to unconsolidated affiliates. The intersegment profit associated with Generation’s sale of certain products and services by and between Exelon’s segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in Operating revenues in the Consolidated Statements 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 4 — Segment Information

PHI:



	Pepco		DPL		ACE		Other^(b)			Intersegment Eliminations			PHI
Operating revenues^(a):
2020
Rate-regulated electric revenues	$	544	$	286	$	276	$	—		$	(2	)	$	1,104
Rate-regulated natural gas revenues	—		64		—		—			—			64
Shared service and other revenues	—		—		—		93			(90		)	3
Total operating revenues	$	544	$	350	$	276	$	93		$	(92	)	$	1,171
2019
Rate-regulated electric revenues	$	575	$	310	$	273	$	—		$	(5	)	$	1,153
Rate-regulated natural gas revenues	—		70		—		—			1			71
Shared service and other revenues	—		—		—		106			(102		)	4
Total operating revenues	$	575	$	380	$	273	$	106		$	(106	)	$	1,228
Intersegment revenues:
2020	$	1	$	2	$	1	$	92		$	(93	)	$	3
2019	2		2		1		105			(106		)	4
Depreciation and amortization:
2020	$	95	$	48	$	43	$	9		$	(1	)	$	194
2019	94		46		31		10			(1		)	180
Operating expenses:
2020	$	462	$	284	$	251	$	93		$	(90	)	$	1,000
2019	491		308		252		108			(105		)	1,054
Interest expense, net:
2020	$	34	$	16	$	15	$	3		$	(1	)	$	67
2019	34		15		14		3			(1		)	65
Income (loss) before income taxes:
2020	$	57	$	52	$	14	$	106		$	(110	)	$	119
2019	57		60		10		113			(118		)	122
Income Taxes:
2020	$	5	$	7	$	1	$	(2	)	$	—		$	11
2019	2		7		—		(4		)	—			5
Net income (loss):
2020	$	52	$	45	$	13	$	(5	)	$	3		$	108
2019	55		53		10		(5		)	4			117
Capital Expenditures
2020	$	180	$	95	$	101	$	—		$	—		$	376
2019	144		78		128		8			—			358
Total assets:
March 31, 2020	$	8,837	$	4,849	$	3,978	$	11,241		$	(6,152	)	$	22,753
December 31, 2019	8,661		4,830		3,933		11,105			(5,810		)	22,719

__________


(a)	Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 17 — Supplemental Financial Information for additional information on total utility taxes.


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

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 4 — Segment Information

The following tables disaggregate the Registrants' revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. For Generation, the disaggregation of revenues reflects Generation’s two primary products of power sales and natural gas sales, with further disaggregation of power sales provided by geographic region. For the Utility Registrants, the disaggregation of revenues reflects the two primary utility services of rate-regulated electric sales and rate-regulated natural gas sales (where applicable), with further disaggregation of these tariff sales provided by major customer groups. Exelon’s disaggregated revenues are consistent with Generation and the Utility Registrants, but exclude any intercompany revenues.

Competitive Business Revenues (Generation):



	Three Months Ended March 31, 2020
	Revenues from external customers^(a)							Intersegment Revenues			Total Revenues
	Contracts with customers		Other^(b)			Total		Intersegment Revenues			Total Revenues
Mid-Atlantic	$	1,264	$	(96	)	$	1,168	$	6		$	1,174
Midwest	944		64			1,008		(6		)	1,002
New York	335		(21		)	314		—			314
ERCOT	155		28			183		7			190
Other Power Regions	1,007		72			1,079		(7		)	1,072
Total Competitive Businesses Electric Revenues	3,705		47			3,752		—			3,752
Competitive Businesses Natural Gas Revenues	503		169			672		—			672
Competitive Businesses Other Revenues^(c)	99		210			309		—			309
Total Generation Consolidated Operating Revenues	$	4,307	$	426		$	4,733	$	—		$	4,733



	Three Months Ended March 31, 2019
	Revenues from external customers^(a)							Intersegment revenues			Total Revenues
	Contracts with customers		Other^(b)			Total		Intersegment revenues			Total Revenues
Mid-Atlantic	$	1,286	$	(24	)	$	1,262	$	(6	)	$	1,256
Midwest	1,055		59			1,114		(6		)	1,108
New York	409		(16		)	393		—			393
ERCOT	130		79			209		3			212
Other Power Regions	1,165		194			1,359		(6		)	1,353
Total Competitive Businesses Electric Revenues	4,045		292			4,337		(15		)	4,322
Competitive Businesses Natural Gas Revenues	584		295			879		15			894
Competitive Businesses Other Revenues^(c)	120		(40		)	80		—			80
Total Generation Consolidated Operating Revenues	$	4,749	$	547		$	5,296	$	—		$	5,296

__________


(a)	Includes all wholesale and retail electric sales to third parties and affiliated sales to the Utility Registrants.


(b)	Includes revenues from derivatives and leases.


(c)	Other represents activities not allocated to a region. See text above for a description of included activities. Includes unrealized mark-to-market gains of $179 million and losses of $52 million in 2020 and 2019, respectively, and elimination of intersegment revenues.

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 4 — Segment Information

Revenues net of purchased power and fuel expense (Generation):



	Three Months Ended March 31, 2020							Three Months Ended March 31, 2019
	RNF from external customers^(a)		Intersegment RNF			Total RNF		RNF from external customers^(a)		Intersegment RNF			Total RNF
Mid-Atlantic	$	559	$	8		$	567	$	679	$	4		$	683
Midwest	732		(5		)	727		769		2			771
New York	189		4			193		262		3			265
ERCOT	76		4			80		98		(24		)	74
Other Power Regions	177		(19		)	158		174		(18		)	156
Total Revenues net of purchased power and fuel expense for Reportable Segments	1,733		(8		)	1,725		1,982		(33		)	1,949
Other^(b)	296		8			304		109		33			142
Total Generation Revenues net of purchased power and fuel expense	$	2,029	$	—		$	2,029	$	2,091	$	—		$	2,091

__________


(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 unrealized mark-to-market gains of $132 million and losses of $28 million in 2020 and 2019, respectively and the elimination of intersegment RNF.

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 4 — Segment Information

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



	Three Months Ended March 31, 2020
Revenues from contracts with customers	ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Rate-regulated electric revenues
Residential	$	701	$	382	$	339	$	534	$	236	$	161	$	137
Small commercial & industrial	362		99		67		115		35		43		37
Large commercial & industrial	134		53		103		253		188		23		42
Public authorities & electric railroads	13		7		7		15		9		3		3
Other^(a)	211		58		79		169		60		54		55
Total rate-regulated electric revenues^(b)	$	1,421	$	599	$	595	$	1,086	$	528	$	284	$	274
Rate-regulated natural gas revenues
Residential	$	—	$	150	$	206	$	40	$	—	$	40	$	—
Small commercial & industrial	—		51		34		17		—		17		—
Large commercial & industrial	—		—		51		1		—		1		—
Transportation	—		6		—		4		—		4		—
Other^(c)	—		1		9		2		—		2		—
Total rate-regulated natural gas revenues^(d)	$	—	$	208	$	300	$	64	$	—	$	64	$	—
Total rate-regulated revenues from contracts with customers	$	1,421	$	807	$	895	$	1,150	$	528	$	348	$	274

Other revenues
Revenues from alternative revenue programs	$	12	$	2	$	36	$	18	$	15	$	1	$	1
Other rate-regulated electric revenues^(e)	6		3		3		3		1		1		1
Other rate-regulated natural gas revenues^(e)	—		1		3		—		—		—		—
Total other revenues	$	18	$	6	$	42	$	21	$	16	$	2	$	2
Total rate-regulated revenues for reportable segments	$	1,439	$	813	$	937	$	1,171	$	544	$	350	$	276

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 4 — Segment Information



	Three Months Ended March 31, 2019
Revenues from contracts with customers	ComEd			PECO			BGE		PHI		Pepco		DPL		ACE
Rate-regulated electric revenues
Residential	$	710		$	409		$	385	$	579	$	256	$	185	$	138
Small commercial & industrial	360			96			70		120		38		48		34
Large commercial & industrial	132			48			110		267		204		24		39
Public authorities & electric railroads	13			7			7		14		8		3		3
Other^(a)	217			62			80		157		53		47		57
Total rate-regulated electric revenues^(b)	$	1,432		$	622		$	652	$	1,137	$	559	$	307	$	271
Rate-regulated natural gas revenues
Residential	$	—		$	198		$	219	$	44	$	—	$	44	$	—
Small commercial & industrial	—			72			35		19		—		19		—
Large commercial & industrial	—			1			50		1		—		1		—
Transportation	—			7			—		4		—		4		—
Other^(c)	—			2			4		3		—		3		—
Total rate-regulated natural gas revenues^(d)	$	—		$	280		$	308	$	71	$	—	$	71	$	—
Total rate-regulated revenues from contracts with customers	$	1,432		$	902		$	960	$	1,208	$	559	$	378	$	271

Other revenues
Revenues from alternative revenue programs	$	(28	)	$	(3	)	$	10	$	15	$	14	$	—	$	1
Other rate-regulated electric revenues^(e)	4			1			3		4		2		1		1
Other rate-regulated natural gas revenues^(e)	—			—			3		1		—		1		—
Total other revenues	$	(24	)	$	(2	)	$	16	$	20	$	16	$	2	$	2
Total rate-regulated revenues for reportable segments	$	1,408		$	900		$	976	$	1,228	$	575	$	380	$	273

__________


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

(b)

Includes operating revenues from affiliates of $5 million, $2 million, $6 million, $3 million, $1 million, $2 million and $1 million at ComEd, PECO, BGE, PHI, ~~Pepco, DPL and ACE)~~

~~ComEd, PECO, BGE,~~ Pepco, DPL and ACE, respectively, in 2020 and $4 million, $1 million, $2 million, $3 million, $2 million, $2 million and $1 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2019.


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


(d)	Includes operating revenues from affiliates of less than $1 million and $3 million at PECO and BGE, respectively, in 2020 and less than $1 million and $4 million at PECO and BGE, respectively, in 2019.


(e)	Includes late payment charge revenues.

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 5 — Accounts Receivable

5. Accounts Receivable (All Registrants)

Unbilled Customer Revenue

The following table provides additional information about unbilled customer revenues recorded in the Registrants' Consolidated Balance Sheets.



	Unbilled customer revenues^(a)
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
March 31, 2020	$	1,225	$	698	$	160	$	96	$	134	$	137	$	75	$	42	$	20
December 31, 2019	1,535		807		218		146		170		194		100		61		33

_________


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

Allowance for Credit Losses on Accounts Receivable

The following table presents the rollforward of Allowance for Credit Losses on Customer Accounts Receivable.



	Three Months Ended March 31, 2020
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance as of December 31, 2019	$	243	$	80	$	59	$	55	$	12	$	37	$	13	$	11	$	13
Plus: Current Period Provision for Expected Credit Losses	55		4		18		18		8		7		3		2		2
Less: Write-offs, net of recoveries^(a)	20		3		6		7		2		2		1		—		1
Balance as of March 31, 2020	$	278	$	81	$	71	$	66	$	18	$	42	$	15	$	13	$	14

_________


(a)	Recoveries were not material to the Registrants.

The following table presents the rollforward of Allowance for Credit Losses on Other Accounts Receivable.



	Three Months Ended March 31, 2020
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance as of December 31, 2019	$	48	$	—	$	20	$	7	$	5	$	16	$	7	$	4	$	5
Plus: Current Period Provision for Expected Credit Losses	8		—		3		1		2		2		1		—		1
Less: Write-offs, net of recoveries^(a)	4		—		1		1		2		—		—		—		—
Balance as of March 31, 2020	$	52	$	—	$	22	$	7	$	5	$	18	$	8	$	4	$	6

_________


(a)	Recoveries were not material to the Registrants.

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 5 — Accounts Receivable

Purchases and Sales of Customer and Other Accounts Receivables

Generation is required, under supplier tariffs in ISO-NE, MISO, NYISO and PJM, to sell customer and other receivables to utility companies, which include the Utility Registrants. The Utility Registrants are required, under separate legislation and regulations in Illinois, Pennsylvania, Maryland, District of Columbia 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 ~~receivables of those companies as of September 30, 2017~~ and ~~December 31, 2016.~~sold.



	Three Months Ended March 31, 2020
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Total Receivables Purchased	$	781	$	—	$	280	$	284	$	195	$	264	$	165	$	53	$	46
Total Receivables Sold	507		749		—		—		—		—		—		—		—

Related Party Transactions:
Receivables purchased from Generation	—		—		34		67		69		72		51		13		8
Receivables sold to the Utility Registrants	—		242		—		—		—		—		—		—		—

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)~~

14 - Debt and Credit Agreements of 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 Income 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 the Exelon 2016 Form 10-K for further information.

In the second quarter of 2016, updates to the Company's long-term view of energy and capacity prices suggested that the carrying value of a group of merchant wind assets, located in West Texas, may be impaired. Upon review, the estimated undiscounted future cash flows and fair value of the group were less than their carrying value. The fair value analysis was based on the income approach using significant unobservable inputs (Level 3) including revenue and generation forecasts, projected capital and maintenance expenditures and discount rates. As a result of the fair value analysis, long-lived assets held and used with a carrying amount of approximately $60 million were written down to their fair value of $24 million and a pre-tax impairment charge of $36 million was recorded during the second quarter in Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

Also 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 review of the estimated undiscounted future cash flows 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 MEAG as part of the transactions (Leases).

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

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

Exelon and Generation ~~continue to~~continuously evaluate factors that affect 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,~~including, 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 benefits they provide through their carbon-free emissions, reliability, or fuel security, and the impact of potential rules from the EPA requiring reduction of carbon and other emissions and the efforts of states to implement those final rules. The precise timing of an early retirement date for any ~~nuclear~~ plant, and the resulting financial statement impacts, may be affected by ~~a number of~~many 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~~NDT fund requirements for nuclear plants, among other factors. However, the earliest retirement date for any plant would usually be the first year in which the unit does not have capacity or other obligations, and where applicable, ~~and~~ just prior to its next scheduled nuclear refueling outage.

Nuclear Generation

In 2015 and 2016, Generation identified the Clinton and Quad Cities nuclear plants in Illinois, Ginna and Nine Mile Point nuclear plants in New York and Three Mile Island ~~(TMI)~~ nuclear ~~plants~~plant in Pennsylvania as having the greatest risk of early retirement based on economic valuation and other factors. In 2017, PSEG ~~has also recently~~ made public similar financial challenges facing its New Jersey nuclear plants, including Salem, of which Generation owns a 42.59% ownership interest. PSEG is the operator of Salem and also has the decision-making authority to retire Salem.

Assuming the continued effectiveness of the Illinois ZES, New Jersey ZEC program and the New York CES, Generation and CENG, through its ownership of Ginna and Nine Mile Point, no longer consider Clinton, Quad Cities, Salem, Ginna or Nine Mile Point to be at heightened risk for early retirement. However, to the extent the Illinois ZES, New Jersey ZEC program or the New York CES do not operate as expected over their full terms, each of these plants could again be at heightened risk for early retirement, which could have a material impact on Exelon’s and Generation’s future financial statements. In addition, FERC’s December 19, 2019 order on the MOPR in PJM may undermine the continued effectiveness of the Illinois ZES and the New Jersey ZEC program unless Illinois and New Jersey implement an FRR mechanism under which the Generation plants in these states would be removed from PJM’s capacity auction. See Note 2 — Regulatory Matters for additional information on the New Jersey ZEC program, New York CES and FERC's December 19, 2019 order and Note 3 — Regulatory Matters of the 2019 Form 10-K for additional information on the Illinois ZES.

9573

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 6 — Early Plant Retirements

~~of which Generation owns a 42.59% ownership interest. As previously disclosed, Exelon and Generation have committed to cease operation of~~

In Pennsylvania, the ~~Oyster Creek nuclear plant by the end of 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~~auction and on May ~~2019.~~

~~Based~~30, 2017, based on these capacity auction results, prolonged periods of low wholesale power prices, and the absence of federal or state policies that place a value on nuclear energy for its ability to produce electricity without air pollution, ~~Exelon~~Generation announced that ~~Generation will~~it would permanently cease generation operations at ~~TMI on or about~~TMI. On September ~~30, 2019. The current NRC license for TMI expires in 2034.~~20, 2019, 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 notification to the NRC on June 20, 2017. PJM has subsequently notified Generation that it has not identified any reliability issues and has approved the deactivation of TMI as proposed.permanently ceased generation operations at TMI.

~~In 2017, as~~As a result of the early nuclear plant retirement decision ofat 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~~lives primarily related to accelerated depreciation of plant assets (including any ARC), and accelerated amortization of nuclear fuel, as well as operating and ~~additional ARO accretion expense associated with the changes in decommissioning timing and cost assumptions. During~~maintenance expenses. The total impact for the three ~~and nine~~ months ended September 30, 2017, both Exelon’s and Generation’s results include an incremental $112 million and $149 million, respectively, of pre-tax expense for these items. Please refer to Note 13 — Nuclear Decommissioning for additional detail on changes toMarch 31, 2019 are summarized in the ~~nuclear decommissioning ARO balances resulting from the early retirement of TMI.~~table below.


Income statement expense (pre-tax)	Q3 2017		YTD 2017		Three Months Ended March 31, 2019
Depreciation and amortization
Accelerated depreciation^(a)	$	106	$	141	$	74
Accelerated nuclear fuel amortization	6		8		5
Operating and maintenance^(a)					(83		)
Total	$	112	$	149	$	(4	)

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 13 — Fair Value of Financial Assets and Liabilities

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)~~

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~~

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

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

~~ACE~~

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

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

~~_________~~

~~(a)~~

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


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

~~Short-Term Liabilities.~~ The short-term liabilities included in the tables above are comprised of dividends payable (included in other current liabilities) (Level 1) and short-term borrowings (Level 2). The Registrants’ carrying amounts of the short-term liabilities are representative of fair value because of the short-term nature of these instruments.

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

The fair value of Generation’s and Pepco's non-government-backed fixed rate nonrecourse debt (Level 3) is based on market and quoted prices for its own and other nonrecourse debt with similar risk profiles. Given the low trading volume in the nonrecourse debt market, the price quotes used to determine fair value will reflect certain qualitative factors, such as market conditions, investor demand, new developments that might significantly impact the project

~~100~~

~~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~~Short-Term Borrowings

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

Commercial Paper

The following table reflects the Registrants' commercial paper programs as of March 31, 2020 and December 31, 2019. PECO had no commercial paper borrowings as of both March 31, 2020 and December 31, 2019.



	Outstanding Commercial Paper as of				Average Interest Rate on Commercial Paper Borrowings as of
Commercial Paper Issuer	March 31, 2020		December 31, 2019		March 31, 2020		December 31, 2019
Exelon^(a)	$	979	$	870	2.91	%	2.25	%
Generation	595		320		2.01	%	1.84	%
ComEd	—		130		—	%	2.38	%
BGE	141		76		4.45	%	2.46	%
PHI^(b)	108		208		4.25	%	N/A
PEPCO	—		82		—	%	2.56	%
DPL	54		56		4.17	%	2.02	%
ACE	54		70		4.32	%	2.43	%

__________


(a)	Includes outstanding commercial paper at Exelon Corporate of $135 million and $136 million with average interest rates on commercial paper borrowings of 4.20% and 1.92% at March 31, 2020 and December 31, 2019, respectively.


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

On March 19, 2020, Generation borrowed $1.5 billion on its revolving credit facility due to disruptions in the commercial paper markets as a result of COVID-19, which is recorded in Long-term debt on Exelon’s and Generation’s Consolidated Balance Sheet. The funds were used to refinance commercial paper. Generation repaid the $1.5 billion borrowed on the revolving credit facility on April 3, 2020. As of March 31, 2020, the available capacity on Generation’s revolving credit facility was $2.4 billion. See Note 16— Debt and Credit Agreements of the Exelon 2019 Form 10-K for additional information on the Registrants’ credit facilities.

Short-Term Loan Agreements

On March 23, 2017, Exelon Corporate entered into a term loan agreement for $500 million. The loan agreement was renewed on March 19, 2020 and will expire on March 18, 2021. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.65% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Exelon's Consolidated Balance Sheet within Short-Term borrowings.

On March 19, 2020, Generation entered into a term loan agreement for $200 million. The loan agreement has an expiration of March 18, 2021. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.50% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Generation's Consolidated Balance Sheet within Short-term borrowings.

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 12 — Debt and Credit Agreements

On March 31, 2020, Generation entered into a term loan agreement for $300 million. The loan agreement has an expiration of March 30, 2021. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.75% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Generation's Consolidated Balance Sheet within Short-term borrowings.

Credit Agreements

On April 24, 2020, Exelon Corporate entered into a credit agreement establishing a $550 million 364-day revolving credit facility at a variable interest rate of LIBOR plus 1.75%. This facility will be used by Exelon as an additional source of short-term liquidity over the next 12 months.

Long-Term Debt

Issuance of Long-Term Debt

During the three months ended March 31, 2020, the following long-term debt was issued:

Company

Type

Interest Rate

Maturity

Amount

Use of Proceeds

Generation

Energy Efficiency Project Financing^(a)

3.95

August 31, 2020

Funding to install energy conservation measures for the Fort Meade project.

Generation

Energy Efficiency Project Financing^(a)

2.53

April 30, 2021

Funding to install energy conservation measures for the Fort AP Hill project.

ComEd

First Mortgage Bonds, Series 129

3.00

March 1, 2050

650

Repay a portion of outstanding commercial paper obligations and to fund general corporate purposes.

ComEd

First Mortgage Bonds, Series 128

2.20

March 1, 2030

350

Repay a portion of outstanding commercial paper obligations and fund other general corporate purposes.

Pepco^(b)

First Mortgage Bonds

2.53

February 25, 2030

150

Repay existing indebtedness and for general corporate purposes.

__________


(a)	For Energy Efficiency Project Financing, the maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt.


(b)	On February 25, 2020, Pepco entered into a purchase agreement of First Mortgage Bonds for $150 million at 3.28% due on September 23, 2050. The closing date of the issuance is expected to occur in September 2020.

On April 1, 2020, Exelon Corporate issued notes for $1.25 billion at 4.05%, which are due in 2030 and notes for $750 million at 4.70%, which are due in 2050. A portion of the net proceeds from the sale of these notes, together with available cash balances, will be used to repay $900 million of Exelon Corporate notes maturing in June of 2020. The remainder of the net proceeds will be used for general corporate purposes.

Debt Covenants

As of March 31, 2020, the Registrants are in compliance with debt covenants, except for Antelope Valley's ongoing nonrecourse debt event of default as discussed below.

Nonrecourse Debt

Exelon and Generation have issued nonrecourse debt financing. 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.

Antelope Valley Solar Ranch One. In December 2011, the DOE Loan Programs Office issued a guarantee for up to $646 million for a nonrecourse loan from the Federal Financing Bank to support the financing of the construction of the Antelope Valley facility. The project became fully operational in 2014. The loan will mature on January 5, 2037. As of March 31, 2020, approximately $479 million was outstanding. In addition, Generation has issued letters of credit to support its equity investment in the project. As of March 31, 2020, Generation had $37 million in letters of

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 12 — Debt and Credit Agreements

credit outstanding related to the project. In 2017, Generation’s interests in Antelope Valley were also contributed to and are pledged as collateral for the EGR IV financing structure referenced below.

Antelope Valley sells all of its output to PG&E through a PPA. On January 29, 2019, PG&E filed for protection under Chapter 11 of the U.S. Bankruptcy Code, which created an event of default for Antelope Valley’s nonrecourse debt that provides the lender with a right to accelerate amounts outstanding under the loan such that they would become immediately due and payable. As a result of the ongoing event of default and the absence of a waiver from the lender foregoing their acceleration rights, the debt was reclassified as current in Exelon’s and Generation’s Consolidated Balance Sheets in the first quarter of 2019 and continues to be classified as current as of March 31, 2020. Further, distributions from Antelope Valley to EGR IV are currently suspended.

ExGen Renewables IV. In November 2017, EGR IV, an indirect subsidiary of Exelon and Generation, entered into an $850 million nonrecourse senior secured term loan credit facility agreement. Generation’s interests in EGRP, Antelope Valley, SolGen, and Albany Green Energy were all contributed to and are pledged as collateral for this financing. The loan is scheduled to mature on November 28, 2024. As of March 31, 2020, $796 million was outstanding.

Although Antelope Valley’s debt is in default, it is nonrecourse to EGR IV. However, if in the future Antelope Valley were to file for bankruptcy protection as a result of events culminating from PG&E’s bankruptcy proceedings this would represent an event of default for EGR IV’s debt that would provide the lender with an opportunity to accelerate EGR IV’s debt.

See Note 16— Debt and Credit Agreements of the Exelon 2019 Form 10-K for additional information on nonrecourse debt.

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

Exelon ~~records the~~measures and classifies fair value ~~of assets and liabilities~~measurements in accordance with the hierarchy ~~established~~as defined by ~~the authoritative guidance for fair value measurements.~~GAAP. The hierarchy prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:

Level 1 —- quoted prices (unadjusted) in active markets for identical assets or liabilities that the Registrants have the ability to liquidate as of the reporting date.

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

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~~90

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 13 — Fair Value of Financial Assets and Liabilities

~~Generation and Exelon~~

~~In accordance with the applicable guidance on fair value measurement, certain investments that are measured~~Fair Value of Financial Liabilities Recorded 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.~~Amortized Cost

The following tables present ~~assets~~the carrying amounts and fair values of the Registrants’ short-term liabilities, ~~measured~~long-term debt, SNF obligation and ~~recorded at fair value~~trust preferred securities (long-term debt to financing trusts or junior subordinated debentures) as of March 31, 2020 and December 31, 2019. The Registrants have no financial liabilities classified as Level 1.

The carrying amounts of the Registrants’ short-term liabilities as presented on ~~Exelon's and Generation’s~~their Consolidated Balance Sheets ~~on a recurring basis and~~are representative of their ~~level within the~~ fair value ~~hierarchy as~~(Level 2) because of ~~September 30, 2017 and December 31, 2016:~~the short-term nature of these instruments.



	March 31, 2020								December 31, 2019
	Carrying Amount		Fair Value						Carrying Amount		Fair Value
	Carrying Amount		Level 2		Level 3		Total		Carrying Amount		Level 2		Level 3		Total
Long-Term Debt, including amounts due within one year^(a)
Exelon	$	37,656	$	36,908	$	2,556	$	39,464	$	36,039	$	37,453	$	2,580	$	40,033
Generation	8,449		7,034		1,330		8,364		7,974		7,304		1,366		8,670
ComEd	9,478		10,483		—		10,483		8,491		9,848		—		9,848
PECO	3,406		3,762		50		3,812		3,405		3,868		50		3,918
BGE	3,271		3,572		—		3,572		3,270		3,649		—		3,649
PHI	6,708		5,602		1,176		6,778		6,563		5,902		1,164		7,066
Pepco	3,015		3,009		483		3,492		2,864		3,198		388		3,586
DPL	1,575		1,334		271		1,605		1,567		1,408		311		1,719
ACE	1,325		991		421		1,412		1,327		1,026		464		1,490
Long-Term Debt to Financing Trusts^(a)
Exelon	$	390	$	—	$	387	$	387	$	390	$	—	$	428	$	428
ComEd	205		—		204		204		205		—		227		227
PECO	184		—		183		183		184		—		201		201
SNF Obligation
Exelon	$	1,204	$	723	$	—	$	723	$	1,199	$	1,055	$	—	$	1,055
Generation	1,204		723		—		723		1,199		1,055		—		1,055

____


(a)	Includes unamortized debt issuance costs which are not fair valued.

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~~91

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

~~108~~

~~Table of Contents~~

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

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

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

Pledged Assets
for Zion Station
Decommissioning

Mark-to-Market
Derivatives

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

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

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

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

~~_________~~


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

~~(b)~~

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


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

~~109~~

~~Table of Contents~~

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

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

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

Pledged Assets
for Zion Station
Decommissioning

Mark-to-Market
Derivatives

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

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

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

$ 19

$ 935

$ 42

$ 1,689

$ (244 )
$ 21
$ —

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

~~110~~

~~Table of Contents~~

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

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

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

Pledged Assets
for Zion Station
Decommissioning

Mark-to-Market
Derivatives

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

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

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

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

~~_________~~


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

~~(b)~~

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


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


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

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

~~111~~

~~Table of Contents~~

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

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

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

$ 21
$ 21

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

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

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

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

Successor
Generation PHI Exelon

Operating
Revenues

Purchased
Power and
Fuel

Other, net^(a)

Other, net^(a)

Operating
Revenues

Purchased
Power and
Fuel

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

~~112~~

~~Table of Contents~~

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

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

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

Other, net^(a)

Other, net^(a)

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

~~_________~~


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

~~Valuation Techniques Used to Determine Fair Value~~

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

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

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

~~Nuclear Decommissioning Trust Fund Investments and Pledged Assets for Zion Station Decommissioning (Exelon and Generation).~~ The trust fund investments have been established to satisfy Generation’s and CENG's nuclear decommissioning obligations as required by the NRC. The NDT funds hold debt and equity securities directly and indirectly through commingled funds and mutual funds, which are included in Equities and Fixed Income. Generation’s and CENG's NDT fund investments policies outline investment guidelines for the trusts and limit the trust funds’ exposures to investments in highly illiquid markets and other alternative investments. Investments with maturities of three months or less when purchased, including certain short-term fixed income securities are considered cash equivalents and included in the recurring fair value measurements hierarchy as Level 1 or Level 2.

With respect to individually held equity securities, the trustees obtain prices from pricing services, whose prices are generally obtained from direct feeds from market exchanges, which Generation is able to independently corroborate. The fair values of equity securities held directly by the trust funds which are based on quoted prices in active markets are categorized in Level 1. Certain equity securities have been categorized as Level 2 because they are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities. Equity securities held individually are primarily traded on the New York Stock Exchange and NASDAQ-Global Select Market, which contain only actively traded securities due to the volume trading requirements imposed by these exchanges.

For fixed income securities, multiple prices from pricing services are obtained whenever possible, which enables cross-provider validations in addition to checks for unusual daily movements. A primary price source is identified based on asset type, class or issue for each security. With respect to individually held fixed income securities, the trustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the portfolio managers challenge an assigned price and the trustees determine that another

~~113~~

~~Table of Contents~~

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

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

price source is considered to be preferable. Generation has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, Generation selectively corroborates the fair values of securities by comparison to other market-based price sources. U.S. Treasury securities are categorized as Level 1 because they trade in a highly liquid and transparent market. The fair values of fixed income securities, excluding U.S. Treasury securities, are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities, adjusted for observable differences and are categorized in Level 2. The fair values of private placement fixed income securities, which are included in Corporate debt, are determined using a third party valuation that contains significant unobservable inputs and are categorized in Level 3.

Equity and fixed income commingled funds and mutual funds are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives such as holding short-term fixed income securities or tracking the performance of certain equity indices by purchasing equity securities to replicate the capitalization and characteristics of the indices. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized as Level 1. For commingled funds and mutual funds, which are not publicly quoted, the funds are valued using NAV as a practical expedient for fair value, which is primarily derived from the quoted prices in active markets on the underlying securities, and are not classified within the fair value hierarchy. These investments typically can be redeemed monthly with 30 or less days of notice and without further restrictions.

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

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

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

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

~~Concentrations of Credit Risk~~. Generation evaluated its NDT portfolios for the existence of significant concentrations of credit risk as of September 30, 2017. Types of concentrations that were evaluated include, but are not limited to, investment concentrations in a single entity, type of industry, foreign country, and individual fund. As of September 30, 2017, there were no significant concentrations (generally defined as greater than 10 percent) of risk in Generation's NDT assets.

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

~~Rabbi Trust Investments (Exelon, Generation, PECO, BGE, PHI, Pepco, DPL and ACE).~~ The Rabbi trusts were established to hold assets related to deferred compensation plans existing for certain active and retired members of Exelon’s executive management and directors. The Rabbi trusts assets are included in investments in the Registrants’ Consolidated Balance Sheets and consist primarily of money market funds, mutual funds, fixed income securities and

~~114~~

~~Table of Contents~~

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

~~(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~~of Financial Assets 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

~~115~~

~~Table of Contents~~

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

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

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.

~~116~~

~~Table of Contents~~

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

~~(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

~~117~~

~~Table of Contents~~

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

~~(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. 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 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. 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), cash flow hedge, and fair value hedge. For Generation, all 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 are a complement to Generation’s energy marketing portfolio but represent a small portion of Generation’s overall energy marketing activities.

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

~~118~~

~~Table of Contents~~

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

~~(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 a 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 the NPNS scope exception under current derivative authoritative guidance.

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

~~119~~

~~Table of Contents~~

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

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

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

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

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

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

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

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

~~120~~

~~Table of Contents~~

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

~~(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.

~~121~~

~~Table of Contents~~

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

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

~~The following table provides a summary of the 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 as the offsetting loss 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

~~122~~

~~Table of Contents~~

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

~~(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

~~123~~

~~Table of Contents~~

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

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

million and $8 million of cash collateral held, respectively, was not offset against derivative positions because such collateral was not associated with any energy-related derivatives, were associated with accrual positions, or as of the balance sheet date there were no positions to offset. Excluded from the tables below are economic hedges that qualify for the NPNS scope exception and other non-derivative contracts that are accounted for under the accrual method of accounting.

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

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

In the table below, DPL's economic hedges are shown gross. The impact of the netting of fair value balances with the same counterparty that are subject to legally enforceable master netting agreements, as well as netting of cash collateral, including margin on exchange positions, is aggregated in the collateral and netting column.

~~The following table provides a summary of the derivative fair value balances recorded by the Registrants as of September 30, 2017:~~

Successor
Generation ComEd DPL PHI Exelon
Derivatives
Economic
Hedges

Proprietary
Trading

Collateral
and
Netting^{(a) (e)}

Subtotal^(b)

Economic
Hedges^(c)

Economic
Hedges^(d)

Collateral
and
Netting^(a)
Subtotal Subtotal
Total
Derivatives
Mark-to-market derivative assets (current assets) $ 2,608
$ 55
$ (1,969 ) $ 694
$ —
$ —
$ —
$ —
$ —
$ 694
Mark-to-market derivative assets (noncurrent assets) 1,583
30
(1,197 ) 416
—
—
—
—
—
416
Total mark-to-market derivative assets 4,191

85
(3,166 ) 1,110
—
—
—
—

—
1,110
Mark-to-market derivative liabilities (current liabilities) (2,334 ) (46 ) 2,230
(150 ) (20 ) —
—
—
—
(170 )
Mark-to-market derivative liabilities (noncurrent liabilities) (1,476 ) (27 ) 1,351
(152 ) (257 ) —
—
—
—
(409 )
Total mark-to-market derivative liabilities (3,810 ) (73 ) 3,581
(302 ) (277 ) —
—
—

—
(579 )
Total mark-to-market derivative net assets (liabilities) $ 381
$ 12
$ 415
$ 808
$ (277 ) $ —
$ —
$ —

$ —
$ 531

~~_________~~

~~(a)~~

Exelon, Generation, PHI and DPL net all available amounts allowed under the derivative accounting guidance on the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, letters of credit and other forms of non-cash collateral. These are not reflected in the table above.


~~(b)~~	Current and noncurrent assets are shown net of collateral of $123 million and $61 million, respectively, and current and noncurrent liabilities are shown net of collateral of $138 million and $93 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $415 million at September 30, 2017.


