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

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

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

(d)	Electric supply procured under site specific agreements.

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

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

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

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

(b)	Includes wind, hydroelectric, solar and biomass generating assets.

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

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

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

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

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

•	the impacts of on-going competition, and

•	emerging technologies and business models.

•	the design of power markets,

•	zero emission credit programs,

•	utility regulatory business model,

•	regulations and other standards,

•	environmental policy, and

•	tax policy.

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

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

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

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

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

(b)	100%, unless otherwise indicated.

(c)

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

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

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

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

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

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

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

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

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

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

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

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

•	All dividends are reinvested.

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

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

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

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

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

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

•	Higher net unrealized and realized gains on NDT funds;

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

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

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

•	Decreased nuclear outage days;

•	Lower mark-to-market losses;

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

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

•	Decreased storms costs at PECO and BGE; and

•	Research and development income tax benefits.

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•	Lower realized energy prices;

•	Lower capacity prices;

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

•	Unfavorable volume at PECO.

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

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

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

(d)

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

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

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

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

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

(i)

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

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

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

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

(b)	Excludes any retired sites.

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(a)

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

(a)

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

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•	Higher net unrealized and realized gains on NDT funds;

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

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

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

•	Decreased nuclear outage days;

•	Lower mark-to-market losses;

•	Research and development income tax credits.

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•	Lower realized energy prices; and

•	Lower capacity prices.

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

(b)	Includes results of transactions with ComEd.

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

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

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

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

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

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

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

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

(a)	Unrealized gains (losses), realized gains and interest and dividend income on the NDT funds are associated with the Non-Regulatory Agreement units.

(b)	Contractual elimination of income tax expense is associated with the income taxes on the NDT funds of the Regulatory Agreement units.

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(a)	Primarily reflects an increase in discount rates and the favorable impacts of the merger of two of Exelon’s pension plans

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

(c)

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

•	During 2018, Exelon and Generation had expenditures of $81 million and $57 related to the acquisitions of the Everett Marine Terminal and the Handley generating station.

•	During 2017, Exelon and Generation had expenditures of $23 million and $178 million related to the acquisitions of ConEdison Solutions and the FitzPatrick nuclear generating station.

•	During 2018, Exelon and Generation had proceeds of $85 million relating to the sale of Generation’s interest in an electrical contracting business that primarily installs, maintains and repairs underground and high-voltage cable transmission and distribution services.

•	During 2017, Exelon and Generation had proceeds of $218 million from sales of long-lived assets, primarily related to the sale back of turbine equipment.

•	Changes in intercompany money pool are driven by short-term borrowing needs. Refer to more information regarding the intercompany money pool below.

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•	Changes in short-term borrowings, net, is driven by repayments on and issuances of notes due in less than 90 days. Refer to Note 16 - Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on short-term borrowings.

•	Long-term debt, net, varies due to debt issuances and redemptions each year. Refer to debt issuances and redemptions tables below for more information.

•	Changes in intercompany money pool are driven by short-term borrowing needs. Refer to more information regarding the intercompany money pool below.

•	Exelon issued common stock in 2017 to fund the PHI merger. Refer to Note 19 - Shareholders' Equity of the Combined Notes to Consolidated Financial statements for additional information on common stock issuances.

•

Exelon’s ability to pay dividends on its common stock depends on the receipt of dividends paid by its operating subsidiaries. The payments of dividends to Exelon by its subsidiaries in turn depend on their results of operations and cash flows and other items affecting retained earnings. See Note 18 - Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on dividend restrictions. See below for quarterly dividends declared.

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•	The change in sale of controlling interest from 2017 to 2018 was primarily related to cash received in 2017 for the sale of a 49% interest in EGRP. Refer to Note 22 - Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for additional information on sale of controlling interest.

(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.

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(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.

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

(b)	See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of nonrecourse debt.

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(c)	As a result of the bankruptcy filing for EGTP on November 7, 2017, the nonrecourse debt was deconsolidated from Exelon's and Generation's consolidated financial statements. See Note 2 — Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.

(a)	On January 15, 2020, Generation redeemed $1 billion of 2.95% Senior Notes at maturity.

(b)	See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of nonrecourse debt.

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(a)	See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of nonrecourse debt.

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(a)	See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of nonrecourse debt.

(b)	As a result of the bankruptcy filing for EGTP on November 7, 2017, the nonrecourse debt was deconsolidated from Exelon's and Generation's consolidated financial statements. See Note 2 — Mergers, Acquisitions and Dispositions for additional information.

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

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

(a)

Includes approximately $390 million, $205 million and $184 million owed to unconsolidated affiliates of Exelon, ComEd, and PECO respectively. These special purpose entities were created for the sole purposes of issuing mandatorily redeemable trust preferred securities of ComEd and PECO. See Note 22 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for additional information regarding the authoritative guidance for VIEs.

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(a)	Generation currently has blanket financing authority it received from FERC in connection with its market-based rate authority.

(b)	On October 15, 2019, ComEd, BGE, Pepco and DPL filed applications with FERC and on September 12, 2019, ACE filed an application with NJBPU for renewal of their short-term financing authority through December 31, 2021. ComEd, BGE, Pepco and DPL received approval on December 13, 2019 and ACE received approval on December 6, 2019.

(c)	As of December 31, 2019, ComEd had $393 million in new money long-term debt financing authority from the ICC with an expiration date of August 1, 2021. On January 22, 2020, ComEd had an additional $1.5 billion available in new money long-term debt financing authority from the ICC with an effective date of February 1, 2020 and an expiration date of February 1, 2023.

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(a)	Includes amounts from ComEd and PECO financing trusts.

(b)	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2019 and do not reflect anticipated future refinancing, early redemptions or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2019. Includes estimated interest payments due to ComEd and PECO financing trusts.

(c)	Capacity payments associated with contracted generation lease agreements are net of sublease and capacity offsets of $143 million, $98 million, $55 million, $44 million, $44 million and $223 million for 2020, 2021, 2022, 2023, 2024 and thereafter, respectively and $607 million in total.

(d)	Purchase power obligations primarily include expected payments for REC purchases and payments associated with contracted generation agreements, which may be reduced based on plant availability. Expected payments exclude payments on renewable generation contracts that are contingent in nature.

(e)	Represents commitments to purchase nuclear fuel, natural gas and related transportation, storage capacity and services.

(f)

Represents the future estimated value at December 31, 2019 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between the Registrants and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.

(g)	These amounts represent Exelon’s expected contributions to its qualified pension plans. Qualified pension contributions for years after 2025 are not included.

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(a)	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2019 and do not reflect anticipated future refinancing, early redemptions or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2019.

(b)	Capacity payments associated with contracted generation lease agreements are net of sublease and capacity offsets of $143 million, $98 million, $55 million, $44 million, $44 million and $223 million for 2020, 2021, 2022, 2023, 2024 and thereafter, respectively and $607 million in total.

(c)	Purchase power obligations primarily include expected payments for REC purchases and capacity payments associated with contracted generation agreements, which may be reduced based on plant availability. Expected payments exclude payments on renewable generation contracts that are contingent in nature.

(d)	Primarily represents commitments to purchase fuel supplies for nuclear and fossil generation, including those related to CENG.

(e)

Represents the future estimated value at December 31, 2019 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between Generation and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.

(a)	Includes amounts from ComEd financing trust.

(b)	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2019 and do not reflect anticipated future refinancing, early redemptions or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2019. Includes estimated interest payments due to the ComEd financing trust.

(c)

Represents the future estimated value at December 31, 2019 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between ComEd and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.

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(a)	Includes amounts from PECO financing trusts.

(b)	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2019 and do not reflect anticipated future refinancing, early redemptions or debt issuances. Includes estimated interest payments due to the PECO financing trust.

(c)	Represents commitments to purchase natural gas and related transportation, storage capacity and services.

(d)

Represents the future estimated value at December 31, 2019 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between PECO and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.

(a)	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2019 and do not reflect anticipated future refinancing, early redemptions or debt issuances.

(b)	Represents commitments to purchase natural gas and related transportation, storage capacity and services.

(c)

Represents the future estimated value at December 31, 2019 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between BGE and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.

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(a)	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2019 and do not reflect anticipated future refinancing, early redemptions or debt issuances.

(b)	Represents commitments to purchase natural gas and related transportation, storage capacity and services.

(c)

Represents the future estimated value at December 31, 2019 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between PHI and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.

(a)	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2019 and do not reflect anticipated future refinancing, early redemptions or debt issuances.

(b)

Represents the future estimated value at December 31, 2019 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between Pepco and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.

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(a)	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2019 and do not reflect anticipated future refinancing, early redemptions or debt issuances.

(b)	Represents commitments to purchase natural gas and related transportation, storage capacity and services.

(c)

Represents the future estimated value at December 31, 2019 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between DPL and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.

(a)	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2019 and do not reflect anticipated future refinancing, early redemptions or debt issuances.

(b)

Represents the future estimated value at December 31, 2019 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between ACE and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.

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(a)	Amounts are shown net of collateral paid to and received from counterparties.

(b)

For ComEd, the changes in fair value are recorded as a change in regulatory assets or liabilities. As of December 31, 2018 and 2019, ComEd recorded a regulatory liability of $249 million and $301 million, respectively, related to its mark-to-market derivative liabilities with Generation and unaffiliated suppliers. ComEd recorded $24 million of decreases in fair value and an increase for realized losses due to settlements of $17 million in purchased power expense associated with floating-to-fixed energy swap suppliers for the year ended December 31, 2018. ComEd recorded $78 million of decreases in fair value and an increase for realized losses due to settlements of $26 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2019.

(c)	Includes derivative contracts acquired or sold by Generation through upfront payments or receipts of cash, excluding option premiums, and the associated amortizations.

(d)	Includes fair value from contracts received at acquisition of the Everett Marine Terminal.

(a)	Mark-to-market gains and losses on other economic hedge and trading derivative contracts that are recorded in results of operations.

(b)	Amounts are shown net of collateral paid to and received from counterparties (and offset against mark-to-market assets and liabilities) of $929 million at December 31, 2019.

(c)	Includes ComEd’s net assets (liabilities) associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.

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(a)	Mark-to-market gains and losses on other economic hedge and trading derivative contracts that are recorded in the results of operations.

(b)	Amounts are shown net of collateral paid to and received from counterparties (and offset against mark-to-market assets and liabilities) of $929 million at December 31, 2019.

(a)	Represents ComEd’s net liabilities associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.

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(a)	As of December 31, 2019, credit collateral held from counterparties where Generation had credit exposure included $25 million of cash and $81 million of letters of credit.

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(a)	The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was immaterial for the year ended December 31, 2019 and approximately 3 million and 8 million for the years ended December 31, 2018 and 2017, respectively.

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(a)

Exelon’s consolidated assets include $9,532 million and $9,667 million at December 31, 2019 and 2018, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $3,473 million and $3,548 million at December 31, 2019 and 2018, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 22–Variable Interest Entities for additional information.

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(a)

Generation’s consolidated assets include $9,512 million and $9,634 million at December 31, 2019 and 2018, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $3,429 million and $3,480 million at December 31, 2019 and 2018, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 22–Variable Interest Entities for additional information.

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(a)	In millions, shares round to zero. Number of shares is 1,500 authorized and 1,000 outstanding at December 31, 2019 and 2018.

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(a)

PHI’s consolidated total assets include $20 million and $33 million at December 31, 2019 and 2018, respectively, of PHI's consolidated VIE that can only be used to settle the liabilities of the VIE. PHI’s consolidated total liabilities include $44 million and $69 million at December 31, 2019 and 2018, respectively, of PHI's consolidated VIE for which the VIE creditors do not have recourse to PHI. See Note 22 - Variable Interest Entities for additional information.

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(a)	In millions, shares round to zero. Number of shares is 100 outstanding at December 31, 2019 and 2018.

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(a)	In millions, shares round to zero. Number of shares is 1,000 authorized and 1,000 outstanding at December 31, 2019 and 2018.

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(a)

ACE’s consolidated assets include $17 million and $23 million at December 31, 2019 and 2018, respectively, of ACE’s consolidated VIE that can only be used to settle the liabilities of the VIE. ACE’s consolidated liabilities include $41 million and $59 million at December 31, 2019 and 2018, respectively, of ACE’s consolidated VIE for which the VIE creditors do not have recourse to ACE. See Note 22 - Variable Interest Entities for additional information.

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Description of Business (All Registrants)

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

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

Basis of Presentation (All Registrants)

This is a combined annual report of all Registrants. The Notes to the Consolidated Financial Statements apply to the Registrants as indicated above in the Index to Combined Notes to Consolidated Financial Statements and parenthetically next to each corresponding disclosure. When appropriate, the Registrants are named specifically for their related activities and disclosures. Each of the Registrant’s Consolidated Financial Statements includes the accounts of its subsidiaries. All intercompany transactions have been eliminated.

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

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Exelon owns 100% of Generation, PECO, BGE and PHI and more than 99% of ComEd. PHI owns 100% of Pepco, DPL and ACE. Generation owns 100% of its significant consolidated subsidiaries, either directly or indirectly, except for certain consolidated VIEs, including CENG and EGRP, of which Generation holds a 50.01% and 51% interest, respectively. The remaining interests in these consolidated VIEs are included in noncontrolling interests on Exelon’s and Generation’s Consolidated Balance Sheets. See Note 22 — Variable Interest Entities for additional information of Exelon’s and Generation’s consolidated VIEs.

The Registrants consolidate the accounts of entities in which a Registrant has a controlling financial interest, after the elimination of intercompany transactions. Where the Registrants do not have a controlling financial interest in an entity, proportionate consolidation, equity method accounting or accounting for investments in equity securities without readily determinable fair value is applied. The Registrants apply proportionate consolidation when they have an undivided interest in an asset and are proportionately liable for their share of each liability associated with the asset. The Registrants proportionately consolidate their undivided ownership interests in jointly owned electric plants and transmission facilities. Under proportionate consolidation, the Registrants separately record their proportionate share of the assets, liabilities, revenues and expenses related to the undivided interest in the asset. The Registrants apply equity method accounting when they have significant influence over an investee through an ownership in common stock, which generally approximates a 20% to 50% voting interest. The Registrants apply equity method accounting to certain investments and joint ventures, including certain financing trusts of ComEd and PECO. Under equity method accounting, the Registrants report their interest in the entity as an investment and the Registrants’ percentage share of the earnings from the entity as single line items in their financial statements. The Registrants use accounting for investments in equity securities without readily determinable fair values if they lack significant influence, which generally results when they hold less than 20% of the common stock of an entity. Under accounting for investments in equity securities without readily determinable fair values, the Registrants report their investments at cost adjusted for changes from observable transactions for identical or similar investments of the same issuer, less impairment. Changes in measurement are reported in earnings.

The accompanying consolidated financial statements have been prepared in accordance with GAAP for annual financial statements and in accordance with the instructions to Form 10-K and Regulation S-X promulgated by the SEC.

Use of Estimates (All Registrants)

The preparation of financial statements of each of the Registrants in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Areas in which significant estimates have been made include, but are not limited to, the accounting for nuclear decommissioning costs and other AROs, pension and OPEB, the application of purchase accounting, inventory reserves, allowance for uncollectible accounts, goodwill and asset impairments, derivative instruments, unamortized energy contracts, fixed asset depreciation, environmental costs and other loss contingencies, taxes and unbilled energy revenues. Actual results could differ from those estimates.

Prior Period Adjustments and Reclassifications (Exelon, PHI and Pepco)

In the fourth quarter 2019, management identified an error related to an overstatement of the regulatory asset associated with Pepco’s decoupling mechanism for Maryland that originated in 2007 upon the inception of the program. Management has concluded that the error was not material to previously issued consolidated financial statements and the error was corrected through a revision to Exelon’s, PHI’s and Pepco’s consolidated financial statements contained herein for the years ended December 31, 2018 and 2017. The impact of the error correction was an $11 million reduction to Exelon’s, PHI’s and Pepco’s opening Retained earnings as of January 1, 2017 with a corresponding reduction to current Regulatory assets of $18 million and Deferred income taxes and unamortized investment tax credits of $7 million. In addition, Exelon’s, PHI’s and Pepco’s Total operating revenues decreased by $7 million for the years ended December 31, 2018 and 2017 and Net income decreased by $5 million and $7 million for the years ended December 31, 2018 and 2017, respectively, from originally reported amounts. The error did not impact net cash flows provided by operating activities, net cash flows used in investing activities or net cash flows provided by financing activities for the years ended December 31, 2018 and 2017 for Exelon, PHI and Pepco. Exelon’s diluted earnings per share of common stock remained unchanged from the originally reported amount for the year ended December 31, 2018. Exelon’s basic earnings per share of common stock for the year ended December 31, 2018 and basic and diluted earnings per share of common stock for the year ended December 31, 2017 decreased by $0.01 from the originally reported amount.

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Accounting for the Effects of Regulation (Exelon and the Utility Registrants)

For their regulated electric and gas operations, Exelon and the Utility Registrants reflect the effects of cost-based rate regulation in their financial statements, which is required for entities with regulated operations that meet the following criteria: 1) rates are established or approved by a third-party regulator; (2) rates are designed to recover the entities’ cost of providing services or products; and (3) there is a reasonable expectation that rates designed to recover costs can be charged to and collected from customers. Exelon and the Utility Registrants account for their regulated operations in accordance with regulatory and legislative guidance from the regulatory authorities having jurisdiction, principally the ICC, PAPUC, MDPSC, DCPSC, DPSC and NJBPU, under state public utility laws and the FERC under various Federal laws. Regulatory assets and liabilities are amortized and the related expense or revenue is recognized in the Consolidated Statements of Operations consistent with the recovery or refund included in customer rates. Exelon's regulatory assets and liabilities as of the balance sheet date are probable of being recovered or settled in future rates. If a separable portion of the Registrants' business was no longer able to meet the criteria discussed above, the affected entities would be required to eliminate from their consolidated financial statements the effects of regulation for that portion, which could have a material impact on their financial statements. See Note 3 — Regulatory Matters for additional information.

With the exception of income tax-related regulatory assets and liabilities, Exelon and the Utility Registrants classify regulatory assets and liabilities with a recovery or settlement period greater than one year as both current and non-current in their Consolidated Balance Sheets, with the current portion representing the amount expected to be recovered from or settled to customers over the next twelve-month period as of the balance sheet date.  Income tax-related regulatory assets and liabilities are classified entirely as non-current in Exelon's and the Utility Registrants’ Consolidated Balance Sheets to align with the classification of the related deferred income tax balances.

Exelon and the Utility Registrants treat the impacts of a final rate order received after the balance sheet date but prior to the issuance of the financial statements as a non-recognized subsequent event, as the receipt of a final rate order is a separate and distinct event that has future impacts on the parties affected by the order.

Revenues (All Registrants)

Operating Revenues. The Registrants’ operating revenues generally consist of revenues from contracts with customers involving the sale and delivery of energy commodities and related products and services, utility revenues from ARP, and realized and unrealized revenues recognized under mark-to-market energy commodity derivative contracts. The Registrants recognize revenue from contracts with customers to depict the transfer of goods or services to customers in an amount that the entities expect to be entitled to in exchange for those goods or services. Generation’s primary sources of revenue include competitive sales of power, natural gas, and other energy-related products and services. The Utility Registrants’ primary sources of revenue include regulated electric and natural gas tariff sales, distribution and transmission services. At the end of each month, the Registrants accrue an estimate for the unbilled amount of energy delivered or services provided to customers.

ComEd records ARP revenue for its best estimate of the electric distribution, energy efficiency, and transmission revenue impacts resulting from future changes in rates that ComEd believes are probable of approval by the ICC and FERC in accordance with its formula rate mechanisms. BGE, Pepco and DPL record ARP revenue for their best estimate of the electric and natural gas distribution revenue impacts resulting from future changes in rates that they believe are probable of approval by the MDPSC and/or DCPSC in accordance with their revenue decoupling mechanisms. PECO, BGE, Pepco, DPL and ACE record ARP revenue for their best estimate of the transmission revenue impacts resulting from future changes in rates that they believe are probable of approval by FERC in accordance with their formula rate mechanisms. See Note 3 — Regulatory Matters for additional information.

Option Contracts, Swaps and Commodity Derivatives. Certain option contracts and swap arrangements that meet the definition of derivative instruments are recorded at fair value with subsequent changes in fair value recognized as revenue or expense. The classification of revenue or expense is based on the intent of the transaction. To the extent a Utility Registrant receives full cost recovery for energy procurement and related costs from retail customers, it records the fair value of its energy swap contracts with unaffiliated suppliers as well as an offsetting regulatory asset or liability in its Consolidated Balance Sheets. See Note 3 — Regulatory Matters and Note 15 — Derivative Financial Instruments for additional information.

Taxes Directly Imposed on Revenue-Producing Transactions. The Registrants collect certain taxes from customers such as sales and gross receipts taxes, along with other taxes, surcharges and fees, that are levied by

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state or local governments on the sale or distribution of gas and electricity. Some of these taxes are imposed on the customer, but paid by the Registrants, while others are imposed on the Registrants. Where these taxes are imposed on the customer, such as sales taxes, they are reported on a net basis with no impact to the Consolidated Statements of Operations and Comprehensive Income. However, where these taxes are imposed on the Registrants, such as gross receipts taxes or other surcharges or fees, they are reported on a gross basis. Accordingly, revenues are recognized for the taxes collected from customers along with an offsetting expense. See Note 23 — Supplemental Financial Information for Generation’s, ComEd’s, PECO’s, BGE’s, Pepco's, DPL's and ACE's utility taxes that are presented on a gross basis.

Leases (All Registrants)

The Registrants recognize a ROU asset and lease liability for operating leases with a term of greater than one year. The ROU asset is included in Other deferred debits and other assets and the lease liability is included in Other current liabilities and Other deferred credits and other liabilities on the Consolidated Balance Sheets. The ROU asset is measured as the sum of (1) the present value of all remaining fixed and in-substance fixed payments using each Registrant’s incremental borrowing rate, (2) any lease payments made at or before the commencement date (less any lease incentives received) and (3) any initial direct costs incurred. The lease liability is measured the same as the ROU asset, but excludes any payments made before the commencement date and initial direct costs incurred. Lease terms include options to extend or terminate the lease if it is reasonably certain they will be exercised. The Registrants include non-lease components for most asset classes, which are service-related costs that are not integral to the use of the asset, in the measurement of the ROU asset and lease liability.

Expense for operating leases and leases with a term of one year or less is recognized on a straight-line basis over the term of the lease, unless another systematic and rational basis is more representative of the derivation of benefit from use of the leased property. Variable lease payments are recognized in the period in which the related obligation is incurred and consist primarily of payments for purchases of electricity under contracted generation and are based on the electricity produced by those generating assets. Operating lease expense and variable lease payments are recorded to Purchased power and fuel expense for contracted generation or Operating and maintenance expense for all other lease agreements on the Registrants’ Statements of Operations and Comprehensive Income.

Income from operating leases, including subleases, is recognized on a straight-line basis over the term of the lease, unless another systematic and rational basis is more representative of the pattern in which income is earned over the term of the lease. Variable lease payments are recognized in the period in which the related obligation is performed and consist primarily of payments received from sales of electricity under contracted generation and are based on the electricity produced by those generating assets. Operating lease income and variable lease payments are recorded to Operating revenues on the Registrants’ Statements of Operations and Comprehensive Income.

The Registrants’ operating leases consist primarily of contracted generation, real estate including office buildings, and vehicles and equipment. The Registrants generally account for contracted generation in which the generating asset is not renewable as a lease if the customer has dispatch rights and obtains substantially all of the economic benefits. For new agreements entered after January 1, 2019, the Registrants generally do not account for contracted generation in which the generating asset is renewable as a lease if the customer does not design the generating asset. The Registrants account for land right arrangements that provide for exclusive use as leases while shared use land arrangements are generally not leases. The Registrants do not account for secondary use pole attachments as leases.

See Note 10 — Leases for additional information.

Income Taxes (All Registrants)

Deferred Federal and state income taxes are recorded on significant temporary differences between the book and tax basis of assets and liabilities and for tax benefits carried forward. Investment tax credits have been deferred in the Registrants’ Consolidated Balance Sheets and are recognized in book income over the life of the related property. The Registrants account for uncertain income tax positions using a benefit recognition model with a two-step approach; a more-likely-than-not recognition criterion; and a measurement approach that measures the position as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. If it is not more-likely-than-not that the benefit of the tax position will be sustained on its technical merits, no benefit is recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. The Registrants recognize accrued interest related to unrecognized tax

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benefits in Interest expense or Other income and deductions (interest income) and recognize penalties related to unrecognized tax benefits in Other, net in their Consolidated Statements of Operations and Comprehensive Income.

Cash and Cash Equivalents (All Registrants)

The Registrants consider investments purchased with an original maturity of three months or less to be cash equivalents.

Restricted Cash and Cash Equivalents (All Registrants)

Restricted cash and cash equivalents represent funds that are restricted to satisfy designated current liabilities. As of December 31, 2019 and 2018, the Registrants' restricted cash and cash equivalents primarily represented the following items:

Registrant	Description
Exelon	Payment of medical, dental, vision and long-term disability benefits, in addition to the items listed for Generation and the Utility Registrants.
Generation	Project-specific nonrecourse financing structures for debt service and financing of operations of the underlying entities.
ComEd	Collateral held from suppliers associated with energy and REC procurement contracts, any over-recovered RPS costs and alternative compliance payments received from RES pursuant to FEJA and costs for the remediation of an MGP site.
PECO	Proceeds from the sales of assets that were subject to PECO’s mortgage indenture.
BGE	Proceeds from the loan program for the completion of certain energy efficiency measures and collateral held from energy suppliers.
PHI	Payment of merger commitments, collateral held from its energy suppliers associated with procurement contracts and repayment of transition bonds.
Pepco	Payment of merger commitments and collateral held from energy suppliers.
DPL	Collateral held from energy suppliers.
ACE	Repayment of transition bonds and collateral held from energy suppliers.

Restricted cash and cash equivalents not available to satisfy current liabilities are classified as noncurrent assets. As of December 31, 2019 and 2018, the Registrants' noncurrent restricted cash and cash equivalents primarily represented ComEd’s over-recovered RPS costs and alternative compliance payments received from RES pursuant to FEJA and costs for the remediation of an MGP site, and ACE’s repayment of transition bonds.

See Note 23 — Supplemental Financial Information for additional information.

Allowance for Uncollectible Accounts (All Registrants)

The allowance for uncollectible accounts reflects the Registrants’ best estimates of losses on the customers' accounts receivable balances. For Generation, the allowance is based on accounts receivable aging historical experience and other currently available information. Utility Registrants estimate the allowance by applying loss rates developed specifically for each company to the outstanding receivable balance by customer risk segment. Utility Registrants' customer accounts are written off consistent with approved regulatory requirements. See Note 3 — Regulatory Matters for additional information regarding the regulatory recovery of uncollectible accounts receivable at ComEd and ACE.

Variable Interest Entities (Exelon, Generation, PHI and ACE)

Exelon accounts for its investments in and arrangements with VIEs based on the following specific requirements:

•	requires an entity to qualitatively assess whether it should consolidate a VIE based on whether the entity has a controlling financial interest,

•	requires an ongoing reconsideration of this assessment instead of only upon certain triggering events, and

•	requires the entity that consolidates a VIE (the primary beneficiary) to disclose (1) the assets of the consolidated VIE, if they can be used to only settle specific obligations of the consolidated VIE, and (2) the

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liabilities of a consolidated VIE for which creditors do not have recourse to the general credit of the primary beneficiary.

See Note 22 — Variable Interest Entities for additional information.

Inventories (All Registrants)

Inventory is recorded at the lower of weighted average cost or net realizable value. Provisions are recorded for excess and obsolete inventory. Fossil fuel, materials and supplies, and emissions allowances are generally included in inventory when purchased. Fossil fuel and emissions allowances are expensed to purchased power and fuel expense when used or sold. Materials and supplies generally includes transmission, distribution and generating plant materials and are expensed to operating and maintenance or capitalized to property, plant and equipment, as appropriate, when installed or used.

Debt and Equity Security Investments (Exelon and Generation)

Debt Security Investments. Debt securities are reported at fair value and classified as available-for-sale securities. Unrealized gains and losses, net of tax, are reported in OCI.

Equity Security Investments without Readily Determinable Fair Values. Exelon has certain equity securities without readily determinable fair values. Exelon has elected to use the practicability exception to measure these investments, defined as cost adjusted for changes from observable transactions for identical or similar investments of the same issuer, less impairment. Changes in measurement are reported in earnings.

Equity Security Investments with Readily Determinable Fair Values. Equity securities held in the NDT funds are classified as equity securities with readily determinable fair values. Realized and unrealized gains and losses, net of tax, on Generation’s NDT funds associated with the Regulatory Agreement Units are included in regulatory liabilities at Exelon, ComEd and PECO, in Noncurrent payables to affiliates at Generation and in Noncurrent receivables from affiliates at ComEd and PECO. Realized and unrealized gains and losses, net of tax, on Generation’s NDT funds associated with the Non-Regulatory Agreement Units are included in earnings at Exelon and Generation. Exelon's and Generation's NDT funds are classified as current or noncurrent assets, depending on the timing of the decommissioning activities and income taxes on trust earnings. See Note 3 — Regulatory Matters for additional information regarding ComEd’s and PECO’s regulatory assets and liabilities and Note 17 — Fair Value of Financial Assets and Liabilities and Note 9 — Asset Retirement Obligations for additional information regarding marketable securities held by NDT funds.

Property, Plant and Equipment (All Registrants)

Property, plant and equipment is recorded at original cost. Original cost includes construction-related direct labor and material costs. The Utility Registrants also include indirect construction costs including labor and related costs of departments associated with supporting construction activities. When appropriate, original cost also includes capitalized interest for Generation, Exelon Corporate and PHI and AFUDC for regulated property at the Utility Registrants. The cost of repairs and maintenance, including planned major maintenance activities and minor replacements of property, is charged to Operating and maintenance expense as incurred.

Third parties reimburse the Utility Registrants for all or a portion of expenditures for certain capital projects. Such contributions in aid of construction costs (CIAC) are recorded as a reduction to Property, plant and equipment, net. DOE SGIG and other funds reimbursed to the Utility Registrants have been accounted for as CIAC.

For Generation, upon retirement, the cost of property is generally charged to accumulated depreciation in accordance with the composite and group methods of depreciation. Upon replacement of an asset, the costs to remove the asset, net of salvage, are capitalized to gross plant when incurred as part of the cost of the newly-installed asset and recorded to depreciation expense over the life of the new asset. Removal costs, net of salvage, incurred for property that will not be replaced is charged to Operating and maintenance expense as incurred.

For the Utility Registrants, upon retirement, the cost of property, net of salvage, is charged to accumulated depreciation consistent with the composite and group methods of depreciation.  Depreciation expense at ComEd, BGE, Pepco, DPL and ACE includes the estimated cost of dismantling and removing plant from service upon retirement. Actual incurred removal costs are applied against a related regulatory liability or recorded to a regulatory asset if in excess of previously collected removal costs.  PECO’s removal costs are capitalized to accumulated

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depreciation when incurred, and recorded to depreciation expense over the life of the new asset constructed consistent with PECO’s regulatory recovery method.

Capitalized Software. Certain costs, such as design, coding, and testing incurred during the application development stage of software projects that are internally developed or purchased for operational use are capitalized within Property, plant and equipment. Similar costs incurred for cloud-based solutions treated as service arrangements are capitalized within Other Current Assets and Deferred Debits and Other Assets. Such capitalized amounts are amortized ratably over the expected lives of the projects when they become operational, generally not to exceed five years. Certain other capitalized software costs are being amortized over longer lives based on the expected life or pursuant to prescribed regulatory requirements.

Capitalized Interest and AFUDC. During construction, Exelon and Generation capitalize the costs of debt funds used to finance non-regulated construction projects. Capitalization of debt funds is recorded as a charge to construction work in progress and as a non-cash credit to interest expense.

AFUDC is the cost, during the period of construction, of debt and equity funds used to finance construction projects for regulated operations. AFUDC is recorded to construction work in progress and as a non-cash credit to an allowance that is included in interest expense for debt-related funds and other income and deductions for equity-related funds. The rates used for capitalizing AFUDC are computed under a method prescribed by regulatory authorities.

See Note 7 — Property, Plant and Equipment, Note 8 — Jointly Owned Electric Utility Plant and Note 23 — Supplemental Financial Information for additional information regarding property, plant and equipment.

Nuclear Fuel (Exelon and Generation)

The cost of nuclear fuel is capitalized within Property, plant and equipment and charged to fuel expense using the unit-of-production method. Any potential future SNF disposal fees will be expensed through fuel expense. Additionally, certain on-site SNF storage costs are being reimbursed by the DOE since a DOE (or government-owned) long-term storage facility has not been completed. See Note 18 — Commitments and Contingencies for additional information regarding the cost of SNF storage and disposal.

Nuclear Outage Costs (Exelon and Generation)

Costs associated with nuclear outages, including planned major maintenance activities, are expensed to Operating and maintenance expense or capitalized to Property, plant and equipment (based on the nature of the activities) in the period incurred.

Depreciation and Amortization (All Registrants)

Except for the amortization of nuclear fuel, depreciation is generally recorded over the estimated service lives of property, plant and equipment on a straight-line basis using the group, composite or unitary methods of depreciation. The group approach is typically for groups of similar assets that have approximately the same useful lives and the composite approach is used for dissimilar assets that have different lives. Under both methods, a reporting entity depreciates the assets over the average life of the assets in the group. The Utility Registrants' depreciation expense includes the estimated cost of dismantling and removing plant from service upon retirement, which is consistent with each utility's regulatory recovery method. The estimated service lives for the Registrants are based on a combination of depreciation studies, historical retirements, site licenses and management estimates of operating costs and expected future energy market conditions. See Note 6 — Early Plant Retirements for additional information on the impacts of expected and potential early plant retirements.

See Note 7 — Property, Plant and Equipment for additional information regarding depreciation.

Amortization of regulatory assets and liabilities are recorded over the recovery or refund period specified in the related legislation or regulatory order or agreement. When the recovery or refund period is less than one year, amortization is recorded to the line item in which the deferred cost or income would have originally been recorded in the Utility Registrants’ Consolidated Statements of Operations and Comprehensive Income. Amortization of ComEd’s electric distribution and energy efficiency formula rate regulatory assets and the Utility Registrants' transmission formula rate regulatory assets is recorded to Operating revenues.

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Amortization of income tax related regulatory assets and liabilities is generally recorded to Income tax expense. With the exception of the regulatory assets and liabilities discussed above, when the recovery period is more than one year, the amortization is generally recorded to Depreciation and amortization in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.

See Note 3 — Regulatory Matters and Note 23 — Supplemental Financial Information for additional information regarding Generation’s nuclear fuel and ARC, and the amortization of the Utility Registrants' regulatory assets.

Asset Retirement Obligations (All Registrants)

Generation estimates and recognizes a liability for its legal obligation to perform asset retirement activities even though the timing and/or methods of settlement may be conditional on future events. Generation generally updates its nuclear decommissioning ARO annually, unless circumstances warrant more frequent updates, based on its annual evaluation of cost escalation factors and probabilities assigned to the multiple outcome scenarios within its probability-weighted discounted cash flow models. Generation’s multiple outcome scenarios are generally based on decommissioning cost studies which are updated, on a rotational basis, for each of Generation’s nuclear units at least every five years, unless circumstances warrant more frequent updates. AROs are accreted throughout each year to reflect the time value of money for these present value obligations through a charge to Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income for Non-Regulatory Agreement Units and through a decrease to regulatory liabilities for Regulatory Agreement Units or, in the case of the Utility Registrants' accretion, through an increase to regulatory assets. See Note 9 — Asset Retirement Obligations for additional information.

Guarantees (All Registrants)

The Registrants recognize, at the inception of a guarantee, a liability for the fair market value of the obligations they have undertaken by issuing the guarantee, including the ongoing obligation to perform over the term of the guarantee in the event that the specified triggering events or conditions occur.

The liability that is initially recognized at the inception of the guarantee is reduced or eliminated as the Registrants are released from risk under the guarantee. Depending on the nature of the guarantee, the release from risk of the Registrant may be recognized only upon the expiration or settlement of the guarantee or by a systematic and rational amortization method over the term of the guarantee. See Note 18 — Commitments and Contingencies for additional information.

Asset Impairments

Long-Lived Assets (All Registrants). The Registrants regularly monitor and evaluate the carrying value of long-lived assets and asset groups for recoverability whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators of impairment may include a deteriorating business climate, including, but not limited to, declines in energy prices, condition of the asset, specific regulatory disallowance, or plans to dispose of a long-lived asset significantly before the end of its useful life. The Registrants determine if long-lived assets and asset groups are impaired by comparing the undiscounted expected future cash flows to the carrying value. When the undiscounted cash flow analysis indicates a long-lived asset or asset group is not recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. See Note 11 — Asset Impairments for additional information.

Goodwill (Exelon, ComEd and PHI). Goodwill represents the excess of the purchase price paid over the estimated fair value of the net assets acquired and liabilities assumed in the acquisition of a business. Goodwill is not amortized, but is tested for impairment at least annually or on an interim basis if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. See Note 12 — Intangible Assets for additional information.

Equity Method Investments (Exelon and Generation). Exelon and Generation regularly monitor and evaluate equity method investments to determine whether they are impaired. An impairment is recorded when the investment has experienced a decline in value that is other-than-temporary in nature. Additionally, if the entity in which Generation holds an investment recognizes an impairment loss, Exelon and Generation would record their proportionate share of that impairment loss and evaluate the investment for an other-than-temporary decline in value.

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Debt Security Investments (Exelon and Generation). Declines in the fair value of debt security investments below the cost basis are reviewed to determine if such decline is other-than-temporary. If the decline is determined to be other-than-temporary, the amount of the impairment loss is included in earnings.

Equity Security Investments (Exelon and Generation). Equity investments with readily determinable fair values are measured and recorded at fair value with any changes in fair value recorded through earnings. Investments in equity securities without readily determinable fair values are qualitatively assessed for impairment each reporting period. If it is determined that the equity security is impaired on the basis of the qualitative assessment, an impairment loss will be recognized in earnings to the amount by which the security’s carrying amount exceeds its fair value.

Derivative Financial Instruments (All Registrants)

All derivatives are recognized on the balance sheet at their fair value unless they qualify for certain exceptions, including the NPNS. For derivatives intended to serve as economic hedges, changes in fair value are recognized in earnings each period. Amounts classified in earnings are included in Operating revenue, Purchased power and fuel, Interest expense or Other, net in the Consolidated Statements of Operations and Comprehensive Income based on the activity the transaction is economically hedging. While the majority of the derivatives serve as economic hedges, there are also derivatives entered into for proprietary trading purposes, subject to Exelon’s Risk Management Policy, and changes in the fair value of those derivatives are recorded in revenue in the Consolidated Statements of Operations and Comprehensive Income. At the Utility Registrants, changes in fair value may be recorded as a regulatory asset or liability if there is an ability to recover or return the associated costs. Cash inflows and outflows related to derivative instruments are included as a component of operating, investing or financing cash flows in the Consolidated Statements of Cash Flows, depending on the nature of each transaction. On July 1, 2018, Exelon and Generation de-designated its fair value and cash flow hedges. See Note 3 — Regulatory Matters and Note 15 — Derivative Financial Instruments for additional information.

As part of Generation’s energy marketing business, Generation enters into contracts to buy and sell energy to meet the requirements of its customers. These contracts include short-term and long-term commitments to purchase and sell energy and energy-related products in the energy markets with the intent and ability to deliver or take delivery of the underlying physical commodity. NPNS are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period of time and will not be financially settled. Revenues and expenses on derivative contracts that qualify, and are designated, as NPNS are recognized when the underlying physical transaction is completed. While these contracts are considered derivative financial instruments, they are not required to be recorded at fair value, but rather are recorded on an accrual basis of accounting. See Note 15 — Derivative Financial Instruments for additional information.

Retirement Benefits (All Registrants)

Exelon sponsors defined benefit pension plans and OPEB plans for essentially all employees.

The plan obligations and costs of providing benefits under these plans are measured as of December 31. The measurement involves various factors assumptions, and accounting elections. The impact of assumption changes or experience different from that assumed on pension and OPEB obligations is recognized over time rather than immediately recognized in the Consolidated Statements of Operations and Comprehensive Income. Gains or losses in excess of the greater of ten percent of the projected benefit obligation or the MRV of plan assets are amortized over the expected average remaining service period of plan participants. See Note 14 — Retirement Benefits for additional information.

New Accounting Standards (All Registrants)

New Accounting Standards Adopted in 2019: In 2019, the Registrants adopted the following new authoritative accounting guidance issued by the FASB.

Cloud Computing Arrangements (Issued August 2018). Aligns the requirements for capitalizing costs incurred to implement a cloud computing arrangement with the internal-use software guidance. As a result, certain implementation costs incurred in a cloud computing arrangement that are currently expensed as incurred will be deferred and amortized over the non-cancellable term of the arrangement plus any reasonably certain renewal periods. The standard was effective January 1, 2020 and can be applied using either a prospective or retrospective transition approach. A retrospective approach requires a cumulative-effect adjustment to retained earnings as of

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the beginning of the period of adoption. The Registrants early adopted this standard using a prospective approach as of January 1, 2019. The new guidance did not have a material impact on the Registrants' financial statements.

Leases (Issued February 2016). The Registrants applied the new guidance with the following transition practical expedients:

•	a "package of three" expedients that must be taken together and allow entities to (1) not reassess whether existing contracts contain leases, (2) carry forward the existing lease classification, and (3) not reassess initial direct costs associated with existing leases,

•	an implementation expedient which allows the requirements of the standard in the period of adoption with no restatement of prior periods, and

•	a land easement expedient which allows entities to not evaluate land easements under the new standard at adoption if they were not previously accounted for as leases.

The standard resulted in the Registrants recording ROU assets and lease liabilities for operating leases in their Consolidated Balance Sheets but did not have a material impact in the Registrants' Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and Consolidated Statements of Changes in Shareholders' Equity. The operating ROU assets and lease liabilities recognized upon adoption are materially consistent with the balances presented in the Combined Notes to the Consolidated Financial Statements, excluding 2019 expense and payment activity. See Note 10 — Leases for additional information.

New Accounting Standards Adopted as of January 1, 2020: The following new authoritative accounting guidance issued by the FASB was adopted as of January 1, 2020 and will be reflected by the Registrants in their consolidated financial statements beginning in the first quarter of 2020.

Impairment of Financial Instruments (Issued June 2016). Provides for a new Current Expected Credit Loss (CECL) impairment model for specified financial instruments including loans, trade receivables, debt securities classified as held-to-maturity investments and net investments in leases recognized by a lessor. Under the new guidance, on initial recognition and at each reporting period, an entity is required to recognize an allowance that reflects its current estimate of credit losses expected to be incurred over the life of the financial instrument based on historical experience, current conditions and reasonable and supportable forecasts. The standard was effective January 1, 2020 and requires a modified retrospective transition approach through a cumulative-effect adjustment to retained earnings as of the beginning of the period of adoption. This standard is primarily applicable to Generation's and the Utility Registrants' trade accounts receivables balances. The guidance did not have a significant impact on the Registrants' consolidated financial statements.