~~(c)~~	~~Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.~~


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


~~(e)~~	~~Of the collateral posted/(received), $27 million represents variation margin on the exchanges.~~

~~124~~

~~Table of Contents~~

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

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

~~The following table provides a summary of the derivative fair value balances recorded by the Registrants as of December 31, 2016:~~

Successor
Generation ComEd DPL PHI Exelon
Description
Economic
Hedges

Proprietary
Trading

Collateral
and
Netting^{(a) (e)}

Subtotal^(b)

Economic
Hedges^(c)

Economic
Hedges^(d)

Collateral and
Netting^(a)
Subtotal Subtotal Total
Derivatives
Mark-to-market derivative assets (current assets) $ 3,623
$ 55
$ (2,769 ) $ 909
$ —
$ 2
$ (2 ) $ —
$ —
$ 909
Mark-to-market derivative assets (noncurrent assets) 1,467
21
(1,016 ) 472
—
—
—
—
—
472
Total mark-to-market derivative assets 5,090
76
(3,785 ) 1,381
—
2
(2 ) —
—
1,381
Mark-to-market derivative liabilities (current liabilities) (3,165 ) (54 ) 2,964
(255 ) (19 ) —
—
—
—
(274 )
Mark-to-market derivative liabilities (noncurrent liabilities) (1,274 ) (25 ) 1,150
(149 ) (239 ) —
—
—
—
(388 )
Total mark-to-market derivative liabilities (4,439 ) (79 ) 4,114
(404 ) (258 ) —
—
—
—
(662 )
Total mark-to-market derivative net assets (liabilities) $ 651
$ (3 ) $ 329
$ 977
$ (258 ) $ 2
$ (2 ) $ —
$ —
$ 719

~~_________~~

~~(a)~~

Exelon, Generation, PHI and DPL net all available amounts allowed under the derivative accounting guidance on the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, and letters of credit and other forms of non-cash collateral. These are not reflected in the table above.


~~(b)~~	Current and noncurrent assets are shown net of collateral of $100 million and $72 million, respectively, and current and noncurrent liabilities are shown net of collateral of $95 million and $62 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $329 million at December 31, 2016.


~~(c)~~	~~Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.~~


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


~~(e)~~	~~Of the collateral posted/(received), $(158) million represents variation margin on the exchanges.~~

~~125~~

~~Table of Contents~~

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

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

~~Cash Flow Hedges (Exelon and Generation).~~ The tables below provide the activity of OCI related to cash flow hedges for the nine months ended September 30, 2017 and 2016, containing information about the changes in the fair value of cash flow hedges and the reclassification from Accumulated OCI into results of operations. The amounts reclassified from OCI, when combined with the impacts of the hedged transactions, result in the ultimate recognition of net revenues or expenses at the contractual price.

Total Cash Flow Hedge OCI Activity, Net of Income Tax
Generation Exelon
Three Months Ended September 30, 2017
Income Statement
Location
Total Cash
Flow Hedges
Total Cash
Flow Hedges

Accumulated OCI derivative loss at June 30, 2017 $ (14 ) $ (12 )
Effective portion of changes in fair value 1
1

Reclassifications from AOCI to net income Interest Expense (1 )
^(a)
(1 )
^(a)
Accumulated OCI derivative loss at September 30, 2017 $ (14 ) $ (12 )

Total Cash Flow Hedge OCI Activity, Net of Income Tax
Generation Exelon
Nine Months Ended September 30, 2017
Income Statement
Location
Total Cash
Flow Hedges Total Cash
Flow Hedges
Accumulated OCI derivative loss at December 31, 2016 $ (19 ) $ (17 )
Effective portion of changes in fair value 2

2

Reclassifications from AOCI to net income Interest Expense 3
^(b)
3
^(b)
Accumulated OCI derivative loss at September 30, 2017 $ (14 ) $ (12 )

Total Cash Flow Hedge OCI Activity, Net of Income Tax
Generation Exelon
Three Months Ended September 30, 2016
Income Statement
Location
Total Cash
Flow Hedges
Total Cash
Flow Hedges

Accumulated OCI derivative loss at June 30, 2016 $ (25 ) $ (26 )
Effective portion of changes in fair value 1

3

Accumulated OCI derivative loss at September 30, 2016 $ (24 ) $ (23 )

Total Cash Flow Hedge OCI Activity, Net of Income Tax
Generation Exelon
Nine Months Ended September 30, 2016
Income Statement
Location
Total Cash
Flow Hedges
Total Cash
Flow Hedges

Accumulated OCI derivative loss at December 31, 2015 $ (21 ) $ (19 )
Effective portion of changes in fair value —

(1 )
Reclassifications from AOCI to net income Interest Expense (3 )
^(c)
(3 )
^(c)
Accumulated OCI derivative loss at September 30, 2016 $ (24 ) $ (23 )

~~_________~~


~~(a)~~	~~Amount is net of related income tax benefit of $1 million for the three months ended September 30, 2017.~~


~~(b)~~	~~Amount is net of related income tax expense of $2 million for the nine months ended September 30, 2017.~~


~~(c)~~	~~Amount is net of related income tax expense of $2 million for the nine months ended September 30, 2016.~~

~~126~~

~~Table of Contents~~

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

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

~~Economic Hedges (Exelon and Generation).~~ These instruments represent hedges that economically mitigate exposure to fluctuations in commodity prices and include financial options, futures, swaps, physical forward sales and purchases, 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 fair value of the derivative contracts held at the reporting date. The “Reclassification to realized” generally represents the recognized change in fair value that was reclassified from unrealized to realized when the transaction to which the derivative relates occurs.

Generation Exelon
Three Months Ended September 30, 2017
Operating
Revenues

Purchased
Power
and Fuel
Total Total
Change in fair value of commodity positions $ 132
$ 45
$ 177
$ 177
Reclassification to realized at settlement of commodity positions (77 ) (24 ) (101 ) (101 )
Net commodity mark-to-market gains (losses) 55
21
76
76
Change in fair value of treasury positions (3 ) —
(3 ) (3 )
Reclassification to realized at settlement of treasury positions —
—
—
—
Net treasury mark-to-market gains (losses) (3 ) —
(3 ) (3 )
Net mark-to-market gains (losses) $ 52
$ 21
$ 73
$ 73

Generation Exelon
Nine Months Ended September 30, 2017
Operating
Revenues

Purchased
Power
and Fuel
Total Total
Change in fair value of commodity positions $ 123
$ (153 ) $ (30 ) $ (30 )
Reclassification to realized of commodity positions (164 ) 39
(125 ) (125 )
Net commodity mark-to-market gains (losses) (41 ) (114 ) (155 ) (155 )
Change in fair value of treasury positions (4 ) —
(4 ) (4 )
Reclassification to realized of treasury positions (2 ) —
(2 ) (2 )
Net treasury mark-to-market gains (losses) (6 ) —
(6 ) (6 )
Net mark-to-market gains (losses) $ (47 ) $ (114 ) $ (161 ) $ (161 )

Generation Exelon
Three Months Ended September 30, 2016
Operating
Revenues

Purchased
Power
and Fuel
Total Total
Change in fair value of commodity positions $ 280
$ (73 ) $ 207
$ 207
Reclassification to realized at settlement of commodity positions (92 ) (26 ) (118 ) (118 )
Net commodity mark-to-market gains (losses) 188
(99 ) 89
89
Change in fair value of treasury positions 1
—
1
1
Reclassification to realized at settlement of treasury positions (2 ) —
(2 ) (2 )
Net treasury mark-to-market gains (losses) (1 ) —
(1 ) (1 )
Net mark-to-market gains (losses) $ 187
$ (99 ) $ 88
$ 88

~~127~~

~~Table of Contents~~

~~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 in fair value of the derivative contracts held at the reporting date. The “Reclassification to realized” represents the recognized change in fair value that was reclassified to realized due to settlement of the derivative during the period.

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

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

~~128~~

~~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 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

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 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.

~~129~~

~~Table of Contents~~

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

~~(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 does 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 require Generation to post collateral. Generation

~~130~~

~~Table of Contents~~

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

~~(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 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

~~131~~

~~Table of Contents~~

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

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

collateral from suppliers in association with energy procurement contracts. Under the terms of ComEd's annual renewable energy contracts, collateral postings are required to cover a fixed value for RECs only. In addition, under the terms of ComEd’s long-term renewable energy contracts, collateral postings are required from suppliers for both RECs and energy. The REC portion is a fixed value and the energy portion is one-sided from suppliers should the forward market prices exceed contract prices. As of September 30, 2017, ComEd held approximately $21 million in the form of cash and letters of credit as margin for both the annual and long-term REC obligations. If ComEd lost its investment grade credit rating as of September 30, 2017, it would have been required to post approximately $3 million of collateral to its counterparties. See Note 3 — Regulatory Matters of the Exelon 2016 Form 10-K for additional information.

PECO’s natural gas procurement contracts contain provisions that could require PECO to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon PECO’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, PECO was not required to post collateral for any of these agreements. If PECO lost its investment grade credit rating as of September 30, 2017, PECO could have been required to post approximately $20 million of collateral to its counterparties.

~~PECO’s supplier master agreements that govern the terms of its DSP Program contracts do not contain provisions that would require PECO to post collateral.~~

~~BGE’s full requirements wholesale power agreements that govern the terms of its electric supply procurement contracts do not contain provisions that would require BGE to post collateral.~~

BGE’s natural gas procurement contracts contain provisions that could require BGE to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon BGE’s credit rating from the major credit rating agencies. The collateral 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. Debt and Credit Agreements (All Registrants)~~

~~Short-Term Borrowings~~Nuclear Decommissioning Asset Retirement Obligations

~~Exelon, Pepco, DPL~~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 ~~ACE meet their short-term liquidity requirements primarily through the issuance~~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 ~~commercial paper~~updated cost studies and ~~short-term notes. ComEd~~its annual evaluation of cost escalation factors 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. PHI meets its short-term liquidity requirement primarily through the issuance of short-term notes and the Exelon intercompany money pool.probabilities assigned to various scenarios.

~~132~~75

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 7 — Nuclear Decommissioning

~~Commercial Paper~~

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

The following table provides a rollforward of the nuclear decommissioning ARO reflected in Exelon’s and Generation’s Consolidated Balance Sheets from December 31, 2019 to March 31, 2020:



Nuclear decommissioning ARO at December 31, 2019 ^(a)	$	10,504
Accretion expense	121
Costs incurred related to decommissioning plants	(20		)
Nuclear decommissioning ARO at March 31, 2020 ^(a)	$	10,605

_________


(a)	Includes $107 million and $112 million as the current portion of the ARO at March 31, 2020 and December 31, 2019, respectively, which is included in Other current liabilities in Exelon’s and Generation’s Consolidated Balance Sheets.

NDT Funds

Exelon and Generation had ~~the following amounts of commercial paper borrowings outstanding as ofSeptember 30, 2017~~NDT funds totaling $11,824 million and $13,353 million at March 31, 2020 and December 31, ~~2016:~~

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~~2019, respectively. The NDT funds also include $213 million ~~term loan agreement, which was amended on March 28, 2016. The net proceeds~~and $163 million for the current portion of the ~~loan were used~~NDT funds at March 31, 2020 and December 31, 2019, respectively, which are included in Other current assets in Exelon's and Generation's Consolidated Balance Sheets. See Note 17 — Supplemental Financial Information for additional information on activities of the NDT funds.

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 ~~repay PHI's outstanding commercial paper, and~~decommission the facility at the end of its life.

Generation filed its biennial decommissioning funding status report with the NRC on April 1, 2019 for ~~general corporate purposes. Pursuant~~all units, including its shutdown units, except for Zion Station which is included in a separate report to the ~~loan agreement,~~NRC submitted by ZionSolutions, LLC. The status report demonstrated adequate decommissioning funding assurance as ~~amended, loans made thereunder bear interest at a variable rate equal~~of December 31, 2018 for all units except for Clinton and Peach Bottom Unit 1. As of February 28, 2019, Clinton demonstrated adequate minimum funding assurance due to ~~LIBOR plus 1%,~~market recovery and ~~all indebtedness thereunder~~no further action is ~~unsecured.~~required. This demonstration was also included in the April 1, 2019 submittal. On March ~~23, 2017,~~31, 2020, Generation filed its annual decommissioning funding status report with the ~~aggregate principal~~NRC for Generation’s shutdown units (excluding Zion Station for the reason noted above). The annual status report demonstrated adequate decommissioning funding assurance as of December 31, 2019, for all of its shutdown reactors except for Peach Bottom Unit 1. As a former PECO plant, financial assurance for decommissioning Peach Bottom Unit 1 is provided by the NDT fund, collections from PECO ratepayers, and the ability to adjust those collections in accordance with the approved PAPUC tariff. No additional actions are required aside from the PAPUC filing in accordance with the tariff. See Note 9 — Asset Retirement Obligations of the Exelon 2019 Form 10-K for information regarding the amount collected from PECO ratepayers for decommissioning cost.

8. Asset Impairments (Exelon and Generation)

The Registrants evaluate the carrying value of long-lived assets or asset groups for recoverability whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators of impairment may include a deteriorating business climate, including, but not limited to, declines in energy prices, condition of the asset, specific regulatory disallowance, or plans to dispose of a long-lived asset significantly before the end of its useful life. The Registrants determine if long-lived assets or asset groups are impaired by comparing the undiscounted expected future cash flows to the carrying value. When the undiscounted cash flow analysis indicates a long-lived asset or asset group is not recoverable, the amount of ~~all loans, together with any accrued but unpaid interest due under~~ the ~~loan agreement was fully repaid and~~impairment loss is determined by measuring the loan terminated. On March 23, 2017, Exelon Corporate entered into a similar type term loan for $500 million which expires on March 22, 2018. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 1% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Exelon’s Consolidated Balance Sheet within Short-Term borrowings.

~~Credit Agreements~~

On January 9, 2017, the credit agreement for Generation's $75 million bilateral credit facility was amended 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 of credit.

~~On May 26, 2016, Exelon Corporate, Generation, ComEd, PECO and BGE entered into amendments to each of their respective syndicated revolving credit facilities, which extended the maturity of each~~excess 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 datecarrying amount 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~~long-lived asset or asset group over 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.fair value. The fair value

~~133~~76

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

~~Long-Term Debt~~

~~Issuance of Long-Term Debt~~

~~During the nine months ended September 30, 2017, the following long-term debt was issued:~~

Note 8 — Asset Impairments

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~~analysis is primarily based on the income approach using significant unobservable inputs (Level 3) including revenue and generation forecasts, projected capital and maintenance expenditures and discount rates. A variation in the assumptions used could lead to a different conclusion regarding the recoverability of an asset or asset group and, thus, could potentially result in material future impairments of the Registrant's long-lived assets.

~~In September 2014, EGTP, an~~Antelope Valley Solar Facility

Generation’s Antelope Valley, a 242 MW solar facility in Lancaster, CA, sells all of its output to PG&E through a PPA. As of March 31, 2020, Generation had approximately $717 million of net long-lived assets related to Antelope Valley. As a result of the PG&E bankruptcy filing in the first quarter of 2019, Generation completed a comprehensive review of Antelope Valley's estimated undiscounted future cash flows and no impairment charge was recorded. Significant changes in assumptions such as the likelihood of the PPA being rejected as part of the bankruptcy proceedings could potentially result in future impairments of Antelope Valley’s net long-lived assets, which could be material.

Antelope Valley is a wholly owned indirect subsidiary of EGR IV, which had approximately $1,865 million of additional net long-lived assets as of March 31, 2020. EGR IV is a wholly owned indirect subsidiary of Exelon and Generation ~~issued $675 million aggregate principal~~and includes Generation's interest in EGRP and other projects with non-controlling interests. To date, there have been no indicators to suggest that the carrying amount of other net long-lived assets of EGR IV may not be recoverable.

Generation will continue to monitor the bankruptcy proceedings for any changes in circumstances that may indicate the carrying amount of the net long-lived assets of Antelope Valley or other long-lived assets of EGR IV may not be recoverable.

See Note 12 - Debt and Credit Agreements for additional information on the PG&E bankruptcy.

New England Asset Group

During the first quarter of 2018, Mystic Unit 9 did not clear in the ISO-NE capacity auction for the 2021 - 2022 planning year. On March 29, 2018, Generation notified ISO-NE of the early retirement of its Mystic Generating Station's Units 7, 8, 9 and the Mystic Jet Unit (Mystic Generating Station assets) absent regulatory reforms. These events suggested that the carrying value of its New England asset group may be impaired. In the second quarter of 2018, Generation completed a ~~nonrecourse senior secured term loan. The net proceeds were distributed~~comprehensive review of the estimated undiscounted future cash flows of the New England asset group and no impairment charge was required. Generation continues to ~~Generation~~monitor developments in the region that would indicate a potential triggering event for ~~general business purposes. The loan is scheduled~~impairment and continues to ~~mature on September 18, 2021. The term loan bears interest at a variable rate equal~~look for solutions that appropriately compensate both Mystic 8 and 9 and the Everett Marine Terminal for their contributions to ~~LIBOR plus 4.75%, subject~~the region. Further developments such as the failure of ISO-NE to ~~a 1% LIBOR floor with interest payable quarterly. As~~adopt long-term solutions for reliability and fuel security could potentially result in material future impairments of ~~September 30,~~the New England asset group. See Note 6 - Early Plant Retirements for additional information.

~~134~~77

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

2017, $660 million was outstanding. As part of the agreement, a revolving credit facility was established for the amount of $20 million available through, 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 portion of the interest rate exposure in connection with this financing, as required by the debt covenants. See Note 109 — ~~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 classified as Long-term debt due within one year on Exelon's and Generation's Consolidated Balance Sheets. See Note 4 - Mergers, Acquisitions and Dispositions and Note 6 - Impairment of Long-Lived Assets for more information.

~~Junior Subordinated Notes~~

In June 2014, Exelon issued $1.15 billion of junior subordinated notes in the form of 23 million equity units at a stated amount of $50.00 per unit. Each equity unit represented an undivided beneficial ownership interest in Exelon’s $1.15 billion of 2.50% junior subordinated notes due in 2024 (“2024 notes”) and a forward equity purchase contract. As contemplated in the June 2014 equity unit structure, in April 2017, Exelon completed the remarketing of the 2024 notes into $1.15 billion of 3.497% junior subordinated notes due in 2022 (“Remarketing”). Exelon conducted the Remarketing on behalf of the holders of equity units and did not directly receive any proceeds therefrom. Instead, the former holders of the 2024 notes used debt remarketing proceeds towards settling the forward equity purchase contract with Exelon on June 1, 2017. Exelon issued approximately 33 million shares of common stock from treasury stock and received $1.15 billion upon settlement of the forward equity purchase contract. When reissuing treasury stock Exelon uses the average price paid to repurchase shares to calculate a gain or loss on issuance and records gains or losses directly to retained earnings. A loss on reissuance of treasury shares of $1.05 billion was recorded to retained earnings as of September 30, 2017. See Note 17 - Earnings Per Share and Equity 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 of the outstanding shares of BGE Capital Trust II 6.20% Preferred Securities (“Securities”), pursuant to the optional redemption provisions 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.

~~135~~

~~Table of Contents~~

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

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

~~12.~~9. Income Taxes (All Registrants)

Rate Reconciliation

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



	Three Months Ended March 31, 2020
	Exelon^(a)	Generation^(a)	ComEd	PECO	BGE	PHI	Pepco	DPL	ACE
U.S. Federal statutory rate	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	34.0	0.7	8.3	0.1	5.7	5.8	4.7	6.6	6.7
Qualified NDT fund income	(235.8)	36.4	—	—	—	—	—	—	—
Amortization of investment tax credit, including deferred taxes on basis difference	(4.5)	0.5	(0.2)	—	(0.1)	(0.1)	—	(0.2)	(0.2)
Plant basis differences	(23.0)	—	(1.1)	(8.4)	(1.2)	(1.4)	(2.1)	(0.7)	(0.8)
Production tax credits and other credits	(9.9)	1.3	(0.2)	—	(0.2)	—	—	—	—
Noncontrolling interests	10.6	(1.6)	—	—	—	—	—	—	—
Excess deferred tax amortization	(71.7)	—	(10.5)	(3.0)	(7.3)	(15.5)	(14.2)	(12.7)	(18.8)
Tax Settlements	(79.1)	12.2	—	—	—	—	—	—	—
Other	12.5	0.6	0.3	—	0.6	(0.6)	(0.6)	(0.5)	(0.8)
Effective income tax rate	(345.9)%	71.1%	17.6%	9.7%	18.5%	9.2%	8.8%	13.5%	7.1%

Three Months Ended September 30, 2017
Successor
Exelon
Generation
ComEd
PECO
BGE PHI Pepco DPL ACE
U.S. Federal statutory rate 35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit 2.2 5.6 6.6 (0.1) 5.3 5.1 2.2 5.3 5.6
Qualified nuclear decommissioning trust fund income 2.6 5.8 — — — — — — —
Amortization of investment tax credit, including deferred taxes on basis difference
(1.1) (2.2) (0.2) (0.1) (0.1) (0.2) (0.1) (0.2) (0.4)
Plant basis differences (2.6) — (0.3) (14.6) (0.8) (4.9) (6.7) (1.9) (3.4)
Production tax credits and other credits (2.2) (4.8) — — — — — — —
Noncontrolling interests 0.5 1.0 — — — — — — —
FitzPatrick bargain purchase gain (0.2) (0.4) — — — — — — —
Other (0.1) 0.3 (0.2) (0.2) (0.2) 0.2 — (0.2) 0.1
Effective income tax rate 34.1% 40.3% 40.9% 20.0% 39.2% 35.2% 30.4% 38.0% 36.9%

Three Months Ended September 30, 2016
Successor
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
U.S. Federal statutory rate 35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit 3.8 2.6 7.3 2.4 5.2 5.6 5.6 5.2 6.1
Qualified nuclear decommissioning trust fund income 4.0 7.8 — — — — — — —
Amortization of investment tax credit, including deferred taxes on basis difference (0.9) (1.6) (0.6) (0.1) (0.2) (0.1) — (0.2) (0.1)
Plant basis differences (3.0) — (1.9) (6.7) (0.5) (5.0) (6.7) (1.3) (4.6)
Production tax credits and other credits (2.9) (5.7) (0.1) — — — — — —
Noncontrolling interest 0.2 0.5 — — — — — — —
Statute of limitations expiration

(0.1) 0.3 — — — — — — —
Penalties 4.3 — 27.2 — — — — — —
Merger expenses

(0.6) — — — — (5.7) (2.3) (8.6) (2.9)
Other (0.8) (0.5) 0.1 0.1 (0.4) (0.7) (0.9) 0.1 (0.6)
Effective income tax rate 39.0% 38.4% 67.0% 30.7% 39.1% 29.1% 30.7% 30.2% 32.9%

~~136~~

~~Table of Contents~~

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

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

Nine Months Ended September 30, 2017
Successor
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
U.S. Federal statutory rate 35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit 0.7 2.1 5.9 (0.1) 5.2 4.9 3.0 5.1 5.6
Qualified nuclear decommissioning trust fund income 4.0 14.0 — — — — — — —
Amortization of investment tax credit, including deferred taxes on basis difference (0.9) (2.7) (0.2) (0.1) (0.1) (0.2) (0.1) (0.2) (0.4)
Plant basis differences (3.4) — (0.3) (14.4) (0.8) (4.6) (6.3) (1.8) (3.4)
Production tax credits and other credits (1.8) (6.2) — — — — — — —
Noncontrolling interests 0.2 0.7 — — — — — — —
Merger expenses (5.4) (2.5) — — — (11.8) (8.0) (10.0) (23.0)
FitzPatrick bargain purchase gain (3.2) (11.2) — — — — — — —
Like-kind exchange^(a)
(1.7) — 1.7 — — — — — —
Other — (0.4) 0.2 — 0.2 — (0.3) 0.6 (0.3)
Effective income tax rate 23.5% 28.8% 42.3% 20.4% 39.5% 23.3% 23.3% 28.7% 13.5%

~~137~~

~~Table of Contents~~

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

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

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~~Generation recognized a loss before income taxes for the ~~nine months~~quarter ended ~~September 30, 2016, and PHI recognized a loss before income taxes for the period of~~ March ~~24, 2016, through September 30, 2016.~~31, 2020. As a result, positive percentages represent an income tax benefit for the ~~periods~~period presented.


~~(c)~~	~~Includes a remeasurement of uncertain state~~ At the consolidated level, positive percentages represent income tax ~~positions for Pepco and DPL.~~expense.

~~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

~~138~~78

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 9 — Income Taxes

~~first quarter 2017, as a part~~



	Three Months Ended March 31, 2019
	Exelon	Generation	ComEd	PECO	BGE	PHI	Pepco	DPL	ACE
U.S. Federal statutory rate	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	3.9	3.1	8.2	1.0	6.3	4.7	2.1	6.5	6.7
Qualified NDT fund income	7.2	14.2	—	—	—	—	—	—	—
Amortization of investment tax credit, including deferred taxes on basis difference	(0.5)	(0.9)	(0.2)	—	(0.1)	(0.2)	(0.1)	(0.2)	(0.3)
Plant basis differences	(1.4)	—	(0.5)	(6.7)	(0.9)	(1.7)	(2.0)	(0.7)	(2.3)
Production tax credits and other credits	(0.8)	(1.5)	—	—	—	—	—	—	—
Noncontrolling interests	(0.6)	(1.1)	—	—	—	—	—	—	—
Excess deferred tax amortization	(4.7)	—	(8.5)	(2.5)	(7.9)	(19.4)	(17.9)	(15.6)	(23.9)
Other	0.1	(0.5)	0.3	0.2	—	(0.3)	0.4	0.7	(1.2)
Effective income tax rate	24.2%	34.3%	20.3%	13.0%	18.4%	4.1%	3.5%	11.7%	—%

Table 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,~~ Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 9 — Income Taxes

Accounting for Uncertainty in Income Taxes

Exelon, Generation, PHI ~~Pepco, DPL,~~ and ACE ~~decreased their liability for~~have the following unrecognized tax benefits as of March 31, 2020 and December 31, 2019. ComEd, PECO, BGE, Pepco and DPL's amounts are not material.



	Exelon		Generation		PHI		ACE
March 31, 2020	$	98	$	32	$	49	$	14
December 31, 2019	507		441		48		14

Exelon's and Generation's unrecognized federal and state tax benefits decreased in the first quarter of 2020 by ~~$146~~approximately $411 million ~~$19 million, $59 million, $21 million, $16~~due to the settlement of a federal refund claim with IRS Appeals. The recognition of these tax benefits resulted in an increase to Exelon's and Generation’s net income of $76 million and ~~$22~~$73 million, respectively, asfor the quarter ended March 31, 2020, reflecting a decrease to Exelon's and Generation's income tax expense of September 30, 2017, resulting in a benefit to Income taxes on Exelon’s, Generation’s, PHI’s, Pepco’s, DPL’s and ACE’s Consolidated Statements of Operations and Comprehensive Income and corresponding decreases in their effective tax rates.

Exelon reduced the liability related to the uncertain tax position associated with the like-kind exchange in the second quarter of 2017. Please see the Other Income Tax Matters section below for additional details related to the like-kind exchange adjustments made in the second quarter of 2017.$67 million.

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 million and $2 million, respectively, of unrecognized federal and state income tax benefits that could significantly decrease within the 12 months after the reporting date due to a final resolution of the like-kind exchange litigation described below. The recognition of these unrecognized tax benefits would decrease Exelon and ComEd's effective tax rate.

Settlement of Income Tax ~~Positions~~Audits, Refund Claims, and Litigation

~~As of September 30, 2017, Exelon, Generation, BGE, PHI, Pepco, DPL,~~The following table represents Exelon's, PHI's and ~~ACE have approximately $676 million, $469 million, $120 million, $88 million, $59 million, $21 million, and $8 million of~~ACE's unrecognized federal and state tax benefits that could significantly decrease within the 12 months after the reporting date as a result of completing audits, potential settlements, refund claims, and the outcomes of pending court ~~cases. Of the above unrecognized tax benefits, Exelon~~cases as of March 31, 2020. Generation's, ComEd's, PECO's, BGE's, Pepco's 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.DPL's amounts are not material.



Exelon		PHI		ACE^(a)
$	14	$	14	$	14

_________


(a)	The unrecognized tax benefit related to ACE, if recognized, may be included in future base rates and that portion would have no impact to the effective tax rate.

Other Income Tax Matters

~~Like-Kind Exchange (Exelon and ComEd)~~State Income Tax Law Changes

~~Exelon, through its ComEd subsidiary, took~~On June 5, 2019, the Governor of Illinois signed a ~~position on its 1999~~tax bill which would increase the Illinois corporate income tax ~~return~~rate from 9.50% to ~~defer approximately $1.2 billion~~10.49% effective for tax years beginning on or after January 1, 2021. The tax rate is contingent upon ratification of ~~tax gain on the sale of ComEd’s fossil generating assets.~~state constitutional amendments in November 2020. The ~~gain was deferred by reinvesting a portion~~effect of the ~~proceeds from~~rate change will be recognized in the ~~sale~~period in ~~qualifying replacement property under~~which the ~~like-kind exchange provisions~~new legislation is enacted. Exelon, Generation and ComEd do not expect a material impact to their financial statements as a result of the ~~IRC. The like-kind exchange replacement property purchased by~~rate change.

10. Retirement Benefits (All Registrants)

Defined Benefit Pension and OPEB

During the first quarter of 2020, Exelon ~~included interests~~received an updated valuation of its pension and OPEB to reflect actual census data as of January 1, 2020. This valuation resulted in ~~three municipal-owned electric generation facilities which were properly leased back~~an increase to the ~~municipalities.~~pension and OPEB obligations of $8 million and $31 million, respectively. Additionally, accumulated other comprehensive income increased by $7 million (after-tax) and regulatory assets and liabilities increased by $19 million and decreased by $10 million, respectively.

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 salemajority of the ~~fossil plants followed by the purchase~~2020 pension benefit cost for Exelon-sponsored plans is calculated using an expected long-term rate of return on plan assets of 7.00% and ~~leaseback~~a discount rate of 3.34%. The majority of the ~~municipal owned generation facilities did not qualify as~~2020 OPEB cost is calculated using an expected long-term rate of return on plan assets of 6.69% for funded plans and a ~~like-kind exchange and the gain on the sale is fully subject to tax. The IRS also asserted a penalty~~discount rate of ~~approximately $90 million for a substantial understatement of tax.~~3.31%.

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.

~~139~~80

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 10 — Retirement Benefits

In the first quarter of 2013, Exelon concluded that it was no longer more likely than not that the like-kind exchange position would be sustained and recorded charges to earnings representing the amount of interest expense (after-tax) and incremental state income tax expense that would be payable in the event Exelon is unsuccessful in litigation. Exelon agreed to hold ComEd harmless from any unfavorable impacts on ComEd’s equity

A portion of the ~~after-tax interest and penalty amounts.~~

~~Prior~~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 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 recordedcapitalization, for the ~~penalty or for after-tax interest on~~three months ended March 31, 2020 and 2019.



	Pension Benefits Three Months Ended March 31,						OPEB Three Months Ended March 31,
	2020			2019			2020			2019
Components of net periodic benefit cost:
Service cost	$	97		$	89		$	23		$	24
Interest cost	189			221			38			47
Expected return on assets	(318		)	(307		)	(41		)	(38		)
Amortization of:
Prior service cost (benefit)	1			—			(31		)	(45		)
Actuarial loss	128			104			12			11
Net periodic benefit cost	$	97		$	107		$	1		$	(1	)

The amounts below represent the ~~penalty. While it has strong arguments on appeal with respect to both~~Registrants' allocated pension and OPEB plan costs. For Exelon, the ~~merits~~service cost component is included in Operating and maintenance expense and Property, plant and equipment, net while 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,~~non-service cost components are included in the third quarter of 2016, Exelon and ComEd recorded a charge to earnings of approximately $106 million and $86 million, respectively, of penalty and approximately $94 million and $64 million, respectively, of after-tax interest. Exelon and ComEd recorded the penalty and pre-tax interest due on the asserted penalty to Other, net and Interest expense, net, respectively, on their Consolidated Statements of Operations. Consistent with Exelon’s agreement to continue to hold ComEd harmless from any unfavorable impact on its equity fromRegulatory assets. For Generation and the ~~like-kind exchange position, ComEd recorded on its Consolidated Balance Sheets as of September 30, 2016, an additional $150 million receivable~~Utility Registrants, the service cost and ~~non-cash equity contributions from Exelon.~~

As a result of the IRS’s finalization of its computation in the second quarter 2017, Exelon recorded a benefit to earnings of approximately $26 million, consisting of an income tax benefit of $50 million and a reduction of penalties of $2 million, partially offset by after-tax interest expense of $26 million, while ComEd recorded a charge to earnings of approximately $23 million, consisting of income tax expense of $15 million and after-tax interest expense of $8 million.

In the second quarter of 2017, Exelon amended its agreement with ComEd to also hold ComEd harmless for the unfavorable impacts on its equity from the additional income tax amounts owed by ComEd as a result of the IRS’s finalization of its computation related to the like-kind exchange position. Accordingly, in the second quarter of 2017, ComEd recorded an additional receivable and non-cash equity contribution from Exelon for the total $23 million. As of June 30, 2017, ComEd had a total receivable from Exelon pursuant to the hold harmless agreement of $369 million, which wasnon-service cost components are included in ~~Current Receivables from Affiliates on ComEd’s Consolidated Balance Sheet.~~

~~Exelon expects to pay the tax, penalties~~Operating and ~~interest of approximately $1.3 billion related to the like-kind exchange, including $300 million attributable to ComEd,~~maintenance expense and Property, plant and equipment, net 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~~

consolidated financial statements.

~~140~~



	Three Months Ended March 31,
Pension and OPEB Costs	2020		2019
Exelon	$	98	$	106
Generation	27		31
ComEd	28		24
PECO	1		2
BGE	16		16
PHI	17		23
Pepco	3		6
DPL	1		4
ACE	3		4

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 10 — Retirement Benefits

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 ~~significant operational changes. Exelon's, PHI's~~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 months ended March 31, 2020 and ~~Pepco's long-term marginal state income tax~~2019, respectively.



	Three Months Ended March 31,
Savings Plan Matching Contributions	2020		2019
Exelon	$	33	$	31
Generation	13		13
ComEd	7		7
PECO	3		2
BGE	2		2
PHI	3		4
Pepco	1		1
DPL	1		1
ACE	—		1

11. Derivative Financial Instruments (All Registrants)

The Registrants use derivative instruments to manage commodity price risk, interest rate ~~were revised~~risk and foreign exchange risk related to ongoing business operations.

Authoritative guidance requires that derivative instruments be recognized as either assets or liabilities at fair value, with changes in fair value of the ~~first quarter~~derivative recognized in earnings immediately. Other accounting treatments are available through special election and designation, provided they meet specific, restrictive criteria both at the time of ~~2017~~designation and on an ongoing basis. These alternative permissible accounting treatments include NPNS, cash flow hedges and fair value hedges. All derivative economic hedges related to commodities, referred to as ~~a result of a statutory rate change in Washington, D.C. As a result, Exelon, PHI~~economic hedges, are recorded at fair value through earnings at Generation and ~~Pepco recorded a one-time decrease to Deferred income tax liability of $28 million, $8 million, and $8 million, respectively, on their Consolidated Balance Sheets. Because income taxes~~ are ~~recovered through customer rates, Exelon, PHI and Pepco recorded~~offset by a corresponding regulatory asset or liability at ComEd. For all NPNS derivative instruments, accounts receivable or accounts payable are recorded when derivative settles and revenue or expense is recognized in earnings as the underlying physical commodity is sold or consumed.

Authoritative guidance about offsetting assets and liabilities requires the fair value of ~~$8 million,~~derivative instruments to be shown in the Combined Notes to Consolidated Financial Statements on a gross basis, even when the derivative instruments are subject to legally enforceable master netting agreements and qualify for net presentation in the Consolidated Balance Sheets. ~~In addition, Exelon recorded a decrease to Income tax expense~~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 ~~$20 million, net of federal taxes,~~all referencing contracts via one payment stream, which takes place as the contracts deliver, when collateral is requested or in the event of default. In the tables below that present fair value balances, Generation’s energy-related economic hedges and proprietary trading derivatives are shown gross. The impact of the netting of fair value balances with the same counterparty that are subject to legally enforceable master netting agreements, as well as netting of cash collateral, including margin on exchange positions, is aggregated in the collateral and netting columns.

Generation’s and ComEd’s use of cash collateral is generally unrestricted unless Generation or ComEd are downgraded below investment grade. Cash collateral held by PECO, BGE, Pepco, DPL and ACE must be deposited in an unaffiliated major U.S. commercial bank or foreign bank with a U.S. branch office that meet certain qualifications.

Commodity Price Risk (All Registrants)

Each of the Registrants employ established policies and procedures to manage their risks associated with market fluctuations in commodity prices by entering into physical and financial derivative contracts, including swaps, futures, forwards, options and short-term and long-term commitments to purchase and sell energy and commodity products.

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 11 — Derivative Financial Instruments

The Registrants believe these instruments, which are either determined to be non-derivative or classified as economic hedges, mitigate exposure to fluctuations in commodity prices.

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

Additionally, Generation is exposed to certain market risks through its proprietary trading activities. The proprietary trading activities are a complement to Generation’s energy marketing portfolio but represent a small portion of Generation’s overall energy marketing activities and are subject to limits established by Exelon’s RMC.

Utility Registrants. The Utility Registrants procure electric and natural gas supply through a competitive procurement process approved by each of the respective state utility commissions. The Utility Registrants’ hedging programs are intended to reduce exposure to energy and natural gas price volatility and have no direct earnings impact as the costs are fully recovered from customers through regulatory-approved recovery mechanisms. The following table provides a summary of the Utility Registrants’ primary derivative hedging instruments, listed by commodity and accounting treatment.



Registrant	Commodity	Accounting Treatment	Hedging instrument
ComEd	Electricity	NPNS	Fixed price contracts based on all requirements in the IPA procurement plans.
ComEd	Electricity	Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability^(a)	20-year floating-to-fixed energy swap contracts beginning June 2012 based on the renewable energy resource procurement requirements in the Illinois Settlement Legislation of approximately 1.3 million MWhs per year.
PECO^(b)	Gas	NPNS	Fixed price contracts to cover about 20% of planned natural gas purchases in support of projected firm sales.
BGE	Electricity	NPNS	Fixed price contracts for all SOS requirements through full requirements contracts.
BGE	Gas	NPNS	Fixed price contracts for between 10-20% of forecasted system supply requirements for flowing (i.e., non-storage) gas for the November through March period.
Pepco	Electricity	NPNS	Fixed price contracts for all SOS requirements through full requirements contracts.
DPL	Electricity	NPNS	Fixed price contracts for all SOS requirements through full requirements contracts.
	Gas	NPNS	Fixed price contracts through full requirements contracts.
	Gas	Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability ^(c)	Exchange traded future contracts for 50% of estimated monthly purchase requirements each month, including purchases for storage injections.
ACE	Electricity	NPNS	Fixed price contracts for all BGS requirements through full requirements contracts.

__________


(a)	See Note 2 - Regulatory Matters for additional information.


(b)	As part of its hedging program, PECO enters into electric supply procurement contracts that do not meet the definition of a derivative instrument.


(c)	The fair value of the DPL economic hedge is not material as of March 31, 2020 and December 31, 2019 and is not presented in the fair value tables below.

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 11 — Derivative Financial Instruments

The following table provides a summary of the derivative fair value balances recorded by Exelon, Generation and ComEd as of March 31, 2020 and December 31, 2019:



March 31, 2020	Exelon			Generation														ComEd
Derivatives	Total Derivatives			Economic Hedges			Proprietary Trading			Collateral ^(a)(b)		Netting ^(a)			Subtotal			Economic Hedges
Mark-to-market derivative assets (current assets)	$	649		$	4,010		$	63		$	277	$	(3,701	)	$	649		$	—
Mark-to-market derivative assets (noncurrent assets)	625			1,878			23			112		(1,388		)	625			—
Total mark-to-market derivative assets	1,274			5,888			86			389		(5,089		)	1,274			—
Mark-to-market derivative liabilities (current liabilities)	(252		)	(4,219		)	(37		)	339		3,701			(216		)	(36		)
Mark-to-market derivative liabilities (noncurrent liabilities)	(416		)	(1,676		)	(11		)	161		1,388			(138		)	(278		)
Total mark-to-market derivative liabilities	(668		)	(5,895		)	(48		)	500		5,089			(354		)	(314		)
Total mark-to-market derivative net assets (liabilities)	$	606		$	(7	)	$	38		$	889	$	—		$	920		$	(314	)



December 31, 2019	Exelon			Generation														ComEd
Description	Total Derivatives			Economic Hedges			Proprietary Trading			Collateral (a)(b)		Netting (a)			Subtotal			Economic Hedges
Mark-to-market derivative assets (current assets)	$	675		$	3,506		$	72		$	287	$	(3,190	)	$	675		$	—
Mark-to-market derivative assets (noncurrent assets)	508			1,238			25			122		(877		)	508			—
Total mark-to-market derivative assets	1,183			4,744			97			409		(4,067		)	1,183			—
Mark-to-market derivative liabilities (current liabilities)	(236		)	(3,713		)	(38		)	357		3,190			(204		)	(32		)
Mark-to-market derivative liabilities (noncurrent liabilities)	(380		)	(1,140		)	(11		)	163		877			(111		)	(269		)
Total mark-to-market derivative liabilities	(616		)	(4,853		)	(49		)	520		4,067			(315		)	(301		)
Total mark-to-market derivative net assets (liabilities)	$	567		$	(109	)	$	48		$	929	$	—		$	868		$	(301	)

_________

(a)

Exelon and Generation net all available amounts allowed under the derivative authoritative guidance in the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, letters of credit and other forms of non-cash collateral. These amounts are immaterial and not reflected in the table above.


(b)	Of the collateral posted/(received), $644 million and $511 million represents variation margin on the exchanges at March 31, 2020 and December 31, 2019 respectively.

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 11 — Derivative Financial Instruments

Economic Hedges (Commodity Price Risk)

Generation. For the three months ended March 31, 2020 and 2019, Exelon and Generation recognized the following net pre-tax commodity mark-to-market gains (losses) which are also located in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows.



	Three Months Ended March 31,
	2020			2019
Income Statement Location	Gain (Loss)
Operating revenues	$	175		$	(50	)
Purchased power and fuel	(47		)	30
Total Exelon and Generation	$	128		$	(20	)

Proprietary Trading (Commodity Price Risk)

Generation also executes commodity derivatives for proprietary trading purposes. Proprietary trading includes all contracts executed with the intent of benefiting from shifts or changes in market prices as opposed to those executed with the intent of hedging or managing risk. Gains and losses associated with proprietary trading are reported as Operating revenues in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income and are included in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows. For the three months ended March 31, 2020 and 2019, net pre-tax commodity mark-to-market gains (losses) for Exelon and Generation were not material. The Utility Registrants do not execute derivatives for proprietary trading purposes.

Interest Rate and Foreign Exchange Risk (Exelon and Generation)

Exelon and Generation utilize interest rate swaps, which are treated as economic hedges, to manage their interest rate exposure. On July 1, 2018, Exelon de-designated its fair value hedges related to interest rate risk and Generation de-designated its cash flow hedges related to interest rate risk. The notional amounts were $1,268 million and $1,269 million at March 31, 2020 and December 31, 2019, respectively, for Exelon and $568 million and $569 million at March 31, 2020 and December 31, 2019, respectively, for Generation.

Generation utilizes foreign currency derivatives to manage foreign exchange rate exposure associated with international commodity purchases in currencies other than U.S. dollars, which are treated as economic hedges. The notional amounts were $144 million and $231 million at March 31, 2020 and December 31, 2019, respectively.

The mark-to-market derivative assets and liabilities as of March 31, 2020 and December 31, 2019 and the mark-to-market gains and losses for the three months ended March 31, ~~2017.~~2020 and 2019 were not material for Exelon and Generation.

Credit Risk (All Registrants)

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

Generation. For commodity derivatives, Generation enters into enabling agreements that allow for payment netting with its counterparties, which reduces Generation’s exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. Typically, each enabling agreement is for a specific commodity and so, with respect to each individual counterparty, netting is limited to transactions involving that specific commodity product, except where master netting agreements exist with a

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 11 — Derivative Financial Instruments

counterparty that allow for cross product netting. In addition to payment netting language in the enabling agreement, Generation’s credit department establishes credit limits, margining thresholds and collateral requirements for each counterparty, which are defined in the derivative contracts. Counterparty credit limits are based on an internal credit review process that considers a variety of factors, including the results of a scoring model, leverage, liquidity, profitability, credit ratings by credit rating agencies, and risk management capabilities. To the extent that a counterparty’s margining thresholds are exceeded, the counterparty is required to post collateral with Generation as specified in each enabling agreement. Generation’s credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis.

The following tables provide information on Generation’s credit exposure for all derivative instruments, NPNS and payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of March 31, 2020. 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.



Rating as of March 31, 2020	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	$	915	$	22	$	893	—	$	—
Non-investment grade	60		49		11
No external ratings
Internally rated — investment grade	228		1		227
Internally rated — non-investment grade	157		22		135
Total	$	1,360	$	94	$	1,266	—	$	—



Net Credit Exposure by Type of Counterparty	As of March 31, 2020
Financial institutions	$	18
Investor-owned utilities, marketers, power producers	983
Energy cooperatives and municipalities	224
Other	41
Total	$	1,266

_________


(a)	As of March 31, 2020, credit collateral held from counterparties where Generation had credit exposure included $29 million of cash and $65 million of letters of credit. The credit collateral does not include non-liquid collateral.

Utility Registrants. The Utility Registrants have contracts to procure electric and natural gas supply that provide suppliers with a certain amount of unsecured credit. If the exposure on the supply contract exceeds the amount of unsecured credit, the suppliers may be required to post collateral. The net credit exposure is mitigated primarily by the ability to recover procurement costs through customer rates. As of March 31, 2020, the Utility Registrants’ counterparty credit risk with suppliers was immaterial.

Credit-Risk-Related Contingent Features (All Registrants)

Generation. As part of the normal course of business, Generation routinely enters into physically or financially settled contracts for the purchase and sale of electric capacity, electricity, fuels, emissions allowances and other energy-related products. Certain of Generation’s derivative instruments contain provisions that require Generation to post collateral. Generation also enters into commodity transactions on exchanges where the exchanges act as the counterparty to each trade. Transactions on the exchanges must adhere to comprehensive collateral and margining requirements. This collateral may be posted in the form of cash or credit support with thresholds contingent upon Generation’s credit rating from each of the major credit rating agencies. The collateral and credit support

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 11 — Derivative Financial Instruments

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 ~~third quarter~~absence 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~~expressly agreed-to provisions that specify the ~~impacts of Illinois’ statutory rate change, which increased the total corporate income tax rate from 7.75% to 9.5% effective July 1, 2017. As~~collateral that must be provided, collateral requested will be a ~~result~~function of the ~~rate changes,~~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 ~~third quarter~~table below:



Credit-Risk Related Contingent Features	March 31, 2020			December 31, 2019
Gross fair value of derivative contracts containing this feature^(a)	$	(1,002	)	$	(956	)
Offsetting fair value of in-the-money contracts under master netting arrangements^(b)	699			649
Net fair value of derivative contracts containing this feature^(c)	$	(303	)	$	(307	)

_________


(a)	Amount represents the gross fair value of out-of-the-money derivative contracts containing credit-risk related contingent features ignoring the effects of master netting agreements.


(b)	Amount represents the offsetting fair value of in-the-money derivative contracts under legally enforceable master netting agreements with the same counterparty, which reduces the amount of any liability for which a Registrant could potentially be required to post collateral.


(c)	Amount represents the net fair value of out-of-the-money derivative contracts containing credit-risk related contingent features after considering the mitigating effects of offsetting positions under master netting arrangements and reflects the actual net liability upon which any potential contingent collateral obligations would be based.

As of ~~2017,~~March 31, 2020 and December 31, 2019, Exelon and Generation posted or held the following amounts of cash collateral and ~~ComEd recorded a one-time increase~~letters of credit on derivative contracts with external counterparties, after giving consideration to ~~Deferred income taxes~~offsetting derivative and non-derivative positions under master netting agreements.



	March 31, 2020		December 31, 2019
Cash collateral posted	$	977	$	982
Letters of credit posted	256		264
Cash collateral held	105		103
Letters of credit held	115		112
Additional collateral required in the event of a credit downgrade below investment grade	1,468		1,509

Utility Registrants

The Utility Registrants’ electric supply procurement contracts do not contain provisions that would require them to post collateral.

PECO’s, BGE’s, and DPL’s natural gas procurement contracts contain provisions that could require PECO, BGE, and DPL to post collateral in the form of ~~approximately $250~~cash or credit support, which vary by contract and counterparty, with thresholds contingent upon PECO’s, BGE, and DPL’s credit rating. As of March 31, 2020, PECO, BGE, and DPL were not required to post collateral for any of these agreements. If PECO, BGE or DPL lost their investment grade

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 11 — Derivative Financial Instruments

credit ratings as of March 31, 2020, they could have been required to post incremental collateral to its counterparties of $33 million, ~~$20~~$34 million and ~~$270~~$12 million, respectively, on their Consolidated Balance Sheets. Because income taxes are recovered through customer rates, each of Exelon and ComEd recorded a corresponding regulatory asset of $272 million. Further, Exelon recorded a decrease to Income tax expense of approximately $20 million and Generation recorded an increase to Income tax expense of approximately $20 million (each net of federal taxes) in their Consolidated Statements of Operations and Comprehensive Income for the three and nine months ended September 30, 2017. The Illinois statutory rate increase is not expected to have a material ongoing impact to Exelon’s, Generation’s or ComEd’s future results of operations.respectively.

~~13. Nuclear Decommissioning (Exelon~~12. Debt and ~~Generation)~~Credit Agreements (All Registrants)

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.

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 7 — Nuclear Decommissioning

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

The following table provides a rollforward of the nuclear decommissioning ARO reflected onin Exelon’s and Generation’s Consolidated Balance Sheets from December 31, ~~2016~~2019 to ~~September 30, 2017:~~March 31, 2020:

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



Nuclear decommissioning ARO at December 31, 2019 ^(a)	$	10,504
Accretion expense	121
Costs incurred related to decommissioning plants	(20		)
Nuclear decommissioning ARO at March 31, 2020 ^(a)	$	10,605

_________


(a)	Includes ~~$12~~$107 million and ~~$10~~$112 million ~~for~~as the current portion of the ARO at ~~September 30, 2017~~March 31, 2020 and December 31, ~~2016,~~2019, respectively, which is included in Other current liabilities onin 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

~~141~~

~~Table of Contents~~

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

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

for refinements in estimated fleet wide labor costs expected to be incurred for certain on-site personnel during decommissioning as well as decreases resulting from updates to the cost studies of Clinton and Quad Cities. These decreases were partially offset by a $138 million increase in TMI's ARO liability associated with the May 30, 2017 announcement to early retire the unit on September 30, 2019. The increase in the ARO liability for TMI incorporates the early shutdown date, increases the probabilities of longer term decommissioning scenarios, and reflects an increase in the estimated costs to decommission based on an updated decommissioning cost study. Refer to Note 7 - Early Nuclear Plant Retirements for additional information regarding the announced early retirement of TMI.

~~Nuclear Decommissioning Trust Fund Investments~~

NDT funds have been established for each generation station unit to satisfy Generation’s nuclear decommissioning obligations. Generally, NDT funds established for a particular unit may not be used to fund the decommissioning obligations of any other unit.

The NDT funds associated with Generation’s nuclear units have been funded with amounts collected from the previous owners and their respective utility customers. PECO is authorized to collect funds, in revenues, for decommissioning the former PECO nuclear plants through regulated rates, and these collections are scheduled through the operating lives of the former PECO plants. The amounts collected from PECO customers are remitted to Generation and deposited into the NDT funds for the unit for which funds are collected. Every five years, PECO files a rate adjustment with the PAPUC that reflects PECO’s calculations of the estimated amount needed to decommission each of the former PECO units based on updated fund balances and estimated decommissioning costs. The rate adjustment is used to determine the amount collectible from PECO customers. On March 31, 2017, PECO filed its Nuclear Decommissioning Cost Adjustment (NDCA) with the PAPUC proposing an annual recovery from customers of approximately $4 million. This amount reflects a decrease from the current approved annual collection of approximately $24 million primarily due to the removal of the collections for Limerick Units 1 and 2 as a result of the NRC approving the extension of the operating licenses for an additional 20 years. On August 8, 2017, the PAPUC approved the filing and the new rates will be effective January 1, 2018. See Note 16 - Asset Retirement Obligations of Exelon's 2016 Form 10-K, for information regarding the amount collected from PECO ratepayers for decommissioning costs.Funds

Exelon and Generation had NDT ~~fund investments~~funds totaling ~~$12,966~~$11,824 million and ~~$11,061~~$13,353 million at ~~September 30, 2017~~March 31, 2020 and December 31, ~~2016,~~2019, respectively. The ~~increase is primarily driven by improved market performance and the acquisition of FitzPatrick.~~

~~The following table provides unrealized gains on~~ NDT funds also include $213 million and $163 million for the ~~three~~current portion of the NDT funds at March 31, 2020 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~~December 31, 2019, respectively, which 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.

~~142~~

~~Table of Contents~~

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

~~(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-relatedcurrent 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.~~Exelon's 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’sGeneration's Consolidated Balance Sheets. ~~Changes in the value~~See Note 17 — Supplemental Financial Information for additional information on activities 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:funds.

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~~April 1, 2019 for all units, including its shutdown units, except for Zion Station which is included in a separate report to the NRC submitted by ZionSolutions, ~~(see Zion Station Decommissioning above).~~LLC. The status report demonstrated adequate decommissioning funding assurance as of December 31, 2018 for all units except for Clinton and Peach Bottom Unit 1. As of February 28, 2019, Clinton demonstrated adequate minimum funding assurance due to market recovery and no further action is required. This demonstration was also included in the April 1, 2019 submittal. On March 31, 2020, Generation filed its annual decommissioning funding status report with the NRC for Generation’s shutdown units (excluding Zion Station for the reason noted above). The annual status report demonstrated adequate decommissioning funding assurance as of December 31, 2019, for all of its shutdown reactors 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,~~ratepayers, and the ability to adjust those collections in accordance with the approved PAPUC tariff. No additional actions are required aside from the PAPUC filing in accordance with the tariff. See Note 9 — Asset Retirement Obligations of the Exelon 2019 Form 10-K for information regarding the amount collected from PECO ratepayers ~~has been adjusted~~for decommissioning cost.

8. Asset Impairments (Exelon and Generation)

The Registrants evaluate the carrying value of long-lived assets or asset groups for recoverability whenever events or changes in circumstances indicate that the ~~March 31, 2017 filing~~carrying value of those assets may not be recoverable. Indicators of impairment may include a deteriorating business climate, including, but not limited to, declines in energy prices, condition of the asset, specific regulatory disallowance, or plans to dispose of a long-lived asset significantly before the end of its useful life. The Registrants determine if long-lived assets or asset groups are impaired by comparing the undiscounted expected future cash flows to the ~~PAPUC which was approved on August 8, 2017 and will be effective January 1, 2018.~~carrying value. When the undiscounted cash flow analysis indicates a long-lived asset or asset group is not recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. The fair value

~~143~~76

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 8 — Asset Impairments

analysis is primarily based on the income approach using significant unobservable inputs (Level 3) including revenue and generation forecasts, projected capital and maintenance expenditures and discount rates. A variation in the assumptions used could lead to a different conclusion regarding the recoverability of an asset or asset group and, thus, could potentially result in material future impairments of the Registrant's long-lived assets.

Antelope Valley Solar Facility

Antelope Valley is a wholly owned indirect subsidiary of EGR IV, which had approximately $1,865 million of additional net long-lived assets as of March 31, 2020. EGR IV is a wholly owned indirect subsidiary of Exelon and Generation and includes Generation's interest in EGRP and other projects with non-controlling interests. To date, there have been no indicators to suggest that the carrying amount of other net long-lived assets of EGR IV may not be recoverable.

Generation will ~~file its next decommissioning funding status report with~~continue to monitor the ~~NRC by March 31, 2018~~bankruptcy proceedings for ~~shutdown reactors and reactors within five years of shutdown. This report will reflect~~any changes in circumstances that may indicate the ~~status of decommissioning funding assurance as of December 31, 2017 and will include the impact~~carrying amount of the ~~announced early retirement~~net long-lived assets of ~~TMI. A shortfall could necessitate that Exelon post a parental guarantee~~Antelope Valley or other long-lived assets of EGR IV may not be recoverable.

See Note 12 - Debt and Credit Agreements for ~~Generation’s share of the funding assurance. However, the amount of any required guarantee will ultimately depend~~additional information on the ~~decommissioning approach adopted at TMI, the associated level of costs, and the decommissioning trust fund investment performance going forward.~~PG&E bankruptcy.

~~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.New England Asset Group

During the first quarter of ~~2017,~~2018, Mystic Unit 9 did not clear in ~~connection with~~ the ~~acquisition~~ISO-NE capacity auction for the 2021 - 2022 planning year. On March 29, 2018, Generation notified ISO-NE of ~~Fitzpatrick, Exelon established a new qualified pension plan~~the early retirement of its Mystic Generating Station's Units 7, 8, 9 and ~~a new OPEB plan, and recorded a provisional obligation for Fitzpatrick employees based on information available at~~ the ~~merger date~~Mystic Jet Unit (Mystic Generating Station assets) absent regulatory reforms. These events suggested that the carrying value of ~~$38 million and $11 million, respectively. As permitted by business combinations accounting guidance, during~~its New England asset group may be impaired. In the ~~third~~second quarter of ~~2017, Exelon updated those obligations based on~~2018, Generation completed a ~~final valuation for Fitzpatrick employees as~~comprehensive review of the ~~merger date~~estimated undiscounted future cash flows of the New England asset group and no impairment charge was required. Generation continues to monitor developments in the region that would indicate a potential triggering event for impairment and continues to look for solutions that appropriately compensate both Mystic 8 and 9 and the Everett Marine Terminal for their contributions to the region. Further developments such as the failure of ISO-NE to adopt long-term solutions for reliability and fuel security could potentially result in material future impairments of the New England asset group. See Note 6 - Early Plant Retirements for additional information.

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 9 — Income Taxes

9. Income Taxes (All Registrants)

Rate Reconciliation

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



	Three Months Ended March 31, 2020
	Exelon^(a)	Generation^(a)	ComEd	PECO	BGE	PHI	Pepco	DPL	ACE
U.S. Federal statutory rate	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	34.0	0.7	8.3	0.1	5.7	5.8	4.7	6.6	6.7
Qualified NDT fund income	(235.8)	36.4	—	—	—	—	—	—	—
Amortization of investment tax credit, including deferred taxes on basis difference	(4.5)	0.5	(0.2)	—	(0.1)	(0.1)	—	(0.2)	(0.2)
Plant basis differences	(23.0)	—	(1.1)	(8.4)	(1.2)	(1.4)	(2.1)	(0.7)	(0.8)
Production tax credits and other credits	(9.9)	1.3	(0.2)	—	(0.2)	—	—	—	—
Noncontrolling interests	10.6	(1.6)	—	—	—	—	—	—	—
Excess deferred tax amortization	(71.7)	—	(10.5)	(3.0)	(7.3)	(15.5)	(14.2)	(12.7)	(18.8)
Tax Settlements	(79.1)	12.2	—	—	—	—	—	—	—
Other	12.5	0.6	0.3	—	0.6	(0.6)	(0.6)	(0.5)	(0.8)
Effective income tax rate	(345.9)%	71.1%	17.6%	9.7%	18.5%	9.2%	8.8%	13.5%	7.1%

_________


(a)	Generation recognized a loss before income taxes for the quarter ended March 31, 2020. As a result, positive percentages represent an income tax benefit for the period presented. At the consolidated level, positive percentages represent income tax expense.

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 9 — Income Taxes



	Three Months Ended March 31, 2019
	Exelon	Generation	ComEd	PECO	BGE	PHI	Pepco	DPL	ACE
U.S. Federal statutory rate	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	3.9	3.1	8.2	1.0	6.3	4.7	2.1	6.5	6.7
Qualified NDT fund income	7.2	14.2	—	—	—	—	—	—	—
Amortization of investment tax credit, including deferred taxes on basis difference	(0.5)	(0.9)	(0.2)	—	(0.1)	(0.2)	(0.1)	(0.2)	(0.3)
Plant basis differences	(1.4)	—	(0.5)	(6.7)	(0.9)	(1.7)	(2.0)	(0.7)	(2.3)
Production tax credits and other credits	(0.8)	(1.5)	—	—	—	—	—	—	—
Noncontrolling interests	(0.6)	(1.1)	—	—	—	—	—	—	—
Excess deferred tax amortization	(4.7)	—	(8.5)	(2.5)	(7.9)	(19.4)	(17.9)	(15.6)	(23.9)
Other	0.1	(0.5)	0.3	0.2	—	(0.3)	0.4	0.7	(1.2)
Effective income tax rate	24.2%	34.3%	20.3%	13.0%	18.4%	4.1%	3.5%	11.7%	—%

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 9 — Income Taxes

Accounting for Uncertainty in Income Taxes

Exelon, Generation, PHI and ACE have the following unrecognized tax benefits as of March 31, ~~2017.~~2020 and December 31, 2019. ComEd, PECO, BGE, Pepco and DPL's amounts are not material.



	Exelon		Generation		PHI		ACE
March 31, 2020	$	98	$	32	$	49	$	14
December 31, 2019	507		441		48		14

Exelon's and Generation's unrecognized federal and state tax benefits decreased in the first quarter of 2020 by approximately $411 million due to the settlement of a federal refund claim with IRS Appeals. The ~~updated obligations for pension~~recognition of these tax benefits resulted in an increase to Exelon's and ~~OPEB were $16~~Generation’s net income of $76 million and ~~$17~~$73 million, ~~respectively. Refer~~respectively, for the quarter ended March 31, 2020, reflecting a decrease to ~~Note 4 - Mergers, Acquisitions~~Exelon's and ~~Dispositions~~Generation's income tax expense of $67 million.

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

Settlement of Income Tax Audits, Refund Claims, and Litigation

The following table represents Exelon's, PHI's and ACE's unrecognized federal and state tax benefits that could significantly decrease within the 12 months after the reporting date as a result of completing audits, potential settlements, refund claims, and the outcomes of pending court cases as of March 31, 2020. Generation's, ComEd's, PECO's, BGE's, Pepco's and DPL's amounts are not material.



Exelon		PHI		ACE^(a)
$	14	$	14	$	14

_________


(a)	The unrecognized tax benefit related to ACE, if recognized, may be included in future base rates and that portion would have no impact to the effective tax rate.

Other Income Tax Matters

State Income Tax Law Changes

On June 5, 2019, the Governor of Illinois signed a tax bill which would increase the Illinois corporate income tax rate from 9.50% to 10.49% effective for ~~additional discussion~~tax years beginning on or after January 1, 2021. The tax rate is contingent upon ratification of state constitutional amendments in November 2020. The effect of the ~~acquisition~~rate change will be recognized in the period in which the new legislation is enacted. Exelon, Generation and ComEd do not expect a material impact to their financial statements as a result of ~~FitzPatrick.~~the rate change.

10. Retirement Benefits (All Registrants)

Defined Benefit Pension and ~~Other Postretirement Benefits~~OPEB

During the first quarter of ~~2017,~~2020, Exelon received an updated valuation of its pension and ~~other postretirement benefit obligations~~OPEB to reflect actual census data as of January 1, ~~2017.~~2020. This valuation resulted in an increase to the pension ~~obligation~~and OPEB obligations of ~~$92~~$8 million and ~~an increase to the other postretirement benefit obligation of $57 million.~~$31 million, respectively. Additionally, accumulated other comprehensive ~~loss~~income increased by ~~approximately $59~~$7 million ~~(after tax),~~(after-tax) and regulatory assets ~~increased by approximately $57 million~~ and ~~regulatory~~ liabilities increased by ~~approximately $4 million.~~$19 million and decreased by $10 million, respectively.

The majority of the ~~2017~~2020 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%~~3.34%. The majority of the ~~2017 other postretirement benefit~~2020 OPEB cost is calculated using an expected long-term rate of return on plan assets of ~~6.58%~~6.69% for funded plans and a discount rate of ~~4.04%~~3.31%.

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 10 — Retirement Benefits

A portion of the net periodic benefit cost for all plans is capitalized within the Consolidated Balance Sheets. The following ~~tables present~~table presents the components of Exelon's net periodic benefit costs, prior to capitalization, for the three ~~and nine~~ months ended ~~September 30, 2017~~March 31, 2020 and ~~2016~~2019.



	Pension Benefits Three Months Ended March 31,						OPEB Three Months Ended March 31,
	2020			2019			2020			2019
Components of net periodic benefit cost:
Service cost	$	97		$	89		$	23		$	24
Interest cost	189			221			38			47
Expected return on assets	(318		)	(307		)	(41		)	(38		)
Amortization of:
Prior service cost (benefit)	1			—			(31		)	(45		)
Actuarial loss	128			104			12			11
Net periodic benefit cost	$	97		$	107		$	1		$	(1	)

The amounts below represent the Registrants' allocated pension and ~~PHI's~~OPEB plan costs. For Exelon, the service cost component is included in Operating and maintenance expense and Property, plant and equipment, net ~~periodic benefit costs, prior to capitalization, for~~while the ~~predecessor period of January 1, 2016 to March 23, 2016.~~non-service cost components are included in Other, net and Regulatory assets. For Generation and 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	2020		2019
Exelon	$	98	$	106
Generation	27		31
ComEd	28		24
PECO	1		2
BGE	16		16
PHI	17		23
Pepco	3		6
DPL	1		4
ACE	3		4

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

~~144~~81

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 10 — Retirement Benefits

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

~~145~~

~~Table of Contents~~

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

~~(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~~March 31, 2020 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,~~2019, respectively.



	Three Months Ended March 31,
Savings Plan Matching Contributions	2020		2019
Exelon	$	33	$	31
Generation	13		13
ComEd	7		7
PECO	3		2
BGE	2		2
PHI	3		4
Pepco	1		1
DPL	1		1
ACE	—		1

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~~11. Derivative Financial Instruments (All Registrants)

The Registrants ~~have an~~use derivative instruments to manage commodity price risk, interest rate risk and foreign exchange risk related to 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~~business operations.

Authoritative guidance requires that derivative instruments be recognized as either assets 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 expenseliabilities at fair value, with changes in fair value of the derivative recognized in earnings immediately. Other accounting treatments are available through special election and designation, provided they meet specific, restrictive criteria both at the ~~communication date if there~~time of designation and on an ongoing basis. These alternative permissible accounting treatments include NPNS, cash flow hedges and fair value hedges. All derivative economic hedges related to commodities, referred to as economic hedges, are norecorded at fair value through earnings at Generation and are offset by a corresponding regulatory asset or liability at ComEd. For all NPNS derivative instruments, accounts receivable or accounts payable are recorded when derivative settles and revenue or expense is recognized in earnings as the underlying physical commodity is sold or consumed.

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

Commodity Price Risk (All Registrants)

~~146~~82

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 11 — Derivative Financial Instruments

~~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~~believe these instruments, which are either determined to be non-derivative or classified as economic hedges, mitigate exposure to fluctuations in commodity prices.

Generation. To the extent the amount of energy Generation produces differs from the amount of energy it has contracted to sell, Exelon and ~~health and welfare benefits under Exelon’s ongoing severance benefit plans~~Generation are exposed to ~~terminated employees~~market fluctuations in the ~~normal course~~prices of ~~business. These benefits are accrued for when the benefits are considered probable~~electricity, fossil fuels and ~~can be reasonably estimated.~~

~~For the three and nine months ended September 30, 2017 and 2016,~~other commodities. Within Exelon, Generation ~~ComEd, PHI, Pepco, DPL,~~has the most exposure to commodity price risk. As such, Generation uses a variety of derivative and ~~ACE recorded~~non-derivative instruments to manage the commodity price risk of its electric generation facilities, including power and gas sales, fuel and power purchases, natural gas transportation and pipeline capacity agreements and other energy-related products marketed and purchased. To manage these risks, Generation may enter into fixed-price derivative or non-derivative contracts to hedge the variability in future cash flows from expected sales of power and gas and purchases of power and fuel. The objectives for executing such hedges include fixing the price for a portion of anticipated future electricity sales at a level that provides an acceptable return. Generation is also exposed to differences between the locational settlement prices of certain economic hedges and the hedged generating units. This price difference is actively managed through other instruments which include derivative congestion products, whose changes in fair value are recognized in earnings each period, and auction revenue rights, which are accounted for on an accrual basis.

Utility Registrants. The Utility Registrants procure electric and natural gas supply through a competitive procurement process approved by each of the respective state utility commissions. The Utility Registrants’ hedging programs are intended to reduce exposure to energy and natural gas price volatility and have no direct earnings impact as the costs are fully recovered from customers through regulatory-approved recovery mechanisms. The following ~~severance costs associated with these ongoing severance benefits within Operating~~table provides a summary of the Utility Registrants’ primary derivative hedging instruments, listed by commodity and ~~maintenance expense in their Consolidated Statements of Operations and Comprehensive Income.~~accounting treatment.

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
—
—
—



Registrant	Commodity	Accounting Treatment	Hedging instrument
ComEd	Electricity	NPNS	Fixed price contracts based on all requirements in the IPA procurement plans.
ComEd	Electricity	Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability^(a)	20-year floating-to-fixed energy swap contracts beginning June 2012 based on the renewable energy resource procurement requirements in the Illinois Settlement Legislation of approximately 1.3 million MWhs per year.
PECO^(b)	Gas	NPNS	Fixed price contracts to cover about 20% of planned natural gas purchases in support of projected firm sales.
BGE	Electricity	NPNS	Fixed price contracts for all SOS requirements through full requirements contracts.
BGE	Gas	NPNS	Fixed price contracts for between 10-20% of forecasted system supply requirements for flowing (i.e., non-storage) gas for the November through March period.
Pepco	Electricity	NPNS	Fixed price contracts for all SOS requirements through full requirements contracts.
DPL	Electricity	NPNS	Fixed price contracts for all SOS requirements through full requirements contracts.
	Gas	NPNS	Fixed price contracts through full requirements contracts.
	Gas	Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability ^(c)	Exchange traded future contracts for 50% of estimated monthly purchase requirements each month, including purchases for storage injections.
ACE	Electricity	NPNS	Fixed price contracts for all BGS requirements through full requirements contracts.

~~_________~~__________

(a)

~~The amounts above~~See Note 2 - Regulatory Matters 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.~~additional information.


(b)	As part of its hedging program, PECO enters into electric supply procurement contracts that do not meet the definition of a derivative instrument.


(c)	The ~~amounts above for Generation, ComEd, PECO~~fair value of the DPL economic hedge is not material as of March 31, 2020 and ~~BGE include $7 million, $3 million, $1 million~~December 31, 2019 and ~~$1 million, respectively, for amounts billed by BSC through intercompany allocations for~~is not presented in the ~~nine months ended September 30, 2016.~~fair value tables below.