Goodwill Impairment (Issued January 2017). Simplifies the accounting for goodwill impairment by removing Step 2 of the current test, which requires calculation of a hypothetical purchase price allocation. Under the revised guidance, goodwill impairment will be measured as the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill (currently Step 1 of the two-step impairment test). Entities will continue to have the option to perform a qualitative assessment to determine if a quantitative impairment test is necessary. The standard was effective January 1, 2020 and must be applied on a prospective basis. Exelon, Generation, ComEd, PHI and DPL will apply the new guidance for their goodwill impairment assessments in 2020 and do not expect the updated guidance to have a material impact to their financial statements.

CENG Put Option (Exelon and Generation)

Generation owns a 50.01% membership interest in CENG, a joint venture with EDF, which wholly owns the Calvert Cliffs and Ginna nuclear stations and Nine Mile Point Unit 1, in addition to an 82% undivided ownership interest in Nine Mile Point Unit 2. CENG is 100% consolidated in Exelon's and Generation's financial statements. See Note 22 — Variable Interest Entities for additional information.

On April 1, 2014, Generation and EDF entered into various agreements including a Nuclear Operating Services Agreement, an amended LLC Operating Agreement, an Employee Matters Agreement, and a Put Option Agreement, among others. Under the amended Operating Agreement, CENG made a $400 million special distribution to EDF

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and committed to make preferred distributions to Generation until Generation has received aggregate distributions of $400 million plus a return of 8.50% per annum. Under the Put Option Agreement, EDF has the option to sell its 49.99% equity interest in CENG to Generation exercisable beginning on January 1, 2016 and thereafter until June 30, 2022. On November 20, 2019, Generation received notice of EDF’s intention to exercise the put option to sell its interest in CENG to Generation and the put automatically exercised on January 19, 2020 at the end of the sixty-day advance notice period.

Under the terms of the Put Option Agreement, the purchase price is to be determined by agreement of the parties, or absent such agreement, by a third-party arbitration process. The third parties determining fair market value of EDF’s 49.99% interest are to take into consideration all rights and obligations under the LLC Operating Agreement and Employee Matters Agreement including but not limited to Generation’s rights with respect to any unpaid aggregate preferred distributions and the related return. As of December 31, 2019, the total unpaid aggregate preferred distributions and related return owed to Generation is $571 million. At this time, Generation cannot reasonably predict the ultimate purchase price that will be paid to EDF for its interest in CENG. The transaction will require approval by the NYPSC, the FERC and the NRC. The process and regulatory approvals could take one to two years or more to complete.

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

On March 31, 2017, Generation acquired the single-unit James A. FitzPatrick (FitzPatrick) nuclear generating station located in Scriba, New York from Entergy Nuclear FitzPatrick LLC (Entergy) for a total purchase price of $289 million, which consisted of a cash purchase price of $110 million and a net cost reimbursement to and on behalf of Entergy of $179 million. As part of the transaction, Generation received the FitzPatrick NDT fund assets and assumed the obligation to decommission FitzPatrick. The NRC license for FitzPatrick expires in 2034. An after-tax bargain purchase gain of $233 million was included within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income which primarily reflects differences in strategies between Generation and Entergy for the intended use and ultimate decommissioning of the plant.

Exelon and Generation incurred $57 million of merger and integration related costs for FitzPatrick for the year ended December 31, 2017 which are included within Operating and maintenance expense in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.

Disposition of Oyster Creek (Exelon and Generation)

On July 31, 2018, Generation entered into an agreement with Holtec International (Holtec) and its indirect wholly owned subsidiary, Oyster Creek Environmental Protection, LLC (OCEP), for the sale and decommissioning of Oyster Creek located in Forked River, New Jersey, which permanently ceased generation operations on September 17, 2018. Completion of the transaction contemplated by the sale agreement was subject to the satisfaction of several closing conditions, including approval of the license transfer from the NRC and other regulatory approvals, and a private letter ruling from the IRS, which were satisfied in the second quarter 2019. The sale was completed on July 1, 2019. Exelon and Generation recognized a loss on the sale in the third quarter, which was immaterial.

Under the terms of the transaction, Generation transferred to OCEP substantially all the assets associated with Oyster Creek, including assets held in NDT funds, along with the assumption of liability for all responsibility for the site, including full decommissioning and ongoing management of spent fuel until the spent fuel is moved offsite. The terms of the transaction also include various forms of performance assurance for the obligations of OCEP to timely complete the required decommissioning, including a parental guaranty from Holtec for all performance and payment obligations of OCEP, and a requirement for Holtec to deliver a letter of credit to Generation upon the occurrence of specified events.

As a result of the transaction, in the third quarter of 2018, Exelon and Generation reclassified certain Oyster Creek assets and liabilities in Exelon’s and Generation’s Consolidated Balance Sheets as held for sale at their respective fair values. Exelon and Generation had $897 million and $777 million of Assets and Liabilities held for sale, respectively, at December 31, 2018. Upon remeasurement of the Oyster Creek ARO, Exelon and Generation recognized an $84 million and a $9 million pre-tax charge to Operating and maintenance expense in the third quarter of 2018 and in the second quarter of 2019, respectively. See Note 9 — Asset Retirement Obligations for additional information.

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Disposition of EGTP and Acquisition of Handley Generating Station (Exelon and Generation)

EGTP, a Delaware limited liability company, was formed in 2014 with the purpose of financing a portfolio of assets comprised of two combined-cycle gas turbines (CCGTs) and three peaking/simple cycle facilities consisting of approximately 3.4 GW of generation capacity in ERCOT North and Houston Zones. EGTP was an indirect wholly owned subsidiary of Exelon and Generation.

EGTP’s operating cash flows were negatively impacted by certain market conditions and the seasonality of its cash flows. On May 2, 2017, as a result of the negative impacts of certain market conditions and the seasonality of its cash flows, EGTP entered into a consent agreement with its lenders to permit EGTP to draw on its revolving credit facility and initiate an orderly sales process to sell the assets of its wholly owned subsidiaries. As a result, Exelon and Generation classified certain of EGTP assets and liabilities as held for sale at their respective fair values less costs to sell and recorded a $460 million pre-tax impairment loss. See Note 16 — Debt and Credit Agreements for details regarding the nonrecourse debt associated with EGTP and Note 11 — Asset Impairments for additional information.

On November 7, 2017, EGTP and all of its wholly owned subsidiaries filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Code in the United States Bankruptcy Court for the District of Delaware, which resulted in Exelon and Generation deconsolidating EGTP's assets and liabilities from their consolidated financial statements in the fourth quarter of 2017 that resulted in a pre-tax gain upon deconsolidation of $213 million. Concurrently with the Chapter 11 filings, Generation entered into an asset purchase agreement to acquire one of EGTP's generating plants, the Handley Generating Station, subject to a potential adjustment for fuel oil and assumption of certain liabilities. In the Chapter 11 Filings, EGTP requested that the proposed acquisition of the Handley Generating Station be consummated through a court-approved and supervised sales process. The acquisition closed on April 4, 2018 for a purchase price of $62 million. The Chapter 11 bankruptcy proceedings were finalized on April 17, 2018, resulting in the ownership of EGTP assets (other than the Handley Generating Station) being transferred to EGTP's lenders.

Disposition of Electrical Contracting Business (Exelon and Generation)

On February 28, 2018, Generation completed the sale of its interest in an electrical contracting business that primarily installs, maintains and repairs underground and high-voltage cable transmission and distribution systems for $87 million, resulting in a pre-tax gain which is included within Gain on sales of assets and businesses in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2018.

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The following matters below discuss the status of material regulatory and legislative proceedings of the Registrants.

Utility Regulatory Matters (Exelon and the Utility Registrants)

Distribution Base Rate Case Proceedings

The following tables show the completed and pending distribution base rate case proceedings in 2019.

Completed Distribution Base Rate Case Proceedings

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 16, 2018	$	(23	)		$	(24	)		8.69	%		December 4, 2018	January 1, 2019
ComEd - Illinois (Electric)(a)	April 8, 2019	(6		)		(17		)		8.91	%		December 4, 2019	January 1, 2020
PECO - Pennsylvania (Electric)	March 29, 2018	82				25				N/A		(b)	December 20, 2018	January 1, 2019
BGE - Maryland (Natural Gas)	June 8, 2018 (amended October 12, 2018)	61				43				9.8	%		January 4, 2019	January 4, 2019
BGE - Maryland (Electric)	May 24, 2019 (amended December 17, 2019)	74				18				9.7	%	(d)	December 17, 2019	December 17, 2019
BGE - Maryland (Natural Gas)	May 24, 2019 (amended December 17, 2019)	59				45				9.75	%	(d)	December 17, 2019	December 17, 2019
ACE - New Jersey (Electric)	August 21, 2018 (amended November 19, 2018)	122			(c)	70			(c)	9.6	%		March 13, 2019	April 1, 2019
Pepco - Maryland (Electric)	January 15, 2019 (amended May 16, 2019)	27				10				9.6	%		August 12, 2019	August 13, 2019

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(a)

Pursuant to EIMA and FEJA, ComEd’s electric distribution rates are established through a performance-based formula, which sunsets at the end of 2022. ComEd is required to file an annual update to its electric distribution formula rate on or before May 1st, with resulting rates effective in January of the following year. ComEd’s annual electric distribution formula rate update is based on prior year actual costs and current year projected capital additions (initial year revenue requirement). The update also reconciles any differences between the revenue requirement in effect for the prior year and actual costs incurred from the year (annual reconciliation).

ComEd’s 2018 approved revenue requirement above reflects a decrease of $58 million for the initial year revenue requirement for 2018 and an increase of $34 million related to the annual reconciliation for 2017. The revenue requirement for 2018 and the annual reconciliation for 2017 provides for a weighted average debt and equity return on distribution rate base of 6.52%

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inclusive of an allowed ROE of 8.69%, reflecting the average rate on 30-year treasury notes plus 580 basis points. ComEd’s 2019 approved revenue requirement above reflects an increase of $51 million for the initial year revenue requirement for 2019 and a decrease of $68 million related to the annual reconciliation for 2018. The revenue requirement for 2019 and the annual reconciliation for 2018 provides for a weighted average debt and equity return on distribution rate base of 6.51% inclusive of an allowed ROE of 8.91%, reflecting the average rate on 30-year treasury notes plus 580 basis points. See table below for ComEd's regulatory assets associated with its electric distribution formula rate.

During the first quarter of 2018, ComEd revised its electric distribution formula rate to implement revenue decoupling provisions provided for under FEJA. As a result of this revision, ComEd’s electric distribution formula rate revenues are not impacted by abnormal weather, usage per customer or numbers of customers. ComEd began reflecting the impacts of this change in its Operating revenues and electric distribution formula rate regulatory asset in the first quarter of 2017.

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

(c)	Requested and approved increases are before New Jersey sales and use tax.

(d)	ROEs in approved settlement are for the purpose of calculating AFUDC and carrying charges.

Pending Distribution Base Rate Case Proceedings

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

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(a)	Reflects a three-year cumulative multi-year plan and total requested revenue requirement increases of $84 million, $40 million and $36 million for years 2020, 2021, and 2022, respectively, to recover capital investments made in 2018 and 2019 and planned capital investments from 2020 to 2022.

Transmission Formula Rates

Transmission Formula Rate (Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE).  ComEd’s, BGE’s, Pepco's, DPL's and ACE's transmission rates are each established based on a FERC-approved formula. ComEd, BGE, Pepco, DPL and ACE are required to file an annual update to the FERC-approved formula on or before May 15, with the resulting rates effective on June 1 of the same year. The annual formula rate update is based on prior year actual costs and current year projected capital additions (initial year revenue requirement). The update also reconciles any differences between the revenue requirement in effect beginning June 1 of the prior year and actual costs incurred for that year (annual reconciliation).

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For 2019, the following total increases/(decreases) were included in ComEd’s, BGE’s, Pepco's, DPL's and ACE's electric transmission formula rate filings:

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

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(a)	The time period for any formal challenges to the annual transmission formula rate update filings expired with no formal challenges submitted

(b)	The change in BGE's transmission revenue requirement includes a FERC approved dedicated facilities charge of $14 million to recover the costs of providing transmission service to specifically designated load by BGE.

(c)	Represents the weighted average debt and equity return on transmission rate bases.

(d)

As part of the FERC-approved settlement of ComEd’s 2007 transmission rate case, the rate of return on common equity is 11.50%, inclusive of a 50-basis-point incentive adder for being a member of a RTO, and the common equity component of the ratio used to calculate the weighted average debt and equity return for the transmission formula rate is currently capped at 55%. As part of the FERC-approved settlement of the ROE complaint against BGE, Pepco, DPL and ACE, the rate of return on common equity is 10.50%, inclusive of a 50-basis-point incentive adder for being a member of a RTO.

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

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

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

Other State Regulatory Matters

Illinois Regulatory Matters

Energy Efficiency Formula Rate (Exelon and ComEd). FEJA allows ComEd to defer energy efficiency costs (except for any voltage optimization costs which are recovered through the electric distribution formula rate) as a separate regulatory asset that is recovered through the energy efficiency formula rate over the weighted average useful life, as approved by the ICC, of the related energy efficiency measures. ComEd earns a return on the energy efficiency regulatory asset at a rate equal to its weighted average cost of capital, which is based on a year-end capital structure and calculated using the same methodology applicable to ComEd’s electric distribution formula rate. Beginning January 1, 2018 through December 31, 2030, the return on equity that ComEd earns on its energy efficiency regulatory asset is subject to a maximum downward or upward adjustment of 200 basis points if ComEd’s

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cumulative persisting annual MWh savings falls short of or exceeds specified percentage benchmarks of its annual incremental savings goal. ComEd is required to file an update to its energy efficiency formula rate on or before June 1^st each year, with resulting rates effective in January of the following year. The annual update is based on projected current year energy efficiency costs, PJM capacity revenues, and the projected year-end regulatory asset balance less any related deferred income taxes (initial year revenue requirement). The update also reconciles any differences between the revenue requirement in effect for the prior year and actual costs incurred from the year (annual reconciliation). The approved energy efficiency formula rate also provides for revenue decoupling provisions similar to those in ComEd’s electric distribution formula rate.

During 2019, the ICC approved the following total increases in ComEd's requested energy efficiency revenue requirement:

Filing Date	Requested Revenue Requirement Increase			Approved Revenue Requirement Increase				Approved ROE		Approval Date	Rate Effective Date
May 23, 2019	$	51		$	50		(a)	8.91	%	November 26, 2019	January 1, 2020

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(a)

ComEd’s 2020 approved revenue requirement above reflects an increase of $53 million for the initial year revenue requirement for 2020 and a decrease of $3 million related to the annual reconciliation for 2018. The revenue requirement for 2020 provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 6.51% inclusive of an allowed ROE of 8.91%, reflecting the average rate on 30-year treasury notes plus 580 basis points. See table below for ComEd's regulatory assets associated with its energy efficiency formula rate.

Maryland Regulatory Matters

Maryland Alternative Rate Plans Rulemaking (Exelon, BGE, PHI, Pepco and DPL). On August 9, 2019, the MDPSC issued an order in which the MDPSC determined that it is now appropriate to move forward to implement alternative rate plans in Maryland.  The MDPSC found that a multi-year rate plan, based on a historic test year and allowing up to three future test years, can produce just and reasonable rates.  A working group was convened and submitted a detailed implementation report related to multi-year rate plans to the MDPSC on December 20, 2019.  In response to the working group report, the MDPSC issued an order on February 4, 2020 establishing a multi-year rate plan pilot and an associated framework for a Maryland utility to use in the pilot multi-year rate plan filing. The working group was required to continue and discuss how best to integrate performance-based measures into a multi-year rate plan. The working group is currently discussing performance-based measures which could be combined with future multi-year rate plans and will submit its report to the MDPSC by April 1, 2020. BGE, Pepco and DPL cannot predict the outcome or the potential financial impact, if any, on BGE, Pepco or DPL.

The Maryland Strategic Infrastructure Development and Enhancement Program (Exelon and BGE). On December 1, 2017 (as amended on January 22, 2018), BGE filed an application with the MDPSC seeking approval for a new gas infrastructure replacement plan and associated surcharge, effective for the five-year period from 2019 through 2023. On May 30, 2018, the MDPSC approved with modifications a new infrastructure plan and associated surcharge, subject to BGE's acceptance of the Order. On June 1, 2018, BGE accepted the MDPSC Order and the associated surcharge became effective January 2019. The five-year plan calls for capital expenditures over the 2019-2023 timeframe of $732 million with an associated revenue requirement of $200 million.

Cash Working Capital Order (Exelon and BGE). On November 17, 2016, the MDPSC rendered a decision in the proceeding to review BGE’s request to recover its cash working capital (CWC) requirement for its Provider of Last Resort service, also known as Standard Offer Service (SOS), as well as other components that make up the Administrative Charge, the mechanism that enables BGE to recover its SOS-related costs.  The Administrative Charge is comprised of five components:  CWC, uncollectibles, incremental costs, return, and an administrative adjustment, which acts as a proxy for retail suppliers’ costs.  The MDPSC accepted BGE's positions on recovery of CWC and pass-through recovery of BGE’s actual uncollectibles and incremental costs.  The order also grants BGE a return on the SOS. Subsequently, the MDPSC Staff and residential consumer advocate sought clarification and appealed the amount of return awarded to BGE on the SOS. The appeal currently resides with the Maryland Court of Special Appeals. Also, in BGE’s 2019 electric and gas distribution base rate proceeding, the MDPSC established a normalized administrative adjustment. However, a group of electric suppliers appealed the MDPSC’s decision to the Circuit Court for Baltimore City. BGE cannot predict the outcome of these appeals.

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New Jersey Regulatory Matters

ACE Infrastructure Investment Program Filing (Exelon, PHI and ACE). On February 28, 2018, ACE filed with the NJBPU the company’s Infrastructure Investment Program (IIP) proposing to seek recovery of a series of investments through a new rider mechanism, totaling $338 million, between 2019-2022 to provide safe and reliable service for its customers. The IIP will allow for more timely recovery of investments made to modernize and enhance ACE’s electric system. On April 15, 2019, ACE entered into a settlement agreement with other parties, which allows for a recovery totaling $96 million of reliability related capital investments from July 1, 2019 through June 30, 2023. On April 18, 2019, the NJBPU approved the settlement agreement.

New Jersey Clean Energy Legislation (Exelon, PHI and ACE). On May 23, 2018, New Jersey enacted legislation that established and modified New Jersey’s clean energy and energy efficiency programs and solar and renewable energy portfolio standards. On the same day, New Jersey enacted legislation that established a ZEC program that provides compensation for nuclear plants that demonstrate to the NJBPU that they meet certain requirements, including that they make a significant contribution to air quality in the state and that their revenues are insufficient to cover their costs and risks. Electric distribution utilities in New Jersey, including ACE, began collecting from retail distribution customers, through a non-bypassable charge, all costs associated with the utility’s procurement of the ZECs effective April 18, 2019. See Generation Regulatory Matters below for additional information.

Other Federal Regulatory Matters

Transmission-Related Income Tax Regulatory Assets (Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE). On December 13, 2016 (and as amended on March 13, 2017), BGE filed with FERC to begin recovering certain existing and future transmission-related income tax regulatory assets through its transmission formula rate. BGE’s existing regulatory assets included (1) amounts that, if BGE’s transmission formula rate provided for recovery, would have been previously amortized and (2) amounts that would be amortized and recovered prospectively. ComEd, Pepco, DPL and ACE had similar transmission-related income tax regulatory liabilities and assets also requiring FERC approval. On November 16, 2017, FERC issued an order rejecting BGE’s proposed revisions to its transmission formula rate to recover these transmission-related income tax regulatory assets. As a result of the FERC's order, ComEd, BGE, Pepco, DPL and ACE took a charge to Income tax expense within their Consolidated Statements of Operations and Comprehensive Income in the fourth quarter of 2017, reducing their associated transmission-related income tax regulatory assets for the portion of the total transmission-related income tax regulatory assets that would have been previously amortized and recovered through rates. Similar regulatory assets and liabilities at PECO are not subject to the same FERC transmission rate recovery formula. See above for additional information regarding PECO's transmission formula rate filing.

On December 18, 2017, BGE filed for clarification and rehearing of FERC’s November 16, 2017 order and on February 23, 2018 (as amended on July 9, 2018), ComEd, Pepco, DPL, and ACE each filed with FERC to revise their transmission formula rate mechanisms to permit recovery of transmission-related income tax regulatory assets, including those amounts that would have been previously amortized and recovered through rates had the transmission formula rate provided for such recovery.

On September 7, 2018, FERC issued orders rejecting BGE’s December 18, 2017 request for rehearing and clarification and ComEd's, Pepco's, DPL's and ACE's February 23, 2018 (as amended on July 9, 2018) filings, citing the lack of timeliness of the requests to recover amounts that would have been previously amortized, but indicating that ongoing recovery of certain transmission-related income tax regulatory assets would provide for a more accurate revenue requirement, consistent with its November 16, 2017 order.

On October 1, 2018, ComEd, BGE, Pepco, DPL, and ACE submitted filings to recover ongoing non-TCJA amortization amounts and refund TCJA transmission-related income tax regulatory liabilities for the prospective period starting on October 1, 2018. In addition, on October 9, 2018, ComEd, Pepco, DPL, and ACE sought rehearing of FERC's September 7, 2018 order. On November 2, 2018, BGE filed an appeal of FERC's September 7, 2018 order to the Court of Appeals for the D.C. Circuit. On April 26, 2019 FERC issued an order accepting ComEd's, BGE's, Pepco's, DPL's, and ACE's October 1, 2018 filings, effective October 1, 2018, subject to refund and established hearing and settlement judge procedures. ComEd, BGE, Pepco, DPL, and ACE cannot predict the outcome of these proceedings.

If FERC ultimately rules that the future, ongoing non-TCJA amortization amounts are not recoverable, Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE would record additional charges to Income tax expense, which could be

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up to approximately $79 million, $51 million, $17 million, $11 million, $4 million, $5 million and $2 million, respectively, as of December 31, 2019.

PJM Transmission Rate Design (All Registrants). On June 15, 2016, several parties, including the Utility Registrants, filed a proposed settlement with FERC to resolve outstanding issues related to cost responsibility for charges to transmission customers for certain transmission facilities that operate at or above 500 kV. The settlement included provisions for monthly credits or charges related to the periods prior to January 1, 2016 that are expected to be refunded or recovered through PJM wholesale transmission rates through December 2025. On May 31, 2018, FERC issued an order approving the settlement. Pursuant to the order, similar charges for the period January 1, 2016 through June 30, 2018 would also be refunded or recovered through PJM wholesale transmission rates over the subsequent 12-month period. PJM commenced billing the refunds and charges associated with this settlement in August 2018.

The Utility Registrants recorded the following payables to/receivables from PJM and related regulatory assets/liabilities in 2018 and have been refunding or recovering these amounts through electric distribution customer rates. Generation recorded a $41 million net payable to PJM and a pre-tax charge within Purchased power and fuel expense in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.

	PJM Receivable			PJM Payable			Regulatory Asset			Regulatory Liability
Exelon	$	220		$	176		$	136		$	221
Generation(a)	—			41			—			—
ComEd	122			—			—			122
PECO	85			—			—			85
BGE	—			51			51			—
PHI	13			84			85			14
Pepco	—			84			84			—
DPL	10			—			—			10
ACE	3			—			1			4

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(a)	Does not include an offsetting receivable from New Jersey Utilities of $16 million as of December 31, 2018.

Regulatory Assets and Liabilities

Regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent the excess recovery of costs or accrued credits that have been deferred because it is probable such amounts will be returned to customers through future regulated rates or represent billings in advance of expenditures for approved regulatory programs.

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The following tables provide information about the regulatory assets and liabilities of Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE as of December 31, 2019 and December 31, 2018:

December 31, 2019	Exelon				ComEd				PECO				BGE				PHI				Pepco				DPL				ACE
Regulatory assets
Pension and other postretirement benefits	$	2,784			$	—			$	—			$	—			$	—			$	—			$	—			$	—
Pension and other postretirement benefits - Merger related	1,138				—				—				—				—				—				—				—
Deferred income taxes	528				—				518				—				10				10				—				—
AMI programs - Deployment costs	207				—				—				129				78				43				35				—
AMI programs - Legacy Meters	276				113				12				45				106				79				27				—
Electric distribution formula rate annual reconciliations	34				34				—				—				—				—				—				—
Electric distribution formula rate significant one-time events	66				66				—				—				—				—				—				—
Energy efficiency costs	746				746				—				—				—				—				—				—
Fair value of long-term debt	650				—				—				—				523				—				—				—
Fair value of PHI's unamortized energy contracts	443				—				—				—				443				—				—				—
Asset retirement obligations	127				85				23				16				3				2				—				1
MGP remediation costs	302				287				11				4				—				—				—				—
Renewable energy	301				301				—				—				—				—				—				—
Electric Energy and Natural Gas Costs	110				—				6				36				68				43				5				20
Transmission formula rate annual reconciliations	11				—				—				1				10				1				2				7
Energy efficiency and demand response programs	572				—				—				303				269				196				73				—
Merger integration costs	32				—				—				2				30				15				8				7
Under-recovered revenue decoupling	37				—				—				8				29				29				—				—
Securitized stranded costs	37				—				—				—				37				—				—				37
Removal costs	641				—				—				67				574				152				100				324
DC PLUG charge	126				—				—				—				126				126				—				—
Other	337				129				25				26				167				76				24				29
Total regulatory assets	9,505				1,761				595				637				2,473				772				274				425
Less: current portion	1,170				281				41				183				412				188				52				57
Total noncurrent regulatory assets	$	8,335			$	1,480			$	554			$	454			$	2,061			$	584			$	222			$	368

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December 31, 2019	Exelon				ComEd				PECO				BGE				PHI				Pepco				DPL				ACE
Regulatory liabilities
Deferred income taxes	$	4,944			$	2,297			$	—			$	1,089			$	1,558			$	725			$	477			$	356
Nuclear decommissioning	3,102				2,622				480				—				—				—				—				—
Removal costs	1,621				1,435				—				58				128				20				108				—
Electric Energy and Natural Gas Costs	109				45				56				—				8				—				8				—
Transmission formula rate annual reconciliations	34				6				28				—				—				—				—				—
Other	582				337				37				81				83				9				18				26
Total regulatory liabilities	10,392				6,742				601				1,228				1,777				754				611				382
Less: current portion	406				200				91				33				70				8				37				25
Total noncurrent regulatory liabilities	$	9,986			$	6,542			$	510			$	1,195			$	1,707			$	746			$	574			$	357

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December 31, 2018	Exelon				ComEd				PECO				BGE				PHI				Pepco				DPL				ACE
Regulatory assets
Pension and other postretirement benefits	$	2,553			$	—			$	—			$	—			$	—			$	—			$	—			$	—
Pension and other postretirement benefits - Merger related	1,266				—				—				—				—				—				—				—
Deferred income taxes	414				—				404				—				10				10				—				—
AMI programs - Deployment costs	234				—				—				145				89				50				39				—
AMI programs - Legacy Meters	328				136				24				48				120				90				30				—
Electric distribution formula rate annual reconciliations	158				158				—				—				—				—				—				—
Electric distribution formula rate significant one-time events	81				81				—				—				—				—				—				—
Energy efficiency costs	472				472				—				—				—				—				—				—
Fair value of long-term debt	702				—				—				—				569				—				—				—
Fair value of PHI's unamortized energy contracts	561				—				—				—				561				—				—				—
Asset retirement obligations	118				79				22				16				1				1				—				—
MGP remediation costs	326				309				17				—				—				—				—				—
Renewable energy	249				249				—				—				—				—				—				—
Electric Energy and Natural Gas Costs	193				—				49				51				93				84				—				9
Transmission formula rate annual reconciliations	41				6				—				4				31				10				14				7
Energy efficiency and demand response programs	545				—				1				289				255				188				67				—
Merger integration costs	42				—				—				3				39				18				11				10
Under-recovered revenue decoupling	27				—				—				2				25				25				—				—
Securitized stranded costs	50				—				—				—				50				—				—				50
Removal costs	564				—				—				—				564				158				97				309
DC PLUG charge	159				—				—				—				159				159				—				—
Deferred storm costs	41				—				—				—				41				9				4				28
Other	303				110				24				17				162				79				28				13
Total regulatory assets	9,427				1,600				541				575				2,769				881				290				426
Less: current portion	1,190				293				81				177				457				238				59				40
Total noncurrent regulatory assets	$	8,237			$	1,307			$	460			$	398			$	2,312			$	643			$	231			$	386

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December 31, 2018	Exelon				ComEd				PECO					BGE				PHI				Pepco				DPL				ACE
Regulatory liabilities
Deferred income taxes	$	5,228			$	2,394			$	—				$	1,132			$	1,702			$	798			$	510			$	394
Nuclear decommissioning	2,606				2,217				389					—				—				—				—				—
Removal costs	1,547				1,368				—					52				127				20				107				—
Electric Energy and Natural Gas Costs	294				137				132					6				19				—				18				1
Other	528				227				75					79				100				11				30				25
Total regulatory liabilities	10,203				6,343				596			—		1,269				1,948				829				665				420
Less: current portion	644				293				175					77				84				7				59				18
Total noncurrent regulatory liabilities	$	9,559			$	6,050			$	421				$	1,192			$	1,864			$	822			$	606			$	402

Descriptions of the regulatory assets and liabilities included in the tables above are summarized below, including their recovery and amortization periods.

Line Item	Description	End Date of Remaining Recovery/Refund Period	Return
Pension and Other Postretirement Benefits	Primarily reflects the Utility Registrants' portion of deferred costs, including unamortized actuarial losses (gains) and prior service costs (credits), associated with Exelon's pension and other postretirement benefit plans, which are recovered through customer rates once amortized through net periodic benefit cost. Also, includes the Utility Registrants' non–service cost components capitalized in Property, plant and equipment, net on their Consolidated Balance Sheets.	The deferred costs are amortized over the plan participants' average remaining service periods subject to applicable pension and other postretirement cost recognition policies. See Note 14 – Retirement Benefits for additional information. The capitalized non–service cost components are amortized over the lives of the underlying assets.	No
Pension and Other Postretirement Benefits - Merger Related	The deferred costs are amortized over the plan participants' average remaining service periods subject to applicable pension and other postretirement cost recognition policies. See Note 14 – Retirement Benefits for additional information. The capitalized non–service cost components are amortized over the lives of the underlying assets.	Legacy Constellation - 2038 Legacy PHI - 2032	No

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Line Item	Description	End Date of Remaining Recovery/Refund Period	Return
Deferred Income Taxes	Deferred income taxes that are recoverable or refundable through customer rates, primarily associated with accelerated depreciation, the equity component of AFUDC, and the effects of income tax rate changes, including those resulting from the TCJA. These amounts include transmission-related regulatory liabilities that require FERC approval separate from the transmission formula rate. See Transmission-Related Income Tax Regulatory Assets section above for additional information.	Over the period in which the related deferred income taxes reverse, which is generally based on the expected life of the underlying assets. For TCJA, generally refunded over the remaining depreciable life of the underlying assets, except in certain jurisdictions where the commissions have approved a shorter refund period for certain assets not subject to IRS normalization rules.	No
AMI Programs - Deployment Costs	Installation costs of new smart meters, including implementation costs at Pepco and DPL of dynamic pricing for energy usage resulting from smart meters.	BGE - 2026 Pepco - 2027 DPL - 2030	Yes
AMI Programs - Legacy Meters	Early retirement costs of legacy meters.	ComEd - 2028 PECO - 2020 BGE - 2026 Pepco - 2027 DPL - 2030	ComEd, Pepco (District of Columbia), DPL (Delaware) - Yes PECO, BGE, Pepco (Maryland), DPL (Maryland) - No
Electric distribution formula rate annual reconciliations	Under-recoveries related to electric distribution service costs recoverable through ComEd's performance-based formula rate, which is updated annually with rates effective on January 1st.	2021	Yes
Electric distribution formula rate significant one-time events	Under-recoveries of electric distribution service costs related to ComEd's significant one-time events (e.g., storm costs), which are recovered over 5 years from date of the event.	2023	Yes
Energy Efficiency Costs	ComEd's costs recovered through the energy efficiency formula rate tariff and the reconciliation of the difference of the revenue requirement in effect for the prior year and the revenue requirement based on actual prior year costs. Deferred energy efficiency costs are recovered over the weighted average useful life of the related energy measure.	2029	Yes

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Line Item	Description	End Date of Remaining Recovery/Refund Period	Return
Fair Value of Long-Term Debt	Represents the difference between the carrying value and fair value of long-term debt of PHI and BGE of $523 million and $127 million, respectively, as of December 30, 2019 and $569 million and $133 million, respectively, as of December 30, 2018, as of the PHI and Constellation merger dates.	BGE - 2043 PHI - 2045	No
Fair Value of PHI’s Unamortized Energy Contracts	Represents the regulatory assets recorded at Exelon and PHI offsetting the fair value adjustment related to Pepco's, DPL's and ACE's electricity and natural gas energy supply contracts recorded at PHI as of the PHI merger date.	2036	No
Asset Retirement Obligations	Future legally required removal costs associated with existing asset retirement obligations.	Over the life of the related assets.	Yes, once the removal activities have been performed.
MGP Remediation Costs	Environmental remediation costs for MGP sites.	Over the expected remediation period. See Note 18 - Commitments and Contingencies for additional information.	ComEd, PECO - No
Renewable Energy	Represents the change in fair value of ComEd‘s 20-year floating-to-fixed long-term renewable energy swap contracts.	2032	No
Electric Energy and Natural Gas Costs	Under (over) recoveries related to energy and gas supply related costs recoverable (refundable) under approved rate riders.	2025	DPL (Delaware), ACE - Yes ComEd, PECO, BGE, Pepco, DPL (Maryland) - No
Transmission formula rate annual reconciliations	Under (over)-recoveries related to transmission service costs recoverable through the Utility Registrants’ FERC formula rates, which are updated annually with rates effective each June 1st.	2021	Yes
Energy efficiency and demand response programs	Includes under (over)-recoveries of costs incurred related to energy efficiency programs and demand response programs and recoverable costs associated with customer direct load control and energy efficiency and conservation programs that are being recovered from customers.	PECO - 2021 BGE - 2024 Pepco, DPL - 2034	BGE, Pepco, DPL - Yes PECO - Yes on capital investment recovered through this mechanism

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Line Item	Description	End Date of Remaining Recovery/Refund Period	Return
Merger Integration Costs	Integration costs to achieve distribution synergies related to the Constellation merger and PHI acquisition. Costs for Pepco (Maryland) and Pepco (District of Columbia) were $6 million and $9 million, respectively as of December 31, 2019 and $9 million each as of December 31, 2018.	BGE - 2021 Pepco - 2021 DPL- 2023 ACE - 2022	BGE, Pepco (Maryland), DPL - Yes Pepco (District of Columbia), ACE - No
Under (Over)-Recovered Revenue Decoupling	Electric and / or gas distribution costs recoverable from or (refundable) to customers under decoupling mechanisms.	BGE, Pepco and DPL - 2020	BGE, Pepco, DPL- No
Securitized Stranded Costs	Represents certain stranded costs associated with ACE's former electricity generation business.	2022	Yes
Removal Costs	For BGE, PHI, Pepco, DPL and ACE, the regulatory asset represents costs incurred to remove property, plant and equipment in excess of amounts received from customers through depreciation rates. For ComEd, BGE, PHI, Pepco and DPL, the regulatory liability represents amounts received from customers through depreciation rates to cover the future non–legally required cost to remove property, plant and equipment, which reduces rate base for ratemaking purposes.	BGE, PHI, Pepco, DPL and ACE - Asset is generally recovered over the life of the underlining assets. ComEd, BGE, PHI, Pepco and DPL - The liability is reduced as costs are incurred.	Yes
DC PLUG Charge	Costs associated with the District of Columbia Power Line Undergrounding (DC PLUG), which is 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. Rates for the DC PLUG initiative went into effect on February 7, 2018.	2020 - $30M $67 million to be determined based on future biennial plans filed with the DCPSC.	Portion of asset funded by Pepco-Yes
Deferred Storm Costs	For Pepco, DPL and ACE amounts represent total incremental storm restoration costs incurred due to major storm events recoverable from customers in the Maryland and New Jersey jurisdictions.	Pepco - 2024 DPL - 2023 ACE - 2022	Pepco, DPL - Yes ACE - No
Nuclear Decommissioning	Estimated future decommissioning costs for the Regulatory Agreement Units that are less than the associated NDT fund assets. See Note 9 - Asset Retirement Obligations for additional information.	Not currently being refunded.	No

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Capitalized Ratemaking Amounts Not Recognized

The following table presents authorized amounts capitalized for ratemaking purposes related to earnings on shareholders’ investment that are not recognized for financial reporting purposes in Exelon's and the Utility Registrant's Consolidated Balance Sheets. These amounts will be recognized as revenues in the related Consolidated Statements of Operations and Comprehensive Income in the periods they are billable to our customers.

	Exelon				ComEd(a)				PECO				BGE(b)				PHI				Pepco(c)				DPL(c)				ACE
December 31, 2019	$	63			$	3			$	—			$	53			$	7			$	4			$	3			$	—
December 31, 2018	$	65			$	8			$	—			$	49			$	8			$	5			$	3			$	—

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

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

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

Generation Regulatory Matters (Exelon and Generation)

Illinois Regulatory Matters

Zero Emission Standard. Pursuant to FEJA, on January 25, 2018, the ICC announced that Generation’s Clinton Unit 1, Quad Cities Unit 1 and Quad Cities Unit 2 nuclear plants were selected as the winning bidders through the IPA's ZEC procurement event.

Generation executed the ZEC procurement contracts with Illinois utilities, including ComEd, effective January 26, 2018 and began recognizing revenue with compensation for the sale of ZECs retroactive to the June 1, 2017 effective date of FEJA. The ZEC price was initially established at $16.50 per MWh of production, subject to annual future adjustments determined by the IPA for specified escalation and pricing adjustment mechanisms designed to lower the ZEC price based on increases in underlying energy and capacity prices. Illinois utilities are required to purchase all ZECs delivered by the zero-emissions nuclear-powered generating facilities, subject to annual cost caps. For the initial delivery year, June 1, 2017 to May 31, 2018, and subsequent delivery year, June 1, 2018 to May 31, 2019, the ZEC annual cost cap was set at $235 million (ComEd’s share is approximately $170 million). For subsequent delivery years, the IPA-approved targeted ZEC procurement amounts will change based on forward energy and capacity prices. ZECs delivered to Illinois utilities in excess of the annual cost cap may be paid in subsequent years if the payments do not exceed the prescribed annual cost cap for that year. During the first quarter of 2018, Generation recognized $150 million of revenue related to ZECs generated from June 1, 2017 through December 31, 2017.

On February 14, 2017, two lawsuits were filed in the Northern District of Illinois against the IPA alleging that the state’s ZEC program violates certain provisions of the U.S. Constitution. Both lawsuits argued that the Illinois ZEC program would distort PJM's FERC-approved energy and capacity market auction system of setting wholesale prices and sought a permanent injunction preventing the implementation of the program. The lawsuits were dismissed by the district court on July 14, 2017. On September 13, 2018, the U.S. Circuit Court of Appeals for the Seventh Circuit affirmed the lower court's dismissal of both lawsuits. On January 7, 2019, plaintiffs filed a petition seeking U.S. Supreme Court review of the case, which was denied on April 15, 2019.

New Jersey Regulatory Matters

New Jersey Clean Energy Legislation. On May 23, 2018, New Jersey enacted legislation that established a ZEC program that will provide compensation for nuclear plants that demonstrate to the NJBPU that they meet certain requirements, including that they make a significant contribution to air quality in the state and that their revenues are insufficient to cover their costs and risks. Under the legislation, the NJBPU will issue ZECs to qualifying nuclear power plants and the electric distribution utilities in New Jersey, including ACE, will be required to purchase those ZECs. Selected nuclear plants will receive annual ZEC payments for each energy year (12-month period from June 1 through May 31) within 90 days after the completion of such energy year. The quantity of ZECs issued will be

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determined based on the greater of 40% of the total number of MWh of electricity distributed by the public electric distribution utilities in New Jersey in the prior year, or the total number of MWh of electricity generated in the prior year by the selected nuclear power plants. The ZEC price is approximately $10 per MWh during the first 3-year eligibility period. For eligibility periods following the first 3-year eligibility period, the NJBPU has discretion to reduce the ZEC price.

On November 19, 2018, NJBPU issued an order providing for the method and application process for determining the eligibility of nuclear power plants, a draft method and process for ranking and selecting eligible nuclear power plants, and the establishment of a mechanism for each regulated utility to purchase ZECs from selected nuclear power plants. On December 19, 2018, PSEG filed complete applications seeking NJBPU approval for Salem 1 and Salem 2, of which Generation owns a 42.59% ownership interest, to participate in the ZEC program. On April 18, 2019, the NJBPU approved the award of ZECs to Salem 1 and Salem 2. Upon approval, Generation began recognizing revenue for the sale of New Jersey ZECs in the month they are generated and has recognized $53 million for the year ended December 31, 2019. On May 15, 2019, New Jersey Rate Counsel appealed the NJBPU’s decision to the New Jersey Superior Court. The appeal does not prevent implementation of the ZEC program. Exelon and Generation cannot predict the outcome of the appeal. See Note 6 - Early Plant Retirements for additional information related to Salem.

New York Regulatory Matters

New York Clean Energy Standard. On August 1, 2016, the NYPSC issued an order establishing the New York CES, a component of which is a Tier 3 ZEC program targeted at preserving the environmental attributes of zero-emissions nuclear-powered generating facilities that meet the criteria demonstrating public necessity as determined by the NYPSC to be Generation's FitzPatrick, Ginna and Nine Mile Point nuclear facilities. The New York State Energy Research and Development Authority (NYSERDA) centrally procures the ZECs through a 12-year contract extending from April 1, 2017 through March 31, 2029, administered in six two-year tranches. ZEC payments are made based upon the number of MWh produced by each facility, subject to specified caps and minimum performance requirements. The ZEC price for the first tranche was set at $17.48 per MWh of production and is administratively determined using a formula based on the social cost of carbon as determined in 2016 by the federal government, subject to pricing adjustments designed to lower the ZEC price based on increases in underlying energy and capacity prices.  Following the first tranche, the price will be updated bi-annually.  Each Load Serving Entity (LSE) is required to purchase an amount of ZECs from NYSERDA equivalent to its load ratio share of the total electric energy in the New York Control Area.  Cost recovery from ratepayers is incorporated into the commodity charges on customer bills.

On October 19, 2016, a coalition of fossil-generation companies filed a complaint in federal district court against the NYPSC alleging that the ZEC program violates certain provisions of the U.S. Constitution; specifically, that the ZEC program interferes with FERC’s jurisdiction over wholesale rates and that it discriminates against out of state competitors, which was dismissed by the district court on July 25, 2017. On September 27, 2018, the U.S. Court of Appeals for the Second Circuit affirmed the lower court's dismissal of the complaint against the ZEC program. On January 7, 2019, the fossil-generation companies filed a petition seeking U.S. Supreme Court review of the case which was denied on April 15, 2019.

In addition, on November 30, 2016 (as amended on January 13, 2017), a group of parties filed a Petition in New York State court seeking to invalidate the ZEC program, which argued that the NYPSC did not have authority to establish the program, that it violated state environmental law and that it violated certain technical provisions of the State Administrative Procedures Act when adopting the ZEC program. Subsequently, Generation, CENG and the NYPSC filed motions to dismiss the state court action, which were later opposed by the plaintiffs. On January 22, 2018, the court dismissed the environmental claims and the majority of the plaintiffs from the case but denied the motions to dismiss with respect to the remaining five plaintiffs and claims, without commenting on the merits of the case. On October 8, 2019, the court dismissed all remaining claims. The petitioners filed a notice of appeal on November 4, 2019 and have until May 4, 2020 to file their brief.