~~147~~83

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 11 — Derivative Financial Instruments

~~Early Plant Retirement-Related Severance (Exelon and Generation)~~

AsThe following table provides a ~~result~~summary of the ~~Three Mile Island plant retirement decision,~~derivative fair value balances recorded by Exelon, Generation 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, ExelonComEd as of March 31, 2020 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:December 31, 2019:

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



March 31, 2020	Exelon			Generation														ComEd
Derivatives	Total Derivatives			Economic Hedges			Proprietary Trading			Collateral ^(a)(b)		Netting ^(a)			Subtotal			Economic Hedges
Mark-to-market derivative assets (current assets)	$	649		$	4,010		$	63		$	277	$	(3,701	)	$	649		$	—
Mark-to-market derivative assets (noncurrent assets)	625			1,878			23			112		(1,388		)	625			—
Total mark-to-market derivative assets	1,274			5,888			86			389		(5,089		)	1,274			—
Mark-to-market derivative liabilities (current liabilities)	(252		)	(4,219		)	(37		)	339		3,701			(216		)	(36		)
Mark-to-market derivative liabilities (noncurrent liabilities)	(416		)	(1,676		)	(11		)	161		1,388			(138		)	(278		)
Total mark-to-market derivative liabilities	(668		)	(5,895		)	(48		)	500		5,089			(354		)	(314		)
Total mark-to-market derivative net assets (liabilities)	$	606		$	(7	)	$	38		$	889	$	—		$	920		$	(314	)



December 31, 2019	Exelon			Generation														ComEd
Description	Total Derivatives			Economic Hedges			Proprietary Trading			Collateral (a)(b)		Netting (a)			Subtotal			Economic Hedges
Mark-to-market derivative assets (current assets)	$	675		$	3,506		$	72		$	287	$	(3,190	)	$	675		$	—
Mark-to-market derivative assets (noncurrent assets)	508			1,238			25			122		(877		)	508			—
Total mark-to-market derivative assets	1,183			4,744			97			409		(4,067		)	1,183			—
Mark-to-market derivative liabilities (current liabilities)	(236		)	(3,713		)	(38		)	357		3,190			(204		)	(32		)
Mark-to-market derivative liabilities (noncurrent liabilities)	(380		)	(1,140		)	(11		)	163		877			(111		)	(269		)
Total mark-to-market derivative liabilities	(616		)	(4,853		)	(49		)	520		4,067			(315		)	(301		)
Total mark-to-market derivative net assets (liabilities)	$	567		$	(109	)	$	48		$	929	$	—		$	868		$	(301	)

_________

(a)

~~The~~Exelon and Generation net all available amounts ~~above for~~allowed under the derivative authoritative guidance in the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases Exelon and Generation ~~ComEd, PECO, BGE, Pepco, DPL~~may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and ~~ACE include $8 million, $2 million, $1 million, $1 million, $19 million, $11 million~~payables, transactions that do not qualify as derivatives, letters of credit and ~~$10 million, respectively, for~~other forms of non-cash collateral. These amounts ~~billed by BSC and/or PHISCO through intercompany allocations for~~are immaterial and not reflected in the ~~nine months ended September 30, 2016.~~table above.

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)~~(b)	~~Includes salary continuance~~Of the collateral posted/(received), $644 million and ~~health~~$511 million represents variation margin on the exchanges at March 31, 2020 and ~~welfare severance benefits.~~December 31, 2019 respectively.

~~148~~84

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 11 — Derivative Financial Instruments

~~16. Changes~~

Economic Hedges (Commodity Price Risk)

Generation. For the three months ended March 31, 2020 and 2019, Exelon and Generation recognized the following net pre-tax commodity mark-to-market gains (losses) which are also located in ~~Accumulated Other~~the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows.



	Three Months Ended March 31,
	2020			2019
Income Statement Location	Gain (Loss)
Operating revenues	$	175		$	(50	)
Purchased power and fuel	(47		)	30
Total Exelon and Generation	$	128		$	(20	)

Proprietary Trading (Commodity Price Risk)

Interest Rate and Foreign Exchange Risk (Exelon and Generation)

Exelon and Generation ~~PECO~~utilize interest rate swaps, which are treated as economic hedges, to manage their interest rate exposure. On July 1, 2018, Exelon de-designated its fair value hedges related to interest rate risk and ~~PHI)~~Generation de-designated its cash flow hedges related to interest rate risk. The notional amounts were $1,268 million and $1,269 million at March 31, 2020 and December 31, 2019, respectively, for Exelon and $568 million and $569 million at March 31, 2020 and December 31, 2019, respectively, for Generation.

The ~~following tables present changes in accumulated other comprehensive income (loss) (AOCI) by component~~mark-to-market derivative assets and liabilities as of March 31, 2020 and December 31, 2019 and the mark-to-market gains and losses for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2020 and ~~2016:~~2019 were not material for Exelon and Generation.

Credit Risk (All Registrants)

Nine Months Ended September 30, 2017 Gains
and
(losses)
on Cash Flow Hedges
Unrealized
Gains and
(losses) on
Marketable
Securities

Pension and
Non-Pension
Postretirement
Benefit Plan
Items

Foreign
Currency
Items

AOCI of
Equity
Investments
Total
Exelon^(a)

Beginning balance $ (17 ) $ 4
$ (2,610 ) $ (30 ) $ (7 ) $ (2,660 )
OCI before reclassifications 2
2
(55 ) 7
7
(37 )
Amounts reclassified from AOCI^(b)
3
—
105
—
—
108
Net current-period OCI 5
2
50
7
7
71
Ending balance $ (12 ) $ 6
$ (2,560 ) $ (23 ) $ —
$ (2,589 )
Generation^(a)

Beginning balance $ (19 ) $ 2
$ —
$ (30 ) $ (7 ) $ (54 )
OCI before reclassifications 2
—
—
7
6
15
Amounts reclassified from AOCI^(b)
3
—
—
—
—
3
Net current-period OCI 5
—
—
7
6
18
Ending balance $ (14 ) $ 2
$ —
$ (23 ) $ (1 ) $ (36 )
PECO^(a)

Beginning balance $ —
$ 1
$ —
$ —
$ —
$ 1
OCI before reclassifications —
—
—
—
—
—
Amounts reclassified from AOCI^(b)
—
—
—
—
—
—
Net current-period OCI —
—
—
—
—
—
Ending balance $ —
$ 1
$ —
$ —
$ —
$ 1

~~149~~85

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 11 — Derivative Financial Instruments



Rating as of March 31, 2020	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	$	915	$	22	$	893	—	$	—
Non-investment grade	60		49		11
No external ratings
Internally rated — investment grade	228		1		227
Internally rated — non-investment grade	157		22		135
Total	$	1,360	$	94	$	1,266	—	$	—

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 )



Net Credit Exposure by Type of Counterparty	As of March 31, 2020
Financial institutions	$	18
Investor-owned utilities, marketers, power producers	983
Energy cooperatives and municipalities	224
Other	41
Total	$	1,266

_________


(a)	~~All amounts are net~~As of ~~tax~~March 31, 2020, credit collateral held from counterparties where Generation had credit exposure included $29 million of cash and ~~noncontrolling interest. Amounts in parenthesis represent a decrease in AOCI.~~


~~(b)~~	~~See next tables for details about these reclassifications.~~


~~(c)~~	~~As a result~~$65 million 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.~~letters of credit. The credit collateral does not include non-liquid collateral.

Credit-Risk-Related Contingent Features (All Registrants)

~~150~~86

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 11 — Derivative Financial Instruments

~~ComEd, PECO, BGE, Pepco, DPL~~

requirements vary by contract and ~~ACE did~~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 ~~have any reclassifications out of AOCI to Net income during~~fully collateralized (excluding transactions on 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~~exchanges that are fully collateralized) is detailed in the ~~three and nine months ended September 30, 2017 and 2016.~~

~~Three Months Ended September 30, 2017~~table below:

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



Credit-Risk Related Contingent Features	March 31, 2020			December 31, 2019
Gross fair value of derivative contracts containing this feature^(a)	$	(1,002	)	$	(956	)
Offsetting fair value of in-the-money contracts under master netting arrangements^(b)	699			649
Net fair value of derivative contracts containing this feature^(c)	$	(303	)	$	(307	)

~~Nine Months Ended September 30, 2017~~_________


(a)	Amount represents the gross fair value of out-of-the-money derivative contracts containing credit-risk related contingent features ignoring the effects of master netting agreements.


(b)	Amount represents the offsetting fair value of in-the-money derivative contracts under legally enforceable master netting agreements with the same counterparty, which reduces the amount of any liability for which a Registrant could potentially be required to post collateral.


(c)	Amount represents the net fair value of out-of-the-money derivative contracts containing credit-risk related contingent features after considering the mitigating effects of offsetting positions under master netting arrangements and reflects the actual net liability upon which any potential contingent collateral obligations would be based.

As of March 31, 2020 and December 31, 2019, Exelon and Generation posted or held the following amounts of cash collateral and letters of credit on derivative contracts with external counterparties, after giving consideration to offsetting derivative and non-derivative positions under master netting agreements.



	March 31, 2020		December 31, 2019
Cash collateral posted	$	977	$	982
Letters of credit posted	256		264
Cash collateral held	105		103
Letters of credit held	115		112
Additional collateral required in the event of a credit downgrade below investment grade	1,468		1,509

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
Generation entered into supply forward contracts with certain utilities, including PECO and BGE, with one-sided collateral postings only from Generation. If market prices fall below the benchmark price levels in these contracts, the utilities are not required to post collateral. However, when market prices rise above the benchmark price levels, counterparty suppliers, including Generation, are required to post collateral once certain unsecured credit limits are exceeded.

Utility Registrants

The Utility Registrants’ electric supply procurement contracts do not contain provisions that would require them to post collateral.

PECO’s, BGE’s, and DPL’s natural gas procurement contracts contain provisions that could require PECO, BGE, and DPL to post collateral in the form of cash or credit support, which vary by contract and counterparty, with thresholds contingent upon PECO’s, BGE, and DPL’s credit rating. As of March 31, 2020, PECO, BGE, and DPL were not required to post collateral for any of these agreements. If PECO, BGE or DPL lost their investment grade

~~151~~87

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

~~Three Months Ended September 30, 2016~~

Note 11 — Derivative Financial Instruments

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

credit ratings as of March 31, 2020, they could have been required to post incremental collateral to its counterparties of $33 million, $34 million and $12 million, respectively.

12. Debt and Credit Agreements (All Registrants)

Short-Term Borrowings

Commercial Paper

~~152~~



	Outstanding Commercial Paper as of				Average Interest Rate on Commercial Paper Borrowings as of
Commercial Paper Issuer	March 31, 2020		December 31, 2019		March 31, 2020		December 31, 2019
Exelon^(a)	$	979	$	870	2.91	%	2.25	%
Generation	595		320		2.01	%	1.84	%
ComEd	—		130		—	%	2.38	%
BGE	141		76		4.45	%	2.46	%
PHI^(b)	108		208		4.25	%	N/A
PEPCO	—		82		—	%	2.56	%
DPL	54		56		4.17	%	2.02	%
ACE	54		70		4.32	%	2.43	%

__________


(a)	Includes outstanding commercial paper at Exelon Corporate of $135 million and $136 million with average interest rates on commercial paper borrowings of 4.20% and 1.92% at March 31, 2020 and December 31, 2019, respectively.


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

Short-Term Loan Agreements

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 12 — Debt and Credit Agreements

~~Nine Months Ended September~~

On March 31, 2020, Generation entered into a term loan agreement for $300 million. The loan agreement has an expiration of March 30, ~~2016~~2021. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.75% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Generation's Consolidated Balance Sheet within Short-term borrowings.

Credit Agreements

Long-Term Debt

Issuance of Long-Term Debt

During the three months ended March 31, 2020, the following long-term debt was issued:

Company

Type

Interest Rate

Maturity

Amount

Use of Proceeds

Generation

Energy Efficiency Project Financing^(a)

3.95

August 31, 2020

Funding to install energy conservation measures for the Fort Meade project.

Generation

Energy Efficiency Project Financing^(a)

2.53

April 30, 2021

Funding to install energy conservation measures for the Fort AP Hill project.

ComEd

First Mortgage Bonds, Series 129

3.00

March 1, 2050

650

Repay a portion of outstanding commercial paper obligations and to fund general corporate purposes.

ComEd

First Mortgage Bonds, Series 128

2.20

March 1, 2030

350

Repay a portion of outstanding commercial paper obligations and fund other general corporate purposes.

Pepco^(b)

First Mortgage Bonds

2.53

February 25, 2030

150

Repay existing indebtedness and for general corporate purposes.

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~~For Energy Efficiency Project Financing, the maturity dates represent ~~a decrease in net income.~~the expected date of project completion, upon which the respective customer assumes the outstanding debt.


(b)	~~This AOCI component~~ On February 25, 2020, Pepco entered into a purchase agreement of First Mortgage Bonds for $150 million at 3.28% due on September 23, 2050. The closing date of the issuance is ~~included~~expected to occur in ~~the computation of net periodic pension and OPEB cost (see Note 14 — Retirement Benefits for additional details).~~September 2020.

Debt Covenants

As of March 31, 2020, the Registrants are in compliance with debt covenants, except for Antelope Valley's ongoing nonrecourse debt event of default as discussed below.

Nonrecourse Debt

~~153~~89

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(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~~Note 12 — Debt and ~~nine months ended September 30, 2017 and 2016:~~

Credit Agreements

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~~	$	—

See Note 16— Debt and Credit Agreements of the Exelon 2019 Form 10-K for additional information on nonrecourse debt.

~~17. Earnings Per Share~~13. Fair Value of Financial Assets and ~~Equity (Exelon)~~Liabilities (All Registrants)

~~Earnings per Share~~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:

~~Diluted earnings per share is calculated by dividing Net income attributable~~Level 1 - quoted prices (unadjusted) in active markets for identical assets or liabilities that the Registrants have the ability to ~~common shareholders by~~liquidate as of the ~~weighted average number of shares of common stock outstanding, including shares~~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 ~~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~~little or no market activity for 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: asset or liability.

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

~~154~~90

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 13 — Fair Value of Financial Assets and Liabilities

Fair Value of Financial Liabilities Recorded at Amortized Cost

The ~~number~~following tables present the carrying amounts and fair values of ~~stock options not included~~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 March 31, 2020 and December 31, 2019. The Registrants have no financial liabilities classified as Level 1.

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



	March 31, 2020								December 31, 2019
	Carrying Amount		Fair Value						Carrying Amount		Fair Value
	Carrying Amount		Level 2		Level 3		Total		Carrying Amount		Level 2		Level 3		Total
Long-Term Debt, including amounts due within one year^(a)
Exelon	$	37,656	$	36,908	$	2,556	$	39,464	$	36,039	$	37,453	$	2,580	$	40,033
Generation	8,449		7,034		1,330		8,364		7,974		7,304		1,366		8,670
ComEd	9,478		10,483		—		10,483		8,491		9,848		—		9,848
PECO	3,406		3,762		50		3,812		3,405		3,868		50		3,918
BGE	3,271		3,572		—		3,572		3,270		3,649		—		3,649
PHI	6,708		5,602		1,176		6,778		6,563		5,902		1,164		7,066
Pepco	3,015		3,009		483		3,492		2,864		3,198		388		3,586
DPL	1,575		1,334		271		1,605		1,567		1,408		311		1,719
ACE	1,325		991		421		1,412		1,327		1,026		464		1,490
Long-Term Debt to Financing Trusts^(a)
Exelon	$	390	$	—	$	387	$	387	$	390	$	—	$	428	$	428
ComEd	205		—		204		204		205		—		227		227
PECO	184		—		183		183		184		—		201		201
SNF Obligation
Exelon	$	1,204	$	723	$	—	$	723	$	1,199	$	1,055	$	—	$	1,055
Generation	1,204		723		—		723		1,199		1,055		—		1,055

____


(a)	Includes unamortized debt issuance costs which are not fair valued.

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 13 — Fair Value of Financial Assets and Liabilities

Recurring Fair Value Measurements

The following tables present assets and liabilities measured and recorded at fair value in the ~~calculation~~Registrants' Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of ~~diluted common shares~~March 31, 2020 and December 31, 2019:

Exelon and Generation



	Exelon														Generation
As of March 31, 2020	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)	$	1,399		$	—		$	—		$	—	$	1,399		$	591		$	—		$	—		$	—	$	591
NDT fund investments
Cash equivalents^(b)	373			79			—			—		452			373			79			—			—		452
Equities	2,603			1,377			—			1,080		5,060			2,603			1,377			—			1,080		5,060
Fixed income
Corporate debt	—			1,412			258			—		1,670			—			1,412			258			—		1,670
U.S. Treasury and agencies	1,723			141			—			—		1,864			1,723			141			—			—		1,864
Foreign governments	—			37			—			—		37			—			37			—			—		37
State and municipal debt	—			87			—			—		87			—			87			—			—		87
Other^(c)	—			26			—			872		898			—			26			—			872		898
Fixed income subtotal	1,723			1,703			258			872		4,556			1,723			1,703			258			872		4,556
Private credit	—			—			240			546		786			—			—			240			546		786
Private equity	—			—			—			444		444			—			—			—			444		444
Real estate	—			—			—			636		636			—			—			—			636		636
NDT fund investments subtotal^(d)	4,699			3,159			498			3,578		11,934			4,699			3,159			498			3,578		11,934
Rabbi trust investments
Cash equivalents	51			—			—			—		51			4			—			—			—		4
Mutual funds	75			—			—			—		75			23			—			—			—		23
Fixed income	—			11			—			—		11			—			—			—			—		—
Life insurance contracts	—			72			42			—		114			—			22			—			—		22
Rabbi trust investments subtotal	126			83			42			—		251			27			22			—			—		49
Commodity derivative assets
Economic hedges	714			3,135			2,039			—		5,888			714			3,135			2,039			—		5,888
Proprietary trading	—			29			57			—		86			—			29			57			—		86
Effect of netting and allocation of collateral^(e)(f)	(868		)	(2,770		)	(1,062		)	—		(4,700		)	(868		)	(2,770		)	(1,062		)	—		(4,700		)
Commodity derivative assets subtotal	(154		)	394			1,034			—		1,274			(154		)	394			1,034			—		1,274
Total assets	6,070			3,636			1,574			3,578		14,858			5,163			3,575			1,532			3,578		13,848

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 13 — Fair Value of Financial Assets and Liabilities



	Exelon														Generation
As of March 31, 2020	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	(990		)	(3,476		)	(1,743		)	—		(6,209		)	(990		)	(3,476		)	(1,429		)	—		(5,895		)
Proprietary trading	—			(28		)	(20		)	—		(48		)	—			(28		)	(20		)	—		(48		)
Effect of netting and allocation of collateral^(e)(f)	994			3,318			1,277			—		5,589			994			3,318			1,277			—		5,589
Commodity derivative liabilities subtotal	4			(186		)	(486		)	—		(668		)	4			(186		)	(172		)	—		(354		)
Deferred compensation obligation	—			(126		)	—			—		(126		)	—			(34		)	—			—		(34		)
Total liabilities	4			(312		)	(486		)	—		(794		)	4			(220		)	(172		)	—		(388		)
Total net assets	$	6,074		$	3,324		$	1,088		$	3,578	$	14,064		$	5,167		$	3,355		$	1,360		$	3,578	$	13,460

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 13 — Fair Value of Financial Assets and Liabilities



	Exelon														Generation
As of December 31, 2019	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)	$	639		$	—		$	—		$	—	$	639		$	214		$	—		$	—		$	—	$	214
NDT fund investments
Cash equivalents^(b)	365			87			—			—		452			365			87			—			—		452
Equities	3,353			1,753			—			1,388		6,494			3,353			1,753			—			1,388		6,494
Fixed income
Corporate debt	—			1,469			257			—		1,726			—			1,469			257			—		1,726
U.S. Treasury and agencies	1,808			131			—			—		1,939			1,808			131			—			—		1,939
Foreign governments	—			42			—			—		42			—			42			—			—		42
State and municipal debt	—			90			—			—		90			—			90			—			—		90
Other^(c)	—			33			—			953		986			—			33			—			953		986
Fixed income subtotal	1,808			1,765			257			953		4,783			1,808			1,765			257			953		4,783
Private credit	—			—			254			508		762			—			—			254			508		762
Private equity	—			—			—			402		402			—			—			—			402		402
Real estate	—			—			—			607		607			—			—			—			607		607
NDT fund investments subtotal^(d)	5,526			3,605			511			3,858		13,500			5,526			3,605			511			3,858		13,500
Rabbi trust investments
Cash equivalents	50			—			—			—		50			4			—			—			—		4
Mutual funds	81			—			—			—		81			25			—			—			—		25
Fixed income	—			12			—			—		12			—			—			—			—		—
Life insurance contracts	—			78			41			—		119			—			25			—			—		25
Rabbi trust investments subtotal	131			90			41			—		262			29			25			—			—		54
Commodity derivative assets
Economic hedges	768			2,491			1,485			—		4,744			768			2,491			1,485			—		4,744
Proprietary trading	—			37			60			—		97			—			37			60			—		97
Effect of netting and allocation of collateral^(e)(f)	(908		)	(2,162		)	(588		)	—		(3,658		)	(908		)	(2,162		)	(588		)	—		(3,658		)
Commodity derivative assets subtotal	(140		)	366			957			—		1,183			(140		)	366			957			—		1,183
Total assets	6,156			4,061			1,509			3,858		15,584			5,629			3,996			1,468			3,858		14,951

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 13 — Fair Value of Financial Assets and Liabilities



	Exelon														Generation
As of December 31, 2019	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	(1,071		)	(2,855		)	(1,228		)	—		(5,154		)	(1,071		)	(2,855		)	(927		)	—		(4,853		)
Proprietary trading	—			(34		)	(15		)	—		(49		)	—			(34		)	(15		)	—		(49		)
Effect of netting and allocation of collateral^(e)(f)	1,071			2,714			802			—		4,587			1,071			2,714			802			—		4,587
Commodity derivative liabilities subtotal	—			(175		)	(441		)	—		(616		)	—			(175		)	(140		)	—		(315		)
Deferred compensation obligation	—			(147		)	—			—		(147		)	—			(41		)	—			—		(41		)
Total liabilities	—			(322		)	(441		)	—		(763		)	—			(216		)	(140		)	—		(356		)
Total net assets	$	6,156		$	3,739		$	1,068		$	3,858	$	14,821		$	5,629		$	3,780		$	1,328		$	3,858	$	14,595

_________

(a)

Exelon excludes cash of $483 million and $373 million at March 31, 2020 and December 31, 2019, respectively, and restricted cash of $110 million at both March 31, 2020 and December 31, 2019, and includes long-term restricted cash of $121 million and $177 million at March 31, 2020 and December 31, 2019, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. Generation excludes cash of $317 million and $177 million at March 31, 2020 and December 31, 2019, respectively, and restricted cash of $63 million and $58 million at March 31, 2020 and December 31, 2019, respectively.


(b)	Includes $78 million and $90 million of cash received from outstanding repurchase agreements at March 31, 2020 and December 31, 2019, respectively, and is offset by an obligation to repay upon settlement of the agreement as discussed in (d) below.

(c)

Includes a derivative liability of $2 million and a derivative asset of $2 million, which have total notional amounts of $826 million and $724 million at March 31, 2020 and December 31, 2019, 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 Exelon and Generation's exposure to credit or market loss.

(d)

Excludes net liabilities of $110 million and $147 million at March 31, 2020 and December 31, 2019, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, repurchase agreement obligations, and payables related to pending securities purchases. The repurchase agreements are generally short-term in nature with durations generally of 30 days or less.

(e)

Collateral posted/(received) from counterparties totaled $126 million, $548 million and $215 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of March 31, 2020. Collateral posted/(received) from counterparties, net of collateral paid to counterparties, totaled $163 million, $551 million and $214 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2019.


(f)	Of the collateral posted/(received), $644 million and $511 million represents variation margin on the exchanges as of March 31, 2020 and December 31, 2019, respectively.

As of March 31, 2020, Exelon and Generation have outstanding ~~due~~commitments to ~~their antidilutive effect was~~invest in fixed income, private credit, private equity and real estate investments of approximately 7$80 million, $131 million, $338 million, and 9$428 million, respectively. These commitments will be funded by Generation’s existing NDT funds.

Exelon and Generation hold investments without readily determinable fair values with carrying amounts of $76 million and $66 million as of March 31, 2020, respectively. Changes in fair value, cumulative adjustments and impairments were not material for the three ~~and nine~~ months ended ~~September 30, 2017, respectively,~~March 31, 2020.

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 13 — Fair Value of Financial Assets and ~~11 million~~Liabilities

ComEd, PECO and ~~12 million for~~BGE



	ComEd											PECO										BGE
As of March 31, 2020	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)	$	729	$	—		$	—		$	729		$	8	$	—		$	—	$	8		$	—	$	—		$	—	$	—
Rabbi trust investments
Mutual funds	—		—			—			—			7		—			—		7			8		—			—		8
Life insurance contracts	—		—			—			—			—		10			—		10			—		—			1		1
Rabbi trust investments subtotal	—		—			—			—			7		10			—		17			8		—			1		9
Total assets	729		—			—			729			15		10			—		25			8		—			1		9
Liabilities
Deferred compensation obligation	—		(7		)	—			(7		)	—		(8		)	—		(8		)	—		(5		)	—		(5		)
Mark-to-market derivative liabilities^(b)	—		—			(314		)	(314		)	—		—			—		—			—		—			—		—
Total liabilities	—		(7		)	(314		)	(321		)	—		(8		)	—		(8		)	—		(5		)	—		(5		)
Total net assets (liabilities)	$	729	$	(7	)	$	(314	)	$	408		$	15	$	2		$	—	$	17		$	8	$	(5	)	$	1	$	4



	ComEd											PECO										BGE
As of December 31, 2019	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)	$	280	$	—		$	—		$	280		$	15	$	—		$	—	$	15		$	—	$	—		$	—	$	—
Rabbi trust investments
Mutual funds	—		—			—			—			8		—			—		8			8		—			—		8
Life insurance contracts	—		—			—			—			—		11			—		11			—		—			—		—
Rabbi trust investments subtotal	—		—			—			—			8		11			—		19			8		—			—		8
Total assets	280		—			—			280			23		11			—		34			8		—			—		8
Liabilities
Deferred compensation obligation	—		(8		)	—			(8		)	—		(9		)	—		(9		)	—		(5		)	—		(5		)
Mark-to-market derivative liabilities^(b)	—		—			(301		)	(301		)	—		—			—		—			—		—			—		—
Total liabilities	—		(8		)	(301		)	(309		)	—		(9		)	—		(9		)	—		(5		)	—		(5		)
Total net assets (liabilities)	$	280	$	(8	)	$	(301	)	$	(29	)	$	23	$	2		$	—	$	25		$	8	$	(5	)	$	—	$	3

_________

(a)

ComEd excludes cash of $67 million and $90 million at March 31, 2020 and December 31, 2019, respectively, and restricted cash of $38 million and $33 million at March 31, 2020 and December 31, 2019, respectively, and includes long-term restricted cash of $108 million and $163 million at March 31, 2020 and December 31, 2019, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. PECO excludes cash of $30 million and $12 million at March 31, 2020 and December 31, 2019, respectively. BGE excludes cash of $11 million and $24 million at March 31, 2020 and December 31, 2019, respectively, and restricted cash of $1 million at both March 31, 2020 and December 31, 2019.


(b)	The Level 3 balance consists of the current and noncurrent liability of $36 million and $278 million, respectively, at March 31, 2020, and $32 million and $269 million, respectively, at December 31, 2019, related to floating-to-fixed energy swap contracts with unaffiliated suppliers.

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 13 — Fair Value of Financial Assets and Liabilities

PHI, Pepco, DPL and ACE



	As of March 31, 2020										As of December 31, 2019
PHI	Level 1		Level 2			Level 3		Total			Level 1		Level 2			Level 3		Total
Assets
Cash equivalents^(a)	$	63	$	—		$	—	$	63		$	124	$	—		$	—	$	124
Rabbi trust investments
Cash equivalents	44		—			—		44			44		—			—		44
Mutual funds	13		—			—		13			14		—			—		14
Fixed income	—		11			—		11			—		12			—		12
Life insurance contracts	—		25			42		67			—		24			41		65
Rabbi trust investments subtotal	57		36			42		135			58		36			41		135
Total assets	120		36			42		198			182		36			41		259
Liabilities
Deferred compensation obligation	—		(16		)	—		(16		)	—		(19		)	—		(19		)
Total liabilities	—		(16		)	—		(16		)	—		(19		)	—		(19		)
Total net assets	$	120	$	20		$	42	$	182		$	182	$	17		$	41	$	240



	Pepco										DPL								ACE
As of March 31, 2020	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)	$	34	$	—		$	—	$	34		$	—	$	—	$	—	$	—	$	15	$	—	$	—	$	15
Rabbi trust investments
Cash equivalents	44		—			—		44			—		—		—		—		—		—		—		—
Fixed income	—		1			—		1			—		—		—		—		—		—		—		—
Life insurance contracts	—		25			42		67			—		—		—		—		—		—		—		—
Rabbi trust investments subtotal	44		26			42		112			—		—		—		—		—		—		—		—
Total assets	78		26			42		146			—		—		—		—		15		—		—		15
Liabilities
Deferred compensation obligation	—		(2		)	—		(2		)	—		—		—		—		—		—		—		—
Total liabilities	—		(2		)	—		(2		)	—		—		—		—		—		—		—		—
Total net assets	$	78	$	24		$	42	$	144		$	—	$	—	$	—	$	—	$	15	$	—	$	—	$	15

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 13 — Fair Value of Financial Assets and Liabilities



	Pepco										DPL								ACE
As of December 31, 2019	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)	$	34	$	—		$	—	$	34		$	—	$	—	$	—	$	—	$	16	$	—	$	—	$	16
Rabbi trust investments
Cash equivalents	43		—			—		43			—		—		—		—		—		—		—		—
Fixed income	—		2			—		2			—		—		—		—		—		—		—		—
Life insurance contracts	—		24			41		65			—		—		—		—		—		—		—		—
Rabbi trust investments subtotal	43		26			41		110			—		—		—		—		—		—		—		—
Total assets	77		26			41		144			—		—		—		—		16		—		—		16
Liabilities
Deferred compensation obligation	—		(2		)	—		(2		)	—		—		—		—		—		—		—		—
Total liabilities	—		(2		)	—		(2		)	—		—		—		—		—		—		—		—
Total net assets (liabilities)	$	77	$	24		$	41	$	142		$	—	$	—	$	—	$	—	$	16	$	—	$	—	$	16

_________

(a)

PHI excludes cash of $35 million and $57 million at March 31, 2020 and December 31, 2019, respectively, and includes long-term restricted cash of $12 million and $14 million at March 31, 2020 and December 31, 2019, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. Pepco excludes cash of $17 million and $29 million at March 31, 2020 and December 31, 2019, respectively. DPL excludes cash of $6 million and $13 million at March 31, 2020 and December 31, 2019, respectively. ACE excludes cash of $8 million and $12 million at March 31, 2020 and December 31, 2019, respectively, and includes long-term restricted cash of $12 million and $14 million at March 31, 2020 and December 31, 2019, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets.

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 13 — Fair Value of Financial Assets and Liabilities

Reconciliation of Level 3 Assets and Liabilities

The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the three ~~and nine~~ months ended ~~September 30, 2016, respectively. There were no equity units related~~March 31, 2020 and 2019:



	Exelon			Generation										ComEd				PHI and Pepco
Three Months Ended March 31, 2020	Total			NDT Fund Investments			Mark-to-Market Derivatives				Total Generation			Mark-to-Market Derivatives				Life Insurance Contracts		Eliminated in Consolidation
Balance as of December 31, 2019	$	1,068		$	511		$	817			$	1,328		$	(301	)		$	41	$	—
Total realized / unrealized gains (losses)
Included in net income	10			(1		)	10			^(a)	9			—				1		—
Included in noncurrent payables to affiliates	—			(1		)	—				(1		)	—				—		1
Included in regulatory assets	(14		)	—			—				—			(13		)	^(b)	—		(1		)
Change in collateral	1			—			1				1			—				—		—
Purchases, sales, issuances and settlements
Purchases	42			3			39				42			—				—		—
Sales	(22		)	—			(22		)		(22		)	—				—		—
Settlements	(14		)	(14		)	—				(14		)	—				—		—
Transfers into Level 3	2			—			2			^(c)	2			—				—		—
Transfers out of Level 3	15			—			15			^(c)	15			—				—		—
Balance as of March 31, 2020	$	1,088		$	498		$	862			$	1,360		$	(314	)		$	42	$	—
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of March 31, 2020	$	187		$	(1	)	$	187			$	186		$	—			$	1	$	—

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 13 — Fair Value of Financial Assets and Liabilities



	Exelon			Generation										ComEd				PHI and Pepco
Three Months Ended March 31, 2019	Total			NDT Fund Investments			Mark-to-Market Derivatives				Total Generation			Mark-to-Market Derivatives				Life Insurance Contracts		Eliminated in Consolidation
Balance as of December 31, 2018	$	907		$	543		$	575			$	1,118		$	(249	)		$	38	$	—
Total realized / unrealized gains (losses)
Included in net income	(228		)	2			(231		)	^(a)	(229		)	—				1		—
Included in noncurrent payables to affiliates	—			11			—				11			—				—		(11		)
Included in regulatory assets	20			—			—				—			9			^(b)	—		11
Change in collateral	81			—			81				81			—				—		—
Purchases, sales, issuances and settlements
Purchases	58			1			57				58			—				—		—
Sales	—			—			—				—			—				—		—
Settlements	(17		)	(17		)	—				(17		)	—				—		—
Transfers into Level 3	—			—			—			^(c)	—			—				—		—
Transfers out of Level 3	17			—			17			^(c)	17			—				—		—
Balance as of March 31, 2019	$	838		$	540		$	499			$	1,039		$	(240	)		$	39	$	—
The amount of total (losses) gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of March 31, 2019	$	(148	)	$	2		$	(151	)		$	(149	)	$	—			$	1	$	—

__________


(a)	Includes a reduction for the reclassification of $177 million and $80 million of realized losses due to the settlement of derivative contracts for the three months ended March 31, 2020 and 2019, respectively.

(b)

Includes $23 million of decreases in fair value and an increase for realized losses due to settlements of $10 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended March 31, 2020. Includes $14 million of decreases in fair value and an increase for realized losses due to settlements of $5 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended March 31, 2019.


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

The following tables present the ~~PHI Merger not~~income statement classification of the total realized and unrealized gains (losses) included in ~~the calculation of diluted common shares outstanding due to their antidilutive effect~~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. The number~~March 31, 2020 and 2019:



	Exelon										Generation								PHI and Pepco
	Operating Revenues		Purchased Power and Fuel			Operating and Maintenance		Other, net			Operating Revenues		Purchased Power and Fuel			Other, net			Operating and Maintenance
Total realized gains (losses) for the three months ended March 31, 2020	$	72	$	(62	)	$	1	$	(1	)	$	72	$	(62	)	$	(1	)	$	1
Total unrealized gains (losses) for the three months ended March 31, 2020	205		(18		)	1		(1		)	205		(18		)	(1		)	1

100

Table of ~~equity units related~~Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 13 — Fair Value of Financial Assets and Liabilities



	Exelon										Generation								PHI and Pepco
	Operating Revenues			Purchased Power and Fuel			Operating and Maintenance		Other, net		Operating Revenues			Purchased Power and Fuel			Other, net		Operating and Maintenance
Total realized (losses) gains for the three months ended March 31, 2019	$	(128	)	$	(103	)	$	1	$	2	$	(128	)	$	(103	)	$	2	$	1
Total unrealized (losses) gains for the three months ended March 31, 2019	(91		)	(60		)	1		2		(91		)	(60		)	2		1

Valuation Techniques Used to Determine Fair Value

Exelon’s valuation techniques used to measure the ~~PHI Merger not included~~fair value of the assets and liabilities shown in the ~~calculation~~tables below are in accordance with the policies discussed in Note 17 — Fair Value of ~~diluted common shares outstanding due to their antidilutive effect was less than 1 million for the three~~Financial Assets and ~~nine months ended September 30, 2016. Refer to Note 20 — Shareholders' Equity~~Liabilities of the Exelon ~~2016~~2019 Form ~~10-K for~~10-K.

Valuation Techniques Used to Determine Net asset Value (Exelon and Generation)

Certain NDT Fund Investments are not classified within the fair value hierarchy and are included under the heading “Not subject to leveling” in the table above. These investments are measured at fair value using NAV per share as a practical expedient and include commingled funds, mutual funds which are not publicly quoted, managed private credit funds, private equity and real estate funds.

For commingled funds and mutual funds, which are not publicly quoted, the fair value is primarily derived from the quoted prices in active markets on the underlying securities and can typically be redeemed monthly with 30 or less days of notice and without further ~~information regarding~~restrictions. For managed private credit funds, the fair value is determined using a combination of valuation models including cost models, market models, and income models and typically cannot be redeemed until maturity of the term loan. Private equity ~~units.~~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. These investments typically cannot be redeemed and are generally liquidated over a period of 8 to 10 years from the initial investment date, which is based on Exelon’s understanding of the investment funds. 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.

~~On June 1, 2017, Exelon settled~~

101

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 13 — Fair Value of Financial Assets and Liabilities

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

The table below discloses the significant inputs to the forward ~~purchase contract,~~curve used to value mark-to-market derivatives.



Type of trade	Fair Value at March 31, 2020			Fair Value at December 31, 2019			Valuation Technique	Unobservable Input	2020 Range & Arithmetic Average				2019 Range & Arithmetic Average
Mark-to-market derivatives — Economic Hedges (Exelon and Generation)^(a)(b)	$	610		$	558		Discounted Cash Flow	Forward power price	$6	-	$136	$27	$9	-	$180	$29
								Forward gas price	$1.02	-	$8.10	$2.43	$0.83	-	$10.72	$2.55
							Option Model	Volatility percentage	8%	-	304%	70%	8%	-	236%	70%

Mark-to-market derivatives — Proprietary trading (Exelon and Generation)^(a)(b)	$	37		$	45		Discounted Cash Flow	Forward power price	$15	-	$136	$31	$25	-	$180	$33

Mark-to-market derivatives (Exelon and ComEd)	$	(314	)	$	(301	)	Discounted Cash Flow	Forward heat rate^(c)	9x	-	10x	9.22x	9x	-	10x	9.68x
								Marketability reserve	3%	-	7%	5.11%	3%	-	7%	4.95%
								Renewable factor	90%	-	122%	99%	91%	-	123%	99%

_________


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


(b)	The fair values do not include cash collateral posted on level three positions of $215 million and $214 million as of March 31, 2020 and December 31, 2019, respectively.


(c)	Quoted forward natural gas rates are utilized to project the forward power curve for the delivery of energy at specified future dates. The natural gas curve is extrapolated beyond its observable period to the end of the contract’s delivery.

The inputs listed above, which ~~was a component~~are as of the ~~June 2014 equity units, through~~balance sheet date, would have a direct impact on the ~~issuance~~fair values of ~~approximately 33 million shares of Exelon common stock from treasury stock.~~the above instruments if they were adjusted. The ~~issuance of shares on June 1, 2017, triggered full dilution~~significant unobservable inputs used in the ~~EPS calculation, which prior to settlement were included~~fair value measurement of Generation’s commodity derivatives are forward commodity prices and for options is price volatility. Increases (decreases) in the ~~calculation~~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 ~~diluted EPS using~~ the ~~treasury stock method.~~

~~Prior~~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 ~~June 2017 issuance Exelon had approximately 35 million shares~~reserves listed above would decrease the fair value of ~~treasury stock with~~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 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.similar impact on forward power markets.

~~18.~~14. Commitments and Contingencies (All Registrants)

The following is an update to the current status of commitments and contingencies set forth in Note 2418 of the Exelon ~~2016~~2019 Form ~~10-K . See Note 4 - Mergers, Acquisitions and Dispositions for further discussion on the PHI Merger commitments.~~10-K.

~~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 - Commitments and Contingencies of the Combined Notes to the Consolidated Financial Statements in the Exelon 2016 Form 10-K for additional information regarding Generation’s future minimum lease payments.

The direct investment commitment also includes $450 million to $500 million relating to 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.~~

~~155~~102

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 14 — Commitments and Contingencies

~~Equity Investment~~

Commitments

PHI Merger Commitments (Exelon, PHI, Pepco, DPL 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 needsACE). Approval of the ~~planned operations~~PHI Merger in Delaware, New Jersey, Maryland and the District of Columbia was conditioned upon Exelon and PHI agreeing to certain commitments. The following amounts represent total commitment costs that have been recorded since the acquisition date and the total remaining obligations for Exelon, PHI, Pepco, DPL and ACE as of March 31, 2020:



Description	Exelon		PHI		Pepco		DPL		ACE
Total commitments	$	513	$	320	$	120	$	89	$	111
Remaining commitments^(a)	95		75		62		8		5

_________


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

In addition, Exelon is committed to develop or to assist in the commercial development of approximately 37 MWs of new solar generation in Maryland, District of Columbia, and Delaware at an estimated cost of approximately $127 million, which will generate future earnings at Exelon and Generation. Investment costs, which are expected to be primarily capital in nature, are recognized as incurred and recorded in Exelon's and Generation's financial statements. As of March 31, 2020, 27 MWs of new generation were developed and Exelon and Generation have incurred costs of $122 million. Exelon has also committed to purchase 100 MWs of wind energy in PJM. DPL has committed to conducting three RFPs to procure up to a total of 120 MWs of wind RECs for the purpose of meeting Delaware's renewable portfolio standards. DPL has conducted two of the ~~associated companies. As~~three wind REC RFPs. The first 40 MW wind REC tranche was conducted in 2017 and did not result in a purchase agreement. The second 40 MW wind REC tranche was conducted in 2018 and resulted in a proposed REC purchase agreement that was approved by the DPSC in 2019. The third and final 40 MW wind REC tranche will be conducted in 2022.

103

Table 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:~~Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 14 — Commitments and 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, 2020, representing commitments potentially triggered by future events were as ~~follows:~~follows:

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



			Expiration within
	Total		2020		2021		2022		2023		2024		2025 and beyond
Exelon
Letters of credit	$	1,464	$	1,080	$	384	$	—	$	—	$	—	$	—
Surety bonds^(a)	849		698		151		—		—		—		—
Financing trust guarantees	378		—		—		—		—		—		378
Guaranteed lease residual values^(b)	27		1		2		4		3		12		5
Total commercial commitments	$	2,718	$	1,779	$	537	$	4	$	3	$	12	$	383

Generation
Letters of credit	$	1,449	$	1,071	$	378	$	—	$	—	$	—	$	—
Surety bonds^(a)	685		591		94		—		—		—		—
Total commercial commitments	$	2,134	$	1,662	$	472	$	—	$	—	$	—	$	—

ComEd
Letters of credit	$	7	$	4	$	3	$	—	$	—	$	—	$	—
Surety bonds^(a)	15		11		4		—		—		—		—
Financing trust guarantees	200		—		—		—		—		—		200
Total commercial commitments	$	222	$	15	$	7	$	—	$	—	$	—	$	200

PECO
Surety bonds^(a)	$	9	$	8	$	1	$	—	$	—	$	—	$	—
Financing trust guarantees	178		—		—		—		—		—		178
Total commercial commitments	$	187	$	8	$	1	$	—	$	—	$	—	$	178

BGE
Letters of credit	$	2	$	2	$	—	$	—	$	—	$	—	$	—
Surety bonds^(a)	17		16		1		—		—		—		—
Total commercial commitments	$	19	$	18	$	1	$	—	$	—	$	—	$	—

PHI
Surety bonds^(a)	$	21	$	20	$	1	$	—	$	—	$	—	$	—
Guaranteed lease residual values^(b)	27		1		2		4		3		12		5
Total commercial commitments	$	48	$	21	$	3	$	4	$	3	$	12	$	5

Pepco
Surety bonds^(a)	$	14	$	14	$	—	$	—	$	—	$	—	$	—
Guaranteed lease residual values^(b)	9		—		1		1		1		4		2
Total commercial commitments	$	23	$	14	$	1	$	1	$	1	$	4	$	2

DPL
Surety bonds^(a)	$	4	$	3	$	1	$	—	$	—	$	—	$	—
Guaranteed lease residual values^(b)	11		—		1		2		1		5		2
Total commercial commitments	$	15	$	3	$	2	$	2	$	1	$	5	$	2

ACE
Surety bonds^(a)	$	3	$	3	$	—	$	—	$	—	$	—	$	—
Guaranteed lease residual values^(b)	7		1		—		1		1		3		1
Total commercial commitments	$	10	$	4	$	—	$	1	$	1	$	3	$	1

_________


(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.

104

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 14 — Commitments and Contingencies

~~(c)~~(b)

Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The ~~maximum~~ lease term associated with these assets ranges from 31 to 8 years. The maximum potential obligation at the end of the minimum lease term would be ~~$49~~$72 million ~~$14 million~~guaranteed by Exelon and PHI, of which $24 million, $30 million and $18 million is ~~a guarantee~~guaranteed 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.~~ACE, respectively. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.

~~Nuclear Insurance (Exelon and Generation)~~Environmental Remediation Matters

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.

~~156~~

~~Table of Contents~~

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

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

~~In addition, 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 site in the event of an accident. The property insurance maintained for each facility is currently provided through insurance policies purchased from NEIL, an industry mutual insurance company of which Generation is a member.

Premiums paid to NEIL by its members are also subject to a potential assessment for adverse loss experience in the form of a retrospective premium obligation. NEIL has never assessed this retrospective premium since its formation in 1973, and Generation cannot predict the level of future assessments if any. The current maximum aggregate annual retrospective premium obligation for Generation is approximately $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.

~~Environmental Issues~~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 (Exelon and the Utility Registrants). ComEd, PECO, BGE and DPL have identified sites where former MGP or gas purification activities have or may have resulted in actual site contamination. For almost all of these sites, there are additional PRPs that may share responsibility for the ultimate remediation of each location.

ComEd has ~~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.~~2025.

PECO has ~~identified 26~~8 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.

~~157~~

~~Table of Contents~~

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

~~(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 2021.

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

~~158~~

~~Table of Contents~~

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

~~(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~~ComEd, pursuant to an ICC order, and PECO, pursuant to settlements of natural gas distribution rate cases with the ~~third quarter~~PAPUC, 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~~distribution rates.

105

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 14 — Commitments and ~~$2 million increase to~~Contingencies

As of March 31, 2020 and December 31, 2019, the Registrants had accrued the following undiscounted amounts for environmental liabilities in Other current 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, 2017Other deferred credits and other ~~requirements of the Decree are now being implemented.~~liabilities within their respective Consolidated Balance Sheets:

~~Solid~~



	March 31, 2020				December 31, 2019
	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	$	472	$	317	$	478	$	320
Generation	104		—		105		—
ComEd	301		300		304		303
PECO	19		17		19		17
BGE	2		—		2		—
PHI	46		—		48		—
Pepco	44		—		46		—
DPL	1		—		1		—
ACE	1		—		1		—

Cotter Corporation (Exelon and ~~Hazardous Waste~~

~~Cotter Corporation.~~Generation). The EPA has advised Cotter Corporation (Cotter), a former ComEd subsidiary, that it is potentially liable in connection with radiological contamination at a site known as the West Lake Landfill in Missouri. In 2000, ComEd sold Cotter to an unaffiliated third-party. As part of the sale, ComEd agreed to indemnify Cotter for any liability arising in connection with the West Lake Landfill. In connection with Exelon’s 2001 corporate restructuring, this responsibility to indemnify Cotter was transferred to Generation. ~~On May 29, 2008, the EPA issued a Record of Decision approving the remediation option submitted by~~Including Cotter, ~~and the two other~~there are three 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~~participating 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~~West Lake Landfill remediation proceeding. Investigation by Generation has identified a number of other parties who also may be PRPs and could be liable to contribute to the final remedy. Further investigation is ongoing.

In September 2018, the EPA issued its Record of Decision (ROD) Amendment for the selection of a final remedy. The ROD Amendment modified the remedy previously selected by EPA in its 2008 ROD. While the ROD required only that the radiological materials and other wastes at the site be capped, the ROD Amendment requires partial excavation of the radiological materials in addition to the previously selected capping remedy. The ROD Amendment also allows for variation in depths of excavation depending on ~~going.~~

radiological concentrations. The EPA and the PRPs have entered into a Consent Agreement to perform the Remedial Design, which is expected to be completed by early 2022. In March 2019 the PRPs received Special Notice Letters from the EPA to perform the Remedial Action work. On October 8, 2019, Cotter (Generation’s indemnitee) provided a non-binding good faith offer to conduct, or finance, a portion of the remedy, subject to certain conditions. The total estimated cost of the ~~landfill cover~~ remedy, ~~(taking~~taking into account the current EPA technical requirements ~~incorporated~~and the total costs expected to be incurred collectively by the PRPs in fully executing the ~~third quarter 2017)~~remedy, is approximately ~~$110~~$280 million, including cost escalation on an undiscounted basis, which ~~will~~would be allocated among ~~all~~the final group of PRPs. Generation has ~~accrued what it believes to be an adequate amount to cover its anticipated share of~~determined that a loss associated with the EPA’s partial excavation and enhanced landfill cover ~~which~~remedy is probable and has recorded a liability included in the table ~~above.~~ ~~Generation believes~~above, that ~~a partial excavation~~reflects management’s best estimate of Cotter’s allocable share of the ultimate cost. Given the joint and several nature of this liability, the magnitude of Generation’s ultimate liability will depend on the actual costs incurred to implement the required remedy ~~is reasonably possible,~~as well as on the nature and ~~the partial excavation costs, inclusive~~terms of ~~a landfill cover, could range from approximately $225 million to $650~~ ~~million; such costs would likely be shared by~~any cost-sharing arrangements with the final group of ~~identified~~ PRPs. ~~Generation believes the likelihood~~Therefore, it is reasonably possible that the ~~EPA would require a complete excavation remedy is remote. The~~ultimate cost ~~of a partial or complete excavation~~and Cotter's associated allocable share could differ significantly once these uncertainties are resolved, which could have a material ~~unfavorable~~ impact on ~~Generation’s~~Exelon's and ~~Exelon’s~~Generation's future ~~results of operations and cash flows.~~financial statements.

~~159~~

~~Table of Contents~~

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

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

During December 2015, the EPA took two actions related to the West Lake Landfill designed to abate what it termed as imminent 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, oneOne 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~~Exelon and ~~Exelon~~Generation do not possess sufficient information to assess this claim and therefore are ~~therefore~~ unable to ~~determine~~estimate a range of loss, if any. As such, no liability has been recorded for the potential contribution claim. It is reasonably possible, however, that resolution of this matter could have a material, unfavorable impact on ~~their future results~~Exelon’s and Generation's financial statements.

In January 2018, the PRPs were advised by the EPA that it will begin an additional investigation and evaluation of ~~operations~~groundwater conditions at the West Lake Landfill. In September 2018, the PRPs agreed to an Administrative

106

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 14 — Commitments and ~~cash flows.~~Contingencies

~~On February 2, 2016,~~

Settlement Agreement and Order on Consent for the ~~U.S. Senate passed a bill~~performance by the PRPs of the groundwater Remedial Investigation (RI)/Feasibility Study (FS). The purpose of this RI/FS is to ~~transfer remediation authority over~~define the nature and extent of any groundwater contamination from the West Lake Landfill ~~from~~site and evaluate remedial alternatives. Generation estimates the ~~EPA~~undiscounted cost for the groundwater RI/FS to be approximately $20 million. Generation determined a loss associated with the ~~U.S. Army Corps of Engineers, under the Formerly Utilized Sites Remedial Action Program (FUSRAP). The legislation was not passed~~RI/FS is probable and has recorded a liability included in the ~~U.S. House~~table above that reflects management’s best estimate 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 liabilityCotter’s allocable share of the ~~PRPs, but would likely delay~~cost among the ~~determination~~PRPs. At this time Generation cannot predict the likelihood or the extent to which, if any, remediation activities may be required and therefore cannot estimate a reasonably possible range of loss for response costs beyond those associated with the RI/FS component. It is reasonably possible, however, that resolution of this matter could have a ~~final remedy~~material, unfavorable impact on Exelon’s and ~~its implementation.~~Generation’s future financial statements.

~~On August 8,~~In August 2011, Cotter was notified by the DOJ that Cotter is considered a PRP with respect to the government’s clean-up costs for contamination attributable to low level radioactive residues at a former storage and reprocessing facility named Latty Avenue near St. Louis, Missouri. The Latty Avenue site is included in ComEd’s (now Generation'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~~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~~million from all PRPs. Pursuant to a series of annual agreements since 2011, the DOJ and the PRPs ~~agreed to toll~~have tolled the statute of limitations until August ~~2018~~31, 2020 so that settlement discussions ~~could~~can proceed. ~~Based on Generation’s preliminary review, it appears probable that~~ Generation has ~~liability to Cotter~~determined that a loss associated with this matter is probable under ~~the~~its indemnification agreement with Cotter and has ~~established~~recorded an ~~appropriate accrual for this~~estimated 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

~~160~~

~~Table of Contents~~

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

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

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.

~~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, Generation, PHI and Pepco). In September 2010, PHI received a letter from EPA identifying the Benning Road site as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. A portion of the site was formerly the location of a Pepco Energy Services electric generating ~~facility. That generating~~ facility, which was deactivated

~~161~~

~~Table of Contents~~

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

~~(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 with the DOEE, which requires Pepco and Pepco Energy Services to conduct a ~~Remediation Investigation (RI)/ 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 RI/FS will form the basis for the remedial actions for 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

Since 2013, 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. Pursuant~~(now Generation, pursuant to Exelon's ~~March 23,~~ 2016 acquisition of ~~PHI, Pepco Energy Services was transferred to Generation. On July 1, 2017, Pepco Energy Services was merged into Constellation New Energy, a subsidiary of Generation.~~

~~The initial~~PHI) have been performing RI ~~field~~ work ~~began in January 2013~~ and ~~was completed in December 2014. In April 2015, Pepco and Pepco Energy Services~~have submitted amultiple draft RI ~~Report~~reports to the 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,September 2019, Pepco and Generation ~~will issue~~issued a draft “final” RI report which DOEE approved and on October 4, 2019 released this document for review and comment by ~~DOEE~~the public. The 45 day comment period ended on November 18, 2019 and ~~the public.~~a public meeting was held by Pepco on November 2, 2019. Pepco and Generation will ~~then~~ proceed to develop ana 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.~~September 16, 2021.

~~Upon DOEE’s 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 then prepare a Proposed Plan ~~regarding further response actions. After considering public comment on the Proposed Plan, DOEE will~~and issue a Record of Decision identifying any further response actions determined to be ~~necessary.~~

necessary, after considering public comment on the Proposed Plan. PHI, Pepco and Generation 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 Pepco and Generation, DOEE and ~~certain federal agencies~~the National Park Service have been conducting a separate RI/FS focused on the entire tidal reach of the Anacostia River extending from just north of the ~~Maryland-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 Pepco and Pepco Energy Services as part of the Benning RI/FS, as well as similar sampling efforts conducted by owners of other sites adjacent to this segment of the river and supplemental river sampling conducted by DOEE’s contractor. DOEE asked Pepco, along with parties responsible for other sites along the river, to participate in a ~~“Consultative~~"Consultative Working ~~Group”~~Group" to provide input into the process for future remedial actions ~~addressing the entire tidal reach of the river~~ and to ensure proper coordination with the other river cleanup efforts currently underway, including cleanup of the river segment adjacent to the Benning Road site resulting from the Benning Road site RI/FS. ~~Pepco responded that it will participate in~~In addition, the ~~Consultative Working Group but its participation is not~~District of Columbia Council directed DOEE to form an ~~acceptance~~official advisory committee made up 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~~members of 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.

~~162~~107

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 14 — Commitments and Contingencies

~~Conectiv Energy Wholesale Power Generation Sites.~~ ~~In July 2010, PHI sold~~

state and local environmental regulators, community and environmental groups and various academic and technical experts to provide guidance and support to DOEE as the wholesale power generation business of Conectiv Energy Holdings, Inc. and substantially all of its subsidiaries (Conectiv Energy) to Calpine Corporation (Calpine). Under New Jersey’s Industrial Site Recovery Act (ISRA),project progressed. This group, called the transfer of ownership to Calpine triggered an obligation on the part of Conectiv Energy to remediate any environmental contamination at each of the nine Conectiv Energy generating facility sites located in New Jersey. Under the terms of the sale, Calpine assumed responsibility for performing the ISRA-required remediation and for the payment of all related ISRA compliance costs up to $10 million. Predecessor PHIAnacostia Leadership Council, has met regularly since it was obligated to indemnify Calpine for any ISRA compliance remediation costs in excess of $10 million. According to PHI’s estimates, the costs of ISRA-required remediation activities at the 9 generating facility sites areformed. Pepco has participated in the ~~range~~Consultative Working Group. In April 2018, DOEE released a draft RI report for public review and comment. Pepco submitted written comments to the draft RI and participated in a public hearing.

Pepco has determined that it is probable that costs for remediation will be incurred and recorded a liability in the third quarter 2019 for management’s best estimate of ~~approximately $7 million to $18 million~~, ~~and predecessor PHI established an appropriate accrual for~~ its share of those costs based on DOEE’s stated position following a series of meetings attended by representatives from the ~~estimated clean-up costs. Pursuant to Exelon’s March 2016 acquisition of PHI, the Conectiv Energy legal entity was transferred to Generation~~Anacostia Leadership Council and the ~~accrual~~Consultative Working Group. On December 27, 2019, DOEE released for ~~Predecessor PHI's share~~review and comment by the public a Focused Feasibility Study (FFS) and a Proposed Plan (PP). The FFS and PP will be the basis for the Interim ROD, which is expected to be completed in September 2020. The FFS and PP are consistent with the DOEE’s stated position to follow an adaptive management approach which will allow several identified “hot spots” in the river to be addressed first while continuing to conduct studies and to monitor the river to evaluate improvements and determine potential future remediation plans. The adaptive management process chosen by DOEE is less intrusive, provides more long term environmental certainty, is less costly, and allows for site specific remediation plans already underway, including the plan for the Benning Road site to proceed to conclusion. Pepco concluded that incremental exposure remains reasonably possible, however management cannot reasonably estimate a range of loss beyond the ~~estimated clean- up costs was also transferred to Generation and is~~amounts recorded, which are included in the table above.

In addition to the activities associated with the remedial process outlined above, CERCLA separately requires federal and state (here including Washington, D.C.) Natural Resource Trustees (federal or state agencies designated by the President or the relevant state, respectively, or Indian tribes) to conduct an assessment of any damages to natural resources within their jurisdiction as a ~~liability~~result of ~~Generation.~~the contamination that is being remediated. The ~~responsibility to indemnify Calpine is shared by PHI and Generation.~~Trustees can seek compensation from responsible parties for such damages, including restoration costs. The ~~ultimate resolution~~Natural Resource Damages (NRD) assessment typically takes place following cleanup because cleanups sometimes also effectively restore affected natural resources. During the second quarter of 2018, Pepco became aware that the Trustees are in the beginning stages of this ~~matter is currently not expected~~process that often takes many years beyond the remedial decision to ~~have a material financial impact on PHI and Generation.~~

~~Rock Creek Mineral Oil Release.~~ ~~In late August 2015, a~~complete. Pepco underground transmission line in the District of Columbia suffered a breach, resulting in the release of non-toxic mineral oil surrounding the transmission line into the surrounding soil, and a small amount reached Rock Creek through a storm drain. Pepco notified regulatory authorities, and Pepco and its spill response contractors placed booms in Rock Creek, blocked the storm drain to prevent the release of mineral oil into the creek and commenced remediation of soil around the transmission line and the Rock Creek shoreline. Pepco estimates that approximately 6,100 gallons of mineral oil were released and that its remediation efforts recovered approximately 80% of the amount released. Pepco’s remediation efforts are ongoing under the direction of the DOEE, including the requirements of a February 29, 2016 compliance order which requires Pepco to prepare a full incident investigation report and prepare a removal action work plan to remove all impacted soils in the vicinity of the storm drain outfall, and in collaboration with the National Park Service, the Smithsonian Institution/National Zoo and EPA. Pepco’s investigation presently indicates that the damage to Pepco’s facilities occurred prior to the release of mineral oil when third-party excavators struck the Pepco underground transmission line while installing cable for another utility.

PHI and Pepco have reached a settlement with a third party who contributed to the loss. Exelon, PHI and Pepco do not believe that the balance of the remediation costs to resolve this matter will have a material adverse effect on their respective financial condition, results of operations or cash flows.

~~Brandywine Fly Ash Disposal Site.~~ In February 2013, Pepco received a letter from the MDE requesting that Pepco investigate the extent of waste on a Pepco right-of-way that traverses the Brandywine fly ash disposal site in Brandywine, Prince George’s County, Maryland, owned by NRG Energy, Inc. (as successor to GenOn MD Ash Management, LLC) (NRG). In July 2013, while reserving its rights and related defenses under a 2000 agreement covering the sale of this site, Pepco indicated its willingness to investigate the extent of, and propose an appropriate closure plan to address, ash on the right-of-way. Pepco submitted a schedule for development of a closure plan to MDE on September 30, 2013 and, by letter dated October 18, 2013, MDE approved the schedule.

~~Exelon, PHI and Pepco have determined~~has concluded that a loss associated with ~~this matter~~the eventual NRD assessment is ~~probable and have estimated that~~reasonably possible. Due to the ~~costs for implementation~~very early stage of ~~a closure plan and cap on~~ the ~~site are in~~assessment process, Pepco cannot reasonably estimate the range of approximately $3 million to $6 million, for which an appropriate reserve has been established and is included in the table above. Exelon, PHI and Pepco believe that the costs incurred in this matter will be recoverable from NRG under the 2000 sale agreement.loss.

Litigation and Regulatory Matters

Asbestos Personal Injury Claims (Exelon ~~Generation, ComEd, PECO~~ and ~~BGE)~~

~~Exelon, Generation and PECO~~Generation). Generation maintains a reserve for claims associated with asbestos-related personal injury actions in certain facilities that are currently owned by Generation or were previously owned by ComEd and PECO. The ~~reserve is~~estimated liabilities are recorded on an undiscounted basis and ~~excludes~~exclude the estimated legal costs associated with handling these matters, which could be material.

At ~~September 30, 2017~~March 31, 2020 and December 31, ~~2016,~~2019, Exelon and Generation had ~~reserved~~recorded estimated liabilities of approximately ~~$80~~$82 million and $83 million, respectively, in total for asbestos-related bodily injury claims. As of ~~September 30, 2017,~~March 31, 2020, approximately ~~$22~~$27 million of this amount related to ~~227~~268 open claims presented to Generation, while the remaining ~~$58~~$55 million ~~of the reserve~~ is for estimated future asbestos-related bodily injury claims anticipated to arise through ~~2050,~~2055, based on actuarial

~~163~~

~~Table of Contents~~

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

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

assumptions and analyses, which are updated on an annual basis. On a quarterly basis, Generation monitors actual experience against the number of forecasted claims to be received and expected claim payments and evaluates whether ~~an adjustment~~adjustments to the ~~reserve~~estimated liabilities are necessary.

It is ~~necessary.~~

~~On November 22, 2013, the Supreme Court of Pennsylvania held~~reasonably possible that the Pennsylvania Workers Compensation Act does not apply to an employee’s disability or death resulting from occupational disease, such as diseases related to asbestos exposure, which manifests more than 300 weeks after the employee’s last employment-based exposure, and that therefore the exclusivity provision 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 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 exposure to asbestos. Since the Pennsylvania Supreme Court's ruling in November 2013, Exelon, Generation, and PECO have experienced an increase in asbestos-related personal injury claims brought by former PECO employees, all of which have been reserved for on a claim by claim basis. Those additional claims are taken into account in projecting estimates of future asbestos-related bodily injury claims.

On November 4, 2015, the Illinois Supreme Court found that the provisions of the Illinois' Workers' Compensation Act and the Workers' Occupational Diseases Act barred an employee from bringing a direct civil action against an employer for latent diseases, including asbestos-related diseases that fall outside the 25-year limit of the statute of repose. The Illinois Supreme Court's ruling reversed previous rulings by the Illinois Court of Appeals, which initially ruled that the Illinois Worker's Compensation law 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~~unfavorable impact on ~~Exelon's, Generation's, ComEd's, PECO~~Exelon’s 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 asstatements. However, management cannot reasonably estimate 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.~~beyond the amounts recorded.

~~164~~

~~Table of Contents~~

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

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

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

On September 23, 2015, the Baltimore City Board of Estimates approved an increase in annual rental fees for access to the Baltimore City underground conduit system effective November 1, 2015, from $12 million to $42 million, subject to an annual increase thereafter based on the Consumer Price Index. BGE subsequently entered into litigation with the City regarding the amount of and basis for establishing the conduit fee. On November 30, 2016, the Baltimore City Board of Estimates approved a settlement agreement entered into between BGE 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 to not more than $29 million. BGE recorded a credit to Operating and maintenance expense in the fourth quarter of 2016 of approximately $28 million for the reversal of the previously higher fees accrued in the current year as well as the settlement of prior year disputed fee true-up amounts.

~~Deere Wind Energy Assets (Exelon and Generation)~~

In 2013, Deere & Company (“Deere”) filed a lawsuit against Generation in the Delaware Superior Court relating to Generation’s acquisition of the Deere wind energy assets. Under the purchase agreement, Deere was entitled to receive earn-out payments if certain specific wind projects already under development in Michigan met certain development and construction milestones following the sale. In the complaint, Deere seeks to recover a $14 million earn-out payment associated with one such project, which was never completed. Generation has filed counterclaims against Deere for breach of contract, with a right of recoupment and set off. On June 2, 2016, the Delaware Superior Court entered summary judgment in favor of Deere. On January 17, 2017, Generation filed an appeal of the Superior Court’s summary judgment 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)~~

~~The~~(Exelon and Generation). On April 10, 2017, the City of Everett ~~has filed a petition with~~petitioned the Massachusetts Economic Assistance Coordinating Council (EACC) to revoke the 1999 tax increment financing agreement (TIF Agreement) relating to Mystic Units 8 &and 9 on the grounds that the total investment in Mystic Units 8 &and 9 materially deviates from the investment set forth in the TIF Agreement. ~~The EACC has appointed~~On October 31, 2017, a three-member panel ~~to conduct~~of the EACC conducted an administrative hearing on the City’s petition. ~~Generation has reviewed~~On November 30, 2017, the hearing panel issued a tentative decision denying the City’s ~~claim~~petition, finding that there was no material misrepresentation that would justify revocation of the TIF Agreement. On December 13, 2017, the tentative decision was adopted by the full EACC. On January 12, 2018, the City filed a complaint in Massachusetts Superior Court requesting, among other things, that the court set aside the EACC’s decision, grant the City’s request

108

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 14 — Commitments and Contingencies

to decertify the Project and the TIF Agreement, and award the City damages for alleged underpaid taxes over the period of the TIF Agreement. On January 8, 2020, the Massachusetts Superior Court affirmed the decision of the EACC denying the City's petition. The City had until March 9, 2020 to appeal the decision and did not. As a result, the decision is final and the case is resolved. It is reasonably possible that property taxes assessed in future periods, including those following the expiration of the current TIF Agreement in 2020, could be material to Generation’s financial statements.

Subpoenas (Exelon and ComEd). Exelon and ComEd received a grand jury subpoena in the second quarter of 2019 from the U.S. Attorney’s Office for the Northern District of Illinois requiring production of information concerning their lobbying activities in the State of Illinois. On October 4, 2019, Exelon and ComEd received a second grand jury subpoena from the U.S. Attorney's Office for the Northern District of Illinois requiring production of records of any communications with certain individuals and entities. On October 22, 2019, the SEC notified Exelon and ComEd that it has also opened an investigation into their lobbying activities. Exelon and ComEd have cooperated fully and intend to continue to cooperate fully and expeditiously with the U.S. Attorney’s Office and the SEC. Exelon and ComEd cannot predict the outcome of the U.S. Attorney's Office or the SEC investigations. No loss contingency has been reflected in Exelon's and ComEd's consolidated financial statements as this contingency is neither probable nor reasonably estimable at this time. Management is currently unable to estimate a range of reasonably possible loss as these matters are subject to change.

Subsequent to Exelon announcing the receipt of the subpoenas, a putative class action lawsuit has been filed against Exelon and certain officers of Exelon and ComEd alleging misrepresentations or omissions by Exelon purporting to relate to matters that are the subject of the subpoenas and the SEC investigation. In addition, a derivative shareholder lawsuit has been filed against Exelon, its directors and certain officers alleging, among other things, a breach of fiduciary duties also purporting to relate to matters that are the subject of the subpoenas and the SEC investigation. Exelon believes that ~~it lacks merit. Generation has not recorded an accrual for payment resulting from such a revocation because~~these claims lack merit and intends to defend against them, and though the ~~range of~~costs or any loss ~~if any,~~associated with the lawsuits cannot be reasonably estimated at this ~~time. Property taxes assessed in future periods could be~~time, Exelon does not believe that the lawsuits, either individually or collectively, will have a material ~~to Generation’s results of operations and cash flows.~~adverse impact on Exelon’s or ComEd’s consolidated financial statements.

General (All Registrants)

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

~~Income Taxes (Exelon, Generation, ComEd, PECO and BGE)~~

~~See Note 12 — Income Taxes for information regarding the Registrants’ income tax refund claims and certain tax positions, including the 1999 sale of fossil generating assets.~~

~~165~~

15. Changes in Accumulated Other Comprehensive Income (Exelon)

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



Three Months Ended March 31, 2020	Losses on Cash Flow Hedges			Pension and Non-Pension Postretirement Benefit Plan Items ^(a)			Foreign Currency Items			Total
Beginning balance	$	(2	)	$	(3,165	)	$	(27	)	$	(3,194	)
OCI before reclassifications	(1		)	(7		)	(8		)	(16		)
Amounts reclassified from AOCI	—			37			—			37
Net current-period OCI	(1		)	30			(8		)	21
Ending balance	$	(3	)	$	(3,135	)	$	(35	)	$	(3,173	)

109

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 15 — Changes in Accumulated Other Comprehensive Income

~~19.~~



Three Months Ended March 31, 2019	Losses on Cash Flow Hedges			Pension and Non-Pension Postretirement Benefit Plan Items ^(a)			Foreign Currency Items			AOCI of Investments in Unconsolidated Affiliates ^(b)			Total
Beginning balance	$	(2	)	$	(2,960	)	$	(33	)	$	—		$	(2,995	)
OCI before reclassifications	—			(38		)	2			(1		)	(37		)
Amounts reclassified from AOCI	—			20			—			—			20
Net current-period OCI	—			(18		)	2			(1		)	(17		)
Ending balance	$	(2	)	$	(2,978	)	$	(31	)	$	(1	)	$	(3,012	)

_________


(a)	AOCI amounts are included in the computation of net periodic pension and OPEB cost. See Note 10 — Retirement Benefits for additional information. See Exelon's Statements of Operations and Comprehensive Income for individual components of AOCI.


(b)	All amounts are net of noncontrolling interests.

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



	Three Months Ended March 31,
	2020			2019
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	$	4		$	6
Actuarial loss reclassified to periodic benefit cost	(17		)	(13		)
Pension and non-pension postretirement benefit plans valuation adjustment	3			14

16. Variable Interest Entities (Exelon, Generation, PHI and ACE)

At March 31, 2020 and December 31, 2019, Exelon, Generation, PHI and ACE collectively consolidated several VIEs or VIE groups for which the applicable Registrant was the primary beneficiary (see Consolidated VIEs below) and had significant interests in several other VIEs for which the applicable Registrant does not have the power to direct the entities’ activities and, accordingly, was not the primary beneficiary (see Unconsolidated VIEs below). Consolidated and unconsolidated VIEs are aggregated to the extent that the entities have similar risk profiles.

Consolidated VIEs

The table below shows the carrying amounts and classification of the consolidated VIEs’ assets and liabilities included in the consolidated financial statements of Exelon, Generation, PHI and ACE as of March 31, 2020 and December 31, 2019. The assets, except as noted in the footnotes to the table below, can only be used to settle obligations of the VIEs. The liabilities, except as noted in the footnote to the table below, are such that creditors, or beneficiaries, do not have recourse to the general credit of Exelon, Generation, PHI and ACE.