See Note 6 — Early Plant Retirements for additional information related to Ginna and Nine Mile Point, and Note 2 — Mergers, Acquisitions and Dispositions for additional information on Generation's acquisition of FitzPatrick.

Ginna Nuclear Power Plant Reliability Support Services Agreement. In November 2014, in response to a petition filed by Ginna regarding the possible retirement of Ginna, the NYPSC directed Ginna and Rochester Gas

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& Electric Company (RG&E) to negotiate a RSSA to support the continued operation of Ginna to maintain the reliability of the RG&E transmission grid for a specified period of time.

On April 8, 2016, FERC accepted Ginna’s compliance filing and on April 20, 2016, the NYPSC accepted the revised RSSA with a term expiring on March 31, 2017. In April 2016, Generation began recognizing revenue based on the final approved pricing contained in the RSSA and also recognized a one-time revenue adjustment of $101 million representing the net cumulative previously unrecognized amount of revenue retroactive from the April 1, 2015 effective date through March 31, 2016. A 49.99% portion of the one-time adjustment was removed from Generation’s results of operations as a result of the noncontrolling interests in CENG.

The RSSA required Ginna to continue operating through the RSSA term. On September 30, 2016, Ginna filed the required notice with the NYPSC of its intent to continue operating beyond the March 31, 2017 expiry of the RSSA, conditioned upon successful execution of an agreement between Ginna and NYSERDA for the sale of ZECs under the New York CES. Subject to prevailing over any administrative or legal challenges, it is expected the New York CES will allow Ginna to continue to operate through the end of its current operating license in 2029. See Note 6 — Early Plant Retirements for additional information regarding the impacts of a decision to early retire a nuclear plant.

Federal Regulatory Matters

PJM and NYISO MOPR Proceedings. PJM and NYISO capacity markets include a Minimum Offer Price Rule (MOPR). If a resource is subjected to a MOPR, its offer is adjusted to effectively remove the revenues it receives through a government-provided financial support program - resulting in a higher offer that may not clear the capacity market. Prior to December 19, 2019, the MOPR in PJM applied only to certain new gas-fired resources. Currently, the MOPR in NYISO continues to apply to certain new gas-fired resources.

In January 2017 and May 2018, EPSA filed pleadings at FERC that generally allege that the NYISO and PJM MOPRs should be expanded to apply to existing resources including those receiving ZEC compensation under the New Jersey ZEC (Salem), New York CES (FitzPatrick, Ginna and Nine Mile Point) and Illinois ZES (Quad Cities) programs. For Generation’s facilities in PJM and NYISO that are currently receiving ZEC compensation, an expanded MOPR would require exclusion of ZEC compensation when bidding into future capacity auctions, resulting in an increased risk of these facilities not receiving capacity revenues in future auctions. Exelon filed protests at FERC in response to each filing, arguing generally that ZEC payments provide compensation for an environmental attribute and are no different than other renewable support programs that have generally not been subject to a MOPR.

On December 19, 2019, FERC issued an order in the PJM MOPR proceeding that broadly applies the MOPR to all new and existing resources including nuclear, renewables, demand response, energy efficiency, storage and all resources owned by vertically-integrated utilities, greatly expanding the breadth and scope of PJM’s MOPR, effective as of PJM’s next capacity auction, the timing of which cannot be predicted at this time. FERC directed PJM to make a compliance filing within 90 days. FERC has no deadline for acting on PJM’s compliance filing. While FERC included some limited exemptions (generally available to existing renewable, energy efficiency, demand response, storage and existing vertically-integrated utility resources) in its order, no exemptions were available to state-supported nuclear resources. In addition, FERC provided no new mechanism for accommodating state-supported resources other than the existing FRR mechanism under which an entire utility zone would be removed from PJM’s capacity auction along with sufficient resources to support the load in such zone. Unless Illinois and New Jersey can implement an FRR program in their PJM zones, the MOPR will apply to Generation's owned or jointly owned nuclear plants in those states receiving a benefit under the Illinois ZES or the New Jersey ZEC program, as applicable, resulting in higher offers for those units that may not clear the capacity market.

On January 21, 2020, Exelon, PJM and a number of other entities submitted individual requests for rehearing of FERC’s December 19, 2019 order on the PJM MOPR. FERC routinely extends the deadline by which it must address requests for rehearing. FERC has not yet acted, and has no deadline by which it must act, in the NYISO proceeding.

Exelon is currently working with PJM and other stakeholders to pursue the FRR option prior to the next capacity auction in PJM. If Illinois implements the FRR option, Generation’s Illinois nuclear plants could be removed from PJM’s capacity auction and instead supply capacity and be compensated under the FRR program, which has the potential to mitigate the current economic distress being experienced by Generation's nuclear plants in Illinois, as discussed in Note 6 — Early Plant Retirements. Implementing the FRR program in Illinois will require both legislative

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and regulatory changes. Legislation may be introduced in New Jersey as well. Exelon cannot predict whether such legislative and regulatory changes can be implemented prior to the next capacity auction in PJM.

If Generation’s state-supported nuclear plants in PJM or NYISO are subjected to the MOPR without compensation under an FRR or similar program, it could have a material adverse impact on Exelon's and Generation's financial statements.

Operating License Renewals

Conowingo Hydroelectric Project. On August 29, 2012, Generation submitted a hydroelectric license application to FERC for a new license for the Conowingo Hydroelectric Project (Conowingo). In connection with Generation’s efforts to obtain a water quality certification pursuant to Section 401 of the Clean Water Act (401 Certification) from MDE for Conowingo, Generation has been working with MDE and other stakeholders to resolve water quality licensing issues, including: (1) water quality, (2) fish habitat, and (3) sediment.

On April 21, 2016, Generation and the U.S. Fish and Wildlife Service of the U.S. Department of the Interior executed a settlement agreement (DOI Settlement) resolving all fish passage issues between the parties.

On April 27, 2018, MDE issued its 401 Certification for Conowingo. As issued, the 401 Certification contains numerous conditions, including those relating to reduction of nutrients from upstream sources, removal of all visible trash and debris from upstream sources, and implementation of measures relating to fish passage, which could have a material, unfavorable impact on Exelon’s and Generation’s financial statements through an increase in capital expenditures and operating costs if implemented. On May 25, 2018, Generation filed complaints in federal and state court, along with a petition for reconsideration with MDE, alleging that the conditions are unfair and onerous and in violation of MDE regulations and state, federal, and constitutional law. Generation also requested that FERC defer the issuance of the federal license while these significant state and federal law issues are pending. On February 28, 2019, Generation filed a Petition for Declaratory Order with FERC requesting that FERC issue an order declaring that MDE waived its right to issue a 401 Certification for Conowingo because it failed to timely act on Conowingo’s 401 Certification application and requesting that FERC decline to include the conditions required by MDE in April 2018.

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

The financial impact of the DOI and MDE Settlements and other anticipated license commitments are estimated to be $11 million to $14 million per year, on average, recognized over the new license term, including capital and operating costs. The actual timing and amount of the majority of these costs are not currently fixed and will vary from year to year throughout the life of the new license. Generation cannot currently predict when FERC will issue the new license. As of December 31, 2019, $42 million of direct costs associated with Conowingo licensing efforts have been capitalized. Generation's current depreciation provision for Conowingo assumes renewal of the FERC license.

Peach Bottom Units 2 and 3. On July 10, 2018, Generation submitted a second 20-year license renewal application with the NRC for Peach Bottom Units 2 and 3. Generation anticipates the second license renewal in the first half of 2020. Peach Bottom Units 2 and 3 are currently licensed to operate through 2033 and 2034, respectively. See Note 7 – Property, Plant and Equipment for additional information regarding the estimated useful life and depreciation provisions for Peach Bottom.

PJM Transmission Rate Design. Refer to Other Federal Regulatory Matters above for additional information.

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The Registrants recognize revenue from contracts with customers to depict the transfer of goods or services to customers at an amount that the entities expect to be entitled to in exchange for those goods or services. Generation’s primary sources of revenue include competitive sales of power, natural gas, and other energy-related products and services. The Utility Registrants’ primary sources of revenue include regulated electric and gas tariff sales, distribution and transmission services. The performance obligations, revenue recognition and payment terms associated with these sources of revenue are further discussed in the table below. There are no significant financing components for these sources of revenue and no variable consideration for regulated electric and gas tariff sales and regulated transmission services unless noted below.

Unless otherwise noted, for each of the significant revenue categories and related performance obligations described below, the Registrants have the right to consideration from the customer in an amount that corresponds directly with the value transferred to the customer for the performance completed to date. Therefore, the Registrant's generally recognize revenue in the amount for which they have the right to invoice the customer. As a result, there are generally no significant judgments used in determining or allocating the transaction price.

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Revenue Source	Description	Performance Obligation	Timing of Revenue Recognition	Payment Terms
Competitive Power Sales (Exelon and Generation)	Sales of power and other energy-related commodities to wholesale and retail customers across multiple geographic regions through its customer-facing business, Constellation.	Various including the delivery of power (generally delivered over time) and other energy-related commodities such as capacity (generally delivered over time), ZECs, RECs or other ancillary services (generally delivered at a point in time).	Concurrently as power is generated for bundled power sale contracts. (a)	Within the month following delivery to the customer.
Competitive Natural Gas Sales (Exelon and Generation)	Sales of natural gas on a full requirement basis or for an agreed upon volume to commercial and residential customers.	Delivery of natural gas to the customer.	Over time as the natural gas is delivered and consumed by the customer.	Within the month following delivery to the customer.
Other Competitive Products and Services (Exelon and Generation)	Sales of other energy-related products and services such as long-term construction and installation of energy efficiency assets and new power generating facilities, primarily to commercial and industrial customers.	Construction and/or installation of the asset for the customer.	Revenues, and associated costs, are recognized throughout the contract term using an input method to measure progress towards completion.(b)	Within 30 or 45 days from the invoice date.
Regulated Electric and Gas Tariff Sales (Exelon and the Utility Registrants)	Sales of electricity and electricity distribution services (the Utility Registrants) and natural gas and gas distribution services (PECO, BGE and DPL) to residential, commercial, industrial and governmental customers through regulated tariff rates approved by state regulatory commissions.	Delivery of electricity and/or natural gas.	Over time (each day) as the electricity and/or natural gas is delivered to customers. Tariff sales are generally considered daily contracts as customers can discontinue service at any time. (c)	Within the month following delivery of the electricity or natural gas to the customer.
Regulated Transmission Services (Exelon and the Utility Registrants)	The Utility Registrants provide open access to their transmission facilities to PJM, which directs and controls the operation of these transmission facilities and accordingly compensates the Utility Registrants pursuant to filed tariffs at cost-based rates approved by FERC.	Various including (i) Network Integration Transmission Services (NITS), (ii) scheduling, system control and dispatch services, and (iii) access to the wholesale grid.	Over time utilizing output methods to measure progress towards completion. (d)	Paid weekly by PJM.

__________

(a)

Certain contracts may contain limits on the total amount of revenue Exelon and Generation are able to collect over the entire term of the contract. In such cases, Exelon and Generation estimate the total consideration expected to be received over the term of the contract net of the constraint and allocate the expected consideration to the performance obligations in the contract such that revenue is recognized ratably over the term of the entire contract as the performance obligations are satisfied.

(b)	The method recognizes revenue based on the various inputs used to satisfy the performance obligation, such as costs incurred and total labor hours expended. The total amount of revenue that will be recognized is based on the agreed upon contractually-stated amount. The average contract term for these projects is approximately 18 months.

(c)	Electric and natural gas utility customers have the choice to purchase electricity or natural gas from competitive electric generation and natural gas suppliers. While the Utility Registrants are required under state legislation to bill their customers

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for the supply and distribution of electricity and/or natural gas, they recognize revenue related only to the distribution services when customers purchase their electricity or natural gas from competitive suppliers.

(d)	Passage of time is used for NITS and access to the wholesale grid and MWHs of energy transported over the wholesale grid is used for scheduling, system control and dispatch services.

Generation incurs incremental costs in order to execute certain retail power and gas sales contracts. These costs, which primarily relate to retail broker fees and sales commissions, are capitalized when incurred as contract acquisition costs and were immaterial as of December 31, 2019 and 2018. The Utility Registrants do not incur any material costs to obtain or fulfill contracts with customers.

Contract Balances (All Registrants)

Contract Assets and Liabilities

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

Generation records contract liabilities when consideration is received or due prior to the satisfaction of the performance obligations. These contract liabilities primarily relate to upfront consideration received or due for equipment service plans, solar panel leases and the Illinois ZEC program that introduces a cap on the total consideration to be received by Generation. The Generation contract liability related to the Illinois ZEC program includes certain amounts with ComEd that are eliminated in consolidation in Exelon’s Consolidated Statements of Operations and Consolidated Balance Sheets. Generation records contract liabilities within Other current liabilities and Other noncurrent liabilities within Exelon’s and Generation’s Consolidated Balance Sheets.

The following table provides a rollforward of the contract assets and liabilities reflected in Exelon's and Generation's Consolidated Balance Sheets from January 1, 2018 to December 31, 2019:

		Contract Assets								Contract Liabilities
		Exelon				Generation				Exelon				Generation
Balance as of January 1, 2018		$	283			$	283			$	35			$	35
Consideration received or due		(146		)		(146		)		179				465
Revenues recognized		50				50				(187		)		(458		)
Balance at December 31, 2018		187				187				27				42
Consideration received or due		(143		)		(143		)		94				287
Revenues recognized		130				130				(88		)		(258		)
Balance at December 31, 2019		$	174			$	174			$	33			$	71

The Utility Registrants do not have any contract assets. The Utility Registrants also record contract liabilities when consideration is received prior to the satisfaction of the performance obligations. As of December 31, 2019 and December 31, 2018, the Utility Registrants' contract liabilities were immaterial.

Transaction Price Allocated to Remaining Performance Obligations (All Registrants)

The following table shows the amounts of future revenues expected to be recorded in each year for performance obligations that are unsatisfied or partially unsatisfied as of December 31, 2019. This disclosure only includes contracts for which the total consideration is fixed and determinable at contract inception. The average contract term varies by customer type and commodity but ranges from one month to several years.

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

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	2020				2021				2022				2023				2024 and thereafter				Total
Exelon	$	400			$	141			$	65			$	45			$	199			$	850
Generation	501				196				80				45				199				1,021

Revenue Disaggregation (All Registrants)

The Registrants disaggregate revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. See Note Note 5 — Segment Information for the presentation of the Registrant's revenue disaggregation.

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

Exelon has eleven reportable segments, which include Generation's five reportable segments consisting of the Mid-Atlantic, Midwest, New York, ERCOT and all other power regions referred to collectively as “Other Power Regions” and ComEd, PECO, BGE, and PHI's three reportable segments consisting of Pepco, DPL, and ACE. ComEd, PECO, BGE, Pepco, DPL and ACE each represent a single reportable segment, and as such, no separate segment information is provided for these Registrants. Exelon, ComEd, PECO, BGE, Pepco, DPL and ACE's CODMs evaluate the performance of and allocate resources to ComEd, PECO, BGE, Pepco, DPL and ACE based on net income.

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

•	Mid-Atlantic represents operations in the eastern half of PJM, which includes New Jersey, Maryland, Virginia, West Virginia, Delaware, the District of Columbia and parts of Pennsylvania and North Carolina.

•	Midwest represents operations in the western half of PJM and the United States footprint of MISO, excluding MISO’s Southern Region.

•	New York represents operations within NYISO.

•	ERCOT represents operations within Electric Reliability Council of Texas.

•	Other Power Regions:

•	New England represents operations within ISO-NE.

•	South represents operations in the FRCC, MISO’s Southern Region, the remaining portions of the SERC not included within MISO or PJM.

•	West represents operations in the WECC, including California ISO.

•	Canada represents operations across the entire country of Canada and includes AESO, OIESO and the Canadian portion of MISO.

The CODMs for Exelon and Generation evaluate the performance of Generation’s electric business activities and allocate resources based on RNF. Generation believes that RNF is a useful measurement of operational performance. RNF is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report. Generation’s operating revenues include all sales to third parties and affiliated sales to the Utility Registrants. Purchased power costs include all costs associated with the procurement and supply of electricity including capacity, energy and ancillary services. Fuel expense includes the fuel costs for Generation’s owned generation and fuel costs associated with tolling agreements. The results of Generation's other business activities are not regularly reviewed by the CODM and are therefore not classified as operating segments or included in the regional reportable segment

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amounts. These activities include natural gas, as well as other miscellaneous business activities that are not significant to Generation's overall operating revenues or results of operations. Further, Generation’s unrealized mark-to-market gains and losses on economic hedging activities and its amortization of certain intangible assets and liabilities relating to commodity contracts recorded at fair value from mergers and acquisitions are also excluded from the regional reportable segment amounts. Exelon and Generation do not use a measure of total assets in making decisions regarding allocating resources to or assessing the performance of these reportable segments.

During the first quarter of 2019, due to a change in economics in our New England region, Generation changed the way that information is reviewed by the CODM. The New England region is no longer regularly reviewed as a separate region by the CODM nor is it presented separately in any external information presented to third parties. Information for the New England region is reviewed by the CODM as part of Other Power Regions. Exelon and Generation retrospectively applied this change.

An analysis and reconciliation of the Registrants’ reportable segment information to the respective information in the consolidated financial statements for the years ended December 31, 2019, 2018, and 2017 is as follows:

	Generation (a)				ComEd				PECO				BGE				PHI				Other (b)				Intersegment Eliminations				Exelon
Operating revenues(c):
2019
Competitive businesses electric revenues	$	16,285			$	—			$	—			$	—			$	—			$	—			$	(1,165	)		$	15,120
Competitive businesses natural gas revenues	2,148				—				—				—				—				—				(1		)		2,147
Competitive businesses other revenues	491				—				—				—				—				—				(4		)		487
Rate-regulated electric revenues	—				5,747				2,490				2,379				4,626				—				(47		)		15,195
Rate-regulated natural gas revenues	—				—				610				727				167				—				(15		)		1,489
Shared service and other revenues	—				—				—				—				13				1,921				(1,934		)		—
Total operating revenues	$	18,924			$	5,747			$	3,100			$	3,106			$	4,806			$	1,921			$	(3,166	)		$	34,438

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	Generation (a)				ComEd				PECO				BGE				PHI				Other (b)				Intersegment Eliminations				Exelon
2018
Competitive businesses electric revenues	$	17,411			$	—			$	—			$	—			$	—			$	—			$	(1,256	)		$	16,155
Competitive businesses natural gas revenues	2,718				—				—				—				—				—				(8		)		2,710
Competitive businesses other revenues	308				—				—				—				—				—				(5		)		303
Rate-regulated electric revenues	—				5,882				2,470				2,428				4,602				—				(45		)		15,337
Rate-regulated natural gas revenues	—				—				568				741				181				—				(20		)		1,470
Shared service and other revenues	—				—				—				—				15				1,948				(1,960		)		3
Total operating revenues	$	20,437			$	5,882			$	3,038			$	3,169			$	4,798			$	1,948			$	(3,294	)		$	35,978
2017
Competitive businesses electric revenues	$	15,332			$	—			$	—			$	—			$	—			$	—			$	(1,105	)		$	14,227
Competitive businesses natural gas revenues	2,575				—				—				—				—				—				—				2,575
Competitive businesses other revenues	593				—				—				—				—				—				(1		)		592
Rate-regulated electric revenues	—				5,536				2,375				2,489				4,462				—				(29		)		14,833
Rate-regulated natural gas revenues	—				—				495				687				161				—				(10		)		1,333
Shared service and other revenues	—				—				—				—				49				1,831				(1,880		)		—
Total operating revenues	$	18,500			$	5,536			$	2,870			$	3,176			$	4,672			$	1,831			$	(3,025	)		$	33,560
Intersegment revenues(d):
2019	$	1,172			$	30			$	6			$	26			$	14			$	1,913			$	(3,159	)		$	2
2018	1,269				27				8				29				15				1,942				(3,289		)		1
2017	1,110				15				7				16				50				1,824				(3,020		)		2
Depreciation and amortization:
2019	$	1,535			$	1,033			$	333			$	502			$	754			$	95			$	—			$	4,252
2018	1,797				940				301				483				740				92				—				4,353
2017	1,457				850				286				473				675				87				—				3,828

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	Generation (a)				ComEd				PECO				BGE				PHI				Other (b)				Intersegment Eliminations				Exelon
Operating expenses (c):
2019	$	17,628			$	4,580			$	2,388			$	2,574			$	4,084			$	1,996			$	(3,154	)		$	30,096
2018	19,510				4,741				2,452				2,696				4,156				1,929				(3,341		)		32,143
2017	18,001				4,214				2,215				2,562				3,911				1,742				(3,026		)		29,619
Interest expense, net:
2019	$	429			$	359			$	136			$	121			$	263			$	308			$	—			$	1,616
2018	432				347				129				106				261				279				—				1,554
2017	440				361				126				105				245				283				—				1,560
Income (loss) before income taxes:
2019	$	1,917			$	851			$	593			$	439			$	514			$	(327	)		$	(2	)		$	3,985
2018	365				832				466				387				425				(249		)		(1		)		2,225
2017	1,455				984				538				525				571				(296		)		(2		)		3,775
Income taxes:
2019	$	516			$	163			$	65			$	79			$	38			$	(87	)		$	—			$	774
2018	(108		)		168				6				74				33				(55		)		—				118
2017	(1,376		)		417				104				218				217				294				—				(126		)
Net income (loss):
2019	$	1,217			$	688			$	528			$	360			$	477			$	(240	)		$	(2	)		$	3,028
2018	443				664				460				313				393				(193		)		(1		)		2,079
2017	2,798				567				434				307				355				(590		)		(2		)		3,869
Capital expenditures:
2019	$	1,845			$	1,915			$	939			$	1,145			$	1,355			$	49			$	—			$	7,248
2018	2,242				2,126				849				959				1,375				43				—				7,594
2017	2,259				2,250				732				882				1,396				65				—				7,584
Total assets:
2019	$	48,995			$	32,765			$	11,469			$	10,634			$	22,719			$	8,484			$	(10,089	)		$	124,977
2018	47,556				31,213				10,642				9,716				21,952				8,355				(9,800		)		119,634

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(a)	See Note 24 — Related Party Transactions for additional information on intersegment revenues.

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

(c)	Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 23 — Supplemental Financial Information for additional information on total utility taxes.

(d)

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

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PHI:

	Pepco				DPL				ACE				Other(b)				Intersegment Eliminations				PHI
Operating revenues(a):
2019
Rate-regulated electric revenues	$	2,260			$	1,139			$	1,240			$	—			$	(13	)		$	4,626
Rate-regulated natural gas revenues	—				167				—				—				—				167
Shared service and other revenues	—				—				—				396				(383		)		13
Total operating revenues	$	2,260			$	1,306			$	1,240			$	396			$	(396	)		$	4,806
2018
Rate-regulated electric revenues	$	2,232			$	1,151			$	1,236			$	—			$	(17	)		$	4,602
Rate-regulated natural gas revenues	—				181				—				—				—				181
Shared service and other revenues	—				—				—				435				(420		)		15
Total operating revenues	$	2,232			$	1,332			$	1,236			$	435			$	(437	)		$	4,798
2017
Rate-regulated electric revenues	$	2,151			$	1,139			$	1,186			$	—			$	(14	)		$	4,462
Rate-regulated natural gas revenues	—				161				—				—				—				161
Shared service and other revenues	—				—				—				52				(3		)		49
Total operating revenues	$	2,151			$	1,300			$	1,186			$	52			$	(17	)		$	4,672
Intersegment revenues:
2019	$	5			$	7			$	3			$	396			$	(397	)		$	14
2018	6				8				3				435				(437		)		15
2017	6				8				2				53				(19		)		50
Depreciation and amortization:
2019	$	374			$	184			$	157			$	39			$	—			$	754
2018	385				182				136				37				—				$	740
2017	321				167				146				42				(1		)		$	675
Operating expenses:
2019	$	1,899			$	1,089			$	1,089			$	403			$	(396	)		$	4,084
2018	1,919				1,143				1,087				442				(435		)		$	4,156
2017	1,760				1,071				1,029				68				(17		)		$	3,911
Interest expense, net:
2019	$	133			$	61			$	58			$	10			$	1			$	263
2018	128				58				64				11				—				$	261
2017	121				51				61				13				(1		)		$	245
Income (loss) before income taxes:
2019	$	259			$	169			$	99			$	476			$	(489	)		$	514
2018	216				142				87				388				(408		)		$	425
2017	303				192				103				377				(404		)		$	571
Income taxes:
2019	$	16			$	22			$	—			$	(1	)		$	1			$	38
2018	11				22				12				(10		)		(2		)		$	33
2017	105				71				26				15				—				$	217

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	Pepco				DPL				ACE				Other(b)				Intersegment Eliminations				PHI
Net income (loss):
2019	$	243			$	147			$	99			$	(26	)		$	14			$	477
2018	205				120				75				(22		)		15				$	393
2017	198				121				77				(91		)		50				$	355
Capital expenditures:
2019	$	626			$	348			$	375			$	6			$	—			$	1,355
2018	656				364				335				20				—				$	1,375
2017	628				428				312				28				—				1,396
Total assets:
2019	$	8,661			$	4,830			$	3,933			$	11,105			$	(5,810	)		$	22,719
2018	8,267				4,588				3,699				10,819				(5,421		)		21,952

__________

(a)	Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 23 — Supplemental Financial Information for additional information on total utility taxes.

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

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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):

	2019
	Revenues from external customers(a)
	Contracts with customers				Other(b)				Total				Intersegment Revenues				Total Revenues
Mid-Atlantic	$	5,053			$	17			$	5,070			$	4			$	5,074
Midwest	4,095				232				4,327				(34		)		4,293
New York	1,571				25				1,596				—				1,596
ERCOT	768				229				997				16				1,013
Other Power Regions	3,687				608				4,295				(49		)		4,246
Total Competitive Businesses Electric Revenues	15,174				1,111				16,285				(63		)		16,222
Competitive Businesses Natural Gas Revenues	1,446				702				2,148				62				2,210
Competitive Businesses Other Revenues(c)	440				51				491				1				492
Total Generation Consolidated Operating Revenues	17,060				1,864				$	18,924			$	—			$	18,924

	2018
	Revenues from external customers(a)
	Contracts with customers				Other(b)				Total				Intersegment Revenues				Total Revenues
Mid-Atlantic	$	5,241			$	233			$	5,474			$	13			$	5,487
Midwest	4,527				190				4,717				(11		)		4,706
New York	1,723				(36		)		1,687				—				1,687
ERCOT	572				560				1,132				1				1,133
Other Power Regions	3,530				871				4,401				(66		)		4,335
Total Competitive Businesses Electric Revenues	15,593				1,818				17,411				(63		)		17,348
Competitive Businesses Natural Gas Revenues	1,524				1,194				2,718				62				2,780
Competitive Businesses Other Revenues(c)	510				(202		)		308				1				309
Total Generation Consolidated Operating Revenues	$	17,627			$	2,810			$	20,437			$	—			$	20,437

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	2017
	Revenues from external customers(a)
	Contracts with customers				Other(b)				Total				Intersegment Revenues				Total Revenues
Mid-Atlantic	$	5,523			$	(8	)		$	5,515			$	25			$	5,540
Midwest	3,923				283				4,206				(25		)		4,181
New York	1,605				(38		)		1,567				(17		)		1,550
ERCOT	641				317				958				4				962
Other Power Regions	2,658				428				3,086				(35		)		3,051
Total Competitive Businesses Electric Revenues	14,350				982				15,332				(48		)		15,284
Competitive Businesses Natural Gas Revenues	1,658				917				2,575				53				2,628
Competitive Businesses Other Revenues(c)	744				(151		)		593				(5		)		588
Total Generation Consolidated Operating Revenues	$	16,752			$	1,748			$	18,500			$	—			$	18,500

__________

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

(b)	Includes revenues from derivatives and leases.

(c)

Other represents activities not allocated to a region. See text above for a description of included activities. Includes a $38 million decrease to revenues for the amortization of intangible assets and liabilities related to commodity contracts recorded at fair value in 2017, unrealized mark-to-market losses of $4 million, $262 million, and $131 million in 2019, 2018, and 2017, respectively, and elimination of intersegment revenues.

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

	2019												2018												2017
	RNF from external customers(a)				Intersegment RNF				Total RNF				RNF from external customers(a)				Intersegment RNF				Total RNF				RNF from external customers(a)				Intersegment RNF				Total RNF
Mid-Atlantic	$	2,637			$	18			$	2,655			$	3,022			$	51			$	3,073			$	3,105			$	109			$	3,214
Midwest	2,994				(32		)		2,962				3,112				23				3,135				2,810				10				2,820
New York	1,081				13				1,094				1,112				10				1,122				1,007				1				1,008
ERCOT	338				(30		)		308				501				(243		)		258				575				(243		)		332
Other Power Regions	694				(74		)		620				883				(154		)		729				1,014				(195		)		819
Total Revenues net of purchased power and fuel for Reportable Segments	$	7,744			$	(105	)		$	7,639			$	8,630			$	(313	)		$	8,317			$	8,511			$	(318	)		$	8,193
Other (b)	324				105				429				114				313				427				299				318				617
Total Generation Revenues net of purchased power and fuel expense	$	8,068			$	—			$	8,068			$	8,744			$	—			$	8,744			$	8,810			$	—			$	8,810

__________ 

(a)	Includes purchases and sales from/to third parties and affiliated sales to the Utility Registrants.

(b)

Other represents activities not allocated to a region. See text above for a description of included activities. Includes a $54 million decrease in RNF for the amortization of intangible assets and liabilities related to commodity contracts in 2017, unrealized mark-to-market losses of $215 million, $319 million, and $175 million in 2019, 2018, and 2017, respectively, accelerated nuclear fuel amortization associated with the announced early plant retirements as discussed in Note 6 - Early Plant Retirements of $13 million, $57 million and $12 million in 2019, 2018, and 2017, respectively, and the elimination of intersegment RNF.

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

	2019
Revenues from contracts with customers	ComEd				PECO				BGE				PHI				Pepco				DPL				ACE
Rate-regulated electric revenues
Residential	$	2,916			$	1,596			$	1,326			$	2,316			$	1,012			$	645			$	659
Small commercial & industrial	1,463				404				254				505				149				186				170
Large commercial & industrial	540				219				436				1,112				833				99				180
Public authorities & electric railroads	47				29				27				61				34				14				13
Other(a)	888				249				321				650				227				204				218
Total rate-regulated electric revenues(b)	5,854				2,497				2,364				4,644				2,255				1,148				1,240
Rate-regulated natural gas revenues
Residential	—				409				474				96				—				96				—
Small commercial & industrial	—				169				77				44				—				45				—
Large commercial & industrial	—				1				132				5				—				5				—
Transportation	—				25				—				14				—				14				—
Other(c)	—				6				31				7				—				7				—
Total rate-regulated natural gas revenues(d)	—				610				714				166				—				167				—
Total rate-regulated revenues from contracts with customers	5,854				3,107				3,078				4,810				2,255				1,315				1,240
Other revenues
Revenues from alternative revenue programs	(133		)		(21		)		12				(14		)		(3		)		(11		)		—
Other rate-regulated electric revenues(e)	26				13				12				10				8				2				—
Other rate-regulated natural gas revenues(e)	—				1				4				—				—				—				—
Total other revenues	(107		)		(7		)		28				(4		)		5				(9		)		—
Total rate-regulated revenues for reportable segments	$	5,747			$	3,100			$	3,106			$	4,806			$	2,260			$	1,306			$	1,240

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	2018
Revenues from contracts with customers	ComEd				PECO				BGE				PHI				Pepco				DPL				ACE
Rate-regulated electric revenues
Residential	$	2,942			$	1,566			$	1,382			$	2,351			$	1,021			$	669			$	661
Small commercial & industrial	1,487				404				257				488				140				186				162
Large commercial & industrial	538				223				429				1,124				846				100				178
Public authorities & electric railroads	47				28				28				58				32				14				12
Other(a)	867				243				327				593				193				175				227
Total rate-regulated electric revenues(b)	5,881				2,464				2,423				4,614				2,232				1,144				1,240
Rate-regulated natural gas revenues
Residential	—				395				491				99				—				99				—
Small commercial & industrial	—				143				77				44				—				44				—
Large commercial & industrial	—				1				124				8				—				8				—
Transportation	—				23				—				16				—				16				—
Other(c)	—				6				63				13				—				13				—
Total rate-regulated natural gas revenues(d)	—				568				755				180				—				180				—
Total rate-regulated revenues from contracts with customers	5,881				3,032				3,178				4,794				2,232				1,324				1,240
Other revenues
Revenues from alternative revenue programs	(29		)		(7		)		(26		)		(7		)		(7		)		4				(4		)
Other rate-regulated electric revenues(e)	30				12				13				10				7				3				—
Other rate-regulated natural gas revenues(e)	—				1				4				1				—				1				—
Total other revenues	1				6				(9		)		4				—				8				(4		)
Total rate-regulated revenues for reportable segments	$	5,882			$	3,038			$	3,169			$	4,798			$	2,232			$	1,332			$	1,236

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	2017
Revenues from contracts with customers	ComEd				PECO				BGE				PHI				Pepco				DPL				ACE
Rate-regulated electric revenues
Residential	$	2,715			$	1,505			$	1,365			$	2,246			$	964			$	663			$	619
Small commercial & industrial	1,363				401				254				490				137				187				166
Large commercial & industrial	455				223				427				1,086				794				103				189
Public authorities & electric railroads	44				30				31				60				33				14				13
Other(a)	886				204				299				541				199				163				191
Total rate-regulated electric revenues(b)	5,463				2,363				2,376				4,423				2,127				1,130				1,178
Rate-regulated natural gas revenues
Residential	—				331				437				90				—				90				—
Small commercial & industrial	—				131				75				38				—				38				—
Large commercial & industrial	—				1				119				8				—				8				—
Transportation	—				23				—				15				—				15				—
Other(c)	—				8				28				9				—				9				—
Total rate-regulated natural gas revenues(d)	—				494				659				160				—				160				—
Total rate-regulated revenues from contracts with customers	5,463				2,857				3,035				4,583				2,127				1,290				1,178
Other revenues
Revenues from alternative revenue programs	43				—				124				33				19				6				8
Other rate-regulated electric revenues(e)	30				12				13				8				5				3				—
Other rate-regulated natural gas revenues(e)	—				1				4				1				—				1				—
Other revenues(f)	—				—				—				47				—				—				—
Total other revenues	73				13				141				89				24				10				8
Total rate-regulated revenues for reportable segments	$	5,536			$	2,870			$	3,176			$	4,672			$	2,151			$	1,300			$	1,186

__________

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

(b)

Includes operating revenues from affiliates of $30 million, $5 million, $8 million, $14 million, $5 million, $7 million and $3 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2019, $27 million, $7 million, $8 million, $15 million, $6 million, $8 million and $3 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, in 2018, and $15 million, $6 million, $5 million, $3 million, $6 million, $8 million and $2 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2017.

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

(d)	Includes operating revenues from affiliates of $1 million and $18 million at PECO and BGE, respectively, in 2019, $1 million and $21 million at PECO and BGE, respectively, in 2018, and $1 million and $11 million at PECO and BGE, respectively, in 2017.

(e)	Includes late payment charge revenues.

(f)	Includes operating revenues from affiliates of $47 million at PHI in 2017.

Exelon and Generation continuously evaluate factors that affect the current and expected economic value of Generation’s plants, including, but not limited to: market power prices, results of capacity auctions, potential legislative and regulatory solutions to ensure plants are fairly compensated for benefits they provide through their carbon-free emissions, reliability, or fuel security, and the impact of potential rules from the EPA requiring reduction of carbon and other emissions and the efforts of states to implement those final rules. The precise timing of an early retirement date for any plant, and the resulting financial statement impacts, may be affected by many factors,

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including the status of potential regulatory or legislative solutions, results of any transmission system reliability study assessments, the nature of any co-owner requirements and stipulations, and NDT fund requirements for nuclear plants, among other factors. However, the earliest retirement date for any plant would usually be the first year in which the unit does not have capacity or other obligations, and where applicable, just prior to its next scheduled nuclear refueling outage.

Nuclear Generation

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

Assuming the continued effectiveness of the Illinois ZES, New Jersey ZEC program and the New York CES, Generation and CENG, through its ownership of 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 3 — Regulatory Matters for additional information on the Illinois ZES, New Jersey ZEC program, New York CES and FERC's December 19, 2019 order.

In Pennsylvania, the TMI nuclear plant did not clear in the May 2017 PJM capacity auction for the 2020-2021 planning year, the third consecutive year that TMI failed to clear the PJM base residual capacity auction and on May 30, 2017, based on these capacity auction results, prolonged periods of low wholesale power prices, and the absence of federal or state policies that place a value on nuclear energy for its ability to produce electricity without air pollution, Generation announced that it would permanently cease generation operations at TMI. On September 20, 2019, Generation permanently ceased generation operations at TMI.

On February 2, 2018, Generation announced that it would permanently cease generation operations at the Oyster Creek nuclear plant at the end of its current operating cycle and permanently ceased generation operations on September 17, 2018.

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As a result of these early nuclear plant retirement decisions, Exelon and Generation recognized incremental non-cash charges to earnings stemming from shortening the expected economic useful lives primarily related to accelerated depreciation of plant assets (including any ARC) and accelerated amortization of nuclear fuel, as well as operating and maintenance expenses. The total annual impact of these charges by year are summarized in the table below.

Income statement expense (pre-tax)		2019(a)				2018(b)				2017(c)
Depreciation and Amortization
Accelerated depreciation		$	216			$	539			$	250
Accelerated nuclear fuel amortization		13				57				12
Operating and Maintenance(d)		(53		)		32				77
Total		$	176			$	628			$	339

_________

(a)	Reflects incremental charges for TMI from January 1, 2019 through September 20, 2019.

(b)	Reflects incremental charges for TMI in 2018 and Oyster Creek from February 2, 2018 through September 17, 2018.

(c)	Reflects incremental charges for TMI from May 30, 2017 through December 31, 2017.

(d)

In 2019, primarily reflects the net impacts associated with the remeasurements of the TMI ARO in the first and third quarters. In 2018 and 2017, primarily reflects materials and supplies inventory reserve adjustments, employee related costs and CWIP impairments associated with the early retirement decisions for TMI and Oyster Creek. Excludes the charges in the third quarter of 2018 and second quarter of 2019 for the ARO remeasurement due to the sale of Oyster Creek. See Note 2 — Mergers, Acquisitions and Dispositions and Note 9 — Asset Retirement Obligations for additional information.

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

Other Generation

On March 29, 2018, Generation notified grid operator ISO-NE of its plans to early retire Mystic Units 8 and 9 absent regulatory reforms on June 1, 2022, at the end of the then-current capacity commitment for Mystic Units 7 and 8. Mystic Unit 9 was then committed through May 2021.

On May 16, 2018, Generation made a filing with FERC to establish cost-of-service compensation and terms and conditions of service for Mystic Units 8 and 9 for the period between June 1, 2022 - May 31, 2024. On December 20, 2018, FERC issued an order accepting the cost of service compensation, reflecting a number of adjustments to the annual fixed revenue requirement and allowing for recovery of a substantial portion of the costs associated with the Everett Marine Terminal. Those adjustments were reflected in a compliance filing filed on March 1, 2019. In the December 20, 2018 order, FERC also directed a paper hearing on ROE using a new methodology. On January 22, 2019, Exelon and several other parties filed requests for rehearing of certain findings in the order.

On March 25, 2019, ISO-NE filed the Inventoried Energy Program, which is intended to provide an interim fuel security program pending conclusion of the stakeholder process to develop a long-term, market-based solution to address fuel security. The Inventoried Energy Program went into effect on August 5, 2019. On October 7, 2019, requests for rehearing were denied and several parties have appealed to the D.C. Circuit Court. FERC ordered ISO-NE to file long-term, market-based fuel security rules by October 15, 2019; FERC has granted an extension to April 15, 2020.

The following table provides the balance sheet amounts as of December 31, 2019 for Exelon's and Generation’s significant assets and liabilities associated with the Mystic Units 8 and 9 and Everett Marine Terminal assets that would potentially be impacted by the failure to adopt long-term solutions for reliability and fuel security.

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		December 31, 2019
Asset Balances
Materials and supplies inventory		$	31
Fuel inventory		11
Property, plant and equipment, net		902
Liability Balances
Asset retirement obligation		(3		)

To ensure the continued reliable supply of fuel to Mystic Units 8 and 9 while they remain operating, on October 1, 2018, Generation acquired the Everett Marine Terminal in Massachusetts for a purchase price of $81 million, with the majority of the fair value allocated to Property, plant and equipment and no goodwill recorded.  Generation also settled its existing long-term gas supply agreement, resulting in a pre-tax gain of $75 million, which is included within Purchased power and fuel expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

See Note 11 — Asset Impairments for impairment assessment considerations on the New England Asset Group.

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The following tables present a summary of property, plant and equipment by asset category as of December 31, 2019 and 2018:

Asset Category	Exelon				Generation				ComEd				PECO				BGE				PHI				Pepco				DPL				ACE
December 31, 2019
Electric—transmission and distribution	$	56,809			$	—			$	27,566			$	8,957			$	8,326			$	13,809			$	9,734			$	4,464			$	4,207
Electric—generation	29,839				29,839				—				—				—				—				—				—				—
Gas—transportation and distribution	6,147				—				—				2,899				2,999				525				—				690				—
Common—electric and gas	1,907				—				—				877				991				146				—				160				—
Nuclear fuel(a)	5,656				5,656				—				—				—				—				—				—				—
Construction work in progress	3,055				702				662				250				483				921				628				125				166
Other property, plant and equipment(b)	799				13				47				27				25				108				64				21				27
Total property, plant and equipment	104,212				36,210				28,275				13,010				12,824				15,509				10,426				5,460				4,400
Less: accumulated depreciation(c)	23,979				12,017				5,168				3,718				3,834				1,213				3,517				1,425				1,210
Property, plant and equipment, net	$	80,233			$	24,193			$	23,107			$	9,292			$	8,990			$	14,296			$	6,909			$	4,035			$	3,190
December 31, 2018
Electric—transmission and distribution	$	53,090			$	—			$	25,991			$	8,359			$	7,951			$	12,664			$	9,217			$	4,195			$	3,866
Electric—generation	29,170				29,170				—				—				—				—				—				—				—
Gas—transportation and distribution	5,530				—				—				2,694				2,630				486				—				651				—
Common—electric and gas	1,627				—				—				756				860				126				—				136				—
Nuclear fuel(a)	5,957				5,957				—				—				—				—				—				—				—
Construction work in progress	3,377				997				705				343				410				912				536				151				209
Other property, plant and equipment(b)	858				63				46				19				25				99				61				17				28
Total property, plant and equipment	99,609				36,187				26,742				12,171				11,876				14,287				9,814				5,150				4,103
Less: accumulated depreciation(c)	22,902				12,206				4,684				3,561				3,633				841				3,354				1,329				1,137
Property, plant and equipment, net	$	76,707			$	23,981			$	22,058			$	8,610			$	8,243			$	13,446			$	6,460			$	3,821			$	2,966

__________

(a)	Includes nuclear fuel that is in the fabrication and installation phase of $1,025 million and $1,004 million at December 31, 2019 and 2018, respectively.

(b)	Primarily composed of land and non-utility property.