110

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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



	March 31, 2020								December 31, 2019
	Exelon		Generation		PHI ^(a)		ACE		Exelon		Generation		PHI ^(a)		ACE
Cash and cash equivalents	$	51	$	51	$	—	$	—	$	163	$	163	$	—	$	—
Restricted cash and cash equivalents	84		81		3		3		88		85		3		3
Accounts receivable
Customer	131		131		—		—		151		151		—		—
Other	44		44		—		—		39		39		—		—
Unamortized energy contract assets ^(b)	22		22		—		—		23		23		—		—
Inventories, net
Materials and supplies	231		231		—		—		227		227		—		—
Other current assets	42		38		4		—		32		31		1		—
Total current assets	605		598		7		3		723		719		4		3
Property, plant and equipment, net ^(c)	6,017		6,017		—		—		6,022		6,022		—		—
Nuclear decommissioning trust funds	2,405		2,405		—		—		2,741		2,741		—		—
Unamortized energy contract assets ^(b)	264		264		—		—		250		250		—		—
Other noncurrent assets	71		56		15		12		89		73		16		14
Total noncurrent assets	8,757		8,742		15		12		9,102		9,086		16		14
Total assets	$	9,362	$	9,340	$	22	$	15	$	9,825	$	9,805	$	20	$	17
Long-term debt due within one year	$	543	$	519	$	24	$	20	$	544	$	523	$	21	$	20
Accounts payable	121		121		—		—		106		106		—		—
Accrued expenses	46		46		—		—		70		70		—		—
Unamortized energy contract liabilities	7		7		—		—		8		8		—		—
Other current liabilities	3		3		—		—		3		3		—		—
Total current liabilities	720		696		24		20		731		710		21		20
Long-term debt	502		483		19		16		527		504		23		21
Asset retirement obligations ^(d)	2,156		2,156		—		—		2,128		2,128		—		—
Unamortized energy contract liabilities	1		1		—		—		1		1		—		—
Other noncurrent liabilities	37		37		—		—		89		89		—		—
Total noncurrent liabilities	2,696		2,677		19		16		2,745		2,722		23		21
Total liabilities	$	3,416	$	3,373	$	43	$	36	$	3,476	$	3,432	$	44	$	41

_________


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


(b)	These are unrestricted assets to Exelon and Generation.


(c)	Exelon’s and Generation’s balances include unrestricted assets of $20 million as of March 31, 2020 and December 31, 2019.


(d)	Exelon’s and Generation’s balances include liabilities with recourse of $4 million and $3 million as of March 31, 2020 and December 31, 2019, respectively.

111

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

As of March 31, 2020 and December 31, 2019, Exelon's and Generation's consolidated VIEs consist of:



Consolidated VIE or VIE groups:	Reason entity is a VIE:	Reason Generation is primary beneficiary:
CENG - A joint venture between Generation and EDF. Generation has a 50.01% equity ownership in CENG. See additional discussion below.	Disproportionate relationship between equity interest and operational control as a result of the Nuclear Operating Services Agreement (NOSA) described further below.	Generation conducts the operational activities.
EGRP - A collection of wind and solar project entities. Generation has a 51% equity ownership in EGRP. See additional discussion below.	Similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner.	Generation conducts the operational activities.
Bluestem Wind Energy Holdings, LLC - A Tax Equity structure which is consolidated by EGRP. Generation is a minority interest holder.	Similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner.	Generation conducts the operational activities.
Antelope Valley - A solar generating facility, which is 100% owned by Generation. Antelope Valley sells all of its output to PG&E through a PPA.	The PPA contract absorbs variability through a performance guarantee.	Generation conducts all activities.
Equity investment in distributed energy company - Generation has a 31% equity ownership. This distributed energy company has an interest in an unconsolidated VIE (see Unconsolidated VIEs disclosure below). Generation fully impaired this investment in the third quarter of 2019. See Note 11— Asset Impairments of the Exelon 2019 Form 10-K for additional information.	Similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner.	Generation conducts the operational activities.

CENG - On April 1, 2014, Generation, CENG, and subsidiaries of CENG executed the NOSA pursuant to which Generation conducts all activities associated with the operations of the CENG fleet and provides corporate and administrative services to CENG and the CENG fleet for the remaining life of the CENG nuclear plants as if they were a part of the Generation nuclear fleet, subject to the CENG member rights of EDF.

EDF has the option to sell its 49.99% equity interest in CENG to Generation exercisable beginning on January 1, 2016 and thereafter until June 30, 2022. On November 20, 2019, Generation received notice of EDF's intention to exercise the put option to sell its interest in CENG to Generation and the put automatically exercised on January 19, 2020 at the end of the sixty-day advance notice period.

At this time, Generation cannot reasonably predict the ultimate purchase price that will be paid to EDF for its interest in CENG. The transaction will require approval by the NYPSC, the FERC and the NRC. The process and regulatory approvals could take one to two years or more to complete.

See Note 2 - Mergers, Acquisitions and Dispositions of the Exelon 2019 Form 10-K for additional information regarding the Put Option Agreement with EDF.

Exelon and Generation, where indicated, provide the following support to CENG:

•

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 of the Exelon 2019 Form 10-K for more details,

Generation and EDF share in the $688 million of contingent payment obligations for the payment of contingent retrospective premium adjustments for the nuclear liability insurance, and

Exelon has executed an agreement to provide up to $245 million to support the operations of CENG as well as a $165 million guarantee of CENG’s cash pooling agreement with its subsidiaries.

EGRP - EGRP is a collection of wind and solar project entities and some of these project entities are VIEs that are consolidated by EGRP. Generation owns a number of limited liability companies that build, own, and operate solar

112

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

and wind power facilities some of which are owned by EGRP. While Generation or EGRP owns 100% of the solar entities and 100% of the majority of the wind entities, it has been determined that certain of the solar and wind entities are VIEs because the entities require additional subordinated financial support in the form of a parental guarantee of debt, loans from the customers in order to obtain the necessary funds for construction of the solar facilities, or the customers absorb price variability from the entities through the fixed price power and/or REC purchase agreements. Generation is the primary beneficiary of these solar and wind entities that qualify as VIEs because Generation controls the design, construction, and operation of the facilities. Generation provides operating and capital funding to the solar and wind entities for ongoing construction, operations and maintenance and there is limited recourse related to Generation related to certain solar and wind entities.

In 2017, Generation’s interests in EGRP were contributed to and are pledged for the ExGen Renewables IV non-recourse debt project financing structure. Refer to Note 12— Debt and Credit Agreements for additional information on ExGen Renewables IV.

As of March 31, 2020 and December 31, 2019, Exelon's, PHI's and ACE's consolidated VIE consists of:



Consolidated VIEs:	Reason entity is a VIE:	Reason ACE is the primary beneficiary:
ACE Transition Funding - 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. Proceeds from the sale of each series of transition bonds by ATF were transferred to ACE in exchange for the transfer by ACE to ATF of the right to collect a non-bypassable Transition Bond Charge from ACE customers pursuant to bondable stranded costs rate orders issued by the NJBPU in an amount sufficient to fund the principal and interest payments on transition bonds and related taxes, expenses and fees.	ACE’s equity investment is a variable interest as, by design, it absorbs any initial variability of ACETF. The bondholders also have a variable interest for the investment made to purchase the transition bonds.	ACE controls the servicing activities.

Unconsolidated VIEs

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

As of March 31, 2020 and December 31, 2019, Exelon and Generation had significant unconsolidated variable interests in several VIEs for which Exelon or Generation, as applicable, was not the primary beneficiary. These interests include certain equity method investments and certain commercial agreements.

113

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

The following table presents summary information about Exelon's and Generation’s significant unconsolidated VIE entities:



	March 31, 2020						December 31, 2019
	Commercial Agreement VIEs		Equity Investment VIEs		Total		Commercial Agreement VIEs		Equity Investment VIEs		Total
Total assets^(a)	$	695	$	431	$	1,126	$	636	$	443	$	1,079
Total liabilities^(a)	158		223		381		33		227		260
Exelon's ownership interest in VIE^(a)	—		183		183		—		191		191
Other ownership interests in VIE^(a)	538		25		563		604		25		629

_________

(a)

These items represent amounts on the unconsolidated VIE balance sheets, not in Exelon’s or Generation’s Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs. Exelon and Generation do not have any exposure to loss as they do not have a carrying amount in the equity investment VIEs as of March 31, 2020 and December 31, 2019.

As of March 31, 2020 and December 31, 2019, Exelon's and Generation's unconsolidated VIEs consist of:



Unconsolidated VIE groups:	Reason entity is a VIE:	Reason Generation is not the primary beneficiary:
Equity investments in distributed energy companies - 1) Generation has a 90% equity ownership in a distributed energy company. 2) Generation, via a consolidated VIE, has a 90% equity ownership in another distributed energy company (See Consolidated VIEs disclosure above). Generation fully impaired this investment in the third quarter of 2019. See Note 11— Asset Impairments of the Exelon 2019 Form 10-K for additional information.	Similar structures to a limited partnership and the limited partners do not have kick out rights with respect to the general partner.	Generation does not conduct the operational activities.
Energy Purchase and Sale agreements - Generation has several energy purchase and sale agreements with generating facilities.	PPA contracts that absorb variability through fixed pricing.	Generation does not conduct the operational activities.

114

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 17 — Supplemental Financial Information

17. 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.



	Operating revenues
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Three Months Ended March 31, 2020
Operating lease income	$	5	$	3	$	—	$	—	$	—	$	1	$	—	$	1	$	—
Variable lease income	69		69		—		—		—		—		—		—		—

Three Months Ended March 31, 2019
Operating lease income	$	4	$	3	$	—	$	—	$	—	$	1	$	—	$	1	$	—
Variable lease income	52		52		—		—		—		—		—		—		—

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



	Taxes other than income taxes
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Three Months Ended March 31, 2020
Utility taxes^(a)	$	218	$	26	$	60	$	31	$	26	$	75	$	69	$	6	$	—
Property	150		69		7		4		39		31		21		9		1
Payroll	63		31		7		4		4		8		2		1		1

Three Months Ended March 31, 2019
Utility taxes^(a)	$	223	$	26	$	62	$	34	$	27	$	74	$	69	$	5	$	—
Property	149		71		7		3		37		29		21		8		—
Payroll	65		33		7		4		4		7		2		1		1

_________

(a)

Generation’s utility tax represents gross receipts tax related to its retail operations, and the Utility Registrants' utility taxes represents municipal and state utility taxes and gross receipts taxes related to their operating revenues. The offsetting collection of utility taxes from customers is recorded in revenues in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.

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

~~166~~115

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 17 — 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

~~167~~

~~Table of Contents~~

~~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 )



	Other, net
	Exelon			Generation			ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Three Months Ended March 31, 2020
Decommissioning-related activities:
Net realized income on NDT funds^(a)
Regulatory agreement units	$	47		$	47		$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-regulatory agreement units	82			82			—		—		—		—		—		—		—
Net unrealized gains on NDT funds
Regulatory agreement units	(932		)	(932		)	—		—		—		—		—		—		—
Non-regulatory agreement units	(706		)	(706		)	—		—		—		—		—		—		—
Regulatory offset to NDT fund-related activities^(b)	709			709			—		—		—		—		—		—		—
Decommissioning-related activities	(800		)	(800		)	—		—		—		—		—		—		—
AFUDC — Equity	23			—			6		3		5		9		6		1		2
Non-service net periodic benefit cost	10			—			—		—		—		—		—		—		—

Three Months Ended March 31, 2019
Decommissioning-related activities:
Net realized income on NDT funds^(a)
Regulatory agreement units	$	54		$	54		$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-regulatory agreement units	54			54			—		—		—		—		—		—		—
Net unrealized losses on NDT funds
Regulatory agreement units	379			379			—		—		—		—		—		—		—
Non-regulatory agreement units	280			280			—		—		—		—		—		—		—
Regulatory offset to NDT fund-related activities^(b)	(348		)	(348		)	—		—		—		—		—		—		—
Decommissioning-related activities	419			419			—		—		—		—		—		—		—
AFUDC — Equity	22			—			5		3		5		9		6		1		2
Non-service net periodic benefit cost	5			—			—		—		—		—		—		—		—

_________


(a)	~~Includes investment~~Realized income includes interest, dividends and realized gains and losses on sales of ~~investments of the trust funds.~~NDT fund investments.


(b)	Includes the elimination of ~~NDT fund activity~~decommissioning-related activities for the Regulatory Agreement Units, including the elimination of ~~net~~ income taxes related to all NDT fund activity for those units. See Note 169 — Asset Retirement Obligations of the Exelon ~~2016~~2019 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.~~

The following 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 represents 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 on 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~~116

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 17 — Supplemental Financial Information

Three Months Ended September 30, 2016
Successor
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Utility taxes $ 255

$ 35

$ 67

$ 40

$ 21
$ 92
$ 87

$ 5

$ —

Supplemental Cash Flow Information

The following tables provide additional information ~~regarding~~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		Depreciation, amortization and accretion
	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		PHI		Pepco		DPL		ACE
	Exelon			Generation			ComEd		PECO		BGE		Pepco		DPL		ACE		PHI		PHI
Depreciation, amortization and accretion
Three Months Ended March 31, 2020																							Three Months Ended March 31, 2020
Property, plant and equipment^(a)	$	2,490		$	1,297		$	524	$	181	$	223	$	128	$	82	$	61	$	215	$	94	$	856	$	290	$	228	$	79	$	97	$	144	$	64	$	38	$	34
Amortization of regulatory assets^(a)	293			—			49		20		84		93		38		69		140		58		149		—		45		7		46		50		31		10		9
Amortization of intangible assets, net^(a)	38			32			—		—		—		—		—		—		—		—		16		14		—		—		—		—		—		—		—
Amortization of energy contract assets and liabilities^(b)	(7		)	(7		)	—		—		—		—		—		—		—		—		2		2		—		—		—		—		—		—		—
Nuclear fuel^(c)	862			862			—		—		—		—		—		—		—		—		231		231		—		—		—		—		—		—		—
ARO accretion^(d)	333			332			1		—		—		—		—		—		—		—		124		124		—		—		—		—		—		—		—
Total depreciation, amortization and accretion	$	4,009		$	2,516		$	574	$	201	$	307	$	221	$	120	$	130	$	355	$	152	$	1,378	$	661	$	273	$	86	$	143	$	194	$	95	$	48	$	43

Three Months Ended March 31, 2019																							Three Months Ended March 31, 2019
Property, plant and equipment^(a)																							$	917	$	392	$	219	$	74	$	85	$	127	$	58	$	35	$	25
Amortization of regulatory assets^(a)																							143		—		32		7		51		53		36		11		6
Amortization of intangible assets, net^(a)																							15		13		—		—		—		—		—		—		—
Nuclear fuel^(c)																							261		261		—		—		—		—		—		—		—
ARO accretion^(d)																							124		123		—		—		—		—		—		—		—
Total depreciation, amortization and accretion																							$	1,460	$	789	$	251	$	81	$	136	$	180	$	94	$	46	$	31

_________


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


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


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


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

~~169~~117

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 17 — Supplemental Financial Information



	Other non-cash operating activities
	Exelon			Generation			ComEd			PECO		BGE			PHI			Pepco			DPL			ACE
Three Months Ended March 31, 2020
Pension and non-pension postretirement benefit costs	$	98		$	27		$	28		$	1	$	15		$	17		$	3		$	1		$	3
Provision for uncollectible accounts	45			4			7			17		7			10			4			3			3
Other decommissioning-related activity^(a)	128			128			—			—		—			—			—			—			—
Energy-related options^(b)	6			6			—			—		—			—			—			—			—
Amortization of rate stabilization deferral	(54		)	—			—			—		(35		)	(19		)	(15		)	(4		)	—
Discrete impacts from EIMA and FEJA^(c)	(17		)	—			(17		)	—		—			—			—			—			—
Long-term incentive plan	(7		)	—			—			—		—			—			—			—			—
Amortization of operating ROU asset	51			35			—			—		8			5			2			2			1

Three Months Ended March 31, 2019
Pension and non-pension postretirement benefit costs	$	106		$	31		$	24		$	2	$	15		$	23		$	6		$	4		$	4
Provision for uncollectible accounts	43			—			9			16		8			10			4			4			2
Other decommissioning-related activity^(a)	(202		)	(202		)	—			—		—			—			—			—			—
Energy-related options^(b)	37			37			—			—		—			—			—			—			—
Amortization of rate stabilization deferral	(6		)	—			—			—		—			(6		)	(7		)	1			—
Discrete impacts from EIMA and FEJA^(c)	28			—			28			—		—			—			—			—			—
Long-term incentive plan	25			—			—			—		—			—			—			—			—
Amortization of operating ROU asset	53			34			1			—		8			9			2			2			1

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~~

~~Table of Contents~~

~~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~~decommissioning-related activities for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income and income taxes related to all NDT fund activity for these units. See Note ~~16 -~~9 — Asset Retirement Obligations of the Exelon ~~2016~~2019 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 to results of operations.


(c)	Reflects the change in ~~Operating revenues.~~ComEd's distribution and energy efficiency formula rates. See Note 2 — Regulatory Matters for additional information.

~~171~~118

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 17 — Supplemental Financial Information

~~(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.~~

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		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
March 31, 2020
Cash and cash equivalents	$	1,457	$	821	$	514	$	31	$	11	$	49	$	18	$	7	$	8
Restricted cash	414		150		211		7		1		37		33		—		3
Restricted cash included in other long-term assets	121		—		108		—		—		12		—		—		12
Total cash, cash equivalents and restricted cash	$	1,992	$	971	$	833	$	38	$	12	$	98	$	51	$	7	$	23

December 31, 2019
Cash and cash equivalents	$	587	$	303	$	90	$	21	$	24	$	131	$	30	$	13	$	12
Restricted cash	358		146		150		6		1		36		33		—		2
Restricted cash included in other long-term assets	177		—		163		—		—		14		—		—		14
Total cash, cash equivalents and restricted cash	$	1,122	$	449	$	403	$	27	$	25	$	181	$	63	$	13	$	28

March 31, 2019
Cash and cash equivalents	$	880	$	537	$	68	$	41	$	12	$	33	$	11	$	7	$	6
Restricted cash	223		139		17		6		4		39		35		1		3
Restricted cash included in other long-term assets	211		—		193		—		—		19		—		—		19
Total cash, cash equivalents and restricted cash	$	1,314	$	676	$	278	$	47	$	16	$	91	$	46	$	8	$	28

December 31, 2018
Cash and cash equivalents	$	1,349	$	750	$	135	$	130	$	7	$	124	$	16	$	23	$	7
Restricted cash	247		153		29		5		6		43		37		1		4
Restricted cash included in other long-term assets	185		—		166		—		—		19		—		—		19
Total cash, cash equivalents and restricted cash	$	1,781	$	903	$	330	$	135	$	13	$	186	$	53	$	24	$	30

For additional information on restricted cash see Note 1 — Significant Accounting Policies of the Exelon 2019 Form 10-K.

119

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 17 — Supplemental Financial Information

Supplemental Balance Sheet Information

The following tables provide additional information about ~~assets and liabilities of~~material items recorded in the ~~Registrants as of September 30, 2017 and December 31, 2016.~~Registrants' Consolidated Balance Sheets.

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



	Accrued expenses
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
March 31, 2020
Compensation-related accruals^(a)	$	557	$	207	$	87	$	39	$	44	$	63	$	22	$	14	$	10
Taxes accrued	442		244		85		1		43		114		79		25		7
Interest accrued	407		84		69		33		38		78		37		20		19

December 31, 2019
Compensation-related accruals^(a)	$	1,052	$	422	$	171	$	58	$	78	$	101	$	28	$	19	$	15
Taxes accrued	414		222		83		3		26		117		90		14		8
Interest accrued	337		65		110		37		46		49		23		8		12

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~~Primarily includes accrued payroll, bonuses and other incentives, vacation and benefits.

18. Related Party Transactions (All Registrants)

Operating revenues from affiliates

Generation

The following table presents Generation’s Operating revenues from affiliates, which are primarily recorded as Purchased power from affiliates and an immaterial amount recorded as Operating and maintenance expense from affiliates at the Utility Registrants:



	Three Months Ended March 31,
	2020		2019
Operating revenues from affiliates:
ComEd ^(a)(b)	$	90	$	94
PECO ^(c)	37		45
BGE ^(d)	99		76
PHI	103		101
Pepco ^(e)	79		70
DPL ^(f)	22		23
ACE^(g)	2		8
Other	1		1
Total operating revenues from affiliates (Generation)	$	330	$	317

__________


(a)	Generation has an ICC-approved RFP contract with ComEd to provide a portion of ~~nuclear fuel in the reactor core of $3,303 million.~~ComEd’s electricity supply requirements. Generation also sells RECs and ZECs to ComEd.

(b)

~~Includes accumulated amortization~~For the three months ended March 31, 2020, ComEd’s Purchased power from Generation of ~~nuclear~~$97 million is recorded as Operating revenues from ComEd of $90 million and Purchased power and fuel infrom ComEd of $7 million at Generation. For the ~~reactor core~~three months ended March 31, 2019, ComEd’s Purchased power from Generation of ~~$3,186 million.~~$97 million is recorded as Operating revenues from ComEd of $94 million and Purchased power and fuel from ComEd of $3 million at Generation.


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

~~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~~120

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 18 — Related Party Transactions

~~20. Segment Information (All Registrants)~~


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


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


(f)	Generation provides a portion of DPL's energy requirements under its MDPSC and DPSC approved market based SOS and gas commodity programs.


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

PHI

PHI’s Operating revenues from affiliates are primarily with BSC for services that PHISCO provides to BSC.

Operating ~~segments for each~~and maintenance expense from affiliates

The Registrants receive a variety 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 ofcorporate 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 ~~Generation’s sixreportable segments consisting of~~PHISCO.

The following table presents 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 conformservice company costs allocated 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:Registrants:

~~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.~~



	Operating and maintenance from affiliates				Capitalized costs
	Three Months Ended March 31,				Three Months Ended March 31,
	2020		2019		2020		2019
Exelon
BSC					$	113	$	99
PHISCO					14		22
Generation
BSC	$	140	$	149	11		11
ComEd
BSC	72		62		42		25
PECO
BSC	37		37		16		22
BGE
BSC	41		38		28		21
PHI
BSC	37		32		16		19
PHISCO	—		—		14		22
Pepco
BSC	21		21		6		8
PHISCO	30		33		6		9
DPL
BSC	13		13		5		5
PHISCO	24		26		4		7
ACE
BSC	11		11		4		4
PHISCO	22		23		4		6

~~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~~121

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 18 — Related Party Transactions

~~in this report. Generation’s operating revenues include all sales~~

Current Receivables from/Payables to ~~third parties~~affiliates

The following tables present current receivables from affiliates and ~~affiliated sales~~current payables 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.affiliates:

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~~March 31, 2020

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



	Receivables from affiliates:
Payables to affiliates:	Generation			Comed		PECO		BGE		DPL		ACE		BSC		PHISCO		Other		Total
Generation				$	17	$	—	$	—	$	1	$	—	$	67	$	—	$	43	$	128
ComEd	$	69	(a)			—		—		—		—		42		—		3		114
PECO	25			—				—		—		—		19		—		7		51
BGE	22			—		—				—		—		27		—		3		52
PHI	—			—		—		—		—		—		3		—		10		13
Pepco	29			—		—		1		—		—		11		12		2		55
DPL	1			—		—		—				3		7		9		1		21
ACE	12			—		—		—		—				5		9		1		27
Other	9			1		—		—		—		1		—		—				11
Total	$	167		$	18	$	—	$	1	$	1	$	4	$	181	$	30	$	70	$	472

December 31, 2019

~~174~~



	Receivables from affiliates:
Payables to affiliates:	Generation			Comed		PECO		BGE		DPL		ACE		BSC		PHISCO		Other		Total
Generation				$	27	$	—	$	—	$	—	$	—	$	67	$	—	$	23	$	117
ComEd	$	78	(a)			—		—		—		—		54		—		8		140
PECO	27			—				—		—		—		25		—		3		55
BGE	28			—		—				—		—		34		—		4		66
PHI	—			—		—		—		—		—		4		—		10		14
Pepco	34			—		—		—		—		—		16		15		1		66
DPL	7			—		—		—				3		10		11		1		32
ACE	7			—		—		—		—				7		10		1		25
Other	9			1		1		1		—		1		—		—				13
Total	$	190		$	28	$	1	$	1	$	—	$	4	$	217	$	36	$	51	$	528

__________

(a)

At March 31, 2020 and December 31, 2019, Generation also had a contract liability with ComEd for $27 million and $37 million, respectively, that was included in Other liabilities on Generation’s Consolidated Balance Sheets. At March 31, 2020 and December 31, 2019, ComEd had a Current Payable to Generation of $42 million and $41 million, respectively, on its Consolidated Balance Sheets, which consisted of Generation’s Current Receivable from ComEd, partially offset by Generation’s contract liability with ComEd.

Borrowings from Exelon/PHI intercompany money pool

To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing both Exelon and PHI operate an intercompany money pool. Generation, ComEd, PECO, and PHI Corporate participate in the Exelon money pool. Pepco, DPL and ACE participate in the PHI intercompany money pool.

Noncurrent Receivables from/Payables to affiliates

122

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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

Note 18 — Related Party Transactions

Generation has long-term payables to ComEd and PECO as a result of the nuclear decommissioning contractual construct whereby, to the extent NDT funds are greater than the underlying ARO at the end of decommissioning, such amounts are due back to ComEd and PECO, as applicable, for payment to their respective customers. See Note 9 — Asset Retirement Obligations of the Exelon 2019 Form 10-K for additional information.

The following table presents noncurrent receivables from affiliates at ComEd and PECO which are recorded as noncurrent payables to affiliates at Generation:



	March 31, 2020		December 31, 2019
ComEd	$	2,040	$	2,622
PECO	261		480
Other	1		1
Total:	$	2,302	$	3,103

Long-term debt to financing trusts

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



	March 31, 2020						December 31, 2019
	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

Long-term debt to affiliates

In connection with the debt obligations assumed by Exelon as part of the Constellation merger, Exelon and subsidiaries of Generation (former Constellation subsidiaries) assumed intercompany loan agreements that mirror the terms and amounts of the third-party debt obligations of Exelon, resulting in intercompany notes payable included in Long-term debt to affiliates in Generation’s Consolidated Balance Sheets and intercompany notes receivable at Exelon Corporate.

19. Subsequent Events (Exelon and Generation)

Sales of Customer Accounts Receivable

On April 8, 2020, NER, a bankruptcy remote, special purpose entity, which is wholly-owned by Generation, entered into a revolving accounts receivable financing arrangement with a number of financial institutions and a commercial paper conduit (the Purchasers) to sell certain customer accounts receivable (the Facility). The Facility, whose maximum capacity is $750 million, is scheduled to expire on April 7, 2021, unless renewed by the mutual consent of the parties in accordance with its terms. Under the Facility, NER may sell eligible short-term customer accounts receivable to the Purchasers in exchange for cash and subordinated interest. The transfers are reported as sales of receivables in Exelon’s and Generation’s consolidated financial statements. The subordinated interest in collections upon the receivables sold to the Purchasers is referred to as the deferred purchase price (DPP). Generation continues to service the receivables sold in exchange for a servicing fee.

On April 8, 2020, NER received approximately $500 million in cash purchase price in accordance with the initial sale of approximately $1.2 billion receivables to the Purchasers under the Facility.

~~_________~~

~~(a)~~Item 2.

~~Generation includes the six reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT~~Management’s Discussion and ~~Other Power Regions. Intersegment revenues for Generation for the three months ended September 30, 2017 include revenue from sales to PECO~~Analysis of ~~$31 million, sales to BGE~~Financial Condition and Results 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.Operations


~~(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)~~

~~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)

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 generation, delivery, and ~~a wholly owned subsidiary~~marketing of ~~Exelon.~~energy through Generation and the energy distribution and transmission businesses through ComEd, PECO, BGE, Pepco, DPL and ACE.

Exelon has ~~twelve~~eleven reportable segments consisting of Generation’s ~~six~~five reportable segments (Mid-Atlantic, Midwest, ~~New England,~~ New York, ERCOT and Other Power ~~Regions in Generation)~~Regions), 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 4 — 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 separate operating subsidiary registrants, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, which, along with Exelon, are collectively

~~180~~

~~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~~COVID-19. The Registrants are responding to the global outbreak (pandemic) of ~~Operations~~

~~GAAP Results~~COVID-19 and have taken steps to mitigate the potential risks to the Registrants posed by its spread. The Registrants provide a critical service to our customers which means that it is paramount that we keep our employees who operate our business safe and minimize unnecessary risk of ~~Operations~~exposure to the virus. The Registrants have taken extra precautions for our employees who work in the field and for employees who continue to work in our facilities, have implemented work from home policies where appropriate, and imposed travel limitations on our employees. In addition, the Registrants have updated our existing business continuity plans for our business units in the context of this pandemic.

The ~~following tables set forth Exelon's GAAP consolidated results~~Registrants continue to implement strong physical and cyber-security measures to ensure that our systems remain functional in order to both serve our operational needs with a remote workforce and keep them running to ensure uninterrupted service to our customers.

There were no changes in internal control over financial reporting during the first quarter of ~~operations~~2020 as of result of COVID-19 that materially affected, or are reasonably likely to materially affect, any of the Registrants’ internal control over financial reporting. See Item 4. Controls and Procedures for additional information.

Generation has temporarily suspended interruption of service for all retail residential customers for non-payment and temporarily ceased new late payment fees for all retail customers. The Utility Registrants have also temporarily suspended customer disconnections for non-payment and temporarily ceased new late fees for all customers and are restoring service to customers who were disconnected in the last twelve months upon request. There was no material increase in the Registrants’ Customer allowance for credit losses at March 31, 2020 as a result of such measures. However, the Registrants expect an increase in Customer allowance for credit losses for the ~~three and~~year ending December 31, 2020. Generation estimates a reduction in Net income due to an increase in credit loss expense of $25 to $75 million for the nine months ~~ended September 30, 2017 compared~~ending December 31, 2020. The Utility Registrants do not expect a reduction in Net income. Typically, they recover credit loss expense through rate required programs or distribution base rate cases. For those jurisdictions without an existing rate required program to recover credit loss expense, the ~~same period~~Utility Registrants are pursuing orders with their respective commissions to recover incremental costs being incurred as a result of COVID-19. In April of 2020, the MDPSC and the DCPSC issued orders authorizing the creation of regulatory assets to track incremental COVID-19 related costs, which will allow for assessment of recovery of those costs in ~~2016. The 2016 amounts include~~future distribution base rate cases. PECO and DPL are pursuing similar orders with the ~~operations of PHI, Pepco, DPL~~PAPUC and the DPSC, respectively. ComEd and ACE ~~from March 24, 2016 through September 30, 2016. All amounts presented below are before the impact~~have existing mechanisms for recovery 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.~~

~~181~~

~~Table of Contents~~

credit loss expense. The timing

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~~of the recovery offset of the increase in credit loss expense could extend beyond 2020, which could have a negative impact on Net income ~~attributable~~for the year ending December 31, 2020.

Unfavorable economic conditions due to ~~common shareholders~~COVID-19 could depress demand for electricity and natural gas in the future. There was ~~$824 million~~no material impact to the Registrants’ Net income for the three months ended ~~September 30, 2017 as compared~~March 31, 2020. However, Generation estimates a reduction in Net income due to ~~$490~~reduction in load of $75 to $225 million for the ~~three~~nine months ~~ended September 30, 2016,~~ending December 31, 2020. Generation’s load forecast is highly dependent on many factors including, but not limited to, the duration of the shelter in place restrictions and ~~diluted earnings per average common share were $0.85 for~~ the ~~three months ended September 30, 2017 as compared~~speed and strength of the economic recovery. The Utility Registrants estimate a reduction in Net income due to ~~$0.53 for the three months ended September 30, 2016.~~

~~Revenue net~~reduction in load of ~~purchased power and fuel expense, which is a non-GAAP measure discussed below, decreased by $21~~$20 to $40 million for the ~~three~~nine months ~~ended September 30, 2017 as compared~~ending December 31, 2020, assuming shelter in place restrictions begin 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.

~~182~~

~~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~~lift in the third quarter of ~~2016 related~~2020. The Utility Registrants load forecast is dependent on, but not limited to, ~~Exelon's like-kind exchange tax position~~the duration of the shelter in place restrictions and ~~higher net realized gains on NDT funds at Generation~~the speed and strength of the economic recovery. A 1% change in load would result in the following change in Net income for the ~~three~~nine months ended ~~September 30, 2017~~December 31, 2020:

To offset part of the unfavorable impacts from increase in credit loss expense and reduction in load, the Registrants identified and are pursuing approximately $250 million in cost savings across Generation and the Utility Registrants.

The Registrants rely on the capital markets for publicly offered debt as ~~compared~~well as the commercial paper markets to meet their financial commitments and short-term liquidity needs. As a result of the ~~same period~~disruptions in ~~2016.~~

~~Exelon’s effective income tax rates~~the commercial paper markets in March of 2020, Generation borrowed $1.5 billion on its revolving credit facility to refinance commercial paper. Generation repaid the $1.5 billion borrowed on the revolving credit facility on April 3, 2020. Generation also entered into two short-term loan agreements in March of 2020 for an aggregate of $500 million. On April 8, 2020, Generation received approximately $500 million in cash after entering into an accounts receivable financing arrangement. On April 1, 2020, Exelon Corporate issued and sold $2 billion in aggregate principal amount of notes, the ~~three months ended September 30, 2017~~proceeds of which will be used to repay existing debt upon maturity and ~~2016 were 34.1%~~for general corporate purposes. On April 24, 2020, Exelon Corporate entered into a credit agreement establishing a $550 million 364-day revolving credit facility. This facility will be used by Exelon as an additional source of short-term liquidity over the next 12 months. Exelon Corporate and ~~39.0%, respectively.~~the Utility registrants continued to issue commercial paper in March of 2020, albeit at higher interest rates. See Liquidity and Capital Resources, Note 12 ~~— Income Taxes~~- Debt and Credit Agreements and Note 19 - Subsequent Events of the Combined Notes to Consolidated Financial Statements for additional information.

The Registrants assessed long-lived assets, goodwill, and investments for recoverability and there were no material impairment charges recorded in the first quarter of 2020. Certain assumptions are highly sensitive to changes. Changes in significant assumptions could potentially result in future impairments, which could be material.

This is a rapidly evolving situation that could lead to extended disruption of economic activity in our markets. The Registrants will continue to monitor developments affecting our workforce, our customers and our suppliers and we will take additional precautions that we determine are necessary in order to mitigate the impacts. The extent to which COVID-19 may impact the Registrants’ ability to operate their generating and transmission and distribution assets, the ability to access capital markets, and results of operations, including demand for electricity and natural gas, will depend on future developments, which are highly uncertain and cannot be predicted at this time. This includes new information ~~regarding~~that is emerging daily concerning the ~~components~~severity of COVID-19, the ~~effective income tax rates.~~spread and proliferation of COVID-19 around the world, and third-party actions taken to contain its spread or treat it, among others.

~~Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016.~~ ~~Exelon’s~~

Financial Results of Operations

GAAP Results of Operations. The following table sets forth Exelon's GAAP consolidated Net ~~income~~Income attributable to common shareholders ~~was $1,899 million~~by Registrant for the ~~nine~~three 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.

~~183~~

~~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~~March 31, 2020 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.

~~184~~

~~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~~2019. For 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, 2020 and ~~fuel expense,~~2019 see the discussions of Results of Operations by ~~Segment below.~~Registrant.



	Three Months Ended March 31,						Favorable (unfavorable) variance
	2020			2019			Favorable (unfavorable) variance
Exelon	$	582		$	907		$	(325	)
Generation	45			363			(318		)
ComEd	168			157			11
PECO	140			168			(28		)
BGE	181			160			21
PHI	108			117			(9		)
Pepco	52			55			(3		)
DPL	45			53			(8		)
ACE	13			10			3
Other^(a)	(60		)	(58		)	(2		)

__________


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

Three Months Ended March 31, 2020 Compared to Three Months Ended March 31, 2019.Net income attributable to common shareholders decreased by $325 million and diluted earnings per average common share decreased to $0.60 in 2020 from $0.93 in 2019 primarily due to:

Lower capacity revenue;

Lower realized energy prices;

Higher nuclear outage days;

Higher net unrealized and realized losses NDT funds; and

Unfavorable weather conditions at PECO, DPL Delaware and ACE.

The decreases were partially offset by:

Higher mark-to-market gains;

The approval of the New Jersey ZEC program in the second quarter of 2019;

An income tax settlement at Generation;

Regulatory rate increases at BGE, DPL, and ACE; and

Higher electric distribution earnings at ComEd primarily due to distribution formula rate timing, partially offset by lower allowed electric distribution ROE due to a decrease in treasury rates.

Adjusted (non-GAAP) Operating ~~Earnings~~

Exelon’s adjusted (non-GAAP) operating earnings for the three months ended September 30, 2017 were $821 million, or $0.85 per diluted share, compared with adjusted (non-GAAP) operating earnings of $841 million, or $0.91 per diluted share for the same period in 2016. Exelon’s adjusted (non-GAAP) operating earnings for the nine months ended September 30, 2017 were $1,935 million, or $2.05 per diluted share, compared with adjusted (non-GAAP) operating earnings of $2,078 million, or $2.24 per diluted share for the same period in 2016. Earnings. In addition to net 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.

~~185~~

~~Table of Contents~~

The following tables provide a reconciliation between net income attributable to common shareholders 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, 2020 compared to the same period in ~~2016.~~2019.

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

~~186~~

~~Table of Contents~~

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



	Three Months Ended March 31,
	2020						2019
(All amounts in millions after tax)				Earnings per Diluted Share						Earnings per Diluted Share
Net Income Attributable to Common Shareholders	$	582		$	0.60		$	907		$	0.93
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $32 and $12, respectively)	(94		)	(0.10		)	31			0.03
Unrealized (Gains) Losses Related to NDT Fund Investments(net of taxes of $405 and $161, respectively)^(a)	485			0.50			(193		)	(0.20		)
Asset Impairments(net of taxes of $1)	2			—			4			—
Plant Retirements and Divestitures (net of taxes of $4 and $6, respectively)^(b)	13			0.01			19			0.02
Cost Management Program (net of taxes of $3 and $3, respectively)^(c)	9			0.01			11			0.01
Income Tax-Related Adjustments (entire amount represents tax expense)	(2		)	—			—			—
Noncontrolling Interests (net of taxes of $30 and $13, respectively)^(d)	(144		)	(0.15		)	67			0.07
Adjusted (non-GAAP) Operating Earnings	$	851		$	0.87		$	846		$	0.87

~~_________~~__________

Note:

Amounts may not sum due to rounding.

Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net Income and Adjusted (non-GAAP) Operating Earnings is based on the marginal statutory federal and state income tax rates for each Registrant, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part. For all items except the unrealized gains and losses related to NDT fund investments, the marginal statutory income tax rates for 2020 and 2019 ranged from ~~39.0 percent~~26.0% to ~~41.0 percent.~~29.0%. Under IRS regulations, NDT fund investment returns are taxed at ~~differing~~different rates for investments if they are in qualified ~~vs.~~or non-qualified funds. The effective tax rates ~~applied to~~for the unrealized gains and losses related to NDT ~~Fund~~fund investments were ~~43.2 percent~~45.5% and ~~46.2 percent~~45.4% for the three ~~and nine~~ months ended ~~September 30, 2017, respectively,~~March 31, 2020 and ~~52.6 percent and 52.5 percent for the three and nine months ended September 30, 2016,~~2019, respectively.

(a)

Reflects the impact of net unrealized gains and losses on Generation’s ~~economic hedging activities. See Note 10 - Derivative Financial Instruments~~NDT fund investments for Non-Regulatory and Regulatory Agreement Units. The impacts of the ~~Combined Notes to Consolidated Financial Statements for additional detail related to Generation’s hedging activities.~~Regulatory Agreement Units, including the associated income taxes, are contractually eliminated, resulting in no earnings impact.

(b)

~~Reflects~~In 2019, primarily reflects accelerated depreciation and amortization expenses associated with the ~~impact of net unrealized gains on Generation’s NDT fund investments for Non-Regulatory Agreement Units. See Note 13 - Nuclear Decommissioning~~early retirement of the ~~Combined Notes to Consolidated Financial Statements for additional detail related to Generation’s NDT fund investments.~~TMI nuclear facility and a benefit associated with a remeasurement of the TMI ARO. In 2020, primarily reflects accelerated depreciation and amortization expenses associated with the early retirement of certain fossil sites.


(c)	~~Reflects the non-cash amortization of intangible assets, net, primarily~~Primarily represents reorganization costs 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.~~cost management programs.


(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.~~

~~187~~

~~Table of Contents~~


~~(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~~interests related to certain exclusion items, primarily related to ~~the impact of~~ unrealized gains and losses on NDT fund investments ~~at CENG.~~for CENG units.


~~(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 )

~~188~~

~~Table of Contents~~

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~~2020 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.

~~189~~

~~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 the Generation's acquisition of FitzPatrick 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.

~~190~~

~~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 connection with the acquisitions 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 million, and $22 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 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 CCGTs in the nation.

Utility Rates and Base Rate Proceedings

The Utility Registrants file base rate cases with their regulatory commissions seeking increases or decreases to their electric transmission and distribution, and gas distribution rates to recover their costs and earn a fair return on

their investments. The outcomes of these regulatory proceedings impact the Utility Registrants’ current and future ~~results of operations, cash flows and~~ financial ~~position.~~

~~191~~

~~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.

~~192~~

~~Table of Contents~~

~~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.

2020. 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 money2 — 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

~~193~~

~~Table of Contents~~

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

~~194~~

~~Table of Contents~~

~~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 these and other regulatory proceedings.

Completed Distribution Base Rate Case Proceedings



Registrant/Jurisdiction	Filing Date	Requested Revenue Requirement (Decrease) Increase			Approved Revenue Requirement (Decrease) Increase			Approved ROE		Approval Date	Rate Effective Date
ComEd - Illinois (Electric)	April 8, 2019	$	(6	)	$	(17	)	8.91	%	December 4, 2019	January 1, 2020

Pending Distribution Base Rate Case Proceedings



Registrant/Jurisdiction	Filing Date	Requested Revenue Requirement (Decrease) Increase			Requested ROE		Expected Approval Timing
ComEd - Illinois (Electric)	April 16, 2020	$	(11	)	8.38	%	Fourth quarter of 2020
Pepco - District of Columbia (Electric)	May 30, 2019 (amended April 8, 2020)	$	147		10.3	%	Fourth quarter of 2020
DPL - Maryland (Electric)	December 5, 2019 (amended April 23, 2020)	$	17		10.3	%	Third quarter of 2020
DPL - Delaware (Gas)	February 21, 2020 (amended March 17, 2020)	$	9		10.3	%	First quarter of 2021
DPL - Delaware (Electric)	March 6, 2020 (amended April 16, 2020)	$	24		10.3	%	First quarter of 2021

Sales of Customer Accounts Receivable

On April 8, 2020, NER, a bankruptcy remote, special purpose entity, which is wholly owned by Generation, entered into an accounts receivable financing facility with a number of financial institutions and a commercial paper conduit to sell certain customer accounts receivables. Generation received approximately $500 million of cash in accordance with the ~~Smart Meter and Smart Grid Initiatives and infrastructure development and enhancement programs.~~

~~Competitive Energy Businesses~~.Generation continually assesses the optimal structure and composition of its generation assets as well as explores wholesale and retail opportunities within the power and gas sectors. Generation’s long-term growth strategy is to ensure appropriate valuation of its generation assets, in part through public policy efforts, identify and capitalize on opportunities that provide generation to load matching as a means to provide stable earnings, and identify emerging technologies where strategic investments provide the option for significant future growth or influence in market development. As of September 30, 2017, Generation has currently approved plans to invest a totalinitial sale of approximately ~~$300 million through 2018 to complete new plant construction currently in progress.~~

~~Liquidity Considerations~~

Each of the Registrants annually evaluates its financing plan, dividend practices and credit line sizing, focusing on maintaining its investment grade ratings while meeting its cash needs to fund capital requirements, retire debt, pay dividends, fund pension and OPEB obligations and invest in new and existing ventures. A broad spectrum of financing alternatives beyond the core financing options can be used to meet its needs and fund growth including monetizing assets in the portfolio via project financing, asset sales, and the use of other financing structures (e.g., joint ventures, minority partners, etc.). The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs and capital expenditure requirements.

~~Exelon, Generation, ComEd, PECO, BGE, Pepco, DPL and ACE have unsecured syndicated revolving credit facilities with aggregate bank commitments of $0.6~~$1.2 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.~~

~~195~~

~~Table of Contents~~

~~Project Financing~~

Generation utilizes individual project financings as a means to finance the construction of various generating asset projects. Project financing is based upon a nonrecourse financial structure, in which project debt and equity used to finance the project are paid back from the cash generated by the newly constructed asset once operational. Borrowings under these agreements are secured by the assets and equity of each respective project. The lenders do not have recourse against Exelon or 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.receivables. See Note ~~6 Impairment of Long-Lived Assets and Note 11 - Debt and Credit Agreements~~19 — Subsequent Events of the Combined Notes to ~~the~~ Consolidated Financial Statements for additional ~~information on nonrecourse debt.~~information.

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 thisRegistrants' combined 2019 Form 10-K and ~~several related orders, PJM hosted its 2018/2019 Base Residual Auction (results posted on August 21, 2015)~~Note 14 — Commitments 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.

~~196~~

~~Table of Contents~~

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~~Contingencies to the Consolidated Financial Statements in this report for additional information on ~~the impacts of the MISO announcement.~~

~~Subsidized Generation~~

~~The rate of expansion of subsidized generation, in the markets in which Generation’s output is sold can negatively impact wholesale power prices, and in turn, Generation’s results of operations.~~

Various states have attempted to implement or propose legislation, regulations or other policies to subsidize new generation development which may result in artificially depressed wholesale energy and capacity prices. For example, the New Jersey legislature enacted into law in January 2011, the Long Term Capacity Pilot Program Act (LCAPP). LCAPP provides eligible generators with 15-year fixed contracts for the sale of capacity in the PJM capacity market. Under LCAPP, the local utilities in New Jersey are required to pay (or receive) the difference between the price eligible generators receive in the capacity market and the price guaranteed under the 15-year contract. New Jersey ultimately selected three proposals to participate in LCAPP and build new generation in the state. In addition, on April 12, 2012, the MDPSC issued an order directing the Maryland electric utilities to enter into a 20-year contract for differences (CfD) with CPV Maryland, LLC (CPV), under which CPV was required to construct an approximately 700 MW combined cycle gas turbine in Waldorf, Maryland. The CfD mandated that utilities (including BGE, Pepco and DPL) pay (or receive) the difference between CPV’s contract price and the revenues it receives for capacity and energy from clearing the unit in the PJM capacity market.

Exelon and others challenged the constitutionality and other aspects of the New Jersey legislation in federal court. The actions taken by the MDPSC were also challenged in federal court in an action to which Exelon was not a party. The federal trial courts in both the New Jersey and Maryland actions effectively invalidated the actions taken by the New Jersey legislature and the MDPSC, respectively. Each of those decisions was upheld by the U.S. Court of Appeals for the Third Circuit and the U.S. Court of Appeals for the Fourth Circuit, respectively. On April 19, 2016, the U.S. Supreme Court affirmed the decision of the U.S. Court of Appeals for the Fourth Circuit, and subsequently denied certiorari with respect to the appeal from the U.S. Court of Appeals for the Third Circuit, leaving in place that Court’s decision. The matter is now considered closed.

As required under their contracts, generator developers who were selected in the New Jersey and Maryland programs (including CPV) offered and cleared in PJM’s capacity market auctions. To the extent that the state-required customer subsidies are included under their respective contracts, Exelon believes that these projects may have artificially suppressed capacity prices in PJM in these auctions and may continue to do so in future auctions to the detriment of Exelon. While the court decisions are positive developments, continuation of these state efforts, if successful and unabated by an effective minimum offer price rule (MOPR) for future capacity auctions, could continue to result in artificially depressed wholesale capacity and/or energy prices. Other states could seek to establish programs, which could substantially impact Exelon’s position and could have a significant effect on Exelon’s financial results of operations, financial position and cash flows.

~~197~~

~~Table of Contents~~

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 orvarious environmental ~~benefits, or that would threaten the reliability and value of the integrated electricity grid.~~matters.

~~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

~~198~~

~~Table of Contents~~

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,~~March 31, 2020, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York and ERCOT reportable segments is ~~98%-101%, 79%-82%~~89%-92% and ~~45%-48%~~70%-73% for ~~2017, 2018,~~2020 and ~~2019~~2021, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted 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

~~199~~

~~Table of Contents~~

~~swaps.~~ Generation has been and will continue to be proactive in using hedging strategies to mitigate commodity price ~~risk in subsequent years as well.~~risk.

Generation procures ~~oil and~~ natural gas through long-term and short-term contracts and spot-market purchases. Nuclear fuel isassemblies 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 ~~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~~2020 through ~~2021~~2024 are supplied by three ~~producers.~~suppliers. In the event of non-performance by these or other suppliers, Generation believes that replacement uranium concentrate can be obtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements. Non-performance by these counterparties could have a material adverse impact on Exelon’s and Generation’s results of operations, cash flows and financial ~~position.~~positions.

See Note 11 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements and Item 3. Quantitative and Qualitative Disclosures about Market Risk for additional information.

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

~~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

~~200~~

~~Table of Contents~~

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.~~

~~201~~

~~Table of Contents~~

~~Solid and Hazardous Waste~~

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

See Note 18—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for further detail related to environmental matters, including the impact of environmental regulation.

~~Other Legislative and Regulatory Developments~~

~~NRC Task Force on Fukushima Daiichi Accident (Exelon and Generation).~~

In July 2011, an NRC Task Force formed in the aftermath of the March 11, 2011, 9.0 magnitude earthquake and ensuing tsunami, that seriously damaged the nuclear units at the Fukushima Daiichi Nuclear Power Station, issued a report of its review of the accident, including tiered recommendations for future regulatory action by the NRC to be taken in the near and longer term. 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 management cannot predict the outcome 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.

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, 2020, the Registrants’ critical accounting policies and estimates had not changed significantly from December 31, 2019. 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' 2019 Form 10-K for ~~a discussion~~further information.

Results 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.Operations by Registrant

~~202~~129

Table of Contents

Generation

~~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

~~203~~

~~Table of Contents~~

Results of Operations — Generation

Generation’s Results of Operations includes discussion of RNF, which is a financial measure not defined under GAAP and may not be comparable to other companies' presentations or deemed more useful than the GAAP information provided elsewhere in this report. The CODMs for Exelon and Generation evaluate the performance of Generation's electric business activities and allocate resources based on RNF. Generation believes that RNF is a useful measure because it provides information that can be used to evaluate its operational performance.


	Three Months Ended September 30,						Favorable (Unfavorable) Variance				Nine Months Ended September 30,								Favorable (Unfavorable) Variance			Three Months Ended March 31,								(Unfavorable) Favorable Variance
	2017			2016						2017				2016				2020					2019
Operating revenues	$	4,751		$	5,035			$	(284	)		$	13,812			$	13,363					$	449		$	4,733			$	5,296			$	(563	)
Purchased power and fuel expense	2,331			2,589			258				7,286				6,609				(677		)	2,704				3,205				501
Revenues net of purchased power and fuel expense^(a)	2,420			2,446			(26		)		6,526				6,754				(228		)	2,029				2,091				(62		)
Other operating expenses
Operating and maintenance	1,374			1,336			(38		)		4,871				4,333				(538		)	1,263				1,218				(45		)
Depreciation and amortization	410			632			222				1,046				1,329				283			304				405				101
Taxes other than income	141			136			(5		)		425				380				(45		)	129				135				6
Total other operating expenses	1,925			2,104			179				6,342				6,042				(300		)	1,696				1,758				62
(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		)	333				333				—
Other income and (deductions)
Interest expense, net	(113		)	(77		)	(36		)		(342		)		(273		)		(69		)	(109		)		(111		)		2
Other, net	209			185			24				648				395				253			(771		)		430				(1,201		)
Total other income and (deductions)	96			108			(12		)		306				122				184			(880		)		319				(1,199		)
Income before income taxes	596			450			146				726				865				(139		)
(Loss) income before income taxes																						(547		)		652				(1,199		)
Income taxes	240			173			(67		)		209				293				84			(389		)		224				613
Equity in losses of unconsolidated affiliates	(8		)	(6		)	(2		)		(26		)		(16		)		(10		)	(3		)		(6		)		3
Net income	348			271			77				491				556				(65		)
Net income attributable to noncontrolling interests	43			35			(8		)		12				18				6
Net (loss) income																						(161		)		422				(583		)
Net (loss) income attributable to noncontrolling interests																						(206		)		59				(265		)
Net income attributable to membership interest	$	305		$	236		$	69			$	479			$	538			$	(59	)	$	45			$	363			$	(318	)

~~_________~~

~~(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, 2020 Compared to Three Months Ended ~~September 30, 2016.~~ ~~Generation’s~~ March 31, 2019.Net income attributable to membership interest ~~for the three months ended September 30, 2017 increased compared to the same period in 2016,~~ decreased by $318 million primarily due ~~to lower Depreciation~~to:

Lower capacity revenue;

Lower realized energy prices;

Higher nuclear outage days; and ~~amortization expenses, a Bargain purchase gain in 2017,~~

Higher net unrealized and ~~higher other income,~~realized losses on NDT funds;

The decreases were partially offset ~~by lower Revenue net of purchased power and fuel expense, higher Operating and maintenance expenses, and higher interest expense.~~ by:

Higher mark-to-market gains;

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 impactapproval 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.

~~204~~

~~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 increaseJersey ZEC program in the ~~number~~second quarter of ~~nuclear outage days in 2017~~2019; and ~~increased salaries, wages and contracting costs related to the acquisition of the FitzPatrick nuclear facility. The increase in taxes other than~~

An 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.settlement.

Revenues Net of Purchased Power and Fuel ~~Expense~~

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

130

Table of Contents

Generation

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~~Generation's five reportable segments are ~~as follows:~~

Mid-Atlantic, ~~represents operations in the eastern half of PJM, which includes New Jersey, Maryland, Virginia, West Virginia, Delaware, the District of Columbia and parts of Pennsylvania and North Carolina.~~

Midwest, represents operations in the western half of PJM, 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~~ and Other Power Regions. See Note 4 - Segment Information 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.~~

~~205~~

~~Table of Contents~~

Combined Notes to Consolidated Financial Statements for additional information on these reportable segments.

The following business activities are not allocated to a region and are reported under Other: natural gas, as well as other miscellaneous business activities that are not significant to ~~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~~RNF. Operating revenues include all sales to third parties and affiliated sales to the Utility Registrants. Purchased power costs include all costs associated with the procurement and supply of electricity including capacity, energy and ancillary services. Fuel expense includes the fuel costs for owned generation and fuel costs associated with tolling agreements.

For the three ~~and nine~~ months ended ~~September 30, 2017 and 2016, Generation’s Revenue net~~March 31, 2020 compared to 2019, RNF by region were as follows. See Note 4 - Segment Information of ~~purchased~~the Combined Notes to the Consolidated Financial Statements for additional information on Purchase power and fuel expense ~~by region were as follows:~~for Generation’s reportable segments.

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 )%



	Three Months Ended March 31,					Variance			% Change
	2020		2019			Variance			% Change
Mid-Atlantic^(a)	$	567	$	683		$	(116	)	(17.0	)%
Midwest^(b)	727		771			(44		)	(5.7	)%
New York	193		265			(72		)	(27.2	)%
ERCOT	80		74			6			8.1	%
Other Power Regions	158		156			2			1.3	%
Total electric revenues net of purchased power and fuel expense	1,725		1,949			(224		)	(11.5	)%
Mark-to-market gains (losses)	131		(28		)	159			567.9	%
Other	173		170			3			1.8	%
Total revenue net of purchased power and fuel expense	$	2,029	$	2,091		$	(62	)	(3.0	)%

_________


(a)	~~Results~~Includes 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.~~ACE.


(b)	~~Results~~Includes 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.~~ComEd.

~~206~~131

Table of Contents

Generation

Generation’s supply sources by region are summarized below:


	Three Months Ended September 30,		Variance		% Change			Nine Months Ended September 30,			Variance		% Change		Three Months Ended March 31,		Variance		% Change
Supply source (GWhs)	2017	2016			% Change		2017		2016								Variance		% Change
Nuclear generation			Variance								Variance		% Change
Mid-Atlantic^(a)	16,480	15,604	876		5.6	%		48,271		47,035	1,236		2.6	%
Supply Source (GWhs)															2020	2019	Variance		% Change
Nuclear Generation^(a)																	Variance		% Change
Mid-Atlantic															12,784	15,080	(2,296	)	(15.2	)%
Midwest	24,362	24,262	100		0.4	%		69,422		70,925	(1,503	)	(2.1	)%	23,598	23,733	(135	)	(0.6	)%
New York^(a)(d)	6,905	4,843	2,062		42.6	%		17,623		14,002	3,621		25.9	%
New York															6,173	6,902	(729	)	(10.6	)%
Total Nuclear Generation	47,747	44,709	3,038		6.8	%		135,316		131,962	3,354		2.5	%	42,555	45,715	(3,160	)	(6.9	)%
Fossil and Renewables
Mid-Atlantic	596	706	(110	)	(15.6	)%		2,330		2,290	40		1.7	%	853	951	(98	)	(10.3	)%
Midwest	218	273	(55	)	(20.1	)%		1,053		1,046	7		0.7	%	388	392	(4	)	(1.0	)%
New England	1,919	1,886	33		1.7	%		5,921		5,826	95		1.6	%
New York	1	1	—		—	%		3		3	—		—	%	1	1	—		—	%
ERCOT	5,703	2,472	3,231		130.7	%		9,388		5,726	3,662		64.0	%	3,012	3,078	(66	)	(2.1	)%
Other Power Regions	2,149	2,103	46		2.2	%		5,656		6,245	(589	)	(9.4	)%	3,508	3,141	367		11.7	%
Total Fossil and Renewables	10,586	7,441	3,145		42.3	%		24,351		21,136	3,215		15.2	%	7,762	7,563	199		2.6	%
Purchased Power
Mid-Atlantic	2,541	7,139	(4,598	)	(64.4	)%		8,840		14,024	(5,184	)	(37.0	)%	5,943	2,566	3,377		131.6	%
Midwest	217	461	(244	)	(52.9	)%		1,018		1,855	(837	)	(45.1	)%	288	288	—		—	%
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	)%	991	1,042	(51	)	(4.9	)%
Other Power Regions	3,982	3,803	179		4.7	%		10,357		10,281	76		0.7	%	12,167	12,569	(402	)	(3.2	)%
Total Purchased Power	12,452	18,225	(5,773	)	(31.7	)%		39,887		45,471	(5,584	)	(12.3	)%	19,389	16,465	2,924		17.8	%
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	%
Total Supply/Sales by Region
Mid-Atlantic^(b)															19,580	18,597	983		5.3	%
Midwest^(b)															24,274	24,413	(139	)	(0.6	)%
New York	6,906	4,844	2,062		42.6	%		17,654		14,005	3,649		26.1	%	6,174	6,903	(729	)	(10.6	)%
ERCOT	6,902	5,367	1,535		28.6	%		15,112		13,174	1,938		14.7	%	4,003	4,120	(117	)	(2.8	)%
Other Power Regions	6,131	5,906	225		3.8	%		16,013		16,526	(513	)	(3.1	)%	15,675	15,710	(35	)	(0.2	)%
Total Supply/Sales by Region	70,785	70,375	410		0.6	%		199,554		198,569	985		0.5	%	69,706	69,743	(37	)	(0.1	)%

_________


(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, BGE, Pepco, DPL and ~~BGE~~ACE 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.~~

132

Table of Contents

Generation

For the three months ended March 31, 2020 compared to 2019, changes in RNF by region were as follows:



				2020 vs. 2019
	Increase/ (Decrease)			Description
Mid-Atlantic	$	(116	)	• decreased capacity revenue • decreased revenue due to permanent cease of generation operations at Three Mile Island in the third quarter of 2019 • lower realized energy prices, partially offset by • increased ZEC revenues due to the approval of the NJ ZEC program in the second quarter of 2019
Midwest	(44		)	• decreased capacity revenue • lower realized energy prices
New York	(72		)	• lower realized energy prices • increased nuclear outage days
ERCOT	6			• higher portfolio optimization
Other Power Regions	2			• higher portfolio optimization, partially offset by • decreased capacity revenue
Mark-to-market^(a)	159			• gains on economic hedging activities of $131 million in 2020 compared to losses of $28 million in 2019
Other	3			• no significant changes
Total	$	(62	)

_________


~~(d)~~(a)	~~Includes the ownership of the FitzPatrick nuclear facility from March 31, 2017.~~See Note 11 — Derivative Financial Instruments for additional information on mark-to-market gains (losses).

~~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.

~~207~~

~~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.~~

~~208~~

~~Table of Contents~~

~~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~~

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.~~plants, which reflects ownership percentage of stations operated by Exelon, excluding Salem, which is operated by PSEG. The nuclear fleet capacity factor presented in the table is defined as the ratio of the actual output of a plant over a period of time to its output if the plant had operated at full average annual mean capacity for that time period. Generation considers capacity factor to be a useful measure to analyze the nuclear fleet performance between periods. Generation has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, these measures are not a presentation defined under GAAP and may not be comparable to other companies’ presentations or be more useful than the GAAP information provided elsewhere in this report.


	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended March 31,
	2017		2016		2017		2016		2020		2019
Nuclear fleet capacity factor^(a)	96.1	%	96.3	%	93.7	%	94.8	%	93.9	%	97.1	%
Refueling outage days^(a)	13		17		233		174		94		74
Non-refueling outage days^(a)	15		—		35		31		11		—

133

Table of Contents

Generation

The changes in Operating and maintenance expenseconsisted of the following:



	Three Months Ended March 31,
	Increase (Decrease)
Plant retirements and divestitures^(a)	$	82
Nuclear refueling outage costs, including the co-owned Salem plants	42
Credit loss expense	3
Pension and non-pension postretirement benefits expense	(5		)
Accretion expense	(10		)
Corporate allocations	(11		)
Labor, other benefits, contracting and materials^(b)	(56		)
Increase in operating and maintenance expense	$	45

_________


(a)	~~Excludes Salem, which is operated by PSEG Nuclear, LLC. Reflects ownership percentage~~Primarily reflects increase from prior year due to the benefit recorded in the first quarter of ~~stations operated by Exelon. Includes~~2019 for the ~~ownership~~remeasurement of the ~~FitzPatrick nuclear facility from March 31, 2017.~~

~~209~~

~~Table of Contents~~

~~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.~~TMI ARO.


(b)	~~Reflects increased salaries, wages and contracting~~Primarily reflects decreased costs ~~primarily~~ related to the ~~acquisition~~permanent cease of generation operations at TMI and lower labor costs resulting from previous cost management programs.

Depreciation and amortization expense for the three months ended March 31, 2020 compared to the same period in 2019 decreased primarily due to the permanent cease of generation operations at Three Mile Island in the third quarter of 2019.

Other, net for the three months ended March 31, 2020 compared to the same period in 2019 decreased due to activity associated with NDT funds as described in the table below:



	2020			2019
Net unrealized (losses) gains on NDT funds^(a)	$	(706	)	$	280
Net realized gains on sale of NDT funds^(a)	55			29
Interest and dividend income on NDT funds^(a)	27			25
Contractual elimination of income tax expense^(b)	(176		)	85
Other	29			11
Total other, net	$	(771	)	$	430

_________


(a)	Unrealized gains (losses), realized gains and interest and dividend income on the ~~FitzPatrick nuclear facility beginning on March 31, 2017.~~NDT funds are associated with the Non-Regulatory Agreement units.


~~(c)~~(b)	~~Primarily reflects a decrease in the number~~Contractual elimination 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~~income tax expense is 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~~income taxes on the ~~announcement~~NDT funds 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.~~Regulatory Agreement units.

~~Depreciation~~Effective income tax rates were 71.1% 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

~~210~~

~~Table of Contents~~

~~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~~34.3% 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 decreasedMarch 31, 2020 and 2019, respectively. The change is primarily ~~due to the gain associated with Generation's sale of the New Boston generating site in 2016.~~

~~Bargain Purchase Gain~~

Bargain purchase gain for the three and nine months ended September 30, 2017 compared to the three and nine months ended September 30, 2016 increased as a result of the gain associated with the FitzPatrick acquisition. Refer to Note 4 — Mergers, Acquisitions and Dispositions of the Combined Notes to the Consolidated Financial Statements for additional information.

~~Interest Expense, net~~

Interest expense, net for the three and nine months ended September 30, 2017 compared to the three and nine months ended September 30, 2016 increased primarily due to the impact of project in-service dates on the capitalization of interest and higher outstanding debt.

~~Other, Net~~

Other, net for the three and nine months ended September 30, 2017 compared to the three and nine months ended September 30, 2016 increased primarily due to the change in the realized and unrealized gains and losses related to NDT funds of Non-Regulatory Agreement Units as described in the table below. Other, net also reflects $37 million and $39 million for the three months ended September 30, 2017 and 2016, respectively, and $129 million and $84 million for the nine months ended September 30, 2017 and 2016, respectively, related to the contractual elimination of incomea one-time adjustment partially offset by renewable 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.credits. See Note 129 — Income Taxes of the Combined Notes to ~~the~~ Consolidated Financial Statements for ~~further discussion of~~additional information.

Net income attributable to noncontrolling interests for the ~~change~~three months ended March 31, 2020 compared to the same period in ~~the effective income tax rate.~~2019 decreased primarily due to unrealized losses on NDT fund investments for CENG.

~~211~~134

Table of Contents

ComEd

Results of Operations — ComEd


	Three Months Ended September 30,						Favorable (Unfavorable) Variance				Nine Months Ended September 30,								Favorable (Unfavorable) Variance			Three Months Ended March 31,								Favorable (Unfavorable) Variance
	2017			2016						2017				2016				2020					2019
Operating revenues	$	1,571		$	1,497			$	74			$	4,227			$	4,031					$	196		$	1,439			$	1,408			$	31
Operating expenses
Purchased power expense	529			454			(75		)		1,241				1,141				(100		)	486				485				(1		)
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			317				321				4
Depreciation and amortization	212			196			(16		)		631				574				(57		)	273				251				(22		)
Taxes other than income	80			82			2				223				222				(1		)	75				78				3
Total other operating expenses	638			655			17				1,950				1,909				(41		)
Total operating expenses																						1,151				1,135				(16		)
Gain on sales of assets	—			1			(1		)		—				6				(6		)	—				3				(3		)
Operating income	404			389			15				1,036				987				49			288				276				12
Other income and (deductions)
Interest expense, net	(89		)	(197		)	108				(275		)		(374		)		99			(94		)		(87		)		(7		)
Other, net	5			(80		)	85				14				(72		)		86			10				8				2
Total other income and (deductions)	(84		)	(277		)	193				(261		)		(446		)		185			(84		)		(79		)		(5		)
Income before income taxes	320			112			208				775				541				234			204				197				7
Income taxes	131			75			(56		)		328				244				(84		)	36				40				4
Net income	$	189		$	37		$	152			$	447			$	297			$	150		$	168			$	157			$	11

~~_________~~

~~(a)~~

ComEd evaluates its operating performance using the measure of Revenue net of purchased power expense. ComEd believes that Revenue net of purchased power expense is a useful measurement because it provides information that can be used to evaluate its operational performance. In general, ComEd only earns margin based on the delivery and transmission of electricity. ComEd has included its discussion of Revenue net of purchased power expense below as a complement to the financial information provided in accordance with GAAP. However, Revenue net of purchased power expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.


~~(b)~~	For regulatory recovery mechanisms, including ComEd’s electric distribution and transmission formula rates, and riders, revenues increase and decrease i) as fully recoverable costs fluctuate (with no impact on net earnings), and ii) pursuant to changes in rate base, capital structure and ROE (which impact net earnings).

~~Net Income~~

Three Months Ended ~~September 30, 2017~~March 31, 2020 Compared to Three Months Ended ~~September 30, 2016.~~ ~~ComEd’s~~ March 31, 2019. Net income ~~for the three months ended September 30, 2017 was higher than~~ increased $11 million as compared to the same period in ~~2016,~~2019, 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 increasedhigher electric distribution ~~and transmission~~ formula rate earnings (reflecting the impacts of ~~increased capital investment~~higher rate base and ~~higher~~distribution formula rate timing, partially offset by lower allowed electric distribution ROE). The higher Net income was partially offset by the impact of weather conditions in the third quarter of 2016. See Revenue Decoupling discussion below for additional information on the impact of weather.

~~Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016.~~ ~~ComEd’s Net income for the nine months ended September 30, 2017 was higher than the same period in 2016, primarily~~ROE 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~~a decrease 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)treasury rates).

The ~~higher Net income was partially offset by additional tax and interest recorded~~changes 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.

~~212~~

~~Table of Contents~~

~~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 %



	Three Months Ended March 31, 2020
	Increase (Decrease)
Electric distribution	$	22
Transmission	(7		)
Energy efficiency	12
	27
Regulatory required programs	4
Total increase	$	31

~~Retail customers purchasing electric generation from competitive electric generation suppliers at September 30, 2017 and 2016 consisted of the following:~~

September 30, 2017 September 30, 2016
Number of customers % of total retail customers Number of customers % of total retail customers
Electric 1,360,800
34 % 1,526,900
39 %

~~The changes in ComEd’s Revenue net of purchased power expense for the three and nine months ended September 30, 2017, compared to the same period in 2016 consisted of the following:~~

Three Months Ended
September 30, 2017 Nine Months Ended
September 30, 2017
Increase (Decrease) Increase (Decrease)
Weather^(a)
$ (34 ) $ (37 )
Volume^(a)
(5 ) (11 )
Electric distribution revenue 59
119
Transmission revenue 11
45
Energy efficiency revenue^(b)
5
6
Regulatory required programs^(b)
(39 ) (24 )
Uncollectible accounts recovery, net (3 ) (5 )
Pricing and customer mix^(a)
—
(1 )
Other 5
4
Total increase (decrease) $ (1 ) $ 96

~~_________~~

~~(a)~~

These changes only reflect the 2016 impacts of weather, volume, and pricing and customer mix. As further described below, pursuant to the revenue decoupling provision in FEJA, ComEd began recording an adjustment to revenue in the first quarter of 2017 to eliminate the favorable or unfavorable impacts associated with variations in delivery volumes associated with above or below normal weather, number of customers or usage per customer.


~~(b)~~	Beginning on June 1, 2017, ComEd is deferring energy efficiency costs as a regulatory asset that will be recovered through the energy efficiency formula rate over the weighted average useful life of the related energy efficiency measures.

Revenue Decoupling.The demand for electricity is affected by weather ~~conditions. Very warm weather in summer months~~conditions 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~~Operating revenues are not impacted by abnormal weather, ~~reduces demand.~~

~~213~~

~~Table~~usage per customer or number of ~~Contents~~

~~Under EIMA, ComEd's~~customers as a result of a change to the electric distribution formula rate ~~provided for an adjustment~~pursuant to ~~future billings if its earned ROE fell outside a 50 bps collar of its allowed ROE, which partially eliminated the impacts of weather~~FEJA.