(c)	Includes accumulated amortization of nuclear fuel in the reactor core at Generation of $2,867 million and $2,969 million as of December 31, 2019 and 2018, respectively.

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The following table presents the average service life for each asset category in number of years:

	Average Service Life (years)
Asset Category	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Electric - transmission and distribution	5-80		N/A		5-80		5-65		5-75		5-75		5-75		5-70		5-65
Electric - generation	1-56		1-56		N/A		N/A		N/A		N/A		N/A		N/A		N/A
Gas - transportation and distribution	5-80		N/A		N/A		5-70		5-80		5-75		N/A		5-75		N/A
Common - electric and gas	4-75		N/A		N/A		5-50		4-50		5-75		N/A		5-75		N/A
Nuclear fuel	1-8		1-8		N/A		N/A		N/A		N/A		N/A		N/A		N/A
Other property, plant and equipment	1-50		1-10		34-50		50		20-50		3-50		33-50		8-50		13-15

Depreciation provisions are based on the estimated useful lives of the stations, which reflect the first renewal of the operating licenses for all of Generation's operating nuclear generating stations except for Clinton and Peach Bottom. Clinton depreciation provisions are based on an estimated useful life through 2027, which is the last year of the Illinois ZES. Peach Bottom depreciation provisions are based on estimated useful life of 2053 and 2054 for Unit 2 and Unit 3, respectively, which reflects the anticipated second renewal of its operating licenses. Beginning in 2017, TMI and Oyster Creek depreciation provisions were based on their 2019 expected shutdown dates. Beginning February 2018, Oyster Creek depreciation provisions were based on its announced shutdown date of September 2018. See Note 3 — Regulatory Matters for additional information regarding license renewals and the Illinois ZECs and Note 6 — Early Plant Retirements for additional information on the impacts of early plant retirements.

The following table presents the annual depreciation rates for each asset category. Nuclear fuel amortization is charged to fuel expense using the unit-of-production method and not included in the below table.

	Annual Depreciation Rates
	Exelon			Generation			ComEd			PECO			BGE			PHI			Pepco			DPL			ACE
December 31, 2019
Electric—transmission and distribution	2.80	%		N/A			2.99	%		2.36	%		2.60	%		2.77	%		2.47	%		2.86	%		2.94	%
Electric—generation	4.35	%		4.35	%		N/A			N/A			N/A			N/A			N/A			N/A			N/A
Gas—transportation and distribution	2.04	%		N/A			N/A			1.89	%		2.30	%		1.55	%		N/A			1.55	%		N/A
Common—electric and gas	7.37	%		N/A			N/A			6.06	%		8.30	%		8.25	%		N/A			6.24	%		N/A
December 31, 2018
Electric—transmission and distribution	2.73	%		N/A			2.95	%		2.35	%		2.61	%		2.61	%		2.40	%		2.77	%		2.45	%
Electric—generation	5.37	%		5.37	%		N/A			N/A			N/A			N/A			N/A			N/A			N/A
Gas—transportation and distribution	2.07	%		N/A			N/A			1.90	%		2.36	%		1.59	%		N/A			1.59	%		N/A
Common—electric and gas	6.98	%		N/A			N/A			5.44	%		8.50	%		6.30	%		N/A			3.70	%		N/A
December 31, 2017
Electric—transmission and distribution	2.75	%		N/A			2.99	%		2.37	%		2.58	%		2.63	%		2.35	%		2.75	%		2.46	%
Electric—generation	4.36	%		4.36	%		N/A			N/A			N/A			N/A			N/A			N/A			N/A
Gas—transportation and distribution	2.10	%		N/A			N/A			1.89	%		2.33	%		2.07	%		N/A			2.07	%		N/A
Common—electric and gas	7.05	%		N/A			N/A			5.47	%		8.64	%		6.50	%		N/A			4.14	%		N/A

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Capitalized Interest and AFUDC (All Registrants)

The following table summarizes capitalized interest and credits to AFUDC by year:

	Exelon				Generation				ComEd				PECO				BGE				PHI				Pepco				DPL				ACE
December 31, 2019
Capitalized interest	$	24			$	24			$	—			$	—			$	—			$	—			$	—			$	—			$	—
AFUDC debt and equity	132				—				32				17				29				54				39				6				9
December 31, 2018
Capitalized interest	$	31			$	31			$	—			$	—			$	—			$	—			$	—			$	—			$	—
AFUDC debt and equity	109				—				30				12				24				44				34				4				4
December 31, 2017
Capitalized interest	$	63			$	63			$	—			$	—			$	—			$	—			$	—			$	—			$	—
AFUDC debt and equity	108				—				20				12				22				54				34				10				9

See Note 1 — Significant Accounting Policies for additional information regarding property, plant and equipment policies. See Note 16 — Debt and Credit Agreements for additional information regarding Exelon’s, ComEd’s and PECO’s property, plant and equipment subject to mortgage liens.

Exelon's, Generation's, PECO's, DPL's and ACE's material undivided ownership interests in jointly owned electric plants and transmission facilities at December 31, 2019 and 2018 were as follows:

	Nuclear Generation																Transmission
	Quad Cities				Peach Bottom				Salem				Nine Mile Point Unit 2				NJ/DE(a)
Operator	Generation				Generation				PSEG Nuclear				Generation				PSEG/DPL
Ownership interest	75.00		%		50.00		%		42.59		%		82.00		%		various
Exelon’s share at December 31, 2019:
Plant in service	$	1,161			$	1,466			$	663			$	951			$	102
Accumulated depreciation	627				571				249				156				53
Construction work in progress	13				21				53				27				—
Exelon’s share at December 31, 2018:
Plant in service	$	1,131			$	1,451			$	648			$	910			$	103
Accumulated depreciation	587				523				227				126				53
Construction work in progress	13				15				44				56				—

__________

(a)	PECO, DPL and ACE own a 42.55%, 1% and 13.9% share, respectively in 151.3 miles of 500kV lines located in New Jersey and of the Salem generating plant substation. PECO, DPL and ACE also own a 42.55%, 7.45% and 7.45% share, respectively, in 2.5 miles of 500kV line located over the Delaware River. ACE also has a 21.78% share in a 500kV New Freedom Switching substation.

Exelon’s, Generation’s, PECO's, DPL's and ACE's undivided ownership interests are financed with their funds and all operations are accounted for as if such participating interests were wholly owned facilities. Exelon’s, Generation’s, PECO's, DPL's and ACE's share of direct expenses of the jointly owned plants are included in Purchased power and fuel and Operating and maintenance expenses in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income and in Operating and maintenance expenses in PECO's, PHI's, DPL's and ACE's Consolidated Statements of Operations and Comprehensive Income.

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Nuclear Decommissioning Asset Retirement Obligations (Exelon and Generation)

Generation has a legal obligation to decommission its nuclear power plants following the expiration of their operating licenses. To estimate its decommissioning obligation related to its nuclear generating stations for financial accounting and reporting purposes, Generation uses a probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models and discount rates. Generation updates its ARO annually unless circumstances warrant more frequent updates, based on its review of updated cost studies and its annual evaluation of cost escalation factors and probabilities assigned to various scenarios. Generation began decommissioning the TMI nuclear plant upon permanently ceasing operations in 2019. See below section for decommissioning of Zion Station.

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

The following table provides a rollforward of the nuclear decommissioning ARO reflected in Exelon’s and Generation’s Consolidated Balance Sheets, from January 1, 2018 to December 31, 2019:

Nuclear decommissioning ARO at January 1, 2018	$	9,662
Accretion expense	478
Net decrease due to changes in, and timing of, estimated future cash flows	(77		)
Costs incurred related to decommissioning plants	(58		)
Nuclear decommissioning ARO at December 31, 2018 (a) (b)	10,005
Net increase due to changes in, and timing of, estimated future cash flows	864
Sale of Oyster Creek	(755		)
Accretion Expense	479
Costs incurred related to decommissioning plants	(89		)
Nuclear decommissioning ARO at December 31, 2019 (a)	$	10,504

__________

(a)	Includes $112 million and $22 million as the current portion of the ARO at December 31, 2019 and 2018, respectively, which is included in Other current liabilities in Exelon’s and Generation’s Consolidated Balance Sheets.

(b)	Includes $772 million of ARO related to Oyster Creek which is classified as Liabilities held for sale in Exelon's and Generation's Consolidated Balance Sheets at December 31, 2018. See Note 2 — Mergers, Acquisitions and Dispositions for additional information.

The net $864 million increase in the ARO during 2019 for changes in the amounts and timing of estimated decommissioning cash flows was driven by multiple adjustments throughout the year, some with offsetting impacts. These adjustments primarily include:

•	An increase of approximately $780 million for changes in the assumed retirement timing probabilities for sites including certain economically challenged nuclear plants and the extension of Peach Bottom’s operating life; and

•	An increase of approximately $490 million for other impacts that included updated cost escalation rates, primarily for labor, equipment and materials, and current discount rates; partially offset by

•	Lower estimated costs to decommission TMI, Nine Mile Point, Ginna, Braidwood, Byron and LaSalle nuclear units of approximately $410 million resulting from the completion of updated cost studies.

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The 2019 ARO updates resulted in a decrease of $150 million in Operating and maintenance expense for the year ended December 31, 2019 within Exelon and Generation's Consolidated Statements of Operations and Comprehensive Income. See Note 6—Early Plant Retirements for additional information regarding TMI and economically challenged nuclear plants and Note 3 - Regulatory Matters regarding the Peach Bottom second license renewal.

The net $77 million decrease in the ARO during 2018 for changes in the amounts and timing of estimated decommissioning cash flows was driven by multiple adjustments throughout the year, some with offsetting impacts. These adjustments primarily include:

•

A decrease of approximately $205 million primarily due to lower estimated costs for the construction of interim spent fuel storage at TMI and a net decrease in estimated costs to decommission Calvert Cliffs, FitzPatrick, Limerick, and Salem nuclear units resulting from the completion of updated cost studies. There was also a decrease due to changes in decommissioning scenarios and their probabilities. These decreases were partially offset by

•	An increase of approximately $115 million for the impact of the early retirement and the announced pending sale of Oyster Creek which closed on July 1, 2019; and

•	An increase of approximately $120 million for estimated cost escalation rates, primarily for labor, energy and waste burial costs.

See Note 2 — Mergers, Acquisitions and Dispositions and Note 6—Early Plant Retirements for additional information regarding Oyster Creek.

NDT Funds

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

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

Any shortfall of funds necessary for decommissioning, determined for each generating station unit, is ultimately required to be funded by Generation, with the exception of a shortfall for the current decommissioning activities at Zion Station, where certain decommissioning activities have been transferred to a third-party (see Zion Station Decommissioning below) and the CENG units, where any shortfall is required to be funded by both Generation and EDF. Generation, through PECO, has recourse to collect additional amounts from PECO customers related to a shortfall of NDT funds for the former PECO units, subject to certain limitations and thresholds, as prescribed by an order from the PAPUC. Generally, PECO, and likewise Generation will not be allowed to collect amounts associated with the first $50 million of any shortfall of trust funds compared to decommissioning costs, as well as 5% of any additional shortfalls, on an aggregate basis for all former PECO units. The initial $50 million and up to 5% of any additional shortfalls would be borne by Generation. No recourse exists to collect additional amounts from utility customers for any of Generation's other nuclear units. With respect to the former ComEd and PECO units, any funds remaining in the NDTs after all decommissioning has been completed are required to be refunded to ComEd’s or PECO’s customers, subject to certain limitations that allow sharing of excess funds with Generation related to the former PECO units. With respect to Generation's other nuclear units, Generation retains any funds remaining after decommissioning. However, in connection with CENG's acquisition of the Nine Mile Point and Ginna plants

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and settlements with certain regulatory agencies, CENG is subject to certain conditions pertaining to NDT funds that, if met, could possibly result in obligations to make payments to certain third parties (clawbacks). For Nine Mile Point and Ginna, the clawback provisions are triggered only in the event that the required decommissioning activities are discontinued or not started or completed in a timely manner. In the event that the clawback provisions are triggered for Nine Mile Point, then, depending upon the triggering event, an amount equal to 50% of the total amount withdrawn from the funds for non-decommissioning activities or 50% of any excess funds in the trust funds above the amounts required for decommissioning (including spent fuel management and decommissioning) is to be paid to the Nine Mile Point sellers. In the event that the clawback provisions are triggered for Ginna, then an amount equal to any estimated cost savings realized by not completing any of the required decommissioning activities is to be paid to the Ginna sellers. Generation expects to comply with applicable regulations and timely commence and complete all required decommissioning activities.

At December 31, 2019 and 2018, Exelon and Generation had NDT funds totaling $13,353 million and $12,695 million, respectively. The NDT funds included $890 million at December 31, 2018, related to Oyster Creek NDT funds which were classified as Assets held for sale in Exelon's and Generation's Consolidated Balance Sheets. See Note 2 — Mergers, Acquisitions and Dispositions for additional information. The NDT funds include $163 million and $144 million for the current portion of the NDT at December 31, 2019 and 2018, respectively, which are included in Other current assets in Exelon's and Generation's Consolidated Balance Sheets. See Note 23 — Supplemental Financial Information for additional information on activities of the NDT funds.

Accounting Implications of the Regulatory Agreements with ComEd and PECO

Based on the regulatory agreements with the ICC and PAPUC that dictate Generation’s obligations related to the shortfall or excess of NDT funds necessary for decommissioning the former ComEd units on a unit-by-unit basis and the former PECO units in total, decommissioning-related activities net of applicable taxes, including realized and unrealized gains and losses on the NDT funds and accretion of the decommissioning obligation, are generally offset within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. For the former ComEd units, decommissioning-related activities are generally offset within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income as long as the NDT funds are expected to exceed the total estimated decommissioning obligation. For the former PECO units, decommissioning-related activities are generally offset within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income regardless of whether the NDT funds are expected to exceed or fall short of the total estimated decommissioning obligation. The offset of decommissioning-related activities within the Consolidated Statement of Operations and Comprehensive Income results in an equal adjustment to the noncurrent payables to affiliates at Generation. ComEd and PECO have recorded an equal noncurrent affiliate receivable from Generation and corresponding regulatory liability.

Should the expected value of the NDT fund for any former ComEd unit fall below the amount of the expected decommissioning obligation for that unit, the accounting to offset decommissioning-related activities in the Consolidated Statement of Operations and Comprehensive Income for that unit would be discontinued, the decommissioning-related activities would be recognized in the Consolidated Statements of Operations and Comprehensive Income and the adverse impact to Exelon’s and Generation’s financial statements could be material. As of December 31, 2019, the NDT funds of each of the former ComEd units, except for Zion (see Zion Station Decommissioning below), are expected to exceed the related decommissioning obligation for each of the units. For the purposes of making this determination, the decommissioning obligation referred to is different, as described below, from the calculation used in the NRC minimum funding obligation filings based on NRC guidelines.

Any changes to the PECO regulatory agreements could impact Exelon’s and Generation’s ability to offset decommissioning-related activities within the Consolidated Statement of Operations and Comprehensive Income, and the impact to Exelon’s and Generation’s financial statements could be material.

The decommissioning-related activities related to the Non-Regulatory Agreement Units are reflected in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

See Note 3 — Regulatory Matters and Note 24 — Related Party Transactions for additional information regarding regulatory liabilities at ComEd and PECO and intercompany balances between Generation, ComEd and PECO reflecting the obligation to refund to customers any decommissioning-related assets in excess of the related decommissioning obligations.

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Zion Station Decommissioning

In 2010, Generation completed an Asset Sale Agreement (ASA) under which ZionSolutions assumed responsibility for decommissioning Zion Station and Generation transferred to ZionSolutions substantially all the Zion Station’s assets, including the related NDT funds. To reduce the risk of default by ZionSolutions, EnergySolutions has provided a $25 million letter of credit to be used to fund decommissioning costs in the event the NDT assets are insufficient. EnergySolutions and its parent company have also provided a performance guarantee.

Following ZionSolutions' completion of its contractual obligations and transfer of the NRC license to Generation, Generation will store the SNF at Zion Station until it is transferred to the DOE for ultimate disposal, and will complete all remaining decommissioning activities associated with the SNF dry storage facility.

Generation had retained its obligation for the SNF as well as certain NDT assets to fund its obligation to maintain the SNF at Zion Station until transfer to the DOE and to complete all remaining decommissioning activities for the SNF storage facility. Any shortage of funds necessary to maintain the SNF and decommission the SNF storage facility is ultimately required to be funded by Generation. Any Zion Station NDT funds remaining after the completion of all decommissioning activities will be returned to ComEd customers in accordance with the applicable orders.

NRC Minimum Funding Requirements

NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts to decommission the facility at the end of its life. The estimated decommissioning obligations as calculated using the NRC methodology differ from the ARO recorded in Generation’s and Exelon’s Consolidated Balance Sheets primarily due to differences in the type of costs included in the estimates, the basis for estimating such costs, and assumptions regarding the decommissioning alternatives to be used, potential license renewals, decommissioning cost escalation, and the growth rate in the NDT funds. Under NRC regulations, if the minimum funding requirements calculated under the NRC methodology are less than the future value of the NDT funds, also calculated under the NRC methodology, then the NRC requires either further funding or other financial guarantees.

Key assumptions used in the minimum funding calculation using the NRC methodology at December 31, 2019 include: (1) consideration of costs only for the removal of radiological contamination at each unit; (2) the option on a unit-by-unit basis to use generic, non-site specific cost estimates; (3) consideration of only one decommissioning scenario for each unit; (4) the plants cease operation at the end of their current license lives (with no assumed license renewals for those units that have not already received renewals); (5) the assumption of current nominal dollar cost estimates that are neither escalated through the anticipated period of decommissioning, nor discounted using the CARFR; and (6) assumed annual after-tax returns on the NDT funds of 2% (3% for the former PECO units, as specified by the PAPUC).

In contrast, the key criteria and assumptions used by Generation to determine the ARO and to forecast the target growth in the NDT funds at December 31, 2019 include: (1) the use of site specific cost estimates that are updated at least once every five years; (2) the inclusion in the ARO estimate of all legally unavoidable costs required to decommission the unit (e.g., radiological decommissioning and full site restoration for certain units, on-site spent fuel maintenance and storage subsequent to ceasing operations and until DOE acceptance, and disposal of certain low-level radioactive waste); (3) the consideration of multiple scenarios where decommissioning and site restoration activities, as applicable, are completed under possible scenarios ranging from 10 to 70 years after the cessation of plant operations; (4) the consideration of multiple end of life scenarios; (5) the measurement of the obligation at the present value of the future estimated costs and an annual average accretion of the ARO of approximately 5% through a period of approximately 30 years after the end of the extended lives of the units; and (6) an estimated targeted annual pre-tax return on the NDT funds of 5.4% to 6.5% (as compared to a historical 5-year annual average pre-tax return of approximately 6.7%).

Generation is required to provide to the NRC a biennial report by unit (annually for units that have been retired or are within five years of the current approved license life), based on values as of December 31, addressing Generation’s ability to meet the NRC minimum funding levels. Depending on the value of the trust funds, Generation may be required to take steps, such as providing financial guarantees through letters of credit or parent company guarantees or making additional contributions to the trusts, which could be significant, to ensure that the trusts are adequately funded and that NRC minimum funding requirements are met. As a result, Exelon’s and Generation’s cash flows and financial positions may be significantly adversely affected.

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Generation filed its biennial decommissioning funding status report with the NRC on April 1, 2019 for all units except for Zion Station which is included in a separate report to the NRC submitted by ZionSolutions, LLC. The status report demonstrated adequate decommissioning funding assurance as of December 31, 2018 for all units except for Clinton and Peach Bottom Unit 1. As of February 28, 2019, Clinton demonstrated adequate minimum funding assurance due to market recovery and no further action is required. This demonstration was also included in the April 1, 2019 submittal. As a former PECO plant, financial assurance for decommissioning Peach Bottom Unit 1 is provided by the NDT fund, collections from PECO ratepayers and the ability to adjust those collections in accordance with the approved PAPUC tariff. No additional actions are required aside from the PAPUC filing in accordance with the tariff. See NDT Funds section above for additional information.

Generation will file its next annual decommissioning funding status report with the NRC by March 31, 2020 for shutdown reactors, reactors within five years of shutdown except for Zion Station which is included in a separate report to the NRC submitted by EnergySolutions (see Zion Station Decommissioning above). This report will reflect the status of decommissioning funding assurance as of December 31, 2019 and will include an update for the retirement of TMI in 2019. A shortfall at any unit could necessitate that Exelon post a parental guarantee for Generation's share of the funding assurance. However, the amount of any required guarantee will ultimately depend on the decommissioning approach adopted, the associated level of costs, and the decommissioning trust fund investment performance going forward.

As the future values of trust funds change due to market conditions, the NRC minimum funding status of Generation’s units will change. In addition, if changes occur to the regulatory agreement with the PAPUC that currently allows amounts to be collected from PECO customers for decommissioning the former PECO units, the NRC minimum funding status of those plants could change at subsequent NRC filing dates.

Non-Nuclear Asset Retirement Obligations (All Registrants)

Generation has AROs for plant closure costs associated with its fossil and renewable generating facilities, including asbestos abatement, removal of certain storage tanks, restoring leased land to the condition it was in prior to construction of renewable generating stations and other decommissioning-related activities. The Utility Registrants have AROs primarily associated with the abatement and disposal of equipment and buildings contaminated with asbestos and PCBs. See Note 1 — Significant Accounting Policies for additional information on the Registrants’ accounting policy for AROs. 

The following table provides a rollforward of the non-nuclear AROs reflected in the Registrants’ Consolidated Balance Sheets from January 1, 2018 to December 31, 2019:

	Exelon				Generation				ComEd				PECO				BGE				PHI				Pepco				DPL				ACE
Non-nuclear AROs at January 1, 2018	$	384			$	197			$	113			$	27			$	24			$	16			$	3			$	10			$	3
Net increase due to changes in, and timing of, estimated future cash flows(a)	80				35				7				—				2				36				34				1				1
Accretion expense(b)	16				10				4				1				1				—				—				—				—
Asset divestitures	(3		)		(3		)		—				—				—				—				—				—				—
Payments	(6		)		(1		)		(3		)		—				(2		)		—				—				—				—
Non-nuclear AROs at December 31, 2018	471				238				121				28				25				52				37				11				4
Net (decrease) increase due to changes in, and timing of, estimated future cash flows	17				7				8				—				(2		)		4				3				1				—
Development projects	2				2				—				—				—				—				—				—				—
Accretion expense(b)	16				12				1				1				1				1				1				—				—
Asset divestitures	(42		)		(42		)		—				—				—				—				—				—				—
Payments	(4		)		(1		)		(1		)		(1		)		(1		)		—				—				—				—
Non-nuclear AROs at December 31, 2019	$	460			$	216			$	129			$	28			$	23			$	57			$	41			$	12			$	4

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__________

(a)	In 2018, Pepco recorded an increase of $22 million in Operating and maintenance expense primarily related to asbestos identified at its Buzzard Point property as part of an annual ARO study. Buzzard Point is a waterfront property in the District of Columbia occupied by an active substation and former Pepco operated steam plant building, which Pepco retired and closed in 1981.

(b)	For ComEd and PECO, the majority of the accretion is recorded as an increase to a regulatory asset due to the associated regulatory treatment.

Lessee

The Registrants have operating leases for which they are the lessees. The following tables outline the significant types of operating lease at each registrant and other terms and conditions of the lease agreements. The Registrants do not have material finance leases.

Exelon

Generation

ComEd

PECO

BGE

PHI

Pepco

DPL

ACE

Contracted generation

●

●

Real estate

●

●

●

●

●

●

●

●

●

Vehicles and equipment

●

●

●

●

●

●

●

●

●

(in years)	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Remaining lease terms	1-86		1-36		1-5		1-14		1-86		1-12		1-12		1-12		1-6
Options to extend the term	3-30		3-30		5		N/A		N/A		3-30		5		3-30		N/A
Options to terminate within	1-13		1		3		N/A		2		N/A		N/A		N/A		N/A

The components of lease costs for the year ended December 31, 2019 were as follows:

	Exelon				Generation				ComEd				PECO				BGE				PHI				Pepco				DPL				ACE
Operating lease costs	$	320			$	222			$	3			$	1			$	33			$	48			$	12			$	14			$	7
Variable lease costs	300				282				2				—				2				6				2				2				1
Short-term lease costs	19				19				—				—				—				—				—				—				—
Total lease costs (a)	$	639			$	523			$	5			$	1			$	35			$	54			$	14			$	16			$	8

__________

(a)	Excludes $51 million, $44 million, $7 million and $7 million of sublease income recorded at Exelon, Generation, PHI and DPL.

The following table presents the Registrants' rental expense under the prior lease accounting guidance for the years ended December 31, 2018 and 2017:

	Exelon				Generation(a)				ComEd				PECO				BGE				PHI				Pepco				DPL				ACE
2018	$	670			$	558			$	7			$	10			$	35			$	48			$	10			$	13			$	8
2017	709				578				9				9				32				63				11				16				14

__________

(a)	Includes contingent operating lease payments associated with contracted generation agreements that are not included in the minimum future operating lease payments above. Payments made under Generation's contracted generation lease agreements totaled $493 million and $508 million during 2018 and 2017, respectively.

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The following table provides additional information regarding the presentation of operating ROU assets and lease liabilities within the Registrants’ Consolidated Balance Sheets as of December 31, 2019:

	Exelon(a)				Generation(a)				ComEd				PECO				BGE				PHI				Pepco				DPL				ACE
Operating lease ROU assets
Other deferred debits and other assets	$	1,305			$	895			$	9			$	2			$	77			$	273			$	56			$	63			$	18
Operating lease liabilities
Other current liabilities	225				157				3				—				32				31				6				9				4
Other deferred credits and other liabilities	1,307				925				8				1				50				254				51				65				14
Total operating lease liabilities	$	1,532			$	1,082			$	11			$	1			$	82			$	285			$	57			$	74			$	18

__________

(a)	Exelon's and Generation's operating ROU assets and lease liabilities include $515 million and $664 million, respectively, related to contracted generation.

The weighted average remaining lease terms, in years, and discount rates for operating leases as of December 31, 2019 were as follows:

	Exelon			Generation			ComEd			PECO			BGE			PHI			Pepco			DPL			ACE
Remaining lease term	10.1			10.6			4.6			4.4			5.4			9.0			9.8			9.7			4.7
Discount rate	4.6	%		4.8	%		3.0	%		3.2	%		3.6	%		4.2	%		4.0	%		4.0	%		3.6	%

Future minimum lease payments for operating leases as of December 31, 2019 were as follows:

Year	Exelon				Generation				ComEd				PECO				BGE				PHI				Pepco				DPL				ACE
2020	$	287			$	203			$	3			$	—			$	34			$	42			$	8			$	11			$	5
2021	243				162				4				1				31				41				8				11				4
2022	177				113				2				—				16				38				8				10				4
2023	145				100				1				—				1				37				7				9				3
2024	140				97				1				—				—				35				5				9				2
Remaining years	976				741				1				—				18				153				34				41				2
Total	1,968				1,416				12				1				100				346				70				91				20
Interest	436				334				1				—				18				61				13				17				2
Total operating lease liabilities	$	1,532			$	1,082			$	11			$	1			$	82			$	285			$	57			$	74			$	18

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Future minimum lease payments for operating leases under the prior lease accounting guidance as of December 31, 2018 were as follows:

	Exelon(a)(b)				Generation(a)(b)				ComEd(a)(c)				PECO(a)(c)				BGE(a)(c)(d)(e)				PHI(a)				Pepco(a)				DPL(a)(c)				ACE(a)
2019	$	140			$	33			$	7			$	5			$	35			$	48			$	11			$	14			$	7
2020	149				46				5				5				35				46				10				13				6
2021	143				46				4				5				33				43				9				12				5
2022	126				47				4				5				18				42				8				12				5
2023	97				46				3				5				3				39				8				10				4
Remaining years	723				545				—				—				19				159				40				35				5
Total minimum future lease payments	$	1,378			$	763			$	23			$	25			$	143			$	377			$	86			$	96			$	32

__________

(a)	Includes amounts related to shared use land arrangements.

(b)	Excludes Generation’s contingent operating lease payments associated with contracted generation.

(c)

Amounts related to certain real estate leases and railroad licenses effectively have indefinite payment periods. As a result, ComEd, PECO, BGE and DPL have excluded these payments from the remaining years as such amounts would not be meaningful. ComEd's, PECO’s, BGE’s and DPL's average annual obligation for these arrangements, included in each of the years 2019 - 2023, was $3 million, $5 million, $1 million and $1 million respectively. Also includes amounts related to shared use land arrangements.

(d)	Includes all future lease payments on a 99-year real estate lease that expires in 2106.

(e)	The BGE column above includes minimum future lease payments associated with a 6-year lease for the Baltimore City conduit system that became effective during the fourth quarter of 2016. BGE's total commitments under the lease agreement are $26 million, $28 million, $28 million and $14 million related to years 2019 - 2022, respectively.

Cash paid for amounts included in the measurement of lease liabilities for the year ended December 31, 2019 were as follows:

	Exelon				Generation				ComEd				PECO				BGE				PHI				Pepco				DPL				ACE
Operating cash flows from operating leases	$	287			$	206			$	3			$	—			$	33			$	37			$	9			$	6			$	5

ROU assets obtained in exchange for lease obligations for the year ended December 31, 2019 were as follows:

	Exelon				Generation				ComEd				PECO				BGE				PHI				Pepco				DPL				ACE
Operating leases	$	52			$	14			$	6			$	—			$	2			$	(3	)		$	(1	)		$	(2	)		$	(1	)

Lessor

The Registrants have operating leases for which they are the lessors. The following tables outline the significant types of leases at each registrant and other terms and conditions of their lease agreements.

Exelon

Generation

ComEd

PECO

BGE

PHI

Pepco

DPL

ACE

Contracted generation

●

●

Real estate

●

●

●

●

●

●

●

●

●

(in years)	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Remaining lease terms	1-83		1-32		1-17		1-83		23		1-13		1-6		12-13		1-2
Options to extend the term	1-79		1-5		5-79		5-50		N/A		5		N/A		N/A		N/A

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The components of lease income for the year ended December 31, 2019 were as follows:

	Exelon				Generation				ComEd				PECO				BGE				PHI				Pepco				DPL				ACE
Operating lease income	$	54			$	47			$	—			$	—			$	—			$	5			$	—			$	4			$	—
Variable lease income	$	261			$	258			$	—			$	—			$	—			$	3			$	—			$	3			$	—

Future minimum lease payments to be recovered under operating leases as of December 31, 2019 were as follows:

Year	Exelon				Generation				ComEd				PECO				BGE				PHI				Pepco				DPL				ACE
2020	$	51			$	46			$	—			$	—			$	—			$	4			$	—			$	3			$	—
2021	51				45				—				—				—				4				1				3				—
2022	50				45				—				—				—				4				—				3				—
2023	49				44				—				—				—				5				—				4				—
2024	48				44				—				—				—				4				—				4				—
Remaining years	265				226				1				3				1				34				—				34				—
Total	$	514			$	450			$	1			$	3			$	1			$	55			$	1			$	51			$	—

The Registrants evaluate the carrying value of long-lived assets or asset groups for recoverability whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators of impairment may include a deteriorating business climate, including, but not limited to, declines in energy prices, condition of the asset, specific regulatory disallowance, or plans to dispose of a long-lived asset significantly before the end of its useful life. The Registrants determine if long-lived assets or asset groups are impaired by comparing the undiscounted expected future cash flows to the carrying value. When the undiscounted cash flow analysis indicates a long-lived asset or asset group is not recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. The fair value analysis is primarily based on the income approach using significant unobservable inputs (Level 3) including revenue and generation forecasts, projected capital and maintenance expenditures and discount rates. A variation in the assumptions used could lead to a different conclusion regarding the recoverability of an asset or asset group and, thus, could potentially result in material future impairments of the Registrant's long-lived assets.

Equity Method Investments in Certain Distributed Energy Companies (Exelon and Generation)

In the third quarter of 2019, Generation’s equity method investments in certain distributed energy companies were fully impaired due to an other-than-temporary decline in market conditions and underperforming projects. Exelon and Generation recorded a pre-tax impairment charge of $164 million in Equity in losses of unconsolidated affiliates and an offsetting pre-tax $96 million in Net income attributable to noncontrolling interests in their Consolidated Statements of Operations and Comprehensive Income. As a result, Generation accelerated the amortization of investment tax credits associated with these companies and Exelon and Generation recorded a benefit of $46 million in Income taxes. The impairment charge and the accelerated amortization of investment tax credits resulted in a net $15 million decrease to Exelon’s and Generation’s earnings. See Note 22 — Variable Interest Entities for additional information.

Antelope Valley Solar Facility (Exelon and Generation)

Generation’s Antelope Valley, a 242 MW solar facility in Lancaster, CA, sells all of its output to PG&E through a PPA. As of December 31, 2019, Generation had approximately $725 million of net long-lived assets related to Antelope Valley. As a result of the PG&E bankruptcy filing in the first quarter of 2019, Generation completed a comprehensive review of Antelope Valley's estimated undiscounted future cash flows and no impairment charge was recorded. Significant changes in assumptions such as the likelihood of the PPA being rejected as part of the bankruptcy proceedings could potentially result in future impairments of Antelope Valley’s net long-lived assets, which could be material.

Antelope Valley is a wholly owned indirect subsidiary of EGR IV, which had approximately $1,893 million of additional net long-lived assets as of December 31, 2019. EGR IV is a wholly owned indirect subsidiary of Exelon and Generation and includes Generation's interest in EGRP and other projects with non-controlling interests. To date, there have been no indicators to suggest that the carrying amount of other net long-lived assets of EGR IV may not be recoverable.

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

See Note 16 — Debt and Credit Agreements for additional information on the PG&E bankruptcy.

New England Asset Group (Exelon and Generation)

During the first quarter of 2018, Mystic Unit 9 did not clear in the ISO-NE capacity auction for the 2021 - 2022 planning year. On March 29, 2018, Generation notified ISO-NE of the early retirement of its Mystic Generating Station's Units 7, 8, 9 and the Mystic Jet Unit (Mystic Generating Station assets) absent regulatory reforms. These events suggested that the carrying value of its New England asset group may be impaired. Generation completed a comprehensive review of the estimated undiscounted future cash flows of the New England asset group and no impairment charge was required. Further developments such as the failure of ISO-NE to adopt long-term solutions for reliability and fuel security could potentially result in material future impairments of the New England asset group. See Note 6 — Early Plant Retirements for additional information.

District of Columbia Sponsorship (Exelon and PHI)

In the third quarter of 2015, PHI entered into a sponsorship agreement with the District of Columbia for future sponsorship rights associated with public property within the District of Columbia, which Exelon and PHI had recorded as a finite-lived intangible asset as of December 31, 2016. The specific sponsorship rights were to be determined through future negotiations. In the fourth quarter of 2017, based upon the lack of available sponsorship opportunities at that time, the asset was written off and a pre-tax impairment charge of $25 million was recorded within Operating and maintenance expense in Exelon’s and PHI's Consolidated Statements of Operations and Comprehensive Income.

ExGen Texas Power (Exelon and Generation)

On May 2, 2017, EGTP entered into a consent agreement with its lenders to initiate the sale of the assets of its wholly owned subsidiaries. As a result, Exelon and Generation classified certain of EGTP's assets and liabilities as held for sale at their respective fair values less costs to sell and recorded a pre-tax impairment charge in 2017 of $460 million within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income. On November 7, 2017, EGTP and its wholly owned subsidiaries filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Code in the United States Bankruptcy Court for the District of Delaware and, as a result, Exelon and Generation deconsolidated EGTP's assets and liabilities from their consolidated financial statements. See Note 2 — Mergers, Acquisitions and Dispositions for additional information.

Goodwill

The following table presents the gross amount of goodwill, accumulated impairment loss and carrying amount of goodwill of Exelon, ComEd and PHI as of December 31, 2019 and 2018. There were no additions, impairments or measurement period adjustments during the years ended December 31, 2019 and 2018.

	Gross amount				Accumulated impairment loss				Carrying amount
Exelon	$	8,660			$	1,983			$	6,677
ComEd(a)	4,608				1,983				2,625
PHI(b)	4,005				—				4,005

__________

(a)	Reflects goodwill recorded in 2000 from the PECO/Unicom merger (predecessor parent company of ComEd).

(b)	Reflects goodwill recorded in 2016 from the PHI merger.

Goodwill is not amortized, but is subject to an assessment for impairment at least annually, or more frequently if events occur or circumstances change that would more likely than not reduce the fair value of ComEd's and PHI's reporting units below their carrying amounts. A reporting unit is an operating segment or one level below an operating segment (known as a component) and is the level at which goodwill is tested for impairment. A component of an operating segment is a reporting unit if the component constitutes a business for which discrete financial information is available and its operating results are regularly reviewed by segment management. ComEd has a single operating segment. PHI's operating segments are Pepco, DPL and ACE. See Note 5 — Segment Information for additional information. There is no level below these operating segments for which operating results are regularly reviewed by segment management. Therefore, the ComEd, Pepco, DPL and ACE operating segments are also considered reporting units for goodwill impairment testing purposes. Exelon's and ComEd's $2.6 billion of goodwill has been assigned entirely to the ComEd reporting unit, while Exelon's and PHI's $4.0 billion of goodwill has been assigned to the Pepco, DPL and ACE reporting units in the amounts of $2.1 billion, $1.4 billion and $0.5 billion, respectively.

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

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performed. If an entity bypasses the qualitative assessment, a quantitative two-step, fair value-based test is performed. The first step compares the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, the second step is performed. The second step requires an allocation of fair value to the individual assets and liabilities using purchase price allocation authoritative guidance in order to determine the implied fair value of goodwill.

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

2019 and 2018 Goodwill Impairment Assessment. ComEd and PHI qualitatively determined that it was more likely than not that the fair values of their reporting units exceeded their carrying values and, therefore, did not perform quantitative assessments as of November 1, 2019 and 2018 for ComEd and as of November 1, 2019 for PHI. The last quantitative assessments performed were as of November 1, 2016 for ComEd and November 1, 2018 for PHI.

PHI performed a quantitative test for its 2018 annual goodwill impairment assessment as of November 1, 2018. The first step of the test comparing the estimated fair values of the Pepco, DPL and ACE reporting units to their carrying values, including goodwill, indicated no impairments of goodwill; therefore, no second step was required.

While the annual assessments indicated no impairments, certain assumptions used to estimate reporting unit fair values are highly sensitive to changes. Adverse regulatory actions or changes in significant assumptions could potentially result in future impairments of Exelon's, ComEd's and PHI’s goodwill, which could be material. Based on the results of the last quantitative goodwill test performed, the estimated fair values of the ComEd, Pepco, DPL and ACE reporting units would have needed to decrease by more than 30%, 30%, 20% and 30%, respectively, for ComEd and PHI to fail the first step of their respective impairment tests.

Other Intangible Assets and Liabilities

Exelon’s, Generation’s, ComEd’s and PHI's other intangible assets and liabilities, included in Unamortized energy contract assets and liabilities and Other deferred debits and other assets in their Consolidated Balance Sheets, consisted of the following as of December 31, 2019 and 2018. The intangible assets and liabilities shown below are amortized on a straight line basis, except for unamortized energy contracts which are amortized in relation to the expected realization of the underlying cash flows:

		December 31, 2019												December 31, 2018
		Gross				Accumulated Amortization				Net				Gross				Accumulated Amortization				Net
Generation
Unamortized Energy Contracts		1,967				(1,612		)		355				1,957				(1,588		)		369
Customer Relationships		343				(190		)		153				325				(162		)		163
Trade Name		243				(193		)		50				243				(171		)		72
ComEd
Chicago Settlement Agreements		162				(155		)		7				162				(148		)		14
PHI
Unamortized Energy Contracts		(1,515		)		1,073				(442		)		(1,515		)		954				(561		)
Exelon Corporate
Software License		95				(44		)		51				95				(34		)		61
Exelon		$	1,295			$	(1,121	)		$	174			$	1,267			$	(1,149	)		$	118

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The following table summarizes the amortization expense related to intangible assets and liabilities for each of the years ended December 31, 2019, 2018 and 2017:

For the Years Ended December 31,		Exelon (a)(b)				Generation (a)				ComEd				PHI(b)
2019		$	(28	)		$	74			$	7			$	(119	)
2018		(109		)		63				7				(188		)
2017		(237		)		83				7				(336		)

__________

(a)	At Exelon and Generation, amortization of unamortized energy contracts totaling $21 million, $14 million and $35 million for the years ended December 31, 2019, 2018 and 2017, respectively, was recorded in Operating revenues or Purchased power and fuel expense in their Consolidated Statements of Operations and Comprehensive Income.

(b)	At Exelon and PHI, amortization of the unamortized energy contract fair value adjustment amounts and the corresponding offsetting regulatory asset and liability amounts are amortized through Purchased power and fuel expense in their Consolidated Statements of Operations and Comprehensive Income.

The following table summarizes the estimated future amortization expense related to intangible assets and liabilities as of December 31, 2019:

For the Years Ending December 31,		Exelon				Generation				ComEd				PHI
2020		$	(13	)		$	85			$	7			$	(115	)
2021		2				84				—				(92		)
2022		(21		)		58				—				(89		)
2023		(18		)		53				—				(81		)
2024		22				50				—				(38		)

Renewable Energy Credits (Exelon and Generation)

Exelon’s and Generation’s RECs are included in Other current assets and Other deferred debits and other assets in the Consolidated Balance Sheets. Purchased RECs are recorded at cost on the date they are purchased. The cost of RECs purchased on a stand-alone basis is based on the transaction price, while the cost of RECs acquired through PPAs represents the difference between the total contract price and the market price of energy at contract inception. Generally, revenue for RECs that are sold to a counterparty under a contract that specifically identifies a power plant is recognized at a point in time when the power is produced. This includes both bundled and unbundled REC sales. Otherwise, the revenue is recognized upon physical transfer of the REC to the customer.

The following table presents the current and noncurrent Renewable Energy Credits as of December 31, 2019 and 2018:

	As of December 31, 2019						As of December 31, 2018
	Exelon			Generation			Exelon			Generation
Current REC's	345			336			279			270
Noncurrent REC's	86			86			52			52

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Components of Income Tax Expense or Benefit

Income tax expense (benefit) from continuing operations is comprised of the following components:

	For the Year Ended December 31, 2019
	Exelon				Generation				ComEd				PECO				BGE				PHI				Pepco				DPL				ACE
Included in operations:
Federal
Current	$	85			$	147			$	59			$	45			$	(51	)		$	43			$	16			$	29			$	(3	)
Deferred	489				346				15				20				95				(34		)		(6		)		(21		)		(6		)
Investment tax credit amortization	(72		)		(69		)		(2		)		—				—				(1		)		—				—				—
State
Current	5				10				(5		)		—				—				3				—				—				—
Deferred	267				82				96				—				35				27				6				14				9
Total	$	774			$	516			$	163			$	65			$	79			$	38			$	16			$	22			$	—

	For the Year Ended December 31, 2018
	Exelon				Generation				ComEd				PECO				BGE				PHI				Pepco				DPL				ACE
Included in operations:
Federal
Current	$	226			$	337			$	(63	)		$	11			$	(5	)		$	(4	)		$	28			$	(3	)		$	(14	)
Deferred	(99		)		(347		)		145				10				47				23				(22		)		13				18
Investment tax credit amortization	(24		)		(21		)		(2		)		—				—				(1		)		—				—				—
State
Current	(1		)		6				(29		)		1				—				7				—				—				—
Deferred	16				(83		)		117				(16		)		32				8				5				12				8
Total	$	118			$	(108	)		$	168			$	6			$	74			$	33			$	11			$	22			$	12

	For the Year Ended December 31, 2017
	Exelon				Generation				ComEd				PECO				BGE				PHI				Pepco				DPL				ACE
Included in operations:
Federal
Current	$	194			$	584			$	(191	)		$	71			$	74			$	(60	)		$	(20	)		$	(24	)		$	(12	)
Deferred	(470		)		(2,005		)		523				28				101				251				115				82				34
Investment tax credit amortization	(25		)		(21		)		(2		)		—				(1		)		(1		)		—				—				—
State
Current	14				65				(49		)		14				(5		)		(4		)		(2		)		—				—
Deferred	161				1				136				(9		)		49				31				12				13				4
Total	$	(126	)		$	(1,376	)		$	417			$	104			$	218			$	217			$	105			$	71			$	26

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Rate Reconciliation

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

	For the Year Ended December 31, 2019
	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	5.4			3.8			8.5			—			6.4			4.7			2.0			6.8			7.0
Qualified NDT fund income	5.9			12.3			—			—			—			—			—			—			—
Amortization of investment tax credit, including deferred taxes on basis difference	(1.5	)		(3.0	)		(0.2	)		—			(0.1	)		(0.2	)		(0.1	)		(0.2	)		(0.3	)
Plant basis differences	(1.4	)		—			—			(7.2	)		(1.2	)		(1.2	)		(1.8	)		(0.4	)		(0.7	)
Production tax credits and other credits	(3.1	)		(4.8	)		(1.2	)		—			(1.3	)		(0.2	)		(0.1	)		—			(0.1	)
Noncontrolling interests	(0.6	)		(1.2	)		—			—			—			—			—			—			—
Excess deferred tax amortization	(5.5	)		—			(9.7	)		(2.8	)		(6.8	)		(17.5	)		(15.1	)		(14.2	)		(27.0	)
Other	(0.8	)		(1.2	)		0.8			—			—			0.8			0.3			—			0.1
Effective income tax rate	19.4	%		26.9	%		19.2	%		11.0	%		18.0	%		7.4	%		6.2	%		13.0	%		—	%

	For the Year Ended December 31, 2018
	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	0.5			(16.6	)		8.3			(2.6	)		6.6			2.9			2.0			6.7			7.4
Qualified NDT fund income	(1.9	)		(11.8	)		—			—			—			—			—			—			—
Amortization of investment tax credit, including deferred taxes on basis difference	(1.2	)		(6.5	)		(0.2	)		(0.1	)		(0.1	)		(0.2	)		(0.1	)		(0.3	)		(0.4	)
Plant basis differences	(3.5	)		—			(0.2	)		(14.1	)		(1.3	)		(1.6	)		(2.8	)		(0.3	)		(0.5	)
Production tax credits and other credits	(2.2	)		(13.5	)		—			—			—			—			—			—			—
Noncontrolling interests	(1.0	)		(6.1	)		—			—			—			—			—			—			—
Excess deferred tax amortization	(8.3	)		—			(9.1	)		(3.2	)		(8.0	)		(14.8	)		(15.3	)		(12.0	)		(14.9	)
Tax Cuts and Jobs Act of 2017	0.9			2.7			(0.1	)		—			—			0.1			—			—			—
Other	1.0			1.3			0.5			0.3			0.9			0.4			0.3			0.4			1.2
Effective income tax rate	5.3	%		(29.5	)%		20.2	%		1.3	%		19.1	%		7.8	%		5.1	%		15.5	%		13.8	%

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	For the Year Ended December 31, 2017
	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			2.9			5.7			0.6			5.4			4.8			3.1			5.4			5.6
Qualified NDT fund income	3.8			9.9			—			—			—			—			—			—			—
Amortization of investment tax credit, including deferred taxes on basis difference	(0.9	)		(2.1	)		(0.2	)		(0.1	)		(0.1	)		(0.2	)		(0.1	)		(0.2	)		(0.4	)
Plant basis differences(a)	(1.7	)		—			0.3			(13.8	)		0.1			1.1			(0.4	)		2.0			3.6
Production tax credits and other credits	(1.8	)		(4.7	)		—			—			—			—			—			—			—
Like-kind exchange	(1.2	)		—			1.3			—			—			—			—			—			—
Merger expenses	(3.6	)		(1.2	)		—			—			—			(9.6	)		(6.4	)		(7.8	)		(19.8	)
FitzPatrick bargain purchase gain	(2.2	)		(5.6	)		—			—			—			—			—			—			—
Tax Cuts and Jobs Act of 2017(b)	(33.1	)		(128.3	)		0.1			(2.3	)		0.9			6.4			2.8			2.5			1.6
Other	0.2			(0.5	)		0.2			(0.1	)		0.2			0.5			0.7			0.1			(0.4	)
Effective income tax rate	(3.3	)%		(94.6	)%		42.4	%		19.3	%		41.5	%		38.0	%		34.7	%		37.0	%		25.2	%

__________

(a)	Includes the charges related to the transmission-related income tax regulatory asset for Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE of $35 million, $3 million, $5 million, $27 million, $14 million, $6 million and $7 million, respectively. See Note 3 - Regulatory Matters for additional information.

(b)	As a result of TCJA, Generation recorded a net decrease to income tax expense, while the Utility Registrants recorded corresponding regulatory liabilities or assets to the extent such amounts are probable of settlement or recovery through customer rates and an adjustment to income tax expense for all other amounts.

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Tax Differences and Carryforwards

The tax effects of temporary differences and carryforwards, which give rise to significant portions of the deferred tax assets (liabilities), as of December 31, 2019 and 2018 are presented below:

	As of December 31, 2019
	Exelon				Generation				ComEd				PECO				BGE				PHI				Pepco				DPL				ACE
Plant basis differences	$	(13,413	)		$	(2,814	)		$	(4,197	)		$	(1,978	)		$	(1,578	)		$	(2,681	)		$	(1,204	)		$	(753	)		$	(687	)
Accrual based contracts	61				(43		)		—				—				—				104				—				—				—
Derivatives and other financial instruments	165				88				84				—				—				2				—				—				—
Deferred pension and postretirement obligation	1,504				(220		)		(270		)		(28		)		(28		)		(89		)		(75		)		(42		)		(10		)
Nuclear decommissioning activities	(503		)		(503		)		—				—				—				—				—				—				—
Deferred debt refinancing costs	183				20				(7		)		—				(3		)		142				(3		)		(2		)		(1		)
Regulatory assets and liabilities	(884		)		—				183				(169		)		157				(10		)		55				88				77
Tax loss carryforward	240				55				—				25				49				93				13				44				31
Tax credit carryforward	892				897				—				—				—				—				—				—				—
Investment in partnerships	(830		)		(808		)		—				—				—				—				—				—				—
Other, net	926				236				196				70				10				181				85				12				16
Deferred income tax liabilities (net)	$	(11,659	)		$	(3,092	)		$	(4,011	)		$	(2,080	)		$	(1,393	)		$	(2,258	)		$	(1,129	)		$	(653	)		$	(574	)
Unamortized investment tax credits	(668		)		(648		)		(10		)		(1		)		(3		)		(7		)		(2		)		(2		)		(3		)
Total deferred income tax liabilities (net) and unamortized investment tax credits	$	(12,327	)		$	(3,740	)		$	(4,021	)		$	(2,081	)		$	(1,396	)		$	(2,265	)		$	(1,131	)		$	(655	)		$	(577	)

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	As of December 31, 2018
	Exelon				Generation				ComEd				PECO				BGE				PHI				Pepco				DPL				ACE
Plant basis differences	$	(12,533	)		$	(2,495	)		$	(4,059	)		$	(1,862	)		$	(1,399	)		$	(2,577	)		$	(1,148	)		$	(743	)		$	(645	)
Accrual based contracts	117				(44		)		—				—				—				161				—				—				—
Derivatives and other financial instruments	89				35				69				—				—				3				—				—				—
Deferred pension and postretirement obligation	1,435				(188		)		(255		)		(26		)		(26		)		(102		)		(78		)		(46		)		(14		)
Nuclear decommissioning activities	(351		)		(351		)		—				—				—				—				—				—				—
Deferred debt refinancing costs	234				23				(7		)		—				(3		)		187				(4		)		(2		)		(1		)
Regulatory assets and liabilities	(740		)		—				300				(129		)		172				(81		)		67				96				83
Tax loss carryforward	237				78				—				18				25				96				12				52				26
Tax credit carryforward	811				816				—				—				—				—				—				—				—
Investment in partnerships	(797		)		(775		)		—				—				—				—				—				—				—
Other, net	934				239				151				67				12				196				98				17				19
Deferred income tax liabilities (net)	$	(10,564	)		$	(2,662	)		$	(3,801	)		$	(1,932	)		$	(1,219	)		$	(2,117	)		$	(1,053	)		$	(626	)		$	(532	)
Unamortized investment tax credits	(724		)		(700		)		(12		)		(1		)		(3		)		(8		)		(2		)		(2		)		(3		)
Total deferred income tax liabilities (net) and unamortized investment tax credits	$	(11,288	)		$	(3,362	)		$	(3,813	)		$	(1,933	)		$	(1,222	)		$	(2,125	)		$	(1,055	)		$	(628	)		$	(535	)

The following table provides Exelon’s, Generation’s, PECO’s, BGE’s, PHI’s, Pepco’s, DPL’s and ACE’s carryforwards, which are presented on a post-apportioned basis, and any corresponding valuation allowances as of December 31, 2019. ComEd does not have net operating losses or credit carryforwards for the year ended December 31, 2019.

	Exelon				Generation				PECO				BGE				PHI				Pepco				DPL				ACE
Federal
Federal general business credits carryforwards(a)	$	891			$	897			$	—			$	—			$	—			$	—			$	—			$	—
State
State net operating losses	3,986				1,142				312				762				1,360				202				654				438
Deferred taxes on state tax attributes (net)	264				78				25				50				93				13				44				31
Valuation allowance on state tax attributes	26				24				—				1				—				—				—				—
Year in which net operating loss or credit carryforwards will begin to expire	2025				2029				2031				2026				2028				2028				2030				2031

__________

(a)	Exelon's and Generation's federal general business credit carryforwards will begin expiring in 2034.

Tabular Reconciliation of Unrecognized Tax Benefits

The following table presents changes in unrecognized tax benefits, by Registrant.

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	Exelon				Generation				ComEd				PECO				BGE				PHI				Pepco				DPL				ACE
Balance at January 1, 2017	$	916			$	490			$	(12	)		$	—			$	120			$	172			$	80			$	37			$	22
Increases based on tax positions prior to 2017	28				—				14				—				—				14				—				—				14
Decreases based on tax positions prior to 2017(a)	(196		)		(17		)		—				—				—				(61		)		(21		)		(16		)		(22		)
Decrease from settlements with taxing authorities	(5		)		(5		)		—				—				—				—				—				—				—
Balance at December 31, 2017	743				468				2				—				120				125				59				21				14
Change to positions that only affect timing	15				15				—				—				—				—				—				—				—
Increases based on tax positions prior to 2018	30				21				—				—				—				8				7				1				—
Decreases based on tax positions prior to 2018(b)	(251		)		(36		)		—				—				(120		)		(88		)		(66		)		(22		)		—
Decrease from settlements with taxing authorities	(53		)		(53		)		—				—				—				—				—				—				—
Decreases from expiration of statute of limitations	(7		)		(7		)		—				—				—				—				—				—				—
Balance at December 31, 2018	477				408				2				—				—				45				—				—				14
Change to positions that only affect timing	26				12				3				1				4				3				2				1				—
Increases based on tax positions related to 2019	2				1				—				—				—				—				—				—				—
Increases based on tax positions prior to 2019	34				19				3				2				3				—				—				—				—
Decreases based on tax positions prior to 2019	(3		)		(3		)		—				—				—				—				—				—				—
Decrease from settlements with taxing authorities	(29		)		4				(2		)		—				—				—				—				—				—
Balance at December 31, 2019	$	507			$	441			$	6			$	3			$	7			$	48			$	2			$	1			$	14

__________

(a)

Exelon established a liability for an uncertain tax position associated with the tax deductibility of certain merger commitments incurred by Exelon in connection with the acquisitions of Constellation and PHI. In 2017, as a part of its examination of Exelon's return, the IRS National Office issued guidance concurring with Exelon's position that the merger commitments were deductible. As a result, Exelon, Generation, PHI, Pepco, DPL, and ACE decreased their liability for unrecognized tax benefits by $146 million, $19 million, $59 million, $21 million, $16 million and $22 million, respectively, resulting in a benefit to Income taxes on Exelon's, Generation's, PHI's, Pepco's, DPL's, and ACE's Consolidated Statements of Operations and Comprehensive Income and corresponding decreases in their effective tax rates.

(b)

Exelon, Generation, BGE, PHI, Pepco, and DPL decreased their unrecognized state tax benefits primarily due to the receipt of favorable guidance with respect to the deductibility of certain depreciable fixed assets. The recognition of the tax benefits related to BGE, PHI, Pepco, and DPL was offset by corresponding regulatory liabilities and that portion had no immediate impact to their effective tax rate.

Like-Kind Exchange

In 2016, the Tax Court held that Exelon was not entitled to defer a gain on its 1999 like-kind exchange transaction. In addition to the tax and interest related to the gain deferral, the Tax Court also ruled that Exelon was liable for penalties and interest on the penalties. Exelon had fully paid the amounts assessed resulting from the Tax Court decision in 2017. In September 2017, Exelon appealed the Tax Court decision to the U.S. Court of Appeals for the Seventh Circuit. In October 2018, the U.S. Court of Appeals for the Seventh Circuit affirmed the Tax Court’s decision. Exelon filed a petition seeking rehearing of the Seventh Circuit’s decision, but the Seventh Circuit denied that petition in December 2018.  In the first quarter of 2019, Exelon elected not to seek a further review by the U.S. Supreme

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Court. As a result, Exelon's and ComEd's unrecognized tax benefits decreased by approximately $33 million and $2 million, respectively, in the first quarter of 2019.

Recognition of unrecognized tax benefits

The following table presents Exelon's, Generation's and PHI's unrecognized tax benefits that, if recognized, would decrease the effective tax rate. ComEd's, PECO's, BGE's, Pepco's, DPL's and ACE's amounts are not material.

	Exelon				Generation				PHI(a)
December 31, 2019	$	462			$	429			$	32
December 31, 2018	463				408				31
December 31, 2017	523				461				32

__________

(a)	PHI has $21 million of unrecognized state tax benefits that, if recognized, $14 million would be in the form of a net operating loss carryforward, which is expected to require a full valuation allowance based on present circumstances.

The following table presents Exelon's, BGE's, PHI's, Pepco's, DPL's and ACE’s unrecognized tax benefits that, if recognized, may be included in future base rates and that portion would have no impact to the effective tax rate. ComEd's and PECO's amounts are not material.

	Exelon				BGE				PHI				Pepco				DPL				ACE
December 31, 2019	$	19			$	1			$	14			$	—			$	—			$	14
December 31, 2018	14				—				14				—				—				14
December 31, 2017	214				120				94				59				21				14

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

Settlement of Income Tax Audits, Refund Claims, and Litigation

The following table represents Exelon's, Generation's and ACE's unrecognized federal and state tax benefits that could significantly decrease within the 12 months after the reporting date as a result of completing audits, potential settlements, refund claims, and the outcomes of pending court cases as of December 31, 2019. ComEd's, PECO's, BGE's, PHI's, Pepco's and DPL's amounts are not material.

Exelon(a)				Generation(a)				ACE(b)
$	425			$	411			$	14

__________

(a)	Exelon and Generation have $411 million that, if recognized, would decrease the effective tax rate.

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

Total amounts of interest and penalties recognized

The following table represents the net interest and penalties receivable (payable) related to tax positions reflected in Exelon's Consolidated Balance Sheets. Generation's and the Utility Registrants' amounts are not material.

Net interest and penalties receivable as of	Exelon
December 31, 2019	$	318
December 31, 2018	219

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The Registrants did not record material interest and penalty expense related to tax positions reflected in their Consolidated Balance Sheets. Interest expense and penalty expense are recorded in Interest expense, net and Other, net, respectively, in Other income and deductions in the Registrants' Consolidated Statements of Operations and Comprehensive Income.

Description of tax years open to assessment by major jurisdiction

Major Jurisdiction	Open Years	Registrants Impacted
Federal consolidated income tax returns	2002-2018	All Registrants
PHI Holdings and subsidiaries consolidated federal income tax returns	2016	Exelon, Generation, PHI, Pepco, DPL, ACE
Delaware separate corporate income tax returns	Same as federal	DPL
District of Columbia combined corporate income tax returns	2016-2018	Exelon, PHI, Pepco
Illinois unitary corporate income tax returns	2010-2018	Exelon, Generation, ComEd
Maryland separate company corporate net income tax returns	Same as federal	BGE, Pepco, DPL
New Jersey separate corporate income tax returns	2013-2018	Exelon, Generation
New Jersey separate corporate income tax returns	2014-2018	ACE
New York combined corporate income tax returns	2010-March 2012	Exelon, Generation
New York combined corporate income tax returns	2011-2018	Exelon, Generation
Pennsylvania separate corporate income tax returns	2011-2018	Exelon, Generation
Pennsylvania separate corporate income tax returns	2016-2018	PECO

Other Tax Matters

Federal Income Tax Law Changes

On December 22, 2017, President Trump signed the TCJA into law. Pursuant to the enactment of the TCJA, the Registrants remeasured their existing deferred income tax balances as of December 31, 2017 to reflect the decrease in the corporate income tax rate from 35% to 21%, which resulted in a material decrease to their net deferred income tax liability balances as shown in the table below. Generation recorded a corresponding net decrease to income tax expense, while the Utility Registrants recorded corresponding regulatory liabilities or assets to the extent such amounts are probable of settlement or recovery through customer rates and an adjustment to income tax expense for all other amounts.

The one-time impacts recorded by the Registrants to remeasure their deferred income tax balances at the 21% corporate federal income tax rate as of December 31, 2017 are presented below:

	Exelon(b)		Generation		ComEd		PECO(c)		BGE		PHI		Pepco		DPL		ACE
Net Decrease to Deferred Income Tax Liability Balances	$8,624		$1,895		$2,819		$1,407		$1,120		$1,944		$968		$540		$456
Net Increase to Regulatory Liabilities Recorded(a)	7,315		N/A		2,818		1,394		1,124		1,979		976		545		458
Net Deferred Income Tax Benefit/(Expense) Recorded	$1,309		$1,895		$1		$13		$(4)		$(35)		$(8)		$(5)		$(2)

__________

(a)	Reflects the net regulatory liabilities recorded on a pre-tax basis before taking into consideration the income tax benefits associated with the ultimate settlement with customers.

(b)	Amounts do not sum across due to deferred tax adjustments recorded at the Exelon Corporation parent company, primarily related to certain employee compensation plans.

(c)	Given the regulatory treatment of income tax benefits related to electric and gas distribution repairs, PECO remained in an overall net regulatory asset position as of December 31, 2017 after recording the impacts related to the TCJA.

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State Income Tax Law Changes

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

In 2017, Exelon reviewed and updated its marginal state income tax rates based on 2016 state apportionment rates. In addition, Exelon, Generation and ComEd recorded the impacts of Illinois’ statutory rate change, which increased the total corporate income tax rate from 7.75% to 9.50% effective July 1, 2017. The following table provides the one-time impact of the rate changes in 2017 for Exelon, Generation and ComEd:

	Exelon				Generation				ComEd
Increase to Deferred Income Taxes	$	250			$	20			$	270
Increase in Regulatory Assets	270				—				270
(Decrease)/Increase to Income Tax Expense	(20		)		20				—

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

Quarterly, Exelon reviews and updates its marginal state income tax rates for changes in state apportionment. The Registrants remeasure their existing deferred income tax balances to reflect the changes in marginal rates, which results in either an increase or decrease to their net deferred income tax liability balances. Utility Registrants record corresponding regulatory liabilities or assets to the extent such amounts are probable of settlement or recovery through customer rates and an adjustment to income tax expense for all other amounts.

December 31, 2019	Exelon				Generation				PHI				DPL
Increase to Deferred Income Tax Liability	$	23			$	9			$	—			$	—
Increase to Income Tax Expense, Net of Federal Taxes	23				9				—				—
December 31, 2018
Decrease to Deferred Income Tax Liability	$	50			$	53			$	4			$	2
Decrease to Income Tax Expense, Net of Federal Taxes	50				53				3				—

There were no material adjustments to income tax expense in 2017 as a result of changes in state apportionment.

Allocation of Tax Benefits (All Registrants)

Generation and the Utility Registrants are all party to an agreement with Exelon and other subsidiaries of Exelon that provides for the allocation of consolidated tax liabilities and benefits (Tax Sharing Agreement). The Tax Sharing Agreement provides that each party is allocated an amount of tax similar to that which would be owed had the party been separately subject to tax. In addition, any net benefit attributable to Exelon is reallocated to the other Registrants. That allocation is treated as a contribution to the capital of the party receiving the benefit.

The following table presents the allocation of federal tax benefits from Exelon under the Tax Sharing Agreement.

	Generation				ComEd				PECO				BGE				PHI				Pepco				DPL
December 31, 2019(a)	$	41			$	—			$	14			$	3			$	7			$	6			$	1
December 31, 2018(b)	155				1				48				26				2				—				—
December 31, 2017(c)	102				—				16				10				7				—				—

__________

(a)	ACE did not record an allocation of federal tax benefits from Exelon under the Tax Sharing Agreement as a result of a tax net operating loss.

(b)	Pepco, DPL and ACE did not record an allocation of federal tax benefits from Exelon under the Tax Sharing Agreement as a result of a tax net operating loss.

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(c)	ComEd, Pepco, DPL and ACE did not record an allocation of federal tax benefits from Exelon under the Tax Sharing Agreement as a result of a tax net operating loss.

Research and Development Activities

In the fourth quarter 2019, Exelon and Generation recognized additional tax benefits related to certain research and development activities that qualify for federal and state tax incentives for the 2010 through 2018 tax years, which resulted in an increase to Exelon’s and Generation’s net income of $108 million and $75 million, respectively, for the year ended December 31, 2019, reflecting a decrease to Exelon’s and Generation’s Income tax expense of $97 million and $66 million, respectively.

Exelon sponsors defined benefit pension plans and OPEB plans for essentially all current employees. Substantially all non-union employees and electing union employees hired on or after January 1, 2001 participate in cash balance pension plans. Effective January 1, 2009, substantially all newly-hired union-represented employees participate in cash balance pension plans. Effective February 1, 2018, most newly-hired Generation and BSC non-represented, non-craft, employees are not eligible for pension benefits, and will instead be eligible to receive an enhanced non-discretionary employer contribution in an Exelon defined contribution savings plan. Effective January 1, 2018, most newly-hired non-represented, non-craft, employees are not eligible for OPEB benefits and employees represented by Local 614 are not eligible for retiree health care benefits.

Effective January 1, 2019, Exelon merged the Exelon Corporation Cash Balance Pension Plan (CBPP) into the Exelon Corporation Retirement Program (ECRP). The merging of the plans did not change the benefits offered to the plan participants and, thus, had no impact on Exelon's pension obligation. However, beginning in 2019, actuarial losses and gains related to the CBPP and ECRP are amortized over participants’ average remaining service period of the merged ECRP rather than each individual plan.

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The table below shows the pension and OPEB plans in which employees of each operating company participated at December 31, 2019:

Operating Company(e)

Name of Plan:

Generation

ComEd

PECO

BGE

PHI

Pepco

DPL

ACE

Qualified Pension Plans:

Exelon Corporation Retirement Program(a)

X

X

X

X

X

X

X

X

Exelon Corporation Pension Plan for Bargaining Unit Employees(a)

X

X

Exelon New England Union Employees Pension Plan(a)

X

Exelon Employee Pension Plan for Clinton, TMI and Oyster Creek(a)

X

X

X

X

X

Pension Plan of Constellation Energy Group, Inc.(b)

X

X

X

X

X

X

X

Pension Plan of Constellation Energy Nuclear Group, LLC(c)

X

X

X

X

Nine Mile Point Pension Plan(c)

X

Constellation Mystic Power, LLC Union Employees Pension Plan Including Plan A and Plan B(b)

X

Pepco Holdings LLC Retirement Plan(d)

X

X

X

X

X

X

X

X

Non-Qualified Pension Plans:

Exelon Corporation Supplemental Pension Benefit Plan and 2000 Excess Benefit Plan(a)

X

X

X

X

Exelon Corporation Supplemental Management Retirement Plan(a)

X

X

X

X

X

X

X

Constellation Energy Group, Inc. Senior Executive Supplemental Plan(b)

X

X

Constellation Energy Group, Inc. Supplemental Pension Plan(b)

X

X

Constellation Energy Group, Inc. Benefits Restoration Plan(b)

X

X

X

X

Constellation Energy Nuclear Plan, LLC Executive Retirement Plan(c)

X

X

Constellation Energy Nuclear Plan, LLC Benefits Restoration Plan(c)

X

Baltimore Gas & Electric Company Executive Benefit Plan(b)

X

X

Baltimore Gas & Electric Company Manager Benefit Plan(b)

X

X

X

Pepco Holdings LLC 2011 Supplemental Executive Retirement Plan(d)

X

X

X

X

Conectiv Supplemental Executive Retirement Plan (d)

X

X

X

X

Pepco Holdings LLC Combined Executive Retirement Plan (d)

X

X

Atlantic City Electric Director Retirement Plan (d)

X

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Operating Company(e)

Name of Plan:

Generation

ComEd

PECO

BGE

PHI

Pepco

DPL

ACE

OPEB Plans:

PECO Energy Company Retiree Medical Plan(a)

X

X

X

X

X

X

X

X

Exelon Corporation Health Care Program(a)

X

X

X

X

X

X

X

Exelon Corporation Employees’ Life Insurance Plan(a)

X

X

X

X

Exelon Corporation Health Reimbursement Arrangement Plan(a)

X

X

X

X

Constellation Energy Group, Inc. Retiree Medical Plan(b)

X

X

X

X

X

X

Constellation Energy Group, Inc. Retiree Dental Plan(b)

X

X

Constellation Energy Group, Inc. Employee Life Insurance Plan and Family Life Insurance Plan(b)

X

X

X

X

X

X

Constellation Mystic Power, LLC Post-Employment Medical Account Savings Plan(b)

X

Exelon New England Union Post-Employment Medical Savings Account Plan(a)

X

Retiree Medical Plan of Constellation Energy Nuclear Group LLC(c)

X

X

X

Retiree Dental Plan of Constellation Energy Nuclear Group LLC(c)

X

X

X

Nine Mile Point Nuclear Station, LLC Medical Care and Prescription Drug Plan for Retired Employees(c)

X

Pepco Holdings LLC Welfare Plan for Retirees(d)

X

X

X

X

X

X

X

X

__________

(a)	These plans are collectively referred to as the legacy Exelon plans.

(b)	These plans are collectively referred to as the legacy Constellation Energy Group (CEG) Plans.

(c)	These plans are collectively referred to as the legacy CENG plans.

(d)	These plans are collectively referred to as the legacy PHI plans.

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

Exelon’s traditional and cash balance pension plans are intended to be tax-qualified defined benefit plans. Exelon has elected that the trusts underlying these plans be treated as qualified trusts under the IRC. If certain conditions are met, Exelon can deduct payments made to the qualified trusts, subject to certain IRC limitations.

Benefit Obligations, Plan Assets and Funded Status

During the first quarter of 2019, Exelon received an updated valuation of its pension and OPEB to reflect actual census data as of January 1, 2019. This valuation resulted in an increase to the pension and OPEB obligations of $75 million and $36 million, respectively. Additionally, accumulated other comprehensive loss increased by $39 million (after-tax) and regulatory assets and liabilities increased by $53 million and decreased by $5 million, respectively.

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The following tables provide a rollforward of the changes in the benefit obligations and plan assets of Exelon for the most recent two years for all plans combined:

	Pension Benefits								OPEB
	2019				2018				2019				2018
Change in benefit obligation:
Net benefit obligation at beginning of year	$	20,692			$	22,337			$	4,369			$	4,856
Service cost	357				405				93				112
Interest cost	883				802				188				175
Plan participants’ contributions	—				—				44				45
Actuarial (gain) loss(a)	2,322				(1,561		)		250				(540		)
Plan amendments	68				(4		)		—				—
Curtailments	(3		)		—				—				—
Settlements	(35		)		(48		)		(4		)		(4		)
Contractual termination benefits	1				—				—				—
Gross benefits paid	(1,417		)		(1,239		)		(282		)		(275		)
Net benefit obligation at end of year	$	22,868			$	20,692			$	4,658			$	4,369

	Pension Benefits								OPEB
	2019				2018				2019				2018
Change in plan assets:
Fair value of net plan assets at beginning of year	$	16,678			$	18,573			$	2,408			$	2,732
Actual return on plan assets	3,008				(945		)		324				(136		)
Employer contributions	356				337				51				46
Plan participants’ contributions	—				—				44				45
Gross benefits paid	(1,417		)		(1,239		)		(282		)		(275		)
Settlements	(35		)		(48		)		(4		)		(4		)
Fair value of net plan assets at end of year	$	18,590			$	16,678			$	2,541			$	2,408

__________

(a)	The pension actuarial loss in 2019 primarily reflects a decrease in the discount rate. The OPEB actuarial loss in 2019 primarily reflects a decrease in the discount rate. The pension actuarial gain in 2018 primarily reflects an increase in the discount rate. The OPEB actuarial gain in 2018 primarily reflects an increase in the discount rate and favorable health care claims experience.

Exelon presents its benefit obligations and plan assets net on its balance sheet within the following line items:

	Pension Benefits								OPEB
	2019				2018				2019				2018
Other current liabilities	$	31			$	26			$	41			$	33
Pension obligations	4,247				3,988				—				—
Non-pension postretirement benefit obligations	—				—				2,076				1,928
Unfunded status (net benefit obligation less plan assets)	$	4,278			$	4,014			$	2,117			$	1,961

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The following table provides the accumulated benefit obligation (ABO) and fair value of plan assets for all pension plans with an ABO in excess of plan assets. Information for pension and OPEB plans with projected benefit obligations (PBO) and accumulated postretirement benefit obligation (APBO), respectively, in excess of plan assets has been disclosed in the Obligations and Plan Assets table above as all pension and OPEB plans are underfunded.

ABO in excess of plan assets	Exelon
	2019			2018
Accumulated benefit obligation	21,727			19,656
Fair value of net plan assets	18,590			16,678

Components of Net Periodic Benefit Costs

The majority of the 2019 pension benefit cost for the Exelon-sponsored plans is calculated using an expected long-term rate of return on plan assets of 7.00% and a discount rate of 4.31%. The majority of the 2019 OPEB cost is calculated using an expected long-term rate of return on plan assets of 6.67% for funded plans and a discount rate of 4.30%.

A portion of the net periodic benefit cost for all plans is capitalized within the Consolidated Balance Sheets. The following tables present the components of Exelon’s net periodic benefit costs, prior to capitalization, for the years ended December 31, 2019, 2018 and 2017.

	Pension Benefits												OPEB
	2019				2018				2017(a)				2019				2018				2017(a)
Components of net periodic benefit cost:
Service cost	$	357			$	405			$	387			$	93			$	112			$	106
Interest cost	883				802				842				188				175				182
Expected return on assets	(1,225		)		(1,252		)		(1,196		)		(153		)		(173		)		(162		)
Amortization of:
Prior service cost (credit)	—				2				1				(179		)		(186		)		(188		)
Actuarial loss	414				629				607				45				66				61
Settlement and other charges	17				3				3				1				1				—
Contractual termination benefits	1				—				—				—				—				—
Net periodic benefit cost	$	447			$	589			$	644			$	(5	)		$	(5	)		$	(1	)

__________ 

(a)	FitzPatrick net benefit costs are included for the period after acquisition.

Cost Allocation to Exelon Subsidiaries

All Registrants account for their participation in Exelon’s pension and OPEB plans by applying multi-employer accounting. Exelon allocates costs related to its pension and OPEB plans to its subsidiaries based on both active and retired employee participation in each plan.

The amounts below represent the Registrants’ allocated pension and OPEB costs. As a result of new pension guidance effective on January 1, 2018, certain balances have been reclassified on Exelon’s Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2017. For Exelon, the service cost component is included in Operating and maintenance expense and Property, plant and equipment, net, while the non–service cost components are included in Other, net and Regulatory assets for the years ended December 31, 2019 and December 31, 2018 and in Other, net and Property, plant and equipment, net, for the year ended December 31, 2017. For Generation and the Utility Registrants, the service cost and non–service cost components are included

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in Operating and maintenance expense and Property, plant and equipment, net on their consolidated financial statements.

For the Years Ended December 31,	Exelon				Generation(a)				ComEd				PECO				BGE				PHI				Pepco				DPL				ACE
2019	$	442			$	135			$	96			$	12			$	61			$	95			$	25			$	15			$	16
2018	583				204				177				18				60				67				15				6				12
2017	643				227				176				29				64				94				25				13				13

__________

(a)	FitzPatrick net benefit costs are included for the period after acquisition.

Components of AOCI and Regulatory Assets

Exelon recognizes the overfunded or underfunded status of defined benefit pension and OPEB plans as an asset or liability on its balance sheet, with offsetting entries to AOCI and regulatory assets (liabilities). A portion of current year actuarial gains and losses and prior service costs (credits) is capitalized within Exelon’s Consolidated Balance Sheets to reflect the expected regulatory recovery of these amounts, which would otherwise be recorded to AOCI. The following tables provide the components of AOCI and regulatory assets (liabilities) for Exelon for the years ended December 31, 2019, 2018 and 2017 for all plans combined.

	Pension Benefits												OPEB
	2019				2018				2017				2019				2018				2017
Changes in plan assets and benefit obligations recognized in AOCI and regulatory assets (liabilities):
Current year actuarial (gain) loss	$	538			$	635			$	(222	)		$	80			$	(232	)		$	166
Amortization of actuarial loss	(414		)		(629		)		(607		)		(45		)		(66		)		(61		)
Current year prior service cost (credit)	68				(4		)		9				—				—				—
Amortization of prior service (cost) credit	—				(2		)		(1		)		179				186				188
Curtailments	(3		)		—				—				—				—				—
Settlements	(17		)		(3		)		(3		)		(1		)		—				—
Total recognized in AOCI and regulatory assets (liabilities)	$	172			$	(3	)		$	(824	)		$	213			$	(112	)		$	293
Total recognized in AOCI	$	169			$	3			$	(401	)		$	107			$	(55	)		$	168
Total recognized in regulatory assets (liabilities)	$	3			$	(6	)		$	(423	)		$	106			$	(57	)		$	125

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The following table provides the components of gross accumulated other comprehensive loss and regulatory assets (liabilities) for Exelon that have not been recognized as components of periodic benefit cost at December 31, 2019 and 2018, respectively, for all plans combined:

	Pension Benefits								OPEB
	2019				2018				2019				2018
Prior service (credit) cost	$	39			$	(29	)		$	(158	)		$	(337	)
Actuarial loss	7,662				7,558				565				531
Total	$	7,701			$	7,529			$	407			$	194
Total included in AOCI	$	4,068			$	3,899			$	177			$	70
Total included in regulatory assets (liabilities)	$	3,633			$	3,630			$	230			$	124

Average Remaining Service Period

For pension benefits, Exelon amortizes its unrecognized prior service costs and certain actuarial gains and losses, as applicable, based on participants’ average remaining service periods.

For OPEB, Exelon amortizes its unrecognized prior service costs over participants’ average remaining service period to benefit eligibility age and amortizes certain actuarial gains and losses over participants’ average remaining service period to expected retirement. The resulting average remaining service periods for pension and OPEB were as follows:

		2019			2018			2017
Pension plans		11.7			12.0			11.8
OPEB plans:
Benefit Eligibility Age		8.7			8.8			8.8
Expected Retirement		9.3			9.5			9.6

Assumptions

The measurement of the plan obligations and costs of providing benefits under Exelon’s defined benefit and other postretirement plans involves various factors, including the development of valuation assumptions and inputs and accounting policy elections. The measurement of benefit obligations and costs is impacted by several assumptions and inputs, as shown below, among other factors. When developing the required assumptions, Exelon considers historical information as well as future expectations.

Expected Rate of Return. In selecting the EROA, Exelon considers historical economic indicators (including inflation and GDP growth) that impact asset returns, as well as expectations regarding future long-term capital market performance, weighted by Exelon’s target asset class allocations.

Mortality. The mortality assumption is composed of a base table that represents the current expectation of life expectancy of the population adjusted by an improvement scale that attempts to anticipate future improvements in life expectancy. For the year ended December 31, 2018, Exelon’s mortality assumption was supported by an actuarial experience study of Exelon's plan participants and utilized the IRS's RP–2000 base table projected to 2012 with improvement scale AA and projected thereafter with generational improvement scale BB two-dimensional adjusted to a 0.75% long-term rate reached in 2027. For the year ended December 31, 2019, Exelon's mortality assumption utilizes the Society of Actuaries' 2019 base table (Pri-2012) and MP-2019 improvement scale adjusted to a 0.75% long-term rate reached in 2035.

For Exelon, the following assumptions were used to determine the benefit obligations for the plans at December 31, 2019 and 2018. Assumptions used to determine year-end benefit obligations are the assumptions used to estimate the subsequent year’s net periodic benefit costs.

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Pension Benefits

OPEB

2019

2018

2019

2018

Discount rate

3.34

%

(a)

4.31

%

(a)

3.31

%

(a)

4.30

%

(a)

Investment Crediting Rate

3.82

%

(b)

4.46

%

(b)

N/A

N/A

Rate of compensation increase

(c)

(c)

(c)

(c)

Mortality table

Pri-2012 table with MP- 2019 improvement scale (adjusted)

RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)

Pri-2012 table with MP- 2019 improvement scale (adjusted)

RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)

Health care cost trend on covered charges

N/A

N/A

5.00% with ultimate trend of 5.00% in 2017

5.00% with ultimate trend of 5.00% in 2017

__________

(a)	The discount rates above represent the blended rates used to determine the majority of Exelon’s pension and OPEB obligations. Certain benefit plans used individual rates, which range from 3.02% - 3.44% and 3.27% - 3.4% for pension and OPEB plans, respectively, as of December 31, 2019 and 4.13% - 4.36% and 4.27% - 4.38% for pension and OPEB plans, respectively, as of December 31, 2018.

(b)	The investment crediting rate above represents a weighted average rate.

(c)	3.25% through 2019 and 3.75% thereafter.

The following assumptions were used to determine the net periodic benefit cost for Exelon for the years ended December 31, 2019, 2018 and 2017: 

	Pension Benefits									Other Postretirement Benefits
Exelon	2019			2018			2017			2019			2018			2017
Discount rate	4.31	%	(a)	3.62	%	(a)	4.04	%	(a)	4.30	%	(a)	3.61	%	(a)	4.04	%	(a)
Investment Crediting Rate	4.46	%	(b)	4.00	%	(b)	4.46	%	(b)	N/A			N/A			N/A
Expected return on plan assets	7.00	%	(c)	7.00	%	(c)	7.00	%	(c)	6.67	%	(c)	6.60	%	(c)	6.58	%	(c)
Rate of compensation increase			(d)			(d)			(e)			(d)			(d)			(e)
Mortality table	RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)			RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)			RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)			RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)			RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)			RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)
Health care cost trend on covered charges	N/A			N/A			N/A			5.00% with ultimate trend of 5.00% in 2017			5.00% with ultimate trend of 5.00% in 2017			5.50% decreasing to ultimate trend of 5.00% in 2017

__________

(a)

The discount rates above represent the blended rates used to establish the majority of Exelon’s pension and OPEB costs. Certain benefit plans used individual rates, which range from 4.13%-4.36% and 4.27%-4.38% for pension and OPEB plans, respectively, for the year ended December 31, 2019; 3.49%-3.65% and 3.57%-3.68% for pension and OPEB plans; respectively, for the year ended December 31, 2018; and 3.66%-4.11% and 4.00%-4.17% for pension and OPEB plans, respectively, for the year ended December 31, 2017.

(b)	The investment crediting rate above represents a weighted average rate.

(c)	Not applicable to pension and other postretirement benefit plans that do not have plan assets.

(d)	3.25% through 2019 and 3.75% thereafter.

(e)	The legacy Exelon, CEG and CENG pension and other postretirement plans used a rate of compensation increase of 3.25% through 2019 and 3.75% thereafter, while the legacy PHI pension and OPEB plans used a weighted-average rate of compensation increase of 5% for all periods.

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Contributions

Exelon allocates contributions related to its legacy Exelon pension and OPEB plans to its subsidiaries based on accounting cost. For legacy CEG, CENG, FitzPatrick, and PHI plans, pension and OPEB contributions are allocated to the subsidiaries based on employee participation (both active and retired). The following tables provide contributions to the pension and OPEB plans:

	Pension Benefits												OPEB
	2019(a)				2018(a)				2017(a)				2019				2018				2017
Exelon	$	356			$	337			$	341			$	51			$	46			$	64
Generation	160				128				137				15				11				11
ComEd	72				38				36				5				4				5
PECO	27				28				24				1				—				—
BGE	34				40				39				14				14				14
PHI	10				62				67				15				12				32
Pepco	2				6				62				12				11				10
DPL	1				—				—				—				—				2
ACE	—				6				—				1				—				20

__________

(a)	Exelon's and Generation's pension contributions include $21 million related to the legacy CENG plans that was funded by CENG as provided in an Employee Matters Agreement (EMA) between Exelon and CENG for the year ended December 31, 2017. There were no pension contributions for the years ended December 31, 2019 and 2018.

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

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

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

	Qualified Pension Plans				Non-Qualified Pension Plans				OPEB
Exelon	$	505			$	36			$	42
Generation	227				14				16
ComEd	141				2				3
PECO	17				1				—
BGE	56				2				16
PHI	22				9				7
Pepco	—				2				7
DPL	—				1				—
ACE	2				—				—

Estimated Future Benefit Payments

Estimated future benefit payments to participants in all of the pension plans and postretirement benefit plans at December 31, 2019 were:

	Pension Benefits				OPEB
2020	$	1,227			$	258
2021	1,252				263
2022	1,295				267
2023	1,310				270
2024	1,324				275
2025 through 2029	6,770				1,402
Total estimated future benefit payments through 2029	$	13,178			$	2,735

Plan Assets

Investment Strategy. On a regular basis, Exelon evaluates its investment strategy to ensure that plan assets will be sufficient to pay plan benefits when due. As part of this ongoing evaluation, Exelon may make changes to its targeted asset allocation and investment strategy.

Exelon has developed and implemented a liability hedging investment strategy for its qualified pension plans that has reduced the volatility of its pension assets relative to its pension liabilities. Exelon is likely to continue to gradually increase the liability hedging portfolio as the funded status of its plans improves. The overall objective is to achieve attractive risk-adjusted returns that will balance the liquidity requirements of the plans’ liabilities while striving to minimize the risk of significant losses. Trust assets for Exelon’s other postretirement plans are managed in a diversified investment strategy that prioritizes maximizing liquidity and returns while minimizing asset volatility.

Actual asset returns have an impact on the costs reported for the Exelon-sponsored pension and OPEB plans. The actual asset returns across Exelon’s pension and OPEB plans for the year ended December 31, 2019 were 18.80% and 14.40%, respectively, compared to an expected long-term return assumption of 7.00% and 6.67%, respectively. Exelon used an EROA of 7.00% and 6.69% to estimate its 2020 pension and OPEB costs, respectively.