Distribution Revenue. EIMA 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 or below normal weather, numbers of customers or usage per customer. ComEd began recognizing the impacts of this change beginning in the first quarter of 2017. During the three 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~~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 the three ~~and nine~~ months ended ~~September 30, 2017, primarily due to increased capital investment, increased Depreciation expense, and higher allowed ROE due to an increase in treasury rates~~March 31, 2020 as compared to the same period in ~~2016 and~~2019, primarily due to ~~revenue decoupling impacts (as described above) during~~ the ~~nine months ended September 30, 2017.~~impact of higher rate base, higher fully recoverable costs and distribution

135

Table of Contents

ComEd

formula rate timing, offset by lower allowed ROE due to a decrease in treasury rates. See ~~Depreciation and amortization expense discussions below, and~~ Note 52 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Transmission Revenue.Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered and the highest daily peak load, which is updated annually in January based on the prior calendar year. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. ~~For~~Transmission revenue decreased 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, 2020 as compared to the same period in ~~2016.~~2019, primarily due to the impact of decreased peak load partially offset by higher fully recoverable costs. See ~~Operating and maintenance expense below and~~ Note 52 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Energy Efficiency Revenue. ~~Beginning June 1, 2017,~~ FEJA provides for a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs that the ICC determines are prudently and reasonably incurred in a given year. Under FEJA, energy efficiency revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered, and allowed ROE. ~~ComEd’s allowed ROE is~~Energy efficiency revenue increased during the ~~annual average rate on 30-year treasury notes plus 580 basis points. Beginning January 1, 2018, ComEd’s allowed ROE is subject~~three months ended March 31, 2020 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~~

~~214~~

~~Table of Contents~~

~~savings goal.~~the same period in 2019, primarily due to the increased regulatory asset amortization. See Depreciation and amortization expense discussions below and Note 52 — 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, and ~~energy efficiency~~costs related to electricity, ZEC and ~~demand response through June 1, 2017 pursuant to FEJA.~~REC procurement. 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~~Purchased power and ~~maintenance expense. See~~fuel 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 but impact Operating revenues related to supplied electricity. Drivers of Operating revenues related to electricity, ZEC and REC procurement costs and participation in customer choice programs are fully offset by their impact on Purchased power and fuel expense. ComEd recovers electricity, ZEC and REC procurement costs from customers without mark-up.

See Note 4 — Segment Information of the Combined Notes to Consolidated Financial Statements for ~~additional information on included~~the presentation of ComEd's revenue disaggregation.

The increase of $1 million in Purchased power and fuel expense is offset in Operating revenues as part of regulatory required programs.

~~Uncollectible Accounts Recovery, Net.~~ ~~Uncollectible accounts recovery, net represents recoveries under ComEd’s uncollectible accounts tariff. See~~ The changes in Operating and maintenance 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 to other utilities through mutual assistance programs, recoveries of environmental costs associated with MGP sites, and recoveries of energy procurement costs.

~~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 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 $ (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 )



	Three Months Ended March 31, 2020
	(Decrease) Increase
Labor, other benefits, contracting and materials	$	(10	)
Storm-related costs	(7		)
BSC costs	10
Pension and non-pension postretirement benefits expense	3
Other	1
	(3		)
Regulatory required programs^(a)	(1		)
Total decrease	$	(4	)

~~_________~~__________

(a)

ComEd is allowed to recover from or refund to customers the difference between ~~the utility’s~~its annual ~~uncollectible accounts~~credit loss expense and the amounts collected in rates annually through a rider mechanism. During the three ~~and nine~~ months ended ~~September 30, 2017,~~March 31, 2020, ComEd recorded a net decrease in ~~Operating and maintenance expense related to uncollectible accounts~~credit losses account due to the timing of regulatory cost recovery. An equal and offsetting ~~decrease~~amount has been recognized in Operating revenues for the period presented.


~~(b)~~	For the three and nine months ended September 30, 2017, includes the $8 million write-off of a regulatory asset related to Constellation merger and integration costs for which recovery is no longer expected.


~~(c)~~	Beginning on June 1, 2017, ComEd is deferring energy efficiency costs as a regulatory asset that will be recovered through the energy efficiency formula rate over the weighted average useful life of the related energy efficiency measures.

~~215~~136

Table of Contents

ComEd

~~Depreciation and Amortization Expense~~

The ~~increase~~changes in Depreciation and amortization expense ~~during the three and nine months ended September 30, 2017, compared to the same period in 2016,~~ consisted of the following:


	Three Months Ended September 30, 2017		Nine Months Ended September 30, 2017		Three Months Ended March 31, 2020
	Increase (Decrease)		Increase (Decrease)		Increase
Depreciation expense^(a)	$	14	$	47
Depreciation and amortization^(a)					$	13
Regulatory asset amortization^(b)	1		2		9
Other	1		8
Total increase	$	16	$	57	$	22

_________


(a)	~~Primarily reflects~~Reflects ongoing capital ~~expenditures for the three and nine months ended September 30, 2017.~~expenditures.


(b)	~~Beginning in June 2017, includes~~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 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 related to the Tax Court's decision on Exelon's like-kind exchange tax position in the third quarter of 2016.

Effective ~~Income Tax Rate~~

~~ComEd's effective~~ income tax rate was ~~40.9%~~17.6% and ~~67.0%~~20.3% for the three months ended ~~September 30, 2017~~March 31, 2020 and ~~2016,~~2019, 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 129 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

~~216~~

~~Table of Contents~~

~~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.

~~217~~137

Table of Contents

PECO

Results of Operations — PECO


	Three Months Ended September 30,						Favorable (Unfavorable) Variance				Nine Months Ended September 30,								Favorable (Unfavorable) Variance			Three Months Ended March 31,								Favorable (Unfavorable) Variance
	2017			2016						2017				2016				2020					2019
Operating revenues	$	715		$	788			$	(73	)		$	2,141			$	2,293					$	(152	)	$	813			$	900			$	(87	)
Operating expenses
Purchased power and fuel expense	235			272			37				719				809				90			283				331				48
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			217				225				8
Depreciation and amortization	72			67			(5		)		213				201				(12		)	86				81				(5		)
Taxes other than income	42			46			4				116				126				10			39				41				2
Total other operating expenses	311			312			1				924				931				7
Total operating expenses																						625				678				53
Operating income	169			204			(35		)		498				553				(55		)	188				222				(34		)
Other income and (deductions)
Interest expense, net	(31		)	(30		)	(1		)		(93		)		(92		)		(1		)	(36		)		(33		)		(3		)
Other, net	2			2			—				6				6				—			3				4				(1		)
Total other income and (deductions)	(29		)	(28		)	(1		)		(87		)		(86		)		(1		)	(33		)		(29		)		(4		)
Income before income taxes	140			176			(36		)		411				467				(56		)	155				193				(38		)
Income taxes	28			54			26				84				121				37			15				25				10
Net income	$	112		$	122		$	(10	)		$	327			$	346			$	(19	)	$	140			$	168			$	(28	)

~~_________~~

~~(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, 2020 Compared to Three Months Ended ~~September 30, 2016.~~ ~~PECO's~~ March 31, 2019. Net income decreased ~~from the same period in 2016,~~by $28 million primarily due to ~~lower Revenues net of purchased power and fuel from~~ unfavorable weather ~~conditions~~conditions.

The changes 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, fluctuations in electric supply and natural gas procurement costs have no impact on electric and natural gas revenue net of purchased power and fuel expense.

Electric and natural gas revenue and purchased power and fuel expense are also affected by fluctuations in participation in the Customer Choice Program. All PECO customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers, respectively. The customers' choice of suppliers does not impact the volume of deliveries, but affects revenue collected from customers related to supplied energy and natural gas service. Customer choice program activity has no impact on electric and natural gas revenue net of purchased power and fuel expense.

~~218~~

~~Table of Contents~~

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
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Electric 70 % 69 % 71 % 70 %
Natural Gas 29 % 31 % 26 % 26 %



	Three Months Ended March 31, 2020
	Increase (Decrease)
	Electric			Gas			Total
Weather	$	(27	)	$	(21	)	$	(48	)
Volume	(5		)	(1		)	(6		)
Pricing	8			2			10
Transmission	2			—			2
	(22		)	(20		)	(42		)
Regulatory required programs	5			(50		)	(45		)
Total decrease	$	(17	)	$	(70	)	$	(87	)

~~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, 2020 compared to the same period in ~~2016,~~2019, Operating ~~revenue net~~revenues related to weather decreased by the impact of ~~purchased power decreased due to unfavorable summer weather conditions. Operating revenue net of fuel expense was relatively consistent.~~ ~~During the nine months ended September 30, 2017 compared to the same period in 2016, Operating revenue net of purchased power and fuel expense decreased due to~~ unfavorable weather ~~conditions.~~conditions in PECO's service territory.

~~219~~138

Table of Contents

PECO

Heating and cooling ~~degree days~~degree-days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling ~~degree days~~degree-days for a 30-year period in PECO's service territory. The changes in heating and cooling ~~degree days~~degree-days in PECO’s service territory for the three ~~and nine~~ months ended ~~September 30, 2017~~March 31, 2020 compared to the same ~~periods~~period in ~~2016~~2019 and normal weather consisted of the following:


Heating and Cooling Degree-Days			Normal	% Change							Normal	% Change
Three Months Ended September 30,	2017	2016	Normal	2017 vs. 2016		2017 vs. Normal
Three Months Ended March 31,								2020	2019		Normal		Normal	From 2019		2020 vs. Normal
Heating Degree-Days	14	10	35	40.0	%	(60.0	)%	1,989	2,432	(18.2	)%		Normal	(17.8	)%
Cooling Degree-Days	989	1,288	923	(23.2	)%	7.2	%	—	2		1	(100.0	)%	(100.0	)%

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	%



Commission File Number	Name of Registrant; State or Other Jurisdiction of Incorporation; Address of Principal Executive Offices; and Telephone Number	IRS Employer Identification Number

~~1-16169~~001-16169	EXELON CORPORATION	23-2990190
	(a Pennsylvania corporation) 10 South Dearborn Street P.O. Box 805379 Chicago, Illinois 60680-5379 (800) 483-3220

333-85496	EXELON GENERATION COMPANY, LLC	23-3064219
	(a Pennsylvania limited liability company) 300 Exelon Way Kennett Square, Pennsylvania 19348-2473 (610) 765-5959

~~1-1839~~001-01839	COMMONWEALTH EDISON COMPANY	36-0938600
	(an Illinois corporation) 440 South LaSalle Street Chicago, Illinois 60605-1028 (312) 394-4321

000-16844	PECO ENERGY COMPANY	23-0970240
	(a Pennsylvania corporation) P.O. Box 8699 2301 Market Street Philadelphia, Pennsylvania 19101-8699 (215) 841-4000

~~1-1910~~001-01910	BALTIMORE GAS AND ELECTRIC COMPANY	52-0280210
	(a Maryland corporation) 2 Center Plaza 110 West Fayette Street Baltimore, Maryland 21201-3708 (410) 234-5000

001-31403	PEPCO HOLDINGS LLC	52-2297449
	(a Delaware limited liability company) 701 Ninth Street, N.W. Washington, District of Columbia 20068 (202) 872-2000

001-01072	POTOMAC ELECTRIC POWER COMPANY	53-0127880
	(a District of Columbia and Virginia corporation) 701 Ninth Street, N.W. Washington, District of Columbia 20068 (202) 872-2000

001-01405	DELMARVA POWER & LIGHT COMPANY	51-0084283
	(a Delaware and Virginia corporation) 500 North Wakefield Drive Newark, Delaware 19702 (202) 872-2000

001-03559	ATLANTIC CITY ELECTRIC COMPANY	21-0398280
	(a New Jersey corporation) 500 North Wakefield Drive Newark, Delaware 19702 (202) 872-2000



Title of each class	Trading Symbol(s)	Name of each exchange on which registered
EXELON CORPORATION:
Common Stock, without par value	EXC	The Nasdaq Stock Market LLC

PECO ENERGY COMPANY:
Trust Receipts of PECO Energy Capital Trust III, each representing a 7.38% Cumulative Preferred Security, Series D, $25 stated value, issued by PECO Energy Capital, L.P. and unconditionally guaranteed by PECO Energy Company	EXC/28	New York Stock Exchange



Exelon Corporation	Large Accelerated Filer	x	Accelerated Filer	☐	Non-accelerated Filer	☐	Smaller Reporting Company	☐	Emerging Growth Company
~~Exelon Corporation~~	x								☐
Exelon Generation Company, LLC	Large Accelerated Filer	☐	Accelerated Filer	☐	Non-accelerated Filer	x	Smaller Reporting Company	☐	Emerging Growth Company	☐
Commonwealth Edison Company	Large Accelerated Filer	☐	Accelerated Filer	☐	Non-accelerated Filer	x	Smaller Reporting Company	☐	Emerging Growth Company	☐
PECO Energy Company	Large Accelerated Filer	☐	Accelerated Filer	☐	Non-accelerated Filer	x	Smaller Reporting Company	☐	Emerging Growth Company	☐
Baltimore Gas and Electric Company	Large Accelerated Filer	☐	Accelerated Filer	☐	Non-accelerated Filer	x	Smaller Reporting Company	☐	Emerging Growth Company	☐
Pepco Holdings LLC	Large Accelerated Filer	☐	Accelerated Filer	☐	Non-accelerated Filer	x	Smaller Reporting Company	☐	Emerging Growth Company	☐
Potomac Electric Power Company	Large Accelerated Filer	☐	Accelerated Filer	☐	Non-accelerated Filer	x	Smaller Reporting Company	☐	Emerging Growth Company	☐
Delmarva Power & Light Company	Large Accelerated Filer	☐	Accelerated Filer	☐	Non-accelerated Filer	x	Smaller Reporting Company	☐	Emerging Growth Company	☐
Atlantic City Electric Company	Large Accelerated Filer	☐	Accelerated Filer	☐	Non-accelerated Filer	x	Smaller Reporting Company	☐	Emerging Growth Company	☐



Exelon Corporation Common Stock, without par value	~~960,852,473~~974,407,848
Exelon Generation Company, LLC	not applicable
Commonwealth Edison Company Common Stock, $12.50 par value	~~127,021,214~~127,021,353
PECO Energy Company Common Stock, without par value	170,478,507
Baltimore Gas and Electric Company Common Stock, without par value	1,000
Pepco Holdings LLC	not applicable
Potomac Electric Power Company Common Stock, ~~$.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.
GLOSSARY OF TERMS AND ABBREVIATIONS		64
FILING FORMAT		128
CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION		128
WHERE TO FIND MORE INFORMATION		128
PART I.	~~FINANCIAL INFORMATION~~	13FINANCIAL INFORMATION	9
ITEM 1.	~~FINANCIAL STATEMENTS~~	13FINANCIAL STATEMENTS	9
	Exelon Corporation
	Consolidated Statements of Operations and Comprehensive Income	10
	Consolidated Statements of Cash Flows	11
	Consolidated Balance Sheets	12
	Consolidated Statements of Changes in Shareholders’ Equity	14
	Exelon Generation Company, LLC
	Consolidated Statements of ~~Cash Flows~~Operations and Comprehensive Income	15
	Consolidated ~~Balance Sheets~~Statements of Cash Flows	16
	Consolidated ~~Statement of Changes in Shareholders’ Equity~~Balance Sheets	1817
	~~Exelon Generation Company, LLC~~
	Consolidated Statements of ~~Operations and Comprehensive Income~~Changes in Equity	19
	Commonwealth Edison Company
	Consolidated Statements of ~~Cash Flows~~Operations and Comprehensive Income	20
	Consolidated ~~Balance Sheets~~Statements of Cash Flows	21
	Consolidated ~~Statement of Changes in Equity~~Balance Sheets	2322
	~~Commonwealth Edison Company~~
	Consolidated Statements of ~~Operations and Comprehensive Income~~Changes in Shareholders' Equity	24
	PECO Energy Company
	Consolidated Statements of ~~Cash Flows~~Operations and Comprehensive Income	25
	Consolidated ~~Balance Sheets~~Statements of Cash Flows	26
	Consolidated ~~Statement of Changes in Shareholders' Equity~~Balance Sheets	2827
	~~PECO Energy Company~~
	Consolidated Statements of ~~Operations and Comprehensive Income~~Changes in Shareholder's Equity	29
	~~Consolidated~~ Baltimore Gas and Electric Company
	Statements of ~~Cash Flows~~Operations and Comprehensive Income	30
	~~Consolidated Balance Sheets~~ Statements of Cash Flows	31
	~~Consolidated Statement~~ Balance Sheets	32
	Statements of Changes in Shareholder's Equity	33
	~~Baltimore Gas and Electric Company~~
	~~Consolidated Statements of Operations and Comprehensive Income~~	34
	Pepco Holdings LLC
	Consolidated Statements of ~~Cash Flows~~Operations and Comprehensive Income	35
	Consolidated ~~Balance Sheets~~Statements of Cash Flows	36
	Consolidated ~~Statement of Changes in Shareholders’ Equity~~Balance Sheets	3837
	~~Pepco Holdings LLC~~
	Consolidated Statements of ~~Operations and Comprehensive Income~~Changes in Equity	39
	~~Consolidated Statements of Cash Flows~~	40
	~~Consolidated Balance Sheets~~	41
	~~Consolidated Statement of Changes in Equity~~	43



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.
ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	124
	Exelon Corporation	124
	Executive Overview	124
	Financial Results of Operations	126
	Significant 2020 Transactions and Developments	127
	Other Key Business Drivers and Management Strategies	129
	Critical Accounting Policies and Estimates	129
	Results of Operations By Registrant	129
	Exelon Generation Company, LLC	130
	Commonwealth Edison Company	135
	PECO Energy Company	138
	Baltimore Gas and Electric Company	142
	Pepco Holdings LLC	145
	Potomac Electric Power Company	146
	Delmarva Power & Light Company	149
	Atlantic City Electric Company	153
	Liquidity and Capital Resources	156
	Contractual Obligations and Off-Balance Sheet Arrangements	163
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	164
ITEM 4.	CONTROLS AND PROCEDURES	169
PART II.	OTHER INFORMATION	169
ITEM 1.	LEGAL PROCEEDINGS	169
ITEM 1A.	RISK FACTORS	169
ITEM 4.	MINE SAFETY DISCLOSURES	169
ITEM 6.	EXHIBITS	170
SIGNATURES		173
	Exelon Corporation	173
	Exelon Generation Company, LLC	174
	Commonwealth Edison Company	175
	PECO Energy Company	176
	Baltimore Gas and Electric Company	177
	Pepco Holdings LLC	178
	Potomac Electric Power Company	179
	Delmarva Power & Light Company	180
	~~Exelon Corporation~~	~~180~~Atlantic City Electric Company
	~~Executive Overview~~	~~180~~
	~~Financial Results of Operations~~	181
	~~Significant 2017 Transactions and Developments~~	~~189~~
	~~Exelon's Strategy and Outlook for 2017 and Beyond~~	~~194~~
	~~Liquidity Considerations~~	~~195~~
	~~Other Key Business Drivers and Management Strategies~~	~~196~~
	~~Critical Accounting Policies and Estimates~~	~~202~~
	~~Results of Operations By Registrant~~	~~203~~
	~~Exelon Generation Company, LLC~~	~~204~~
	~~Commonwealth Edison Company~~	~~212~~
	~~PECO Energy Company~~	~~218~~
	~~Baltimore Gas and Electric Company~~	~~224~~
	~~Pepco Holdings LLC~~	~~231~~
	~~Potomac Electric Power Company~~	~~234~~
	~~Delmarva Power & Light Company~~	~~240~~
	~~Atlantic City Electric Company~~	~~248~~
	~~Liquidity and Capital Resources~~	~~253~~
	~~Contractual Obligations and Off-Balance Sheet Arrangements~~	~~266~~
~~ITEM 3.~~	~~QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK~~	~~266~~
~~ITEM 4.~~	~~CONTROLS AND PROCEDURES~~	~~275~~
~~PART II.~~	~~OTHER INFORMATION~~	~~276~~
~~ITEM 1.~~	~~LEGAL PROCEEDINGS~~	~~276~~
~~ITEM 1A.~~	~~RISK FACTORS~~	~~276~~
~~ITEM 4.~~	~~MINE SAFETY DISCLOSURES~~	~~276~~
~~ITEM 6.~~	~~EXHIBITS~~	~~276~~
~~SIGNATURES~~		~~279~~
	~~Exelon Corporation~~	~~279~~
	~~Exelon Generation Company, LLC~~	~~280~~
	~~Commonwealth Edison Company~~	~~281~~
	~~PECO Energy Company~~	~~282~~
	~~Baltimore Gas and Electric Company~~	~~283~~
	~~Pepco Holdings LLC~~	~~284~~
	~~Potomac Electric Power Company~~	~~285~~
	~~Delmarva Power & Light Company~~	~~286~~
	~~Atlantic City Electric Company~~	~~287~~



GLOSSARY OF TERMS AND ABBREVIATIONS
Exelon Corporation and Related Entities
Exelon		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~~
~~PHI Corporate~~		~~PHI in its corporate capacity as a holding company~~
Registrants		Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, collectively
Utility Registrants		ComEd, PECO, BGE, Pepco, DPL and ACE, collectively
~~AmerGen~~ACE Funding or ATF		~~AmerGen Energy Company,~~Atlantic City Electric Transition Funding LLC
Antelope Valley		Antelope Valley Solar Ranch One
~~BondCo~~BSC		~~RSB BondCo~~Exelon Business Services Company, 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 IV		ExGen Renewables I,IV, LLC
~~Entergy~~EGRP		~~Entergy Nuclear FitzPatrick,~~ExGen Renewables Partners, LLC
Exelon ~~Transmission Company~~Corporate		Exelon ~~Transmission Company, LLC~~
~~Exelon Wind~~		~~Exelon Wind, LLC and Exelon Generation Acquisition Company, LLC~~in its corporate capacity as a holding company
FitzPatrick		James A. FitzPatrick nuclear generating station
~~Legacy PHI~~NER		~~PHI, Pepco, DPL and ACE, collectively~~NewEnergy Receivables LLC
~~PEC L.P.~~PCI		~~PECO Energy~~Potomac Capital ~~L.P.~~Investment Corporation and its subsidiaries
PECO Trust III		PECO Capital Trust III
PECO Trust IV		PECO Energy Capital Trust IV
~~PETT~~Pepco Energy Services		~~PECO~~Pepco Energy ~~Transition Trust~~Services, Inc. and its subsidiaries
~~RPG~~PHI Corporate		~~Renewable Power Generation~~PHI in its corporate capacity as a holding company
PHISCO		PHI Service Company
SolGen		SolGen, LLC
TMI		Three Mile Island nuclear facility
~~UII~~		~~Unicom Investments, Inc.~~
~~Ventures~~		~~Exelon Ventures Company, LLC~~



GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
Note ~~“—”~~"—" of the ~~Exelon 2016~~2019 Form 10-K		Reference to specific Combined Note to Consolidated Financial Statements within Exelon’s ~~2016~~2019 Annual Report on Form 10-K
~~Act 11~~		~~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~~		~~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~~		~~Albany Green Energy Project~~
AMI		Advanced Metering Infrastructure
AOCI		Accumulated Other Comprehensive Income (Loss)
ARC		Asset Retirement Cost
ARO		Asset Retirement Obligation
~~ASC~~		~~Accounting Standards Codification~~
BGS		Basic Generation Service
~~Block Contracts~~		~~Forward Purchase Energy Block Contracts~~
~~CAIR~~		~~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		Clean Energy Standard
~~CFL~~		~~Compact Fluorescent Light~~
~~Clean Air Act~~		~~Clean Air Act of 1963, as amended~~
Clean Water Act		Federal Water Pollution Control Amendments of 1972, as amended
~~Competition Act~~CODM		~~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~~Chief operating decision maker(s)
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		United States Department of Energy
DOEE		Department of Energy & Environment
DOJ		United States Department of Justice
DPSC		Delaware Public Service Commission



~~GLOSSARY OF TERMS AND ABBREVIATIONS~~
~~Other Terms and Abbreviations~~
~~DRP~~		~~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~~		~~A Maryland demand-side management program for Pepco and DPL~~
EPA		United States Environmental Protection Agency
~~EPSA~~		~~Electric Power Supply Association~~
ERCOT		Electric Reliability Council of Texas
~~ERISA~~		~~Employee Retirement Income Security Act of 1974, as amended~~
~~EROA~~		~~Expected Rate of Return on Assets~~
FASB		Financial Accounting Standards Board
FEJA		Illinois Public Act 99-0906 or Future Energy Jobs Act
FERC		Federal Energy Regulatory Commission
FRCC		Florida Reliability Coordinating Council
FRR		Fixed Resource Requirement
GAAP		Generally Accepted Accounting Principles in the United States
GCR		Gas Cost Rate
~~GHG~~		~~Greenhouse Gas~~
GSA		Generation Supply Adjustment
~~GWh~~		~~Gigawatt hour~~
~~Health Care Reform Acts~~		~~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~~		~~Integrys Energy Services, Inc.~~
IPA		Illinois Power Agency
IRC		Internal Revenue Code
IRS		Internal Revenue Service
~~ISO~~		~~Independent System Operator~~
~~ISO-NE~~		~~Independent System Operator New England Inc.~~
~~ISO-NY~~		~~Independent System Operator New York~~
kV		~~Kilovolt~~
kW		~~Kilowatt~~
~~kWh~~		~~Kilowatt-hour~~
~~LIBOR~~		~~London Interbank Offered Rate~~



GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
~~LLRW~~ISO		~~Low-Level Radioactive Waste~~Independent System Operator
~~LT Plan~~ISO-NE		~~Long-term renewable resources procurement plan~~Independent System Operator New England Inc.
~~LTIP~~LIBOR		~~Long-Term Incentive Plan~~
~~MAPP~~		~~Mid-Atlantic Power Pathway~~
~~MATS~~		~~U.S. EPA Mercury and Air Toxics Rule~~
~~MBR~~		~~Market Based Rates Incentive~~London Interbank Offered Rate
MDE		Maryland Department of the Environment
MDPSC		Maryland Public Service Commission
MGP		Manufactured Gas Plant
MISO		Midcontinent Independent System Operator, Inc.
mmcf		Million Cubic Feet
~~Moody’s~~		~~Moody’s Investor Service~~
MOPR		Minimum Offer Price Rule
~~MRV~~		~~Market-Related Value~~
MW		Megawatt
MWh		Megawatt hour
~~NAAQS~~		~~National Ambient Air Quality Standards~~
~~n.m.~~		~~not meaningful~~
~~NAV~~		~~Net Asset Value~~
NDT		Nuclear Decommissioning Trust
~~NEIL~~		~~Nuclear Electric Insurance Limited~~
NERC		North American Electric Reliability Corporation
~~NGS~~NGX		Natural Gas ~~Supplier~~Exchange
NJBPU		New Jersey Board of Public Utilities
~~NJDEP~~		~~New Jersey Department of Environmental Protection~~
Non-Regulatory Agreements Units		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~~NPNS		~~National Pollutant Discharge Elimination System~~Normal Purchase Normal Sale scope exception
NRC		Nuclear Regulatory Commission
~~NSPS~~NYISO		New ~~Source Performance Standards~~
~~NUGs~~		~~Non-utility generators~~
~~NWPA~~		~~Nuclear Waste Policy Act of 1982~~York Independent System Operator Inc.
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
PG&E		Pacific Gas and Electric Company
PJM		PJM Interconnection, LLC
POLR		Provider of Last Resort
PPA		Power Purchase Agreement
PPE		Property, plant and equipment
Price-Anderson Act		Price-Anderson Nuclear Industries Indemnity Act of 1957
PRP		Potentially Responsible Parties
PSDAR		Post-Shutdown Decommissioning Activities Report
PSEG		Public Service Enterprise Group Incorporated
REC		Renewable Energy Credit which is issued for each megawatt hour of generation from a qualified renewable energy source
RNF		Revenues Net of Purchased Power and Fuel Expense
Regulatory Agreement Units		Nuclear generating units or portions thereof whose decommissioning-related activities are subject to contractual elimination under regulatory accounting



GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
~~POLR~~		~~Provider of Last Resort~~
~~POR~~		~~Purchase of Receivables~~
~~PPA~~		~~Power Purchase Agreement~~
~~Price-Anderson Act~~		~~Price-Anderson Nuclear Industries Indemnity Act of 1957~~
~~Preferred Stock~~		~~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~~		~~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~~		~~Retail Electric Suppliers~~
RFP		Request for Proposal
Rider		Reconcilable Surcharge Recovery Mechanism
~~RGGI~~		~~Regional Greenhouse Gas Initiative~~
RMC		Risk Management Committee
ROE		Return on equity
~~RPM~~ROU		~~PJM Reliability Pricing Model~~
~~RPS~~		~~Renewable Energy Portfolio Standards~~
~~RSSA~~		~~Reliability Support Services Agreement~~
~~RTEP~~		~~Regional Transmission Expansion Plan~~Right-of-use
RTO		Regional Transmission Organization
~~S&P~~		~~Standard & Poor’s Ratings Services~~
SEC		United States Securities and Exchange Commission
~~Senate Bill 1~~		~~Maryland Senate Bill 1~~
SERC		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~~TCJA		~~Security, Police~~Tax Cuts and ~~Fire Professionals of America~~
~~SPP~~		~~Southwest Power Pool~~
~~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~~Jobs Act
Transition Bonds		Transition Bonds issued by ACE Funding
~~UGSOA~~		~~United Government Security Officers of America~~
~~Upstream~~		~~Natural gas exploration and production activities~~
VIE		Variable Interest Entity



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


(a)	The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was immaterial for the three months ended March 31, 2020 and March 31, 2019.



	Nine Months Ended September 30,
(In millions)	2017			2016
Cash flows from operating activities
Net income	$	1,911		$	956
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization	3,999			4,009
Impairment of long-lived assets and losses on regulatory assets	488			274
Gain on sales of assets	(5		)	(41		)
Bargain purchase gain	(233		)	—
Deferred income taxes and amortization of investment tax credits	439			623
Net fair value changes related to derivatives	149			100
Net realized and unrealized gains on nuclear decommissioning trust fund investments	(429		)	(243		)
Other non-cash operating activities	603			1,224
Changes in assets and liabilities:
Accounts receivable	224			(296		)
Inventories	(87		)	21
Accounts payable and accrued expenses	(593		)	296
Option premiums received (paid), net	35			(24		)
Collateral (posted) received, net	(100		)	757
Income taxes	167			527
Pension and non-pension postretirement benefit contributions	(344		)	(283		)
Other assets and liabilities	(547		)	(537		)
Net cash flows provided by operating activities	5,677			7,363
Cash flows from investing activities
Capital expenditures	(5,556		)	(6,368		)
Proceeds from nuclear decommissioning trust fund sales	6,848			7,914
Investment in nuclear decommissioning trust funds	(7,044		)	(8,093		)
Acquisition of businesses, net	(208		)	(6,896		)
Proceeds from sales of long-lived assets	219			49
Proceeds from termination of direct financing lease investment	—			360
Changes in restricted cash	(67		)	(75		)
Other investing activities	(2		)	(110		)
Net cash flows used in investing activities	(5,810		)	(13,219		)
Cash flows from financing activities
Changes in short-term borrowings	(570		)	(1,014		)
Proceeds from short-term borrowings with maturities greater than 90 days	621			195
Repayments on short-term borrowings with maturities greater than 90 days	(610		)	(452		)
Issuance of long-term debt	2,616			4,488
Retirement of long-term debt	(1,728		)	(944		)
Retirement of long-term debt to financing trust	(250		)	—
Restricted proceeds from issuance of long-term debt	—			(30		)
Redemption of preference stock	—			(190		)
Sale of noncontrolling interest	396			—
Dividends paid on common stock	(921		)	(873		)
Common stock issued from treasury stock	1,150			—
Proceeds from employee stock plans	61			36
Other financing activities	(64		)	35
Net cash flows provided by financing activities	701			1,251
Increase (Decrease) in cash and cash equivalents	568			(4,605		)
Cash and cash equivalents at beginning of period	635			6,502
Cash and cash equivalents at end of period	$	1,203		$	1,897



(In millions)	September 30, 2017		December 31, 2016
ASSETS
Current assets
Cash and cash equivalents	$	1,203	$	635
Restricted cash and cash equivalents	320		253
Deposit with IRS	1,250		1,250
Accounts receivable, net
Customer	3,854		4,158
Other	950		1,201
Mark-to-market derivative assets	699		917
Unamortized energy contract assets	81		88
Inventories, net
Fossil fuel and emission allowances	387		364
Materials and supplies	1,281		1,274
Regulatory assets	1,264		1,342
Other	1,435		930
Total current assets	12,724		12,412
Property, plant and equipment, net	73,067		71,555
Deferred debits and other assets
Regulatory assets	10,238		10,046
Nuclear decommissioning trust funds	12,966		11,061
Investments	634		629
Goodwill	6,677		6,677
Mark-to-market derivative assets	426		492
Unamortized energy contract assets	407		447
Pledged assets for Zion Station decommissioning	57		113
Other	1,277		1,472
Total deferred debits and other assets	32,682		30,937
Total assets^(a)	$	118,473	$	114,904



	Three Months Ended March 31, 2020
(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, 2019	974,416	$	19,274		$	(123	)	$	16,267		$	(3,194	)	$	2,349		$	34,573
Net income	—	—			—			582			—			(206		)	376
Long-term incentive plan activity	1,354	(4		)	—			—			—			—			(4		)
Employee stock purchase plan issuances	470	31			—			—			—			—			31
Changes in equity of noncontrolling interests	—				—			—			—			(9		)	(9		)
Sale of noncontrolling interests	—	2			—			—			—			—			2
Common stock dividends ($0.38/common share)	—	—			—			(374		)	—			—			(374		)
Other comprehensive income, net of income taxes	—	—			—			—			21						21
Balance, March 31, 2020	976,240	$	19,303		$	(123	)	$	16,475		$	(3,173	)	$	2,134		$	34,616



	Three Months Ended March 31, 2020
	Member’s Equity
(In millions)	Membership Interest		Undistributed Earnings			Accumulated Other Comprehensive Loss, net			Noncontrolling Interests			Total Equity
Balance, December 31, 2019	$	9,566	$	3,950		$	(32	)	$	2,346		$	15,830
Net income (loss)	—		45			—			(206		)	(161		)
Changes in equity of noncontrolling interests	—		—			—			(11		)	(11		)
Sale of noncontrolling interests	2		—			—			—			2
Distributions to member	—		(468		)	—			—			(468		)
Other comprehensive loss, net of income taxes	—		—			(9		)	—			(9		)
Balance, March 31, 2020	$	9,568	$	3,527		$	(41	)	$	2,129		$	15,183



(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



(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 March 31, 2020
(In millions)	Common Stock		Retained Earnings			Total Shareholder's Equity
Balance, December 31, 2019	$	1,796	$	1,111		$	2,907
Net income	—		52			52
Common stock dividends	—		(28		)	(28		)
Contributions from parent	137		—			137
Balance, March 31, 2020	$	1,933	$	1,135		$	3,068



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		%



													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



	Dresden			Byron			Braidwood			Total
Asset Balances
Materials and supplies inventory, net	$	68		$	68		$	81		$	217
Nuclear fuel inventory, net	204			172			203			579
Completed plant, net	1,084			1,343			1,390			3,817
Construction work in progress	16			22			32			70
Liability Balances
Asset retirement obligation	(1,301		)	(596		)	(554		)	(2,451		)

NRC License First Renewal Term	2029 (Unit 2)			2044 (Unit 1)			2046 (Unit 1)
NRC License First Renewal Term	2031 (Unit 3)			2046 (Unit 2)			2047 (Unit 2)



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



	March 31, 2020
Asset Balances
Materials and supplies inventory	$	32
Fuel inventory	12
Property, plant and equipment, net	902
Liability Balances
Asset retirement obligation	(3		)

Generation’s Net Income

Utility Registrants’ Net Income

Commercial & Industrial Customers

Residential Customers