Exelon’s pension and OPEB plan target asset allocations at December 31, 2019 and 2018 were as follows:

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	December 31, 2019						December 31, 2018
Asset Category	Pension Benefits			OPEB			Pension Benefits			OPEB
Equity securities	33	%		46	%		35	%		47	%
Fixed income securities	44	%		32	%		37	%		28	%
Alternative investments(a)	23	%		22	%		28	%		25	%
Total	100	%		100	%		100	%		100	%

__________

(a)	Alternative investments include private equity, hedge funds, real estate, and private credit.

Concentrations of Credit Risk. Exelon evaluated its pension and OPEB plans’ asset portfolios for the existence of significant concentrations of credit risk as of December 31, 2019. Types of concentrations that were evaluated include, but are not limited to, investment concentrations in a single entity, type of industry, foreign country, and individual fund. As of December 31, 2019, there were no significant concentrations (defined as greater than 10% of plan assets) of risk in Exelon’s pension and OPEB plan assets.

Fair Value Measurements

The following tables present pension and OPEB plan assets measured and recorded at fair value in Exelon's Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy at December 31, 2019 and 2018:

December 31, 2019(a)	Level 1				Level 2				Level 3				Not subject to leveling				Total
Pension plan assets
Cash equivalents	$	258			$	—			$	—			$	—			$	258
Equities(b)	3,616				—				5				2,589				6,210
Fixed income:
U.S. Treasury and agencies	1,294				280				—				—				1,574
State and municipal debt	—				56				—				—				56
Corporate debt	—				4,342				245				—				4,587
Other(b)	—				461				—				851				1,312
Fixed income subtotal	1,294				5,139				245				851				7,529
Private equity	—				—				—				1,391				1,391
Hedge funds	—				—				—				1,126				1,126
Real estate	—				—				—				1,030				1,030
Private credit	—				—				237				929				1,166
Pension plan assets subtotal	$	5,168			$	5,139			$	487			$	7,916			$	18,710

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December 31, 2019(a)	Level 1				Level 2				Level 3				Not subject to leveling				Total
OPEB plan assets
Cash equivalents	$	39			$	—			$	—			$	—			$	39
Equities	473				3				—				719				1,195
Fixed income:
U.S. Treasury and agencies	17				64				—				—				81
State and municipal debt	—				107				—				—				107
Corporate debt	—				49				—				—				49
Other	258				78				—				201				537
Fixed income subtotal	275				298				—				201				774
Hedge funds	—				—				—				293				293
Real estate	—				—				—				109				109
Private credit	—				—				—				131				131
OPEB plan assets subtotal	$	787			$	301			$	—			$	1,453			$	2,541
Total pension and OPEB plan assets(c)	$	5,955			$	5,440			$	487			$	9,369			$	21,251

December 31, 2018(a)	Level 1				Level 2				Level 3				Not subject to leveling				Total
Pension plan assets
Cash equivalents	$	350			$	—			$	—			$	—			$	350
Equities(b)	3,364				—				2				1,980				5,346
Fixed income:
U.S. Treasury and agencies	996				173				—				—				1,169
State and municipal debt	—				59				—				—				59
Corporate debt	—				3,716				216				—				3,932
Other(b)	—				329				—				613				942
Fixed income subtotal	996				4,277				216				613				6,102
Private equity	—				—				—				1,219				1,219
Hedge funds	—				—				—				1,608				1,608
Real estate	—				—				—				1,029				1,029
Private credit	—				—				268				798				1,066
Pension plan assets subtotal	$	4,710			$	4,277			$	486			$	7,247			$	16,720

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December 31, 2018(a)	Level 1				Level 2				Level 3				Not subject to leveling				Total
OPEB plan assets
Cash equivalents	$	22			$	—			$	—			$	—			$	22
Equities	537				2				—				508				1,047
Fixed income:
U.S. Treasury and agencies	11				56				—				—				67
State and municipal debt	—				126				—				—				126
Corporate debt	—				48				—				—				48
Other	183				72				—				170				425
Fixed income subtotal	194				302				—				170				666
Hedge funds	—				—				—				411				411
Real estate	—				—				—				132				132
Private credit	—				—				—				132				132
OPEB plan assets subtotal	$	753			$	304			$	—			$	1,353			$	2,410
Total pension and OPEB plan assets(c)	$	5,463			$	4,581			$	486			$	8,600			$	19,130

__________

(a)	See Note 17—Fair Value of Financial Assets and Liabilities for a description of levels within the fair value hierarchy.

(b)

Includes derivative instruments of $2 million and less than $1 million, which have a total notional amount of $6,668 million and $5,991 million at December 31, 2019 and 2018, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do not represent the amount of the company’s exposure to credit or market loss.

(c)	Excludes net liabilities of $120 million and $44 million at December 31, 2019 and 2018, respectively, which are required to reconcile to the fair value of net plan assets. These items consist primarily of receivables or payables related to pending securities sales and purchases, interest and dividends receivable.

The following table presents the reconciliation of Level 3 assets and liabilities for Exelon measured at fair value for pension and OPEB plans for the years ended December 31, 2019 and 2018:

	Fixed Income				Equities				Private Credit				Total
Pension Assets
Balance as of January 1, 2019	$	216			$	2			$	268			$	486
Actual return on plan assets:
Relating to assets still held at the reporting date	28				3				28				59
Relating to assets sold during the period	(7		)		—				—				(7		)
Purchases, sales and settlements:
Purchases	26				—				41				67
Sales	(4		)		—				—				(4		)
Settlements(a)	(2		)		—				(100		)		(102		)
Transfers out of Level 3	(12		)		—				—				(12		)
Balance as of December 31, 2019	$	245			$	5			$	237			$	487

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	Fixed income				Equities				Private Credit				Total
Pension Assets
Balance as of January 1, 2018	$	232			$	2			$	224			$	458
Actual return on plan assets:
Relating to assets still held at the reporting date	(14		)		—				9				(5		)
Relating to assets sold during the period	(1		)		—				—				(1		)
Purchases, sales and settlements:
Purchases	19				—				35				54
Sales	(8		)		—				—				(8		)
Settlements(a)	(12		)		—				—				(12		)
Balance as of December 31, 2018	$	216			$	2			$	268			$	486

__________

(a)	Represents cash settlements only.

There were no significant transfers between Level 1 and Level 2 during the year ended December 31, 2019 for the pension and OPEB plan assets.

Valuation Techniques Used to Determine Fair Value

The techniques used to fair value the pension and OPEB assets invested in cash equivalents, equities, fixed income, derivatives, private equity, real estate, and private credit investments are the same as the valuation techniques for these types of investments in NDTFs. See Cash Equivalents and NDT Fund Investments in Note 17 - Fair Value of Financial Assets and Liabilities for further information.

Pension and OPEB assets also include investments in hedge funds. Hedge fund investments include those seeking to maximize absolute returns using a broad range of strategies to enhance returns and provide additional diversification. The fair value of hedge funds is determined using NAV or its equivalent as a practical expedient, and therefore, hedge funds are not classified within the fair value hierarchy. Exelon has the ability to redeem these investments at NAV or its equivalent subject to certain restrictions which may include a lock-up period or a gate.

Defined Contribution Savings Plan (All Registrants)

The Registrants participate in various 401(k) defined contribution savings plans that are sponsored by Exelon. The plans are qualified under applicable sections of the IRC and allow employees to contribute a portion of their pre-tax and/or after-tax income in accordance with specified guidelines. All Registrants match a percentage of the employee contributions up to certain limits. The following table presents matching contributions to the savings plan for the years ended December 31, 2019, 2018 and 2017:

For the Year Ended December 31,	Exelon				Generation				ComEd				PECO				BGE				PHI			Pepco				DPL				ACE
2019	$	161			$	73			$	35			$	11			$	12			13			$	3			$	3			$	2
2018	179				86				37				9				12				13			3				2				2
2017	128				55				31				10				10				13			3				2				2

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

Authoritative guidance requires that derivative instruments be recognized as either assets or liabilities at fair value, with changes in fair value of the derivative recognized in earnings immediately. Other accounting treatments are

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

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

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

Commodity Price Risk (All Registrants)

Each of the Registrants employ established policies and procedures to manage their risks associated with market fluctuations in commodity prices by entering into physical and financial derivative contracts, including swaps, futures, forwards, options and short-term and long-term commitments to purchase and sell energy and commodity products. The Registrants believe these instruments, which are either determined to be non-derivative or classified as economic hedges, mitigate exposure to fluctuations in commodity prices.

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

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

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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.
	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.
	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.
		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 3 - Regulatory Matters for additional information.

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

(c)	The fair value of the DPL economic hedge is not material as of December 31, 2019 and 2018 and is not presented in the fair value tables below.

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The following table provides a summary of the derivative fair value balances recorded by Exelon, Generation and ComEd as of December 31, 2019 and 2018:

	Exelon				Generation																				ComEd
December 31, 2019	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	)
December 31, 2018
Mark-to-market derivative assets (current assets)	$	801			$	3,505			$	105			$	121			$	(2,930	)		$	801			$	—
Mark-to-market derivative assets (noncurrent assets)	445				1,266				41				51				(913		)		445				—
Total mark-to-market derivative assets	1,246				4,771				146				172				(3,843		)		1,246				—
Mark-to-market derivative liabilities (current liabilities)	(473		)		(3,429		)		(74		)		125				2,931				(447		)		(26		)
Mark-to-market derivative liabilities (noncurrent liabilities)	(474		)		(1,203		)		(20		)		60				912				(251		)		(223		)
Total mark-to-market derivative liabilities	(947		)		(4,632		)		(94		)		185				3,843				(698		)		(249		)
Total mark-to-market derivative net assets (liabilities)	$	299			$	139			$	52			$	357			$	—			$	548			$	(249	)

_________

(a)

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

(b)	Of the collateral posted/(received), $511 million and $(94) million represents variation margin on the exchanges at December 31, 2019 and 2018, respectively.

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Economic Hedges (Commodity Price Risk)

Generation. For the years ended December 31, 2019, 2018 and 2017, Exelon and Generation recognized the following net pre-tax commodity mark-to-market gains (losses) which are also located in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows.

		2019				2018				2017
Income Statement Location		Gain (Loss)
Operating revenues		$	—			$	(270	)		$	(126	)
Purchased power and fuel		(204		)		(47		)		(43		)
Total Exelon and Generation		$	(204	)		$	(317	)		$	(169	)

In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on Generation’s owned and contracted generation positions that have not been hedged. Generation hedges commodity price risk on a ratable basis over three-year periods. As of December 31, 2019, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York and ERCOT reportable segments is 91%-94% and 61%-64% for 2020 and 2021, respectively.

Proprietary Trading (Commodity Price Risk)

Generation also executes commodity derivatives for proprietary trading purposes. Proprietary trading includes all contracts executed with the intent of benefiting from shifts or changes in market prices as opposed to those executed with the intent of hedging or managing risk. Gains and losses associated with proprietary trading are reported as Operating revenues in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income and are included in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows. For the years ended December 31, 2019, 2018 and 2017, net pre-tax commodity mark-to-market gains (losses) for Exelon and Generation were not material. The Utility Registrants do not execute derivatives for proprietary trading purposes.

Interest Rate and Foreign Exchange Risk (Exelon and Generation)

Exelon and Generation utilize interest rate swaps, which are treated as economic hedges, to manage their interest rate exposure. On July 1, 2018, Exelon 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 $1,269 million and $1,420 million at December 31, 2019 and 2018, respectively, for Exelon and $569 million and $620 million at December 31, 2019 and 2018, respectively, for Generation.

Generation utilizes foreign currency derivatives to manage foreign exchange rate exposure associated with international commodity purchases in currencies other than U.S. dollars, which are treated as economic hedges. The notional amounts were $231 million and $268 million at December 31, 2019 and 2018, respectively.

The mark-to-market derivative assets and liabilities as of December 31, 2019 and 2018 and the mark-to-market gains (losses) for the years ended December 31, 2019, 2018 and 2017 were not material for Exelon and Generation.

Credit Risk (All Registrants)

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

Generation. For commodity derivatives, Generation enters into enabling agreements that allow for payment netting with its counterparties, which reduces Generation’s exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. Typically, each enabling agreement is for a specific commodity and so, with respect to each individual counterparty, netting is limited to transactions involving that specific commodity product, except where master netting agreements exist with a counterparty that allow for cross product netting. In addition to payment netting language in the enabling agreement, Generation’s credit department establishes credit limits, margining thresholds and collateral requirements for each counterparty, which are defined in the derivative contracts. Counterparty credit limits are based on an internal credit

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review process that considers a variety of factors, including the results of a scoring model, leverage, liquidity, profitability, credit ratings by credit rating agencies, and risk management capabilities. To the extent that a counterparty’s margining thresholds are exceeded, the counterparty is required to post collateral with Generation as specified in each enabling agreement. Generation’s credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis.

The following tables provide information on Generation’s credit exposure for all derivative instruments, NPNS and payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of December 31, 2019. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties. The figures in the tables below exclude credit risk exposure from individual retail counterparties, nuclear fuel procurement contracts and exposure through RTOs, ISOs, NYMEX, ICE, NASDAQ, NGX and Nodal commodity exchanges.

Rating as of December 31, 2019	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	$	877			$	20			$	857			—			$	—
Non-investment grade	79				63				16
No external ratings
Internally rated — investment grade	218				—				218
Internally rated — non-investment grade	139				23				116
Total	$	1,313			$	106			$	1,207			—			$	—

Net Credit Exposure by Type of Counterparty	As of December 31, 2019
Financial institutions	$	9
Investor-owned utilities, marketers, power producers	930
Energy cooperatives and municipalities	235
Other	33
Total	$	1,207

__________

(a)	As of December 31, 2019, credit collateral held from counterparties where Generation had credit exposure included $25 million of cash and $81 million of letters of credit. The credit collateral does not include non-liquid collateral.

Utility Registrants. The Utility Registrants have contracts to procure electric and natural gas supply that provide suppliers with a certain amount of unsecured credit. If the exposure on the supply contract exceeds the amount of unsecured credit, the suppliers may be required to post collateral. The net credit exposure is mitigated primarily by the ability to recover procurement costs through customer rates. As of December 31, 2019, the Utility Registrants’ counterparty credit risk with suppliers was immaterial.

Credit-Risk-Related Contingent Features (All Registrants)

Generation. As part of the normal course of business, Generation routinely enters into physically or financially settled contracts for the purchase and sale of electric capacity, electricity, fuels, emissions allowances and other energy-related products. Certain of Generation’s derivative instruments contain provisions that require Generation to post collateral. Generation also enters into commodity transactions on exchanges where the exchanges act as the counterparty to each trade. Transactions on the exchanges must adhere to comprehensive collateral and margining requirements. This collateral may be posted in the form of cash or credit support with thresholds contingent upon Generation’s credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. These credit-risk related contingent features stipulate that if Generation were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. This incremental collateral requirement allows for the offsetting of derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master netting agreements. In the absence of expressly agreed-to provisions that specify

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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:

		As of December 31,
Credit-Risk Related Contingent Features		2019				2018
Gross fair value of derivative contracts containing this feature(a)		$	(956	)		$	(1,723	)
Offsetting fair value of in-the-money contracts under master netting arrangements(b)		649				1,105
Net fair value of derivative contracts containing this feature(c)		$	(307	)		$	(618	)

__________

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

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

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

As of December 31, 2019 and 2018, Exelon and Generation posted or held the following amounts of cash collateral and letters of credit on derivative contracts with external counterparties, after giving consideration to offsetting derivative and non-derivative positions under master netting agreements.

		As of December 31,
		2019				2018
Cash collateral posted		$	982			$	418
Letters of credit posted		264				367
Cash collateral held		103				47
Letters of credit held		112				44
Additional collateral required in the event of a credit downgrade below investment grade		1,509				2,104

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

Utility Registrants

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

PECO’s, BGE’s, and DPL’s natural gas procurement contracts contain provisions that could require PECO, BGE, and DPL to post collateral in the form of cash or credit support, which vary by contract and counterparty, with thresholds contingent upon PECO’s, BGE, and DPL’s credit rating. As of December 31, 2019, PECO, BGE, and DPL were not required to post collateral for any of these agreements. If PECO, BGE or DPL lost their investment grade credit rating as of December 31, 2019, they could have been required to post incremental collateral to its counterparties of $44 million, $50 million, and $11 million, respectively.

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Short-Term Borrowings

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

Commercial Paper

The following table reflects the Registrants' commercial paper programs supported by the revolving credit agreements and bilateral credit agreements at December 31, 2019 and 2018:

	Maximum Program Size at December 31,								Outstanding Commercial Paper at December 31,								Average Interest Rate on Commercial Paper Borrowings for the Year Ended December 31,
Commercial Paper Issuer	2019(a)(b)(c)				2018(a)(b)(c)				2019				2018				2019			2018
Exelon(d)	$	9,000			$	9,000			$	870			$	89			2.25	%		2.15	%
Generation	5,300				5,300				320				—				1.84	%		1.96	%
ComEd	1,000				1,000				130				—				2.38	%		2.14	%
PECO	600				600				—				—				2.39	%		2.24	%
BGE	600				600				76				35				2.46	%		2.18	%
PHI	900				900				208				54				N/A			N/A
Pepco	300				300				82				40				2.56	%		2.24	%
DPL	300				300				56				—				2.02	%		2.07	%
ACE	300				300				70				14				2.43	%		2.21	%

__________

(a)	Excludes $1,400 million and $545 million in bilateral credit facilities at December 31, 2019 and 2018, respectively, and $159 million in credit facilities for project finance at December 31, 2019 and 2018, respectively. These credit facilities do not back Generation's commercial paper program.

(b)

At December 31, 2019, excludes $142 million of credit facility agreements arranged at minority and community banks at Generation, ComEd, PECO, BGE, Pepco, DPL and ACE with aggregate commitments of $44 million, $33 million, $33 million, $8 million, $8 million, $8 million and $8 million, respectively. These facilities expire on October 9, 2020. These facilities are solely utilized to issue letters of credit. At December 31, 2018, excludes $135 million of credit facility agreements arranged at minority and community banks at Generation, ComEd, PECO, BGE, Pepco, DPL and ACE with aggregate commitments of $49 million, $33 million, $34 million, $5 million, $5 million, $5 million, and $5 million, respectively.

(c)

Pepco, DPL and ACE's revolving credit facility has the ability to flex to $500 million, $500 million, and $350 million, respectively. The borrowing capacity may be increased or decreased during the term of the facility, except that (i) the sum of the borrowing capacity must equal the total amount of the facility, and (ii) the aggregate amount of credit used at any given time by each of Pepco, DPL or ACE may not exceed $900 million or the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the borrowing reallocations may not exceed eight per year during the term of the facility.

(d)	Includes revolving credit agreement at Exelon Corporate with a maximum program size of $600 million at both December 31, 2019 and 2018, respectively. Exelon Corporate had $136 million of outstanding commercial paper at December 31, 2019 and no outstanding commercial paper at the end of 2018.

In order to maintain their respective commercial paper programs in the amounts indicated above, each Registrant must have credit facilities in place, at least equal to the amount of its commercial paper program. A registrant does not issue commercial paper in an aggregate amount exceeding the then available capacity under its credit facility.

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At December 31, 2019, the Registrants had the following aggregate bank commitments, credit facility borrowings and available capacity under their respective credit facilities:

															Available Capacity at December 31, 2019
Borrower	Facility Type		Aggregate Bank Commitment(a)				Facility Draws				Outstanding Letters of Credit				Actual				To Support Additional Commercial Paper(b)
Exelon(b)	Syndicated Revolver / Bilaterals / Project Finance		$	10,559			$	—			$	1,443			$	9,116			$	7,353
Generation	Syndicated Revolver		5,300				—				769				4,531				4,211
Generation	Bilaterals		1,400				—				545				855				—
Generation	Project Finance		159				—				120				39				—
ComEd	Syndicated Revolver		1,000				—				2				998				868
PECO	Syndicated Revolver		600				—				—				600				600
BGE	Syndicated Revolver		600				—				—				600				524
PHI	Syndicated Revolver		900				—				—				900				692
Pepco	Syndicated Revolver		300				—				—				300				218
DPL	Syndicated Revolver		300				—				—				300				244
ACE	Syndicated Revolver		300				—				—				300				230

__________

(a)

Excludes $142 million of credit facility agreements arranged at minority and community banks at Generation, ComEd, PECO, BGE, Pepco, DPL and ACE with aggregate commitments of $44 million, $33 million, $33 million, $8 million, $8 million, $8 million and $8 million, respectively. These facilities expire on October 9, 2020. These facilities are solely utilized to issue letters of credit. As of December 31, 2019, letters of credit issued under these facilities totaled $5 million, $5 million, $2 million for Generation, ComEd, and BGE, respectively.

(b)	Includes $600 million aggregate bank commitment related to Exelon Corporate. Exelon Corporate had $6 million and $9 million outstanding letters of credit at December 31, 2019 and 2018, respectively. Exelon Corporate had $458 million in available capacity to support additional commercial paper at December 31, 2019.

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The following tables present the short-term borrowings activity for Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE during 2019 and 2018.

December 31, 2019	Exelon(a)			Generation			ComEd			PECO			BGE			PHI	Pepco			DPL			ACE
Average borrowings	$	472		$	13		$	236		$	—		$	103		N/A	$	45		$	21		$	51
Maximum borrowings outstanding	890			357			465			21			298			N/A	144			125			180
Average interest rates, computed on a daily basis	2.25		%	1.84		%	2.38		%	2.39		%	2.46		%	N/A	2.56		%	2.02		%	2.43		%
Average interest rates, at December 31	2.25		%	1.84		%	2.38		%	2.39		%	2.46		%	N/A	2.56		%	2.02		%	2.43		%
December 31, 2018	Exelon(a)			Generation			ComEd			PECO			BGE			PHI	Pepco			DPL			ACE
Average borrowings	$	531		$	37		$	154		$	68		$	65		N/A	$	22		$	87		$	95
Maximum borrowings outstanding	1,237			583			520			350			239			N/A	90			245			210
Average interest rates, computed on a daily basis	2.21		%	1.96		%	2.14		%	2.24		%	2.18		%	N/A	2.24		%	2.07		%	2.21		%
Average interest rates, at December 31	2.15		%	1.96		%	2.14		%	2.24		%	2.18		%	N/A	2.24		%	2.07		%	2.21		%

__________

(a)

Includes $3 million and $4 million average borrowings related to Exelon Corporate at December 31, 2019 and 2018, respectively. Exelon Corporate had $144 million and $95 million maximum borrowings outstanding at December 31, 2019 and 2018, with 1.92% and 1.93% average interest rates computed on a daily basis for 2019 and 2018, and 1.92% and 1.93% average interest rates at December 31, 2019 and 2018, respectively.

Short-Term Loan Agreements

On March 23, 2017, Exelon Corporate entered into a term loan agreement for $500 million, which was renewed on March 22, 2018 with an expiration of March 21, 2019.  The loan agreement was renewed on March 20, 2019 and will expire on March 19, 2020. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.95% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Exelon's Consolidated Balance Sheet within Short-Term borrowings.

Revolving Credit Agreements

On May 26, 2016, Exelon Corporate, Generation, ComEd, PECO and BGE entered into amendments to each of their respective syndicated revolving credit facilities, which extended the maturity of each of the facilities to May 26, 2021. Exelon Corporate also increased the size of its facility from $500 million to $600 million. On May 26, 2016, PHI, Pepco, DPL and ACE entered into an amendment to their Second Amended and Restated Credit Agreement dated as of August 1, 2011, which (i) extended the maturity date of the facility to May 26, 2021, (ii) removed PHI as a borrower under the facility, (iii) decreased the size of the facility from $1.5 billion to $900 million and (iv) aligned its financial covenant from debt to capitalization leverage ratio to interest coverage ratio. On May 26, 2018, each of the Registrants' respective syndicated revolving credit facilities had their maturity dates extended to May 26, 2023.

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Bilateral Credit Agreements

The following table reflects the bilateral credit agreements at December 31, 2019:

Registrant	Date Initiated		Latest Amendment Date		Maturity Date(a)		Amount
Generation(b)	October 26, 2012		October 24, 2019		October 24, 2020		$	200
Generation(c)	January 11, 2013		January 4, 2019		March 1, 2021		100
Generation(c)	January 5, 2016		January 4, 2019		April 5, 2021		150
Generation(c)	February 21, 2019		N/A		March 31, 2021		100
Generation(c)	October 25, 2019		N/A		N/A		200
Generation(c)	October 25, 2019		N/A		N/A		100
Generation(c)	November 20, 2019		N/A		N/A		300
Generation(c)	November 21, 2019		N/A		November 21, 2020		150
Generation(c)	November 21, 2019		N/A		November 21, 2021		100

__________

(a)	Credit facilities that do not contain a maturity date are specific to the agreements set within each contract. In some instances, credit facilities are automatically renewed based on the contingency standards set within the specific agreement.

(b)	Bilateral credit facility relates to CENG, which is incorporated within Generation, and supports the issuance of letters of credit and funding for working capital and does not back Generation's commercial paper program.

(c)	Bilateral credit agreements solely support the issuance of letters of credit and do not back Generation's commercial paper program.

Borrowings under Exelon Corporate’s, Generation’s, ComEd’s, PECO’s, BGE's, Pepco's, DPL's and ACE's revolving credit agreements bear interest at a rate based upon either the prime rate or a LIBOR-based rate, plus an adder based upon the particular Registrant’s credit rating. The adders for the prime based borrowings and LIBOR-based borrowings are presented in the following table:

	Exelon		Generation		ComEd		PECO		BGE		Pepco		DPL		ACE
Prime based borrowings	27.5		27.5		7.5		—		—		7.5		7.5		7.5
LIBOR-based borrowings	127.5		127.5		107.5		90.0		100.0		107.5		107.5		107.5

If any registrant loses its investment grade rating, the maximum adders for prime rate borrowings and LIBOR-based rate borrowings would be 65 basis points and 165 basis points. The credit agreements also require the borrower to pay a facility fee based upon the aggregate commitments. The fee varies depending upon the respective credit ratings of the borrower.

Variable Rate Demand Bonds

DPL has outstanding obligations in respect of Variable Rate Demand Bonds (VRDB). VRDBs are subject to repayment on the demand of the holders and, for this reason, are accounted for as short-term debt in accordance with GAAP. However, these bonds may be converted to a fixed-rate, fixed-term option to establish a maturity which corresponds to the date of final maturity of the bonds. On this basis, PHI views VRDBs as a source of long-term financing. As of both December 31, 2019 and December 31, 2018, $79 million in variable rate demand bonds issued by DPL were outstanding and are included in the Long-term debt due within one year in Exelon's, PHI's and DPL's Consolidated Balance Sheet.

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Long-Term Debt 

The following tables present the outstanding long-term debt at the Registrants as of December 31, 2019 and 2018:

Exelon

							Maturity Date		December 31,
	Rates								2019				2018
Long-term debt
First mortgage bonds(a)	1.70	%	-	7.90	%		2020 - 2049		$	17,486			$	16,496
Senior unsecured notes	2.45	%	-	7.60	%		2020 - 2046		10,685				11,285
Unsecured notes	2.40	%	-	6.35	%		2021 - 2049		3,300				2,900
Pollution control notes	2.50	%	-	2.70	%		2025 - 2036		412				435
Nuclear fuel procurement contracts				3.15	%		2020		3				39
Notes payable and other	2.53	%	-	7.99	%		2020 - 2053		154				188
Junior subordinated notes				3.50	%		2022		1,150				1,150
Long-term software licensing agreement				3.95	%		2024		55				73
Unsecured Tax-Exempt Bonds(b)	1.63	%	-	5.40	%		2022 - 2031		222				112
Medium-Terms Notes (unsecured)	7.61	%	-	7.72	%		2027		10				22
Transition bonds				5.55	%		2023		40				59
Loan Agreement				2.00	%		2023		50				50
Nonrecourse debt:
Fixed rates	2.29	%	-	6.00	%		2031 - 2037		1,182				1,253
Variable rates	3.18	%	-	4.91	%		2020 - 2024		811				849
Total long-term debt									35,560				34,911
Unamortized debt discount and premium, net									(72		)		(66		)
Unamortized debt issuance costs									(214		)		(216		)
Fair value adjustment									765				795
Long-term debt due within one year									(4,710		)		(1,349		)
Long-term debt									$	31,329			$	34,075
Long-term debt to financing trusts(c)
Subordinated debentures to ComEd Financing III				6.35	%		2033		$	206			$	206
Subordinated debentures to PECO Trust III	6.75	%	-	7.38	%		2028		81				81
Subordinated debentures to PECO Trust IV				5.75	%		2033		103				103
Total long-term debt to financing trusts									390				390
Unamortized debt issuance costs									—				—
Long-term debt to financing trusts									$	390			$	390

__________

(a)	Substantially all of ComEd’s assets other than expressly excepted property and substantially all of PECO’s, Pepco's, DPL's and ACE's assets are subject to the liens of their respective mortgage indentures.

(b)	Bond amount totaling $110 million was previously disclosed within the first mortgage bonds line item, as it was classified as a secured tax-exempt bond. In 2019, the callable bond was reissued as an unsecured tax-exempt bond, and is presented as such within this section.

(c)	Amounts owed to these financing trusts are recorded as Long-term debt to financing trusts within Exelon’s Consolidated Balance Sheets.

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Generation

							Maturity Date		December 31,
	Rates								2019				2018
Long-term debt
Senior unsecured notes	2.95	%	-	7.60	%		2020 - 2042		$	5,420			$	6,019
Pollution control notes	2.50	%	-	2.70	%		2025 - 2036		412				435
Nuclear fuel procurement contracts				3.15	%		2020		3				39
Notes payable and other	2.53	%	-	4.26	%		2020 - 2028		115				164
Nonrecourse debt:
Fixed rates	2.29	%	-	6.00	%		2031 - 2037		1,182				1,253
Variable rates	3.18	%	-	4.91	%		2020 - 2024		811				849
Total long-term debt									7,943				8,759
Unamortized debt discount and premium, net									(5		)		(6		)
Unamortized debt issuance costs									(42		)		(51		)
Fair value adjustment									78				91
Long-term debt due within one year									(3,182		)		(906		)
Long-term debt									$	4,792			$	7,887

ComEd

							Maturity Date		December 31,
	Rates								2019				2018
Long-term debt
First mortgage bonds(a)	2.55	%	-	6.45	%		2020 - 2049		$	8,578			$	8,179
Notes payable and other				7.49	%		2053		8				8
Total long-term debt									8,586				8,187
Unamortized debt discount and premium, net									(27		)		(23		)
Unamortized debt issuance costs									(68		)		(63		)
Long-term debt due within one year									(500		)		(300		)
Long-term debt									$	7,991			$	7,801
Long-term debt to financing trust(b)
Subordinated debentures to ComEd Financing III				6.35	%		2033		$	206			$	206
Total long-term debt to financing trusts									206				206
Unamortized debt issuance costs									(1		)		(1		)
Long-term debt to financing trusts									$	205			$	205

__________

(a)	Substantially all of ComEd’s assets, other than expressly excepted property, are subject to the lien of its mortgage indenture.

(b)	Amount owed to this financing trust is recorded as Long-term debt to financing trust within ComEd’s Consolidated Balance Sheets.

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PECO

							Maturity Date		December 31,
	Rates								2019				2018
Long-term debt
First mortgage bonds(a)	1.70	%	-	5.95	%		2021 - 2049		$	3,400			$	3,075
Loan Agreement				2.00	%		2023		50				50
Total long-term debt									3,450				3,125
Unamortized debt discount and premium, net									(21		)		(18		)
Unamortized debt issuance costs									(24		)		(23		)
Long-term debt									$	3,405			$	3,084
Long-term debt to financing trusts(b)
Subordinated debentures to PECO Trust III	6.75	%	-	7.38	%		2028		$	81			$	81
Subordinated debentures to PECO Trust IV				5.75	%		2033		103				103
Long-term debt to financing trusts									$	184			$	184

__________

(a)	Substantially all of PECO’s assets are subject to the lien of its mortgage indenture.

(b)	Amounts owed to this financing trust are recorded as Long-term debt to financing trusts within PECO’s Consolidated Balance Sheets.

BGE

							Maturity Date		December 31,
	Rates								2019				2018
Long-term debt
Unsecured notes	2.40	%	-	6.35	%		2021 - 2049		$	3,300			$	2,900
Total long-term debt									3,300				2,900
Unamortized debt discount and premium, net									(9		)		(6		)
Unamortized debt issuance costs									(21		)		(18		)
Long-term debt									$	3,270			$	2,876

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PHI

							Maturity Date		December 31,
	Rates								2019				2018
Long-term debt
First mortgage bonds(a)	1.76	%	-	7.90	%		2021 - 2049		$	5,508			$	5,242
Senior unsecured notes				7.45	%		2032		185				185
Unsecured Tax-Exempt Bonds(b)	1.63	%	-	5.40	%		2022 - 2031		222				112
Medium-terms notes (unsecured)	7.61	%	-	7.72	%		2027		10				22
Transition bonds(c)				5.55	%		2023		40				59
Notes payable and other	3.54	%	-	7.99	%		2021 - 2027		30				16
Total long-term debt									5,995				5,636
Unamortized debt discount and premium, net									4				4
Unamortized debt issuance costs									(19		)		(14		)
Fair value adjustment									583				633
Long-term debt due within one year									(103		)		(125		)
Long-term debt									$	6,460			$	6,134

_________

(a)	Substantially all of Pepco's, DPL's, and ACE's assets are subject to the lien of its respective mortgage indenture.

(b)	Bond amount totaling $110 million was previously disclosed within the first mortgage bonds line item, as it was classified as a secured tax-exempt bond. In 2019, the callable bond was reissued as an unsecured tax-exempt bond, and is presented as such within this section.

(c)	Transition bonds are recorded as part of Long-term debt within ACE's Consolidated Balance Sheets.

Pepco

							Maturity Date		December 31,
	Rates								2019				2018
Long-term debt
First mortgage bonds(a)	3.05	%	-	7.90	%		2022 - 2048		$	2,775			$	2,735
Unsecured Tax-Exempt Bonds(b)				1.70	%		2022		110				—
Notes payable and other	3.54	%	-	7.99	%		2021 - 2027		12				16
Total long-term debt									2,897				2,751
Unamortized debt discount and premium, net									2				2
Unamortized debt issuance costs									(35		)		(34		)
Long-term debt due within one year									(2		)		(15		)
Long-term debt									$	2,862			$	2,704

__________

(a)	Substantially all of Pepco's assets are subject to the lien of its respective mortgage indenture.

(b)	Bond amount totaling $110 million was previously disclosed within the first mortgage bonds line item, as it was classified as a secured tax-exempt bond. In 2019, the callable bond was reissued as an unsecured tax-exempt bond, and is presented as such within this section.

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DPL

							Maturity Date		December 31,
	Rates								2019				2018
Long-term debt
First mortgage bonds(a)	1.76	%	-	4.27	%		2023 - 2049		$	1,446			$	1,370
Unsecured Tax-Exempt Bonds	1.63	%	-	5.40	%		2024 - 2031		112				112
Medium-terms notes (unsecured)	7.61	%	-	7.72	%		2027		10				22
Other				3.54	%		2027		10				—
Total long-term debt									1,578				1,504
Unamortized debt discount and premium, net									1				2
Unamortized debt issuance costs									(12		)		(12		)
Long-term debt due within one year									(80		)		(91		)
Long-term debt									$	1,487			$	1,403

__________

(a)	Substantially all of DPL's assets are subject to the lien of its respective mortgage indenture.

ACE

							Maturity Date		December 31,
	Rates								2019				2018
Long-term debt
First mortgage bonds(a)	3.38	%	-	6.80	%		2021 - 2049		$	1,287			$	1,137
Transition bonds(b)				5.55	%		2023		40				59
Other				3.54	%		2027		8				—
Total long-term debt									$	1,335			$	1,196
Unamortized debt discount and premium, net									(1		)		(1		)
Unamortized debt issuance costs									(7		)		(7		)
Long-term debt due within one year									(20		)		(18		)
Long-term debt									$	1,307			$	1,170

__________

(a)	Substantially all of ACE's assets are subject to the lien of its respective mortgage indenture.

(b)	Maturities of ACE's Transition Bonds outstanding at December 31, 2019 are $19 million in 2020 and $21 million in 2021.

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Long-term debt maturities at Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE in the periods 2020 through 2024 and thereafter are as follows:

Year	Exelon				Generation				ComEd				PECO				BGE				PHI				Pepco				DPL				ACE
2020	$	4,710			$	3,182			$	500			$	—			$	—			$	103			$	2			$	80			$	20
2021	1,517				2				350				300				300				265				2				2				261
2022	3,088				1,024				—				350				250				314				311				2				1
2023	855				1				—				50				300				504				1				502				1
2024	1,596				792				250				—				—				553				401				1				151
Thereafter	24,184			(a)	2,942				7,691			(b)	2,934			(c)	2,450				4,256				2,180				991				901
Total	$	35,950			$	7,943			$	8,791			$	3,634			$	3,300			$	5,995			$	2,897			$	1,578			$	1,335

__________

(a)	Includes $390 million due to ComEd and PECO financing trusts.

(b)	Includes $206 million due to ComEd financing trust.

(c)	Includes $184 million due to PECO financing trusts.

Debt Covenants

As of December 31, 2019, the Registrants are in compliance with debt covenants, except for Antelope Valley's nonrecourse debt event of default as discussed below.

Nonrecourse Debt 

Exelon and Generation have issued nonrecourse debt financing, in which approximately $2.8 billion of generating assets have been pledged as collateral at December 31, 2019. Borrowings under these agreements are secured by the assets and equity of each respective project. The lenders do not have recourse against Exelon or Generation in the event of a default. If a specific project financing entity does not maintain compliance with its specific nonrecourse debt financing covenants, there could be a requirement to accelerate repayment of the associated debt or other borrowings earlier than the stated maturity dates. In these instances, if such repayment was not satisfied, the lenders or security holders would generally have rights to foreclose against the project-specific assets and related collateral. The potential requirement to satisfy its associated debt or other borrowings earlier than otherwise anticipated could lead to impairments due to a higher likelihood of disposing of the respective project-specific assets significantly before the end of their useful lives.

Antelope Valley Solar Ranch One. In December 2011, the DOE Loan Programs Office issued a guarantee for up to $646 million for a nonrecourse loan from the Federal Financing Bank to support the financing of the construction of the Antelope Valley facility. The project became fully operational in 2014. The loan will mature on January 5, 2037. Interest rates on the loan were fixed upon each advance at a spread of 37.5 basis points above U.S. Treasuries of comparable maturity. The advances were completed as of December 31, 2015 and the outstanding loan balance will bear interest at an average blended interest rate of 2.82%. As of December 31, 2019, approximately $485 million was outstanding. In addition, Generation has issued letters of credit to support its equity investment in the project. As of December 31, 2019, Generation had $38 million in letters of credit outstanding related to the project. In 2017, Generation’s interests in Antelope Valley were also contributed to and are pledged as collateral for the EGR IV financing structure referenced below.

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

Continental Wind.    In September 2013, Continental Wind, LLC (Continental Wind), an indirect subsidiary of Exelon and Generation, completed the issuance and sale of $613 million senior secured notes. Continental Wind owns

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and operates a portfolio of wind farms in Idaho, Kansas, Michigan, Oregon, New Mexico and Texas with a total net capacity of 667MW. The net proceeds were distributed to Generation for its general business purposes. The notes are scheduled to mature on February 28, 2033. The notes bear interest at a fixed rate of 6.00% with interest payable semi-annually. As of December 31, 2019, $447 million was outstanding.

In addition, Continental Wind entered into a $131 million letter of credit facility and $10 million working capital revolver facility. Continental Wind has issued letters of credit to satisfy certain of its credit support and security obligations. As of December 31, 2019, the Continental Wind letter of credit facility had $115 million in letters of credit outstanding related to the project.

In 2017, Generation’s interests in Continental Wind were contributed to EGRP. Refer to Note 22 - Variable Interest Entities for additional information on EGRP.

Renewable Power Generation.    In March 2016, RPG, an indirect subsidiary of Exelon and Generation, issued $150 million aggregate principal amount of a nonrecourse senior secured notes.  The net proceeds were distributed to Generation for paydown of long term debt obligations at Sacramento PV Energy and Constellation Solar Horizons and for general business purposes.  The loan is scheduled to mature on March 31, 2035.  The term loan bears interest at a fixed rate of 4.11% payable semi-annually.  As of December 31, 2019, $106 million was outstanding.

In 2017, Generation’s interests in Renewable Power Generation were contributed to EGRP. Refer to Note 22 - Variable Interest Entities for additional information on EGRP.

SolGen.    In September 2016, SolGen, LLC (SolGen), an indirect subsidiary of Exelon and Generation, issued $150 million aggregate principal amount of a nonrecourse senior secured notes.  The net proceeds were distributed to Generation for general business purposes.  The loan is scheduled to mature on September 30, 2036.  The term loan bears interest at a fixed rate of 3.93% payable semi-annually.  As of December 31, 2019, $131 million was outstanding. In 2017, Generation’s interests in SolGen were also contributed to and are pledged as collateral for the EGR IV financing structure referenced below.

ExGen Renewables IV.    In November 2017, EGR IV, an indirect subsidiary of Exelon and Generation, entered into an $850 million nonrecourse senior secured term loan credit facility agreement. Generation’s interests in EGRP, Antelope Valley, SolGen, and Albany Green Energy were all contributed to and are pledged as collateral for this financing. The net proceeds of $785 million, after the initial funding of $50 million for debt service and liquidity reserves as well as deductions for original discount and estimated costs, fees and expenses incurred in connection with the execution and delivery of the credit facility agreement, were distributed to Generation for general corporate purposes. The $50 million of debt service and liquidity reserves was treated as restricted cash in Exelon’s and Generation’s Consolidated Balance Sheets and Consolidated Statements of Cash Flows. The loan is scheduled to mature on November 28, 2024. The term loan bears interest at a variable rate equal to LIBOR + 3%, subject to a 1% LIBOR floor with interest payable quarterly. As of December 31, 2019, $796 million was outstanding. In addition to the financing, EGR IV entered into interest rate swaps with an initial notional amount of $636 million at an interest rate of 2.32% to manage a portion of the interest rate exposure in connection with the financing.

Although Antelope Valley’s debt is in default, it is nonrecourse to EGR IV. However, if in the future Antelope Valley were to file for bankruptcy protection as a result of events culminating from PG&E’s bankruptcy proceedings this would represent an event of default for EGR IV’s debt that would provide the lender with an opportunity to accelerate EGR IV’s debt. See Note 22 - Variable Interest Entities for additional information on EGRP.

Exelon measure and records fair value measurements in accordance with the hierarchy as defined by GAAP. The hierarchy prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:

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

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

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

Fair Value of Financial Liabilities Recorded at the Carrying Amount

The following tables present the carrying amounts and fair values of the Registrants’ short-term liabilities, long-term debt, SNF obligation, and trust preferred securities (long-term debt to financing trusts or junior subordinated debentures) as of December 31, 2019 and 2018. The Registrants have no financial liabilities classified as Level 1.

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

		December 31, 2019																December 31, 2018
		Carrying Amount				Fair Value												Carrying Amount				Fair Value
						Level 2				Level 3				Total								Level 2				Level 3				Total
Long-Term Debt, including amounts due within one year(a)
Exelon		$	36,039			$	37,453			$	2,580			$	40,033			$	35,424			$	33,711			$	2,158			$	35,869
Generation		7,974				7,304				1,366				8,670				8,793				7,467				1,443				8,910
ComEd		8,491				9,848				—				9,848				8,101				8,390				—				8,390
PECO		3,405				3,868				50				3,918				3,084				3,157				50				3,207
BGE		3,270				3,649				—				3,649				2,876				2,950				—				2,950
PHI		6,563				5,902				1,164				7,066				6,259				5,436				665				6,101
Pepco		2,864				3,198				388				3,586				2,719				2,901				196				3,097
DPL		1,567				1,408				311				1,719				1,494				1,303				193				1,496
ACE		1,327				1,026				464				1,490				1,188				987				275				1,262
Long-Term Debt to Financing Trusts(a)
Exelon		$	390			$	—			$	428			$	428			$	390			$	—			$	400			$	400
ComEd		205				—				227				227				205				—				209				209
PECO		184				—				201				201				184				—				191				191
SNF Obligation
Exelon		$	1,199			$	1,055			$	—			$	1,055			$	1,171			$	949			$	—			$	949
Generation		1,199				1,055				—				1,055				1,171				949				—				949

________

(a) Includes unamortized debt issuance costs which are not fair valued. Refer to Note 16 — Debt and Credit Agreements for each Registrants’ unamortized debt issuance costs.

Exelon uses the following methods and assumptions to estimate fair value of financial liabilities recorded at carrying cost:

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Type	Level	Registrants	Valuation
Long-term debt, including amounts due within one year
Taxable Debt Securities	2	All	The fair value is determined by a valuation model that is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. Exelon obtains credit spreads based on trades of existing Exelon debt securities as well as other issuers in the utility sector with similar credit ratings. The yields are then converted into discount rates of various tenors that are used for discounting the respective cash flows of the same tenor for each bond or note.
Variable Rate Financing Debt	2	Exelon, Generation, DPL	Debt rates are reset on a regular basis and the carrying value approximates fair value.
Taxable Private Placement Debt Securities	3	Exelon, Pepco, DPL, ACE	Rates are obtained similar to the process for taxable debt securities. Due to low trading volume and qualitative factors such as market conditions, low volume of investors and investor demand, these debt securities are Level 3.
Government Backed Fixed Rate Project Financing Debt	3	Exelon, Generation	The fair value is similar to the process for taxable debt securities. Due to the lack of market trading data on similar debt, the discount rates are derived based on the original loan interest rate spread to the applicable U.S. Treasury rate as well as a current market curve derived from government-backed securities.
Non-Government Backed Fixed Rate Nonrecourse Debt	3	Exelon, Generation, Pepco	Fair value is based on market and quoted prices for its own and other nonrecourse debt with similar risk profiles. Given the low trading volume in the nonrecourse debt market, the price quotes used to determine fair value will reflect certain qualitative factors, such as market conditions, investor demand, new developments that might significantly impact the project cash flows or off-taker credit, and other circumstances related to the project
Long Term Debt to Financing Trusts	3	Exelon, ComEd, PECO	Fair value is based on publicly traded securities issued by the financing trusts. Due to low trading volume of these securities and qualitative factors, such as market conditions, investor demand, and circumstances related to each issue, this debt is classified as Level 3.
SNF Obligation	2	Exelon, Generation	The carrying amount 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 U.S. 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.

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Recurring Fair Value Measurements

The following tables present assets and liabilities measured and recorded at fair value in the Registrants' Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2019 and 2018:

	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

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	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

	Exelon																				Generation
As of December 31, 2018	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)	$	1,243			$	—			$	—			$	—			$	1,243			$	581			$	—			$	—			$	—			$	581
NDT fund investments
Cash equivalents(b)	252				86				—				—				338				252				86				—				—				338
Equities	2,918				1,591				—				1,381				5,890				2,918				1,591				—				1,381				5,890
Fixed income
Corporate debt	—				1,593				230				—				1,823				—				1,593				230				—				1,823
U.S. Treasury and agencies	2,081				99				—				—				2,180				2,081				99				—				—				2,180
Foreign governments	—				50				—				—				50				—				50				—				—				50
State and municipal debt	—				149				—				—				149				—				149				—				—				149
Other(c)	—				30				—				846				876				—				30				—				846				876
Fixed income subtotal	2,081				1,921				230				846				5,078				2,081				1,921				230				846				5,078
Private credit	—				—				313				367				680				—				—				313				367				680
Private equity	—				—				—				329				329				—				—				—				329				329
Real estate	—				—				—				510				510				—				—				—				510				510
NDT fund investments subtotal(d)	5,251				3,598				543				3,433				12,825				5,251				3,598				543				3,433				12,825

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	Exelon																				Generation
As of December 31, 2018	Level 1				Level 2				Level 3				Not subject to leveling				Total				Level 1				Level 2				Level 3				Not subject to leveling				Total
Rabbi trust investments
Cash equivalents	48				—				—				—				48				5				—				—				—				5
Mutual funds	72				—				—				—				72				24				—				—				—				24
Fixed income	—				15				—				—				15				—				—				—				—				—
Life insurance contracts	—				70				38				—				108				—				22				—				—				22
Rabbi trust investments subtotal	120				85				38				—				243				29				22				—				—				51
Commodity derivative assets
Economic hedges	541				2,760				1,470				—				4,771				541				2,760				1,470				—				4,771
Proprietary trading	—				69				77				—				146				—				69				77				—				146
Effect of netting and allocation of collateral(e)(f)	(582		)		(2,357		)		(732		)		—				(3,671		)		(582		)		(2,357		)		(732		)		—				(3,671		)
Commodity derivative assets subtotal	(41		)		472				815				—				1,246				(41		)		472				815				—				1,246
Total assets	6,573				4,155				1,396				3,433				15,557				5,820				4,092				1,358				3,433				14,703
Liabilities
Commodity derivative liabilities
Economic hedges	(642		)		(2,963		)		(1,276		)		—				(4,881		)		(642		)		(2,963		)		(1,027		)		—				(4,632		)
Proprietary trading	—				(73		)		(21		)		—				(94		)		—				(73		)		(21		)		—				(94		)
Effect of netting and allocation of collateral(e)(f)	639				2,581				808				—				4,028				639				2,581				808				—				4,028
Commodity derivative liabilities subtotal	(3		)		(455		)		(489		)		—				(947		)		(3		)		(455		)		(240		)		—				(698		)
Deferred compensation obligation	—				(137		)		—				—				(137		)		—				(35		)		—				—				(35		)
Total liabilities	(3		)		(592		)		(489		)		—				(1,084		)		(3		)		(490		)		(240		)		—				(733		)
Total net assets	$	6,570			$	3,563			$	907			$	3,433			$	14,473			$	5,817			$	3,602			$	1,118			$	3,433			$	13,970

__________

(a)

Exelon excludes cash of $373 million and $458 million at December 31, 2019 and 2018, respectively, and restricted cash of $110 million and $80 million at December 31, 2019 and 2018, respectively, and includes long-term restricted cash of $177 million and $185 million at December 31, 2019 and 2018, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. Generation excludes cash of $177 million and $283 million at December 31, 2019 and 2018, respectively and restricted cash of $58 million and $39 million at December 31, 2019 and 2018, respectively.

(b)	Includes $90 million and $50 million of cash received from outstanding repurchase agreements at December 31, 2019 and 2018, respectively, and is offset by an obligation to repay upon settlement of the agreement as discussed in (d) below.

(c)

Includes derivative instruments of $2 million and $44 million, which have a total notional amount of $724 million and $1,432 million at December 31, 2019 and 2018, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do not represent the amount of the company's exposure to credit or market loss.

(d)

Excludes net liabilities of $147 million and $130 million at December 31, 2019 and 2018, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, repurchase agreement obligations, and payables related to pending securities purchases. The repurchase agreements are generally short-term in nature with durations generally of 30 days or less.

(e)	Collateral posted/(received) from counterparties totaled $163 million, $551 million and $214 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2019. Collateral posted/(received) from

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counterparties totaled $57 million, $224 million and $76 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2018.

(f)	Of the collateral posted/(received), $511 million and $(94) million represents variation margin on the exchanges as of December 31, 2019 and 2018, respectively.

As of December 31, 2019, Generation has outstanding commitments to invest in fixed income, private credit, private equity and real estate investments of approximately $85 million, $166 million, $375 million and $427 million, respectively. These commitments will be funded by Generation’s existing NDT funds.

Exelon and Generation hold investments without readily determinable fair values with carrying amounts of $69 million as of December 31, 2019. Changes were immaterial in fair value, cumulative adjustments and impairments for the year ended December 31, 2019.

	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

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	ComEd																PECO																BGE
As of December 31, 2018	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)	$	209			$	—			$	—			$	209			$	111			$	—			$	—			$	111			$	4			$	—			$	—			$	4
Rabbi trust investments
Mutual funds	—				—				—				—				7				—				—				7				6				—				—				6
Life insurance contracts	—				—				—				—				—				10				—				10				—				—				—				—
Rabbi trust investments subtotal	—				—				—				—				7				10				—				17				6				—				—				6
Total assets	209				—				—				209				118				10				—				128				10				—				—				10
Liabilities
Deferred compensation obligation	—				(6		)		—				(6		)		—				(10		)		—				(10		)		—				(5		)		—				(5		)
Mark-to-market derivative liabilities(b)	—				—				(249		)		(249		)		—				—				—				—				—				—				—				—
Total liabilities	—				(6		)		(249		)		(255		)		—				(10		)		—				(10		)		—				(5		)		—				(5		)
Total net assets (liabilities)	$	209			$	(6	)		$	(249	)		$	(46	)		$	118			$	—			$	—			$	118			$	10			$	(5	)		$	—			$	5

__________

(a)

ComEd excludes cash of $90 million and $93 million at December 31, 2019 and 2018 and restricted cash of $33 million and $28 million at December 31, 2019 and 2018, respectively, and includes long-term restricted cash of $163 million and $166 million at December 31, 2019 and 2018, respectively which is reported in Other deferred debits in the Consolidated Balance Sheets.  PECO excludes cash of $12 million and $24 million at December 31, 2019 and 2018, respectively.  BGE excludes cash of $24 million and $7 million at December 31, 2019 and 2018, respectively, and restricted cash of $1 million and $2 million at December 31, 2019 and 2018, respectively.

(b)	The Level 3 balance consists of the current and noncurrent liability of $32 million and $269 million, respectively, at December 31, 2019, and $26 million and $223 million, respectively, at December 31, 2018, related to floating-to-fixed energy swap contracts with unaffiliated suppliers.

	As of December 31, 2019																As of December 31, 2018
PHI	Level 1				Level 2				Level 3				Total				Level 1				Level 2				Level 3				Total
Assets
Cash equivalents(a)	$	124			$	—			$	—			$	124			$	147			$	—			$	—			$	147
Rabbi trust investments
Cash equivalents	44				—				—				44				42				—				—				42
Mutual Funds	14				—				—				14				13				—				—				13
Fixed income	—				12				—				12				—				15				—				15
Life insurance contracts	—				24				41				65				—				22				38				60
Rabbi trust investments subtotal(b)	58				36				41				135				55				37				38				130
Total assets	182				36				41				259				202				37				38				277
Liabilities
Deferred compensation obligation	—				(19		)		—				(19		)		—				(21		)		—				(21		)
Total liabilities	—				(19		)		—				(19		)		—				(21		)		—				(21		)
Total net assets	$	182			$	17			$	41			$	240			$	202			$	16			$	38			$	256

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	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	$	77			$	24			$	41			$	142			$	—			$	—			$	—			$	—			$	16			$	—			$	—			$	16

	Pepco																DPL																ACE
As of December 31, 2018	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)	$	38			$	—			$	—			$	38			$	16			$	—			$	—			$	16			$	23			$	—			$	—			$	23
Rabbi trust investments
Cash equivalents	41				—				—				41				—				—				—				—				—				—				—				—
Fixed income	—				5				—				5				—				—				—				—				—				—				—				—
Life insurance contracts	—				22				37				59				—				—				—				—				—				—				—				—
Rabbi trust investments subtotal	41				27				37				105				—				—				—				—				—				—				—				—
Total assets	79				27				37				143				16				—				—				16				23				—				—				23
Liabilities
Deferred compensation obligation	—				(3		)		—				(3		)		—				(1		)		—				(1		)		—				—				—				—
Total liabilities	—				(3		)		—				(3		)		—				(1		)		—				(1		)		—				—				—				—
Total net assets	$	79			$	24			$	37			$	140			$	16			$	(1	)		$	—			$	15			$	23			$	—			$	—			$	23

__________

(a)

PHI excludes cash of $57 million and $39 million at December 31, 2019 and 2018, respectively, and includes long term restricted cash of $14 million and $19 million at December 31, 2019 and 2018, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets.  Pepco excludes cash of $29 million and $15 million at December 31, 2019 and 2018, respectively. DPL excludes cash of $13 million and $8 million at December 31, 2019 and 2018, respectively. ACE excludes cash of $12 million and $7 million at December 31, 2019 and 2018, respectively, and includes long-term restricted cash of $14 million and $19 million at December 31, 2019 and 2018, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets.

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The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 2019 and 2018:

	Exelon				Generation												ComEd				PHI and Pepco
For the year ended December 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 January 1, 2019	$	907			$	543			$	575			$	1,118			$	(249	)		$	38			$	—
Total realized / unrealized gains (losses)
Included in net income	(23		)		5				(31		)	(a)	(26		)		—				3				—
Included in noncurrent payables to affiliates	—				34				—				34				—				—				(34		)
Included in regulatory assets/liabilities	(18		)		—				—				—				(52		)	(b)	—				34
Change in collateral	138				—				138				138				—				—				—
Purchases, sales, issuances and settlements
Purchases	176				44				132				176				—				—				—
Sales	(23		)		(21		)		(2		)		(23		)		—				—				—
Settlements	(89		)		(94		)		5				(89		)		—				—				—
Transfers into Level 3	5				—				5			(c)	5				—				—				—
Transfers out of Level 3	(5		)		—				(5		)	(c)	(5		)		—				—				—
Balance as of December 31, 2019	$	1,068			$	511			$	817			$	1,328			$	(301	)		$	41			$	—
The amount of total gains (losses) included in income attributed to the change in unrealized (losses) gains related to assets and liabilities held as of December 31, 2019	$	359			$	5			$	351			$	356			$	—			$	3			$	—

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	Exelon				Generation												ComEd				PHI and Pepco
For the year ended December 31, 2018	Total				NDT Fund Investments				Mark-to-Market Derivatives				Total Generation				Mark-to-Market Derivatives				Life Insurance Contracts				Eliminated in Consolidation
Balance as of January 1, 2018	$	966			$	648			$	552			$	1,200			$	(256	)		$	22			$	—
Total realized / unrealized gains (losses)
Included in net income	(101		)		—				(105		)	(a)	(105		)		—				4				—
Included in noncurrent payables to affiliates	—				(1		)		—				(1		)		—				—				1
Included in regulatory assets/liabilities	6				—				—				—				7			(b)	—				(1		)
Change in collateral	(5		)		—				(5		)		(5		)		—				—				—
Purchases, sales, issuances and settlements
Purchases	226				36				190				226				—				—				—
Sales	(4		)		—				(4		)		(4		)		—				—				—
Settlements	(123		)		(140		)		5				(135		)		—				12				—
Transfers into Level 3	(22		)		—				(22		)	(c)	(22		)		—				—				—
Transfers out of Level 3	(36		)		—				(36		)	(c)	(36		)		—				—				—
Balance as of December 31, 2018	$	907			$	543			$	575			$	1,118			$	(249	)		$	38			$	—
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held as of December 31, 2018	$	160			$	(5	)		$	165			$	160			$	—			$	—			$	—

__________

(a)	Includes a reduction for the reclassification of $377 million and $265 million of realized gains due to the settlement of derivative contracts for the years ended December 31, 2019 and 2018, respectively.

(b)

Includes $78 million of decreases in fair value and an increase for realized losses due to settlements of $26 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2019. Includes $24 million of decreases in fair value and an increase for realized losses due to settlements of $17 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2018.

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

The following tables present the income statement classification of the total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 2019 and 2018:

	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 gains (losses) included in net income for the year ended December 31, 2019	$	219			$	(245	)		$	3			$	5			$	219			$	(245	)		$	5			$	3
Change in the unrealized gains (losses) relating to assets and liabilities held for the year ended December 31, 2019	546				(195		)		3				5				546				(195		)		5				3

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	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 (losses) gains included in net income for the year ended December 31, 2018	$	(7	)		$	(93	)		$	4			$	3			$	(7	)		$	(93	)		$	3			$	4
Change in the unrealized gains (losses) relating to assets and liabilities held for the year ended December 31, 2018	144				21				—				(2		)		144				21				(2		)		—

Valuation Techniques Used to Determine Fair Value

Cash Equivalents (All Registrants). Investments with original maturities of three months or less when purchased, including mutual and money market funds, are considered cash equivalents. The fair values are based on observable market prices and, therefore, are included in the recurring fair value measurements hierarchy as Level 1.

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

Equities. These investments consist of individually held equity securities, equity mutual funds and equity commingled funds in domestic and foreign markets. With respect to individually held equity securities, the trustees obtain prices from pricing services, whose prices are generally obtained from direct feeds from market exchanges, which Exelon and Generation are able to independently corroborate. Equity securities held individually, including real estate investment trusts, rights and warrants, are primarily traded on exchanges that contain only actively traded securities due to the volume trading requirements imposed by these exchanges. The equity securities that are held directly by the trust funds are valued based on quoted prices in active markets and categorized as Level 1. Certain equity securities have been categorized as Level 2 because they are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities. Certain private placement equity securities are categorized as Level 3 because they are not publicly traded and are priced using significant unobservable inputs.

Equity commingled funds and mutual funds are maintained by investment companies, and fund investments are held in accordance with a stated set of fund objectives. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized as Level 1. For equity commingled funds and mutual funds which are not publicly quoted, the fund administrators value the funds using the NAV per fund share, derived from the quoted prices in active markets of the underlying securities and are not classified within the fair value hierarchy. These investments typically can be redeemed monthly or more frequently, with 30 or less days of notice and without further restrictions.

Fixed income. For fixed income securities, which consist primarily of corporate debt securities, U.S. government securities, foreign government securities, municipal bonds, asset and mortgage-backed securities, commingled funds, mutual funds and derivative instruments, the trustees obtain multiple prices from pricing vendors whenever possible, which enables cross-provider validations in addition to checks for unusual daily movements. A primary price source is identified based on asset type, class or issue for each security. With respect to individually held fixed income securities, the trustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the portfolio managers challenge an assigned price and the trustees determine that another price source is considered to be preferable. Exelon and Generation have obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, Exelon and Generation selectively corroborate the fair values of securities by comparison to other market-based price sources. Investments in U.S. Treasury securities have been categorized as Level 1 because they trade in highly-liquid and transparent markets. Certain private placement fixed income securities have been categorized as Level 3 because they are priced using certain significant unobservable inputs and are typically illiquid. The remaining fixed income securities, including certain other fixed income investments,

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are based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences and are categorized as Level 2.

Other fixed income investments primarily consist of fixed income commingled funds and mutual funds, which are maintained by investment companies and hold fund investments in accordance with a stated set of fund objectives. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized as Level 1. For fixed income commingled funds and mutual funds which are not publicly quoted, the fund administrators value the funds using the NAV per fund share, derived from the quoted prices in active markets of the underlying securities and are not classified within the fair value hierarchy. These investments typically can be redeemed monthly or more frequently, with 30 or less days of notice and without further restrictions.

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

Private credit. Private credit investments primarily consist of investments in private debt strategies. These investments are generally less liquid assets with an underlying term of 3 to 5 years and are intended to be held to maturity.  The fair value of these investments is determined by the fund manager or administrator and include unobservable inputs such as cost, operating results, and discounted cash flows. Private credit investments held directly by Exelon and Generation are categorized as Level 3 because they are based largely on inputs that are unobservable and utilize complex valuation models. Private credit fund investments with multiple investors are not classified within the fair value hierarchy because their fair value is determined using NAV or its equivalent as a practical expedient.

Private equity. These investments include those in limited partnerships that invest in operating companies that are not publicly traded on a stock exchange such as leveraged buyouts, growth capital, venture capital, distressed investments and investments in natural resources. Private equity valuations are reported by the fund manager and are based on the valuation of the underlying investments, which include unobservable inputs such as cost, operating results, discounted future cash flows and market based comparable data. The fair value of private equity investments is determined using NAV or its equivalent as a practical expedient, and therefore, these investments are not classified within the fair value hierarchy.

Real estate. These investments are funds with a direct investment in pools of real estate properties. These funds are valued by investment managers on a periodic basis using pricing models that use independent appraisals from sources with professional qualifications. These valuation inputs are not highly observable. The fair value of real estate investments is determined using NAV or its equivalent as a practical expedient, and therefore, these investments are not classified within the fair value hierarchy.

Generation evaluated its NDT portfolios for the existence of significant concentrations of credit risk as of December 31, 2019. Types of concentrations that were evaluated include, but are not limited to, investment concentrations in a single entity, type of industry, foreign country, and individual fund. As of December 31, 2019, there were no significant concentrations (generally defined as greater than 10 percent) of risk in Generation's NDT assets.

See Note 9 — Asset Retirement Obligations for additional information on the NDT fund investments. See Note 14 — Retirement Benefits for the valuation techniques used for hedge fund investments.

Rabbi Trust Investments (Exelon, Generation, PECO, BGE, PHI, Pepco, DPL and ACE). The Rabbi trusts were established to hold assets related to deferred compensation plans existing for certain active and retired members of Exelon’s executive management and directors. The Rabbi trusts' assets are included in investments in the Registrants’ Consolidated Balance Sheets and consist primarily of money market funds, mutual funds, fixed income securities and life insurance policies. Money market funds and mutual funds are publicly quoted and have been categorized as Level 1 given the clear observability of the prices. The fair values of fixed income securities are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities, adjusted for observable differences and are categorized in Level 2. The life insurance policies are valued using the cash surrender value of the policies, net of loans against those policies, which is provided by a third-party. Certain life insurance policies, which consist primarily of mutual funds that are priced based on observable market

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data, have been categorized as Level 2 because the life insurance policies can be liquidated at the reporting date for the value of the underlying assets. Life insurance policies that are valued using unobservable inputs have been categorized as Level 3, where the fair value is determined based on the cash surrender value of the policy, which contains unobservable inputs and assumptions. Because Exelon relies on its third-party insurance provider to develop the inputs without adjustment for the valuations of its Level 3 investments, quantitative information about significant unobservable inputs used in valuing these investments is not reasonably available to Exelon. Therefore, Exelon has not disclosed such inputs.

Deferred Compensation Obligations (All Registrants).  The Registrants’ deferred compensation plans allow participants to defer certain cash compensation into a notional investment account. The Registrants include such plans in other current and noncurrent liabilities in their Consolidated Balance Sheets. The value of the Registrants’ deferred compensation obligations is based on the market value of the participants’ notional investment accounts. The underlying notional investments are comprised primarily of equities, mutual funds, commingled funds and fixed income securities which are based on directly and indirectly observable market prices. Since the deferred compensation obligations themselves are not exchanged in an active market, they are categorized as Level 2 in the fair value hierarchy.

The value of certain employment agreement obligations (which are included with the Deferred Compensation Obligation in the tables above) are based on a known and certain stream of payments to be made over time and are categorized as Level 2 within the fair value hierarchy.

Mark-to-Market Derivatives (Exelon, Generation, ComEd, PHI and DPL). Derivative contracts are traded in both exchange-based and non-exchange-based markets. Exchange-based derivatives that are valued using unadjusted quoted prices in active markets are categorized in Level 1 in the fair value hierarchy. Certain derivatives’ pricing is verified using indicative price quotations available through brokers or over-the-counter, on-line exchanges and are categorized in Level 2. These price quotations reflect the average of the bid-ask, mid-point prices and are obtained from sources that the Registrants believe provide the most liquid market for the commodity. The price quotations are reviewed and corroborated to ensure the prices are observable and representative of an orderly transaction between market participants. This includes consideration of actual transaction volumes, market delivery points, bid-ask spreads and contract duration. The remainder of derivative contracts are valued using the Black model, an industry standard option valuation model. The Black model takes into account inputs such as contract terms, including maturity, and market parameters, including assumptions of the future prices of energy, interest rates, volatility, credit worthiness and credit spread. For derivatives that trade in liquid markets, such as generic forwards, swaps and options, model inputs are generally observable. Such instruments are categorized in Level 2. The Registrants’ derivatives are predominantly at liquid trading points. For derivatives that trade in less liquid markets with limited pricing information, model inputs generally would include both observable and unobservable inputs. These valuations may include an estimated basis adjustment from an illiquid trading point to a liquid trading point for which active price quotations are available. Such instruments are categorized in Level 3.

For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations whose contract tenure extends into unobservable periods. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility and contract duration. Such instruments are categorized in Level 3 as the model inputs generally are not observable. Forward price curves for the power market utilized by the front office to manage the portfolio, are reviewed and verified by the middle office, and used for financial reporting by the back office. The Registrants consider credit and nonperformance risk in the valuation of derivative contracts categorized in Level 2 and 3, including both historical and current market data in its assessment of credit and nonperformance risk by counterparty. Due to master netting agreements and collateral posting requirements, the impacts of credit and nonperformance risk were not material to the financial statements.

Disclosed below is detail surrounding the Registrants’ significant Level 3 valuations. The calculated fair value includes marketability discounts for margining provisions and other attributes. Generation’s Level 3 balance generally consists of forward sales and purchases of power and natural gas and certain transmission congestion contracts. Generation utilizes various inputs and factors including market data and assumptions that market participants would use in pricing assets or liabilities as well as assumptions about the risks inherent in the inputs to the valuation technique. The inputs and factors include forward commodity prices, commodity price volatility, contractual volumes, delivery location, interest rates, credit quality of counterparties and credit enhancements.

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For commodity derivatives, the primary input to the valuation models is the forward commodity price curve for each instrument. Forward commodity price curves are derived by risk management for liquid locations and by the traders and portfolio managers for illiquid locations. All locations are reviewed and verified by risk management considering published exchange transaction prices, executed bilateral transactions, broker quotes, and other observable or public data sources. The relevant forward commodity curve used to value each of the derivatives depends on a number of factors, including commodity type, delivery location, and delivery period. Price volatility varies by commodity and location. When appropriate, Generation discounts future cash flows using risk free interest rates with adjustments to reflect the credit quality of each counterparty for assets and Generation’s own credit quality for liabilities. The level of observability of a forward commodity price varies generally due to the delivery location and delivery period. Certain delivery locations including PJM West Hub (for power) and Henry Hub (for natural gas) are more liquid and prices are observable for up to three years in the future. The observability period of volatility is generally shorter than the underlying power curve used in option valuations. The forward curve for a less liquid location is estimated by using the forward curve from the liquid location and applying a spread to represent the cost to transport the commodity to the delivery location. This spread does not typically represent a majority of the instrument’s market price. As a result, the change in fair value is closely tied to liquid market movements and not a change in the applied spread. The change in fair value associated with a change in the spread is generally immaterial. An average spread calculated across all Level 3 power and gas delivery locations is approximately $2.22 and $0.54 for power and natural gas, respectively. Many of the commodity derivatives are short term in nature and thus a majority of the fair value may be based on observable inputs even though the contract as a whole must be classified as Level 3.

On December 17, 2010, ComEd entered into several 20-year floating to fixed energy swap contracts with unaffiliated suppliers for the procurement of long-term renewable energy and associated RECs. See Note 15 — Derivative Financial Instruments for additional information. The fair value of these swaps has been designated as a Level 3 valuation due to the long tenure of the positions and internal modeling assumptions. The modeling assumptions include using natural gas heat rates to project long term forward power curves adjusted by a renewable factor that incorporates time of day and seasonality factors to reflect accurate renewable energy pricing. In addition, marketability reserves are applied to the positions based on the tenor and supplier risk.

See Note 15 — Derivative Financial Instruments for additional information on mark-to-market derivatives.

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The following table presents the significant inputs to the forward curve used to value these positions:

Type of trade		Fair Value at December 31, 2019			Fair Value at December 31, 2018			Valuation Technique		Unobservable Input		2019 Range			2018 Range
Mark-to-market derivatives—Economic hedges (Exelon and Generation)(a)(b)		$	558		$	443		Discounted Cash Flow		Forward power price		$9	-	$180	$12	-	$174
										Forward gas price		$0.83	-	$10.72	$0.78	-	$12.38
								Option Model		Volatility percentage		8%	-	236%	10%	-	277%
Mark-to-market derivatives—Proprietary trading (Exelon and Generation)(a)(b)		$	45		$	56		Discounted Cash Flow		Forward power price		$25	-	$180	$14	-	$174
Mark-to-market derivatives (Exelon and ComEd)		$	(301	)	$	(249	)	Discounted Cash Flow		Forward heat rate(c)		9X	-	10X	10X	-	11X
										Marketability reserve		3%	-	7%	4%	-	8%
										Renewable factor		91%	-	123%	86%	-	120%

______

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

(b)	The fair values do not include cash collateral posted on level three positions of $214 million and $76 million as of December 31, 2019 and December 31, 2018, respectively.

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

The inputs listed above, which are as of the balance sheet date, would have a direct impact on the fair values of the above instruments if they were adjusted. The significant unobservable inputs used in the fair value measurement of Generation’s commodity derivatives are forward commodity prices and for options is price volatility. Increases (decreases) in the forward commodity price in isolation would result in significantly higher (lower) fair values for long positions (contracts that give Generation the obligation or option to purchase a commodity), with offsetting impacts to short positions (contracts that give Generation the obligation or right to sell a commodity). Increases (decreases) in volatility would increase (decrease) the value for the holder of the option (writer of the option). Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of volatility of prices. An increase to the reserves listed above would decrease the fair value of the positions. An increase to the heat rate or renewable factors would increase the fair value accordingly. Generally, interrelationships exist between market prices of natural gas and power. As such, an increase in natural gas pricing would potentially have a similar impact on forward power markets.

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Commitments

PHI Merger Commitments (Exelon, PHI, Pepco, DPL and ACE). Approval of the PHI Merger in Delaware, New Jersey, Maryland and the District of Columbia was conditioned upon Exelon and PHI agreeing to certain commitments. The following amounts represent total commitment costs that have been recorded since the acquisition date and the total remaining obligations for Exelon, PHI, Pepco, DPL and ACE as of December 31, 2019:

Description	Exelon				PHI				Pepco				DPL				ACE
Total commitments	$	513			$	320			$	120			$	89			$	111
Remaining commitments(a)	$	101			$	79			$	65			$	8			$	6

_________

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

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

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Commercial Commitments (All Registrants). The Registrants' commercial commitments as of December 31, 2019, representing commitments potentially triggered by future events, were as follows:

					Expiration within
Exelon	Total				2020				2021				2022				2023				2024				2025 and beyond
Letters of credit	$	1,455			$	1,314			$	141			$	—			$	—			$	—			$	—
Surety bonds(a)	855				809				46				—				—				—				—
Financing trust guarantees	378				—				—				—				—				—				378
Guaranteed lease residual values(b)	26				2				2				4				3				6				10
Total commercial commitments	$	2,714			$	2,125			$	189			$	4			$	3			$	6			$	388
Generation
Letters of credit	$	1,440			$	1,302			$	138			$	—			$	—			$	—			$	—
Surety bonds(a)	670				662				8				—				—				—				—
Total commercial commitments	$	2,110			$	1,964			$	146			$	—			$	—			$	—			$	—
ComEd
Letters of credit	$	7			$	7			$	—			$	—			$	—			$	—			$	—
Surety bonds(a)	50				48				2				—				—				—				—
Financing trust guarantees	200				—				—				—				—				—				200
Total commercial commitments	$	257			$	55			$	2			$	—			$	—			$	—			$	200
PECO
Surety bonds(a)	$	9			$	9			$	—			$	—			$	—			$	—			$	—
Financing trust guarantees	178				—				—				—				—				—				178
Total commercial commitments	$	187			$	9			$	—			$	—			$	—			$	—			$	178
BGE
Letters of credit	$	2			$	2			$	—			$	—			$	—			$	—			$	—
Surety bonds(a)	3				3				—				—				—				—				—
Total commercial commitments	$	5			$	5			$	—			$	—			$	—			$	—			$	—
PHI
Surety bonds(a)	$	21			$	21			$	—			$	—			$	—			$	—			$	—
Guaranteed lease residual values(b)	26				2				2				4				3				6				10
Total commercial commitments	$	47			$	23			$	2			$	4			$	3			$	6			$	10
Pepco
Surety bonds(a)	$	14			$	14			$	—			$	—			$	—			$	—			$	—
Guaranteed lease residual values(b)	9				—				—				1				1				2				5
Total commercial commitments	$	23			$	14			$	—			$	1			$	1			$	2			$	5
DPL
Surety bonds(a)	$	4			$	4			$	—			$	—			$	—			$	—			$	—
Guaranteed lease residual values(b)	11				1				1				2				1				3				3
Total commercial commitments	$	15			$	5			$	1			$	2			$	1			$	3			$	3
ACE
Surety bonds(a)	$	3			$	3			$	—			$	—			$	—			$	—			$	—
Guaranteed lease residual values(b)	7				1				1				1				1				1				2
Total commercial commitments	$	10			$	4			$	1			$	1			$	1			$	1			$	2

_________

(a)	Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.

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(b)

Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The lease term associated with these assets ranges from 1 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $69 million guaranteed by Exelon and PHI, of which $23 million, $29 million and $18 million is guaranteed by Pepco, DPL and ACE, respectively. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.

Nuclear Insurance (Exelon and Generation)

Generation is subject to liability, property damage and other risks associated with major incidents at any of its nuclear stations. Generation has mitigated its financial exposure to these risks through insurance and other industry risk-sharing provisions.

The Price-Anderson Act was enacted to ensure the availability of funds for public liability claims arising from an incident at any of the U.S. licensed nuclear facilities and to limit the liability of nuclear reactor owners for such claims from any single incident. As of December 31, 2019, the current liability limit per incident is $13.9 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors at least once every five years with the last adjustment effective November 1, 2018. In accordance with the Price-Anderson Act, Generation maintains financial protection at levels equal to the amount of liability insurance available from private sources through the purchase of private nuclear energy liability insurance for public liability claims that could arise in the event of an incident. Effective January 1, 2017, the required amount of nuclear energy liability insurance purchased is $450 million for each operating site. Claims exceeding that amount are covered through mandatory participation in a financial protection pool, as required by the Price Anderson-Act, which provides the additional $13.5 billion per incident in funds available for public liability claims. Participation in this secondary financial protection pool requires the operator of each reactor to fund its proportionate share of costs for any single incident that exceeds the primary layer of financial protection. Exelon’s share of this secondary layer would be approximately $2.9 billion, however any amounts payable under this secondary layer would be capped at $434 million per year.

In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay public liability claims exceeding the $13.9 billion limit for a single incident.

As part of the execution of the NOSA on April 1, 2014, Generation executed an Indemnity Agreement pursuant to which Generation agreed to indemnify EDF and its affiliates against third-party claims that may arise from any future nuclear incident (as defined in the Price-Anderson Act) in connection with the CENG nuclear plants or their operations. Exelon guarantees Generation’s obligations under this indemnity. See Note 22 — Variable Interest Entities for additional information on Generation’s operations relating to CENG.

Generation is required each year to report to the NRC the current levels and sources of property insurance that demonstrates Generation possesses sufficient financial resources to stabilize and decontaminate a reactor and reactor station site in the event of an accident. The property insurance maintained for each facility is currently provided through insurance policies purchased from NEIL, an industry mutual insurance company of which Generation is a member.

NEIL may declare distributions to its members as a result of favorable operating experience. In recent years, NEIL has made distributions to its members, but Generation cannot predict the level of future distributions or if they will continue at all. Generation's portion of the annual distribution declared by NEIL is estimated to be $136 million for 2019, and was $58 million and $60 million for 2018 and 2017, respectively. In addition, in March 2018, NEIL declared a supplemental distribution. Generation's portion of the supplemental distribution declared by NEIL was $31 million. The distributions were recorded as a reduction to Operating and maintenance expense within Exelon and Generation’s Consolidated Statements of Operations and Comprehensive Income.

Premiums paid to NEIL by its members are also subject to a potential assessment for adverse loss experience in the form of a retrospective premium obligation. NEIL has never assessed this retrospective premium since its formation in 1973, and Generation cannot predict the level of future assessments, if any. The current maximum aggregate annual retrospective premium obligation for Generation is approximately $334 million. NEIL requires its members to maintain an investment grade credit rating or to ensure collectability of their annual retrospective premium obligation by providing a financial guarantee, letter of credit, deposit premium, or some other means of assurance.

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NEIL provides “all risk” property damage, decontamination and premature decommissioning insurance for each station for losses resulting from damage to its nuclear plants, either due to accidents or acts of terrorism. If the decision is made to decommission the facility, a portion of the insurance proceeds will be allocated to a fund, which Generation is required by the NRC to maintain, to provide for decommissioning the facility. In the event of an insured loss, Generation is unable to predict the timing of the availability of insurance proceeds to Generation and the amount of such proceeds that would be available. In the event that one or more acts of terrorism cause accidental property damage within a twelve-month period from the first accidental property damage under one or more policies for all insured plants, the maximum recovery by Exelon will be an aggregate of $3.2 billion plus such additional amounts as the insurer may recover for all such losses from reinsurance, indemnity and any other source, applicable to such losses.

For its insured losses, Generation is self-insured to the extent that losses are within the policy deductible or exceed the amount of insurance maintained. Uninsured losses and other expenses, to the extent not recoverable from insurers or the nuclear industry, could also be borne by Generation. Any such losses could have a material adverse effect on Exelon’s and Generation’s financial statements.

Spent Nuclear Fuel Obligation (Exelon and Generation)

Under the NWPA, the DOE is responsible for the development of a geologic repository for and the disposal of SNF and high-level radioactive waste. As required by the NWPA, Generation is a party to contracts with the DOE (Standard Contracts) to provide for disposal of SNF from Generation’s nuclear generating stations. In accordance with the NWPA and the Standard Contracts, Generation historically had paid the DOE one mill ($0.001) per kWh of net nuclear generation for the cost of SNF disposal. Due to the lack of a viable disposal program, the DOE reduced the SNF disposal fee to zero in May 2014. Until a new fee structure is in effect, Exelon and Generation will not accrue any further costs related to SNF disposal fees. This fee may be adjusted prospectively to ensure full cost recovery.

Generation currently assumes the DOE will begin accepting SNF in 2030 and uses that date for purposes of estimating the nuclear decommissioning asset retirement obligations. The SNF acceptance date assumption is based on management’s estimates of the amount of time required for DOE to select a site location and develop the necessary infrastructure for long-term SNF storage.

The NWPA and the Standard Contracts required the DOE to begin taking possession of SNF generated by nuclear generating units by no later than January 31, 1998. The DOE, however, failed to meet that deadline and its performance is expected to be delayed significantly. In August 2004, Generation and the DOJ, in close consultation with the DOE, reached a settlement under which the government agreed to reimburse Generation, subject to certain damage limitations based on the extent of the government’s breach, for costs associated with storage of SNF at Generation’s nuclear stations pending the DOE’s fulfillment of its obligations. Generation’s settlement agreement does not include FitzPatrick and FitzPatrick does not currently have a settlement agreement in place. Calvert Cliffs, Ginna and Nine Mile Point each have separate settlement agreements in place with the DOE which were extended during 2017 to provide for the reimbursement of SNF storage costs through December 31, 2019. Generation expects the terms for each of the settlement agreements to be extended during 2020 for another three years to cover SNF storage costs through December 31, 2022. Generation submits annual reimbursement requests to the DOE for costs associated with the storage of SNF. In all cases, reimbursement requests are made only after costs are incurred and only for costs resulting from DOE delays in accepting the SNF.

Under the settlement agreements, Generation has received cumulative cash reimbursements for costs incurred as follows:

	Total				Net(a)
Cumulative cash reimbursements	$	1,288			$	1,113

__________

(a)	Total after considering amounts due to co-owners of certain nuclear stations and to the former owner of Oyster Creek.

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As of December 31, 2019 and 2018, the amount of SNF storage costs for which reimbursement has been or will be requested from the DOE under the DOE settlement agreements is as follows:

	December 31, 2019				December 31, 2018
DOE receivable - current(a)	$	249			$	124
DOE receivable - noncurrent(b)	30				15
Amounts owed to co-owners(a)(c)	(37		)		(17		)

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(a)	Recorded in Accounts receivable, other.

(b)	Recorded in Deferred debits and other assets, other.

(c)	Non-CENG amounts owed to co-owners are recorded in Accounts receivable, other.  CENG amounts owed to co-owners are recorded in Accounts payable. Represents amounts owed to the co-owners of Peach Bottom, Quad Cities, and Nine Mile Point Unit 2 generating facilities.

The Standard Contracts with the DOE also required the payment to the DOE of a one-time fee applicable to nuclear generation through April 6, 1983. The below table outlines the SNF liability recorded at Exelon and Generation as of December 31, 2019 and 2018:

	December 31, 2019				December 31, 2018
Former ComEd units(a)	$	1,075			$	1,052
Fitzpatrick(b)	124				119
Total SNF Obligation	$	1,199			$	1,171

__________

(a)	ComEd previously elected to defer payment of the one-time fee of $277 million for its units (which are now part of Generation), with interest to the date of payment, until just prior to the first delivery of SNF to the DOE. The unfunded liabilities for SNF disposal costs, including the one-time fee, were transferred to Generation as part of Exelon’s 2001 corporate restructuring.

(b)

A prior owner of FitzPatrick elected to defer payment of the one-time fee of $34 million, with interest to the date of payment, for the FitzPatrick unit. As part of the FitzPatrick acquisition on March 31, 2017, Generation assumed a SNF liability for the DOE one-time fee obligation with interest related to FitzPatrick along with an offsetting asset, included in Other deferred debits and other assets, for the contractual right to reimbursement from NYPA, a prior owner of FitzPatrick, for amounts paid for the FitzPatrick DOE one-time fee obligation.

Interest for Exelon's and Generation's SNF liabilities accrues at the 13-week Treasury Rate. The 13-week Treasury Rate in effect for calculation of the interest accrual at December 31, 2019 was 1.551% for the deferred amount transferred from ComEd and 1.879% for the deferred FitzPatrick amount.

The following table summarizes sites for which Exelon and Generation do not have an outstanding SNF Obligation:

Description	Sites
Fees have been paid	Former PECO units, Clinton and Calvert Cliffs
Outstanding SNF Obligation remains with former owners	Nine Mile Point, Ginna and TMI

Environmental Remediation Matters

General (All Registrants). The Registrants’ operations have in the past, and may in the future, require substantial expenditures to comply with environmental laws. Additionally, under Federal and state environmental laws, the Registrants are generally liable for the costs of remediating environmental contamination of property now or formerly owned by them and of property contaminated by hazardous substances generated by them. The Registrants own or lease a number of real estate parcels, including parcels on which their operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. In addition, the Registrants are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future. Unless otherwise disclosed, the Registrants cannot reasonably estimate whether they will incur significant liabilities for additional investigation and remediation costs at these or additional sites identified by the Registrants, environmental agencies

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or others, or whether such costs will be recoverable from third parties, including customers. Additional costs could have a material, unfavorable impact on the Registrants' financial statements.

MGP Sites (Exelon and the Utility Registrants). ComEd, PECO, BGE and DPL have identified sites where former MGP or gas purification activities have or may have resulted in actual site contamination. For almost all of these sites, there are additional PRPs that may share responsibility for the ultimate remediation of each location.

•	ComEd has 21 sites that are currently under some degree of active study and/or remediation. ComEd expects the majority of the remediation at these sites to continue through at least 2025.

•	PECO has 8 sites that are currently under some degree of active study and/or remediation. PECO expects the majority of the remediation at these sites to continue through at least 2022.

•	BGE has 4 sites that currently require some level of remediation and/or ongoing activity. BGE expects the majority of the remediation at these sites to continue through at least 2021.

•	DPL has 1 site that is currently under study and the required cost at the site is not expected to be material.

The historical nature of the MGP and gas purification sites and the fact that many of the sites have been buried and built over, impacts the ability to determine a precise estimate of the ultimate costs prior to initial sampling and determination of the exact scope and method of remedial activity. Management determines its best estimate of remediation costs using all available information at the time of each study, including probabilistic and deterministic modeling for ComEd and PECO, and the remediation standards currently required by the applicable state environmental agency. Prior to completion of any significant clean up, each site remediation plan is approved by the appropriate state environmental agency.

ComEd, pursuant to an ICC order, and PECO, pursuant to settlements of natural gas distribution rate cases with the PAPUC, are currently recovering environmental remediation costs of former MGP facility sites through customer rates. While BGE and DPL do not have riders for MGP clean-up costs, they have historically received recovery of actual clean-up costs in distribution rates.

As of December 31, 2019 and 2018, the Registrants had accrued the following undiscounted amounts for environmental liabilities in Other current liabilities and Other deferred credits and other liabilities within their respective Consolidated Balance Sheets:

	December 31, 2019								December 31, 2018
	Total environmental investigation and remediation reserve				Portion of total related to MGP investigation and remediation				Total environmental investigation and remediation reserve				Portion of total related to MGP investigation and remediation
Exelon	$	478			$	320			$	496			$	356
Generation	105				—				108				—
ComEd	304				303				329				327
PECO	19				17				27				25
BGE	2				—				5				4
PHI	48				—				27				—
Pepco	46				—				25				—
DPL	1				—				1				—
ACE	1				—				1				—

Cotter Corporation (Exelon and Generation). The EPA has advised Cotter Corporation (Cotter), a former ComEd subsidiary, that it is potentially liable in connection with radiological contamination at a site known as the West Lake Landfill in Missouri. In 2000, ComEd sold Cotter to an unaffiliated third-party. As part of the sale, ComEd agreed to indemnify Cotter for any liability arising in connection with the West Lake Landfill. In connection with Exelon’s 2001 corporate restructuring, this responsibility to indemnify Cotter was transferred to Generation. Including Cotter, there are three PRPs participating in the West Lake Landfill remediation proceeding. Investigation by Generation has identified a number of other parties who also may be PRPs and could be liable to contribute to the final remedy. Further investigation is ongoing.

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In September 2018, the EPA issued its Record of Decision (ROD) Amendment for the selection of the final remedy. The ROD modified the EPA’s previously proposed plan for partial excavation of the radiological materials by reducing the depths of the excavation. The ROD also allows for variation in depths of excavation depending on radiological concentrations. The EPA and the PRPs have entered into a Consent Agreement to perform the Remedial Design, which is expected to be completed in the 2020 - 2021 time frame. In March 2019 the PRPs received Special Notice Letters from the EPA to perform the Remedial Action work. On October 8, 2019, Generation provided a non-binding good faith offer to conduct, or finance, a portion of the remedy, subject to certain conditions. The total estimated cost of the remedy, taking into account the current EPA technical requirements and the total costs expected to be incurred collectively by the PRPs in fully executing the remedy, is approximately $280 million, including cost escalation on an undiscounted basis, which would be allocated among the final group of PRPs. Generation has determined that a loss associated with the EPA’s partial excavation and enhanced landfill cover remedy is probable and has recorded a liability included in the table above, that reflects management’s best estimate of Cotter’s allocable share of the ultimate cost. Given the joint and several nature of this liability, the magnitude of Generation’s ultimate liability will depend on the actual costs incurred to implement the required remediation remedy as well as on the nature and terms of any cost-sharing arrangements with the final group of PRPs. Therefore, it is reasonably possible that the ultimate cost and Generation’s associated allocable share could differ significantly once these uncertainties are resolved, which could have a material impact on Exelon's and Generation's future financial statements.

One of the other PRPs has indicated it will be making a contribution claim against Cotter for costs that it has incurred to prevent the subsurface fire from spreading to those areas of the West Lake Landfill where radiological materials are believed to have been disposed. At this time, Exelon and Generation do not possess sufficient information to assess this claim and therefore are unable to estimate a range of loss, if any. As such, no liability has been recorded for the potential contribution claim. It is reasonably possible, however, that resolution of this matter could have a material, unfavorable impact on Exelon’s and Generation's financial statements.

In January 2018, the PRPs were advised by the EPA that it will begin an additional investigation and evaluation of groundwater conditions at the West Lake Landfill. In September 2018, the PRPs agreed to an Administrative Settlement Agreement and Order on Consent for the performance by the PRPs of the groundwater Remedial Investigation (RI)/Feasibility Study (FS). The purpose of this RI/FS is to define the nature and extent of any groundwater contamination from the West Lake Landfill site and evaluate remedial alternatives. Generation estimates the undiscounted cost for the groundwater RI/FS to be approximately $20 million. Generation determined a loss associated with the RI/FS is probable and has recorded a liability included in the table above that reflects management’s best estimate of Cotter’s allocable share of the cost among the PRPs. At this time Generation cannot predict the likelihood or the extent to which, if any, remediation activities may be required and therefore cannot estimate a reasonably possible range of loss for response costs beyond those associated with the RI/FS component. It is reasonably possible, however, that resolution of this matter could have a material, unfavorable impact on Exelon’s and Generation’s future financial statements.

In August 2011, Cotter was notified by the DOJ that Cotter is considered a PRP with respect to the government’s clean-up costs for contamination attributable to low level radioactive residues at a former storage and reprocessing facility named Latty Avenue near St. Louis, Missouri. The Latty Avenue site is included in ComEd’s indemnification responsibilities discussed above as part of the sale of Cotter. The radioactive residues had been generated initially in connection with the processing of uranium ores as part of the U.S. Government’s Manhattan Project. Cotter purchased the residues in 1969 for initial processing at the Latty Avenue facility for the subsequent extraction of uranium and metals. In 1976, the NRC found that the Latty Avenue site had radiation levels exceeding NRC criteria for decontamination of land areas. Latty Avenue was investigated and remediated by the United States Army Corps of Engineers pursuant to funding under FUSRAP. The DOJ has not yet formally advised the PRPs of the amount that it is seeking, but it is believed to be approximately $90 million from all PRPs. Pursuant to a series of annual agreements since 2011, the DOJ and the PRPs have tolled the statute of limitations until February 2020 so that settlement discussions could proceed. Generation has determined that a loss associated with this matter is probable under its indemnification agreement with Cotter and has recorded an estimated liability, which is included in the table above.

Benning Road Site (Exelon, Generation, PHI and Pepco). In September 2010, PHI received a letter from EPA identifying the Benning Road site as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. A portion of the site was formerly the location of a Pepco Energy Services electric generating facility, which was deactivated in June 2012. The remaining portion of the site consists of a Pepco transmission and distribution service center that remains in operation. In December 2011, the U.S. District Court for the District of Columbia approved a Consent Decree entered into by Pepco and Pepco Energy Services with the DOEE, which

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requires Pepco and Pepco Energy Services to conduct a RI/FS for the Benning Road site and an approximately 10 to 15-acre portion of the adjacent Anacostia River.

Since 2013, Pepco and Pepco Energy Services (now Generation, pursuant to Exelon's 2016 acquisition of PHI) have been performing RI work and have submitted multiple draft RI reports to the DOEE. In September 2019, Pepco and Generation issued a draft “final” RI report which DOEE approved and on October 4, 2019 released this document for review and comment by the public. The 45 day comment period ended on November 18, 2019 and a public meeting was held by Pepco on November 2, 2019. Pepco and Generation will proceed to develop a FS to evaluate possible remedial alternatives for submission to DOEE. The Court has established a schedule for completion of the FS, and approval by the DOEE, by September 16, 2021.

DOEE will then prepare a Proposed Plan and issue a Record of Decision identifying any further response actions determined to be necessary, after considering public comment on the Proposed Plan. PHI, Pepco and Generation have determined that a loss associated with this matter is probable and have accrued an estimated liability, which is included in the table above.

Anacostia River Tidal Reach (Exelon, PHI and Pepco). Contemporaneous with the Benning Road site RI/FS being performed by Pepco and Generation, DOEE and the National Park Service have been conducting a separate RI/FS focused on the entire tidal reach of the Anacostia River extending from just north of the Maryland-District of Columbia boundary line to the confluence of the Anacostia and Potomac Rivers. The river-wide RI incorporated the results of the river sampling performed by Pepco and Pepco Energy Services as part of the Benning RI/FS, as well as similar sampling efforts conducted by owners of other sites adjacent to this segment of the river and supplemental river sampling conducted by DOEE’s contractor. DOEE asked Pepco, along with parties responsible for other sites along the river, to participate in a "Consultative Working Group" to provide input into the process for future remedial actions and to ensure proper coordination with the other river cleanup efforts currently underway, including cleanup of the river segment adjacent to the Benning Road site resulting from the Benning Road site RI/FS. In addition, the District of Columbia Council directed DOEE to form an official advisory committee made up of members of federal, state and local environmental regulators, community and environmental groups and various academic and technical experts to provide guidance and support to DOEE as the project progressed. This group, called the Anacostia Leadership Council, has met regularly since it was formed. Pepco has participated in the Consultative Working Group. In April 2018, DOEE released a draft RI report for public review and comment. Pepco submitted written comments to the draft RI and participated in a public hearing.

Pepco has determined that it is probable that costs for remediation will be incurred and recorded a liability in the third quarter 2019 for management’s best estimate of its share of those costs based on DOEE’s stated position following a series of meetings attended by representatives from the Anacostia Leadership Council and the Consultative Working Group. On December 27, 2019, DOEE released a Focused Feasibility Study (FFS) and a Proposed Plan (PP) for review and comment by the public which will be the basis for the Interim ROD, which is expected to be completed in September 2020. The FFS and PP are consistent with the DOEE’s stated position to follow an adaptive management approach which will allow several identified “hot spots” in the river to be addressed first while continuing to conduct studies and to monitor the river to evaluate improvements and determine potential future remediation plans. The adaptive management process chosen by DOEE is less intrusive, provides more long term environmental certainty, is less costly, and allows for site specific remediation plans already underway, including the plan for the Benning Road site to proceed to conclusion. The comment period ends on March 2, 2020 and a public meeting will be held on January 23, 2021. Pepco concluded that incremental exposure remains reasonably possible, however management cannot reasonably estimate a range of loss beyond the amounts recorded, which are included in the table above.

In addition to the activities associated with the remedial process outlined above, there is a complementary statutory program that requires an assessment to determine if any natural resources have been damaged as a result of the contamination that is being remediated, and, if so, that a plan be developed by the federal, state and local Natural Resource Damage Trustees, who are defined by CERCLA as the responsible parties for the restoration or compensation for any loss of those resources from the environmental contaminants at the site. If natural resources cannot be restored, then compensation for the injury can be sought from the responsible parties. The assessment of Natural Resource Damages (NRD) typically takes place following cleanup because cleanups sometimes also effectively restore habitat. During the second quarter of 2018, Pepco became aware that the Trustees are in the beginning stages of this process that often takes many years beyond the remedial decision to complete. Pepco has concluded that a loss associated with the eventual NRD assessment is reasonably possible. Due to the very early stage of the assessment process, Pepco cannot reasonably estimate the range of loss.

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Litigation and Regulatory Matters

Asbestos Personal Injury Claims (Exelon and Generation). Generation maintains a reserve for claims associated with asbestos-related personal injury actions in certain facilities that are currently owned by Generation or were previously owned by ComEd and PECO. The estimated liabilities are recorded on an undiscounted basis and exclude the estimated legal costs associated with handling these matters, which could be material.

At December 31, 2019 and 2018, Exelon and Generation had recorded estimated liabilities of approximately $83 million and $79 million, respectively, in total for asbestos-related bodily injury claims. As of December 31, 2019, approximately $26 million of this amount related to 263 open claims presented to Generation, while the remaining $57 million is for estimated future asbestos-related bodily injury claims anticipated to arise through 2055, based on actuarial assumptions and analyses, which are updated on an annual basis. On a quarterly basis, Generation monitors actual experience against the number of forecasted claims to be received and expected claim payments and evaluates whether adjustments to the estimated liabilities are necessary.

It is reasonably possible that additional exposure to estimated future asbestos-related bodily injury claims in excess of the amount accrued could have a material, unfavorable impact on Exelon’s and Generation’s financial statements.

Fund Transfer Restrictions (All Registrants). Under applicable law, Exelon may borrow or receive an extension of credit from its subsidiaries. Under the terms of Exelon’s intercompany money pool agreement, Exelon can lend to, but not borrow from the money pool.

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

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

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

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

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

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

ACE is subject to certain dividend restrictions established by settlements approved in New Jersey. ACE is prohibited from paying a dividend on its common shares if (a) after the dividend payment, ACE's equity ratio would be 48% as equity levels are calculated under the ratemaking precedents of the NJBPU or (b) ACE's senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. ACE is also subject to a

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dividend restriction which requires ACE to obtain the prior approval of the NJBPU before dividends can be paid it its equity as a percent of its total capitalization, excluding securitization debt, falls below 30%. No such events have occurred.

City of Everett Tax Increment Financing Agreement (Exelon and Generation). On April 10, 2017, the City of Everett petitioned the Massachusetts Economic Assistance Coordinating Council (EACC) to revoke the 1999 tax increment financing agreement (TIF Agreement) relating to Mystic Units 8 and 9 on the grounds that the total investment in Mystic Units 8 and 9 materially deviates from the investment set forth in the TIF Agreement. On October 31, 2017, a three-member panel of the EACC conducted an administrative hearing on the City’s petition. On November 30, 2017, the hearing panel issued a tentative decision denying the City’s petition, finding that there was no material misrepresentation that would justify revocation of the TIF Agreement. On December 13, 2017, the tentative decision was adopted by the full EACC. On January 12, 2018, the City filed a complaint in Massachusetts Superior Court requesting, among other things, that the court set aside the EACC’s decision, grant the City’s request to decertify the Project and the TIF Agreement, and award the City damages for alleged underpaid taxes over the period of the TIF Agreement. On January 8, 2020, the Massachusetts Superior Court affirmed the decision of the EACC denying the City's petition. The deadline for appeal is March 9, 2020. Generation continues to believe that the City’s claim lacks merit. Accordingly, Generation has not recorded a liability for payment resulting from such a revocation, nor can Generation estimate a reasonably possible range of loss, if any, associated with any such revocation. Further, it is reasonably possible that property taxes assessed in future periods, including those following the expiration of the current TIF Agreement in 2020, could be material to Generation’s financial statements.

Subpoenas (Exelon and ComEd). Exelon and ComEd received a grand jury subpoena in the second quarter of 2019 from the U.S. Attorney’s Office for the Northern District of Illinois requiring production of information concerning their lobbying activities in the State of Illinois. On October 4, 2019, Exelon and ComEd received a second grand jury subpoena from the U.S. Attorney's Office for the Northern District of Illinois requiring production of records of any communications with certain individuals and entities. On October 22, 2019, the SEC notified Exelon and ComEd that it has also opened an investigation into their lobbying activities. Exelon and ComEd have cooperated fully and intend to continue to cooperate fully and expeditiously with the U.S. Attorney’s Office and the SEC. Exelon and ComEd cannot predict the outcome of the U.S. Attorney's Office or the SEC investigations. No loss contingency has been reflected in Exelon's and ComEd's consolidated financial statements as this contingency is neither probable nor reasonably estimable at this time. Management is currently unable to estimate a range of reasonably possible loss as these matters are subject to change.

Subsequent to Exelon announcing the receipt of the subpoenas, a putative class action lawsuit has been filed against Exelon and certain officers of Exelon and ComEd alleging misrepresentations or omissions by Exelon purporting to relate to matters that are the subject of the subpoenas and the SEC investigation. Exelon believes that these claims lack merit and intends to defend against them, and though the costs or any loss associated with the lawsuit cannot be reasonably estimated at this time, Exelon does not believe that the lawsuit will have a material adverse impact on Exelon’s or ComEd’s consolidated financial statements.

General (All Registrants). The Registrants are involved in various other litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. The Registrants maintain accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of reasonably possible loss, particularly where (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.

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ComEd Common Stock Warrants

The following table presents warrants outstanding to purchase ComEd common stock and shares of common stock reserved for the conversion of warrants. The warrants entitle the holders to convert such warrants into common stock of ComEd at a conversion rate of one share of common stock for three warrants.

	December 31,
	2019			2018
Warrants outstanding	60,228			60,285
Common Stock reserved for conversion	20,076			20,095

Equity Securities Offering

In June 2014, Exelon issued $1.15 billion of junior subordinated notes in the form of 23 million equity units. In June 2017, Exelon settled the forward equity purchase contract on these equity units through issuance of 33 million shares of common stock from treasury stock, which triggered full dilution in the EPS calculation. Previously, the equity units were included in the calculation of diluted EPS using the treasury stock method.

Share Repurchases

There currently is no Exelon Board of Director authority to repurchase shares. Any previous shares repurchased are held as treasury shares, at cost, unless cancelled or reissued at the discretion of Exelon’s management.

Preferred and Preference Securities

The following table presents the Registrants' shares of preferred securities authorized, none of which are outstanding as of December 31, 2019 and 2018:

	Preferred Securities Authorized
Exelon	100,000,000
ComEd	850,000
PECO	15,000,000
BGE	1,000,000
Pepco	6,000,000
ACE(a)	2,799,979

__________

(a)	Includes 799,979 shares of cumulative preferred stock and 2,000,000 of no-par preferred stock as of December 31, 2019 and 2018, respectively.

The following table presents ComEd's, BGE's and ACE's preference securities authorized, none of which are outstanding as of December 31, 2019 and 2018:

	Preference Securities Authorized
ComEd - Cumulative preference securities	6,810,451
BGE(a)	6,500,000
ACE	3,000,000

__________

(a)	Includes 4,600,000 shares of unclassified preference securities and 1,900,000 shares of previously redeemed preference securities as of December 31, 2019 and 2018, respectively.

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Stock-Based Compensation Plans

Exelon grants stock-based awards through its LTIP, which primarily includes performance share awards, restricted stock units and stock options. At December 31, 2019, there were approximately 12 million shares authorized for issuance under the LTIP. For the years ended December 31, 2019, 2018 and 2017, exercised and distributed stock-based awards were primarily issued from authorized but unissued common stock shares.

The Registrants grant cash awards. The following table does not include expense related to these plans as they are not considered stock-based compensation plans under the applicable authoritative guidance.

The following table presents the stock-based compensation expense included in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. The Utility Registrants' stock-based compensation expense for the years ended December 31, 2019, 2018 and 2017 was not material.

Exelon	Year Ended December 31,
Components of Stock-Based Compensation Expense	2019				2018				2017
Total stock-based compensation expense included in operating and maintenance expense	$	77			$	208			$	191
Income tax benefit	(20		)		(54		)		(74		)
Total after-tax stock-based compensation expense	$	57			$	154			$	117
Generation
Components of Stock-Based Compensation Expense
Total stock-based compensation expense included in operating and maintenance expense	$	37			$	77			$	88
Income tax benefit	(10		)		(20		)		(34		)
Total after-tax stock-based compensation expense	$	27			$	57			$	54

Exelon receives a tax deduction based on the intrinsic value of the award on the exercise date for stock options and the distribution date for performance share awards and restricted stock units. For each award, throughout the requisite service period, Exelon recognizes the tax benefit related to compensation costs. The following table presents information regarding Exelon’s realized tax benefit when distributed:

	Year Ended December 31,
	2019				2018				2017
Performance share awards	$	41			$	16			$	29
Restricted stock units	24				28				35

Performance Share Awards

Performance share awards are granted under the LTIP. The performance share awards are settled 50% in common stock and 50% in cash at the end of the three-year performance period, except for awards granted to vice presidents and higher officers that are settled 100% in cash if certain ownership requirements are satisfied.

The common stock portion of the performance share awards is considered an equity award and is valued based on Exelon's stock price on the grant date. The cash portion of the performance share awards is considered a liability award which is remeasured each reporting period based on Exelon’s current stock price. As the value of the common stock and cash portions of the awards are based on Exelon’s stock price during the performance period, coupled with changes in the total shareholder return modifier and expected payout of the award, the compensation costs are subject to volatility until payout is established.

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For nonretirement-eligible employees, stock-based compensation costs are recognized over the vesting period of three years using the straight-line method. For performance share awards granted to retirement-eligible employees, the value of the performance shares is recognized ratably over the vesting period, which is the year of grant.

Exelon processes forfeitures as they occur for employees who do not complete the requisite service period.

The following table summarizes Exelon’s nonvested performance share awards activity:

	Shares			Weighted Average Grant Date Fair Value (per share)
Nonvested at December 31, 2018(a)	3,403,228			$	33.13
Granted	1,089,903			47.37
Change in performance	(799,618	)		40.85
Vested	(1,610,146	)		28.90
Forfeited	(25,249	)		45.03
Undistributed vested awards(b)	(348,363	)		48.82
Nonvested at December 31, 2019(a)	1,709,755			$	39.21

__________

(a)	Excludes 2,017,870 and 3,586,259 of performance share awards issued to retirement-eligible employees as of December 31, 2019 and 2018, respectively, as they are fully vested.

(b)	Represents performance share awards that vested but were not distributed to retirement-eligible employees during 2019.

The following table summarizes the weighted average grant date fair value and the total fair value of performance share awards granted and settled.

	Year Ended December 31,
	2019 (a)				2018				2017
Weighted average grant date fair value (per share)	$	47.37			$	38.15			$	35.00
Total fair value of performance shares settled	158				61				72
Total fair value of performance shares settled in cash	131				49				56

__________

(a)	As of December 31, 2019, $17 million of total unrecognized compensation costs related to nonvested performance shares are expected to be recognized over the remaining weighted-average period of 1.6 years.

Restricted Stock Units

Restricted stock units are granted under the LTIP with the majority being settled in a specific number of shares of common stock after the service condition has been met. The corresponding cost of services is measured based on the grant date fair value of the restricted stock unit issued.

The value of the restricted stock units is expensed over the requisite service period using the straight-line method. The requisite service period for restricted stock units is generally three to five years. However, certain restricted stock unit awards become fully vested upon the employee reaching retirement-eligibility. The value of the restricted stock units granted to retirement-eligible employees is either recognized immediately upon the date of grant or through the date at which the employee reaches retirement eligibility. Exelon processes forfeitures as they occur for employees who do not complete the requisite service period.

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The following table summarizes Exelon’s nonvested restricted stock unit activity:

	Shares			Weighted Average Grant Date Fair Value (per share)
Nonvested at December 31, 2018(a)	2,293,341			$	35.06
Granted	902,857			45.65
Vested	(1,232,704	)		32.83
Forfeited	(33,603	)		39.01
Undistributed vested awards (b)	(431,178	)		44.75
Nonvested at December 31, 2019(a)	1,498,713			$	40.35

__________

(a)	Excludes 863,196 and 1,131,487 of restricted stock units issued to retirement-eligible employees as of December 31, 2019 and 2018, respectively, as they are fully vested.

(b)	Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2019.

The following table summarizes the weighted average grant date fair value and the total fair value of restricted stock units granted and vested.

	Year Ended December 31,
	2019 (a)				2018				2017
Weighted average grant date fair value (per share)	$	45.65			$	38.60			$	34.98
Total fair value of restricted stock units vested	92				106				88

__________

(a)	As of December 31, 2019, $28 million of total unrecognized compensation costs related to nonvested restricted stock units are expected to be recognized over the remaining weighted-average period of 2.8 years.

Stock Options

Non-qualified stock options to purchase shares of Exelon’s common stock were granted through 2012 under the LTIP. The exercise price of the stock options is equal to the fair market value of the underlying stock on the date of option grant. Stock options will expire no later than ten years from the date of grant.

At December 31, 2019 all stock options were vested and there were no unrecognized compensation costs.

The following table presents information with respect to stock option activity:

	Shares			Weighted Average Exercise Price (per share)				Weighted Average Remaining Contractual Life (years)		Aggregate Intrinsic Value
Balance of shares outstanding at December 31, 2018	4,027,652			$	43.95			2.90		$	14
Options exercised	(1,388,165	)		42.25
Options expired	(750,442	)		55.96
Balance of shares outstanding at December 31, 2019	1,889,045			$	40.43			1.56		$	10
Exercisable at December 31, 2019(a)	1,889,045			$	40.43			1.56		$	10

__________

(a)	Includes stock options issued to retirement eligible employees.

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The following table summarizes additional information regarding stock options exercised:

	Year Ended December 31,
	2019				2018				2017
Intrinsic value(a)	$	9			$	12			$	15
Cash received for exercise price	59				56				107

__________

(a)	The difference between the market value on the date of exercise and the option exercise price.

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

	Gains and (Losses) on Cash Flow Hedges				Unrealized Gains and (Losses) on Marketable Securities				Pension and Non-Pension Postretirement Benefit Plan Items (a)				Foreign Currency Items				AOCI of Investments Unconsolidated Affiliates (b)				Total
Balance at December 31, 2016	$	(17	)		$	4			$	(2,610	)		$	(30	)		$	(7	)		$	(2,660	)
OCI before reclassifications	(1		)		6				11				7				6				29
Amounts reclassified from AOCI	4				—				140				—				—				144
Net current-period OCI	3				6				151				7				6				173
Impact of adoption of Reclassification of Certain Tax Effects from AOCI(c)	—				—				(539		)		—				—				(539		)
Balance at December 31, 2017	$	(14	)		$	10			$	(2,998	)		$	(23	)		$	(1	)		$	(3,026	)
OCI before reclassifications	11				—				(143		)		(10		)		1				(141		)
Amounts reclassified from AOCI	1				—				181				—				—				182
Net current-period OCI	12				—				38				(10		)		1				41
Impact of adoption of Recognition and Measurement of Financial Assets and Financial Liabilities standard(d)	—				(10		)		—				—				—				(10		)
Balance at December 31, 2018	$	(2	)		$	—			$	(2,960	)		$	(33	)		$	—			$	(2,995	)
OCI before reclassifications	—				—				(289		)		6				(2		)		(285		)
Amounts reclassified from AOCI	—				—				84				—				2				86
Net current-period OCI	—				—				(205		)		6				—				(199		)
Balance at December 31, 2019	$	(2	)		$	—			$	(3,165	)		$	(27	)		$	—			$	(3,194	)

__________ 

(a)	This AOCI component is included in the computation of net periodic pension and OPEB cost. See Note 14 — Retirement Benefits for additional information. See Exelon's Statements of Operations and Comprehensive Income for individual components of AOCI.

(b)	All amounts are net of noncontrolling interests.

(c)	Exelon early adopted the new standard Reclassification of Certain Tax Effects from AOCI. The standard was adopted retrospectively as of December 31, 2017, which resulted in an increase to Exelon’s Retained earnings and Accumulated other comprehensive loss of $539 million, primarily related to deferred income taxes associated with Exelon’s pension and OPEB obligations.

(d)	Exelon prospectively adopted the new standard Recognition and Measurement of Financial Assets and Financial Liabilities. The standard was adopted as of January 1, 2018, which resulted in an increase to Retained earnings and Accumulated other comprehensive loss of $10 million for Exelon. The amounts reclassified related to Rabbi Trusts.

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The following table presents income tax benefit (expense) allocated to each component of Exelon's other comprehensive income (loss):

	For the Year Ended December 31,
	2019				2018				2017
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	$	23			$	24			$	36
Actuarial loss reclassified to periodic benefit cost	(52		)		(86		)		(128		)
Pension and non-pension postretirement benefit plans valuation adjustment	100				50				13

At December 31, 2019 and 2018, Exelon, Generation, PHI and ACE collectively consolidated several VIEs or VIE groups for which the applicable Registrant was the primary beneficiary (see Consolidated VIEs below) and had significant interests in several other VIEs for which the applicable Registrant does not have the power to direct the entities’ activities and, accordingly, was not the primary beneficiary (see Unconsolidated VIEs below). Consolidated and unconsolidated VIEs are aggregated to the extent that the entities have similar risk profiles.

Consolidated VIEs

The table below shows the carrying amounts and classification of the consolidated VIEs’ assets and liabilities included in the consolidated financial statements of Exelon, Generation, PHI and ACE as of December 31, 2019 and 2018. The assets, except as noted in the footnotes to the table below, can only be used to settle obligations of the VIEs. The liabilities, except as noted in the footnotes to the table below, are such that creditors, or beneficiaries, do not have recourse to the general credit of Exelon, Generation, PHI and ACE.

	December 31, 2019																December 31, 2018
	Exelon(a)				Generation				PHI(a)				ACE				Exelon				Generation				PHI				ACE
Cash and cash equivalents	$	163			$	163			$	—			$	—			$	414			$	414			$	—			$	—
Restricted cash and cash equivalents	88				85				3				3				66				62				4				4
Accounts receivable, net
Customer	151				151				—				—				146				146				—				—
Other	39				39				—				—				23				23				—				—
Unamortized energy contract asset (b)	23				23				—				—				25				25				—				—
Inventories, net
Materials and supplies	227				227				—				—				212				212				—				—
Other current assets	32				31				1				—				52				49				3				—
Total current assets	723				719				4				3				938				931				7				4
Property, plant and equipment, net (c)	6,022				6,022				—				—				6,188				6,188				—				—
Nuclear decommissioning trust funds	2,741				2,741				—				—				2,351				2,351				—				—
Unamortized energy contract asset (b)	250				250				—				—				274				274				—				—
Other noncurrent assets	89				73				16				14				258				232				26				19
Total noncurrent assets	9,102				9,086				16				14				9,071				9,045				26				19
Total assets	$	9,825			$	9,805			$	20			$	17			$	10,009			$	9,976			$	33			$	23
Long-term debt due within one year	$	544			$	523			$	21			$	20			$	87			$	66			$	21			$	18
Accounts payable	106				106				—				—				96				96				—				—
Accrued expenses	70				70				—				—				73				72				1				1
Unamortized energy contract liabilities	8				8				—				—				15				15				—				—
Other current liabilities	3				3				—				—				3				3				—				—
Total current liabilities	731				710				21				20				274				252				22				19
Long-term debt	527				504				23				21				1,072				1,025				47				40
Asset retirement obligations (d)	2,128				2,128				—				—				2,165				2,165				—				—
Unamortized energy contract liabilities	1				1				—				—				1				1				—				—
Other noncurrent liabilities	89				89				—				—				42				42				—				—
Total noncurrent liabilities	2,745				2,722				23				21				3,280				3,233				47				40
Total liabilities	$	3,476			$	3,432			$	44			$	41			$	3,554			$	3,485			$	69			$	59

__________

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

(b)	These are unrestricted assets to Exelon and Generation.

(c)	Exelon's and Generation's balances include unrestricted assets of $20 million and $43 million as of December 31, 2019 and 2018, respectively.

(d)	Exelon's and Generation's balances include liabilities with recourse of $3 million and $5 million as of December 31, 2019 and 2018, respectively.

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As of December 31, 2019 and 2018, 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.
Blue Stem Wind - 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 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. See Note 2 — Mergers, Acquisitions and Dispositions for additional information.

Exelon and Generation, where indicated, provide the following support to CENG:

•	Generation provided a $400 million loan to CENG. The remaining balance was fully paid by CENG in January 2019.

•

Generation executed an Indemnity Agreement pursuant to which Generation agreed to indemnify EDF against third-party claims that may arise from any future nuclear incident (as defined in the Price-Anderson Act) in connection with the CENG nuclear plants or their operations. Exelon guarantees Generation’s obligations under this Indemnity Agreement. (See Note 18 — Commitments and Contingencies for more details),

•	Generation and EDF share in the $688 million of contingent payment obligations for the payment of contingent retrospective premium adjustments for the nuclear liability insurance, and

•	Exelon has executed an agreement to provide up to $245 million to support the operations of CENG as well as a $165 million guarantee of CENG’s cash pooling agreement with its subsidiaries.

EGRP - EGRP is a collection of wind and solar project entities and some of these project entities are VIEs that are consolidated by EGRP. Generation owns a number of limited liability companies that build, own, and operate solar and wind power facilities some of which are owned by EGRP. While Generation or EGRP owns 100% of the solar entities and 100% of the majority of the wind entities, it has been determined that certain of the solar and wind entities are VIEs because the entities require additional subordinated financial support in the form of a parental guarantee of debt, loans from the customers in order to obtain the necessary funds for construction of the solar

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facilities, or the customers absorb price variability from the entities through the fixed price power and/or REC purchase agreements. Generation is the primary beneficiary of these solar and wind entities that qualify as VIEs because Generation controls the design, construction, and operation of the facilities. Generation provides operating and capital funding to the solar and wind entities for ongoing construction, operations and maintenance and there is limited recourse related to Generation related to certain solar and wind entities.

In 2017, Generation’s interests in EGRP were contributed to and are pledged for the ExGen Renewables IV non-recourse debt project financing structure. Refer to Note 16 — Debt and Credit Agreements for additional information on ExGen Renewables IV.

As of December 31, 2019 and 2018, Exelon's, PHI's and ACE's consolidated VIE consists of:

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 December 31, 2019 and 2018, Exelon and Generation had significant unconsolidated variable interests in several VIEs for which Exelon or Generation, as applicable, was not the primary beneficiary. These interests include certain equity method investments and certain commercial agreements.

The following table presents summary information about Exelon and Generation’s significant unconsolidated VIE entities:

	December 31, 2019												December 31, 2018
	Commercial Agreement VIEs				Equity Investment VIEs				Total				Commercial Agreement VIEs				Equity Investment VIEs				Total
Total assets(a)	$	636			$	443			$	1,079			$	597			$	472			$	1,069
Total liabilities(a)	33				227				260				37				222				259
Exelon's ownership interest in VIE(a)	—				191				191				—				223				223
Other ownership interests in VIE(a)	604				25				629				560				27				587
Registrants’ maximum exposure to loss:
Carrying amount of equity method investments	—				—				—				—				223				223

__________

(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.

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For each of the unconsolidated VIEs, Exelon and Generation have assessed the risk of a loss equal to their maximum exposure to be remote and, accordingly, Exelon and Generation have not recognized a liability associated with any portion of the maximum exposure to loss.

As of December 31, 2019 and 2018, Exelon's and Generation's unconsolidated VIEs consist of:

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 a distributed energy company (See Consolidated VIEs disclosure above). Generation fully impaired this investment in the third quarter of 2019. See note 11- Asset Impairments 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.

Supplemental Statement of Operations Information

The following tables provide additional information about material items recorded in the Registrants' Consolidated Statements of Operations and Comprehensive Income.

	Taxes other than income taxes
	Exelon				Generation				ComEd				PECO				BGE				PHI				Pepco				DPL				ACE
For the year ended December 31, 2019
Utility(a)	$	881			$	112			$	242			$	132			$	90			$	304			$	286			$	18			$	—
Property	595				274				29				17				153				122				85				34				2
Payroll	232				115				27				15				17				24				7				4				2
For the year ended December 31, 2018
Utility(a)	$	919			$	114			$	243			$	131			$	94			$	337			$	316			$	21			$	—
Property	557				273				30				15				143				94				58				32				3
Payroll	247				130				27				16				17				24				5				3				2
For the year ended December 31, 2017
Utility(a)	$	898			$	126			$	240			$	125			$	89			$	318			$	300			$	18			$	—
Property	545				269				28				14				132				101				62				32				3
Payroll	230				121				26				15				15				26				6				4				2

__________

(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.

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	Other, Net
	Exelon				Generation				ComEd				PECO				BGE				PHI				Pepco				DPL				ACE
For the year ended December 31, 2019
Decommissioning-related activities:
Net realized income on NDT funds(a)
Regulatory agreement units	$	297			$	297			$	—			$	—			$	—			$	—			$	—			$	—			$	—
Non-regulatory agreement units	363				363				—				—				—				—				—				—				—
Net unrealized gains on NDT funds
Regulatory agreement units	795				795				—				—				—				—				—				—				—
Non-regulatory agreement units	411				411				—				—				—				—				—				—				—
Regulatory offset to NDT fund-related activities(b)	(876		)		(876		)		—				—				—				—				—				—				—
Decommissioning-related activities	990				990				—				—				—				—				—				—				—
AFUDC—Equity	85				—				17				13				21				34				25				4				5
Non-service net periodic benefit cost	13				—				—				—				—				—				—				—				—
For the year ended December 31, 2018
Decommissioning-related activities:
Net realized income on NDT funds(a)
Regulatory agreement units	$	506			$	506			$	—			$	—			$	—			$	—			$	—			$	—			$	—
Non-regulatory agreement units	302				302				—				—				—				—				—				—				—
Net unrealized losses on NDT funds
Regulatory agreement units	(715		)		(715		)		—				—				—				—				—				—				—
Non-regulatory agreement units	(483		)		(483		)		—				—				—				—				—				—				—
Regulatory offset to NDT fund-related activities(b)	171				171				—				—				—				—				—				—				—
Decommissioning-related activities	(219		)		(219		)		—				—				—				—				—				—				—
AFUDC—Equity	69				—				19				7				18				25				22				2				1
Non-service net periodic benefit cost	(47		)		—				—				—				—				—				—				—				—
For the year ended December 31, 2017
Decommissioning-related activities:
Net realized income on NDT funds(a)
Regulatory agreement units	$	488			$	488			$	—			$	—			$	—			$	—			$	—			$	—			$	—
Non-regulatory agreement units	209				209				—				—				—				—				—				—				—
Net unrealized gains on NDT funds
Regulatory agreement units	455				455				—				—				—				—				—				—				—
Non-regulatory agreement units	521				521				—				—				—				—				—				—				—
Regulatory offset to NDT fund-related activities(b)	(724		)		(724		)		—				—				—				—				—				—				—
Decommissioning-related activities	949				949				—				—				—				—				—				—				—
AFUDC—Equity	73				—				12				9				16				36				23				7				6
Non-service net periodic benefit cost	(109		)		—				—				—				—				—				—				—				—

__________

(a)	Realized income includes interest, dividends and realized gains and losses on sales of NDT fund investments.

(b)	Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units, including the elimination of income taxes related to all NDT fund activity for those units. See Note 9 — Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning.

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Supplemental Cash Flow Information

The following tables provide additional information about material items recorded in the Registrants' Consolidated Statements of Cash Flows.

	Depreciation, amortization and accretion
	Exelon				Generation				ComEd				PECO				BGE				PHI				Pepco				DPL				ACE
For the year ended December 31, 2019
Property, plant and equipment	$	3,665			$	1,485			$	886			$	303			$	359			$	547			$	239			$	146			$	123
Amortization of regulatory assets	528				—				147				30				143				207				135				38				34
Amortization of intangible assets, net	59				50				—				—				—				—				—				—				—
Amortization of energy contract assets and liabilities(a)	21				21				—				—				—				—				—				—				—
Nuclear fuel(b)	1,016				1,016				—				—				—				—				—				—				—
ARO accretion(c)	491				491				—				—				—				—				—				—				—
Total depreciation, amortization and accretion	$	5,780			$	3,063			$	1,033			$	333			$	502			$	754			$	374			$	184			$	157
For the year ended December 31, 2018
Property, plant and equipment	$	3,740			$	1,748			$	820			$	274			$	335			$	480			$	218			$	131			$	94
Amortization of regulatory assets	555				—				120				27				148				260				167				51				42
Amortization of intangible assets, net	58				49				—				—				—				—				—				—				—
Amortization of energy contract assets and liabilities(a)	14				14				—				—				—				—				—				—				—
Nuclear fuel(b)	1,115				1,115				—				—				—				—				—				—				—
ARO accretion(c)	489				489				—				—				—				—				—				—				—
Total depreciation, amortization and accretion	$	5,971			$	3,415			$	940			$	301			$	483			$	740			$	385			$	182			$	136
For the year ended December 31, 2017
Property, plant and equipment	$	3,293			$	1,409			$	777			$	261			$	312			$	457			$	203			$	124			$	89
Amortization of regulatory assets	478				—				73				25				161				218				118				43				57
Amortization of intangible assets, net	57				48				—				—				—				—				—				—				—
Amortization of energy contract assets and liabilities(a)	35				35				—				—				—				—				—				—				—
Nuclear fuel(b)	1,096				1,096				—				—				—				—				—				—				—
ARO accretion(c)	468				468				—				—				—				—				—				—				—
Total depreciation, amortization and accretion	$	5,427			$	3,056			$	850			$	286			$	473			$	675			$	321			$	167			$	146

__________

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

(b)	Included in Purchased power and fuel expense in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.

(c)	Included in Operating and maintenance expense in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.

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	Cash paid (refunded) during the year:
	Exelon				Generation				ComEd				PECO				BGE				PHI				Pepco				DPL				ACE
For the year ended December 31, 2019
Interest (net of amount capitalized)	$	1,470			$	373			$	343			$	129			$	106			$	255			$	130			$	59			$	55
Income taxes (net of refunds)	265				(44		)		(42		)		82				17				29				7				19				(5		)
For the year ended December 31, 2018
Interest (net of amount capitalized)	$	1,421			$	369			$	332			$	125			$	94			$	250			$	123			$	56			$	61
Income taxes (net of refunds)	95				746				(153		)		(2		)		14				(32		)		41				(6		)		(12		)
For the year ended December 31, 2017
Interest (net of amount capitalized)	$	2,430			$	391			$	307			$	103			$	96			$	236			$	114			$	49			$	59
Income taxes (net of refunds)	540				337				83				47				(2		)		(144		)		(104		)		(49		)		(2		)

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	Other non-cash operating activities:
	Exelon				Generation				ComEd				PECO				BGE				PHI				Pepco				DPL				ACE
For the year ended December 31, 2019
Pension and non-pension postretirement benefit costs	$	438			$	135			$	96			$	12			$	61			$	95			$	25			$	15			$	16
Provision for uncollectible accounts	120				31				33				31				8				17				7				4				5
Other decommissioning-related activity(a)	(506		)		(506		)		—				—				—				—				—				—				—
Energy-related options(b)	22				22				—				—				—				—				—				—				—
Amortization of rate stabilization deferral	(4		)		—				—				—				—				(4		)		(4		)		—				—
Discrete impacts from EIMA and FEJA(d)	128				—				128				—				—				—				—				—				—
Long-term incentive plan	10				—				—				—				—				—				—				—				—
Amortization of operating ROU asset	244				172				3				—				30				33				8				8				4
Change in environmental liabilities	23				—				—				—				—				23				23				—				—
For the year ended December 31, 2018
Pension and non-pension postretirement benefit costs	$	583			$	204			$	177			$	18			$	59			$	67			$	15			$	6			$	12
Provision for uncollectible accounts	159				48				40				33				10				28				11				6				11
Other decommissioning-related activity(a)	(2		)		(2		)		—				—				—				—				—				—				—
Energy-related options(b)	10				10				—				—				—				—				—				—				—
Amortization of rate stabilization deferral	21				—				—				—				—				21				21				—				—
Asset retirement costs	20				—				—				—				—				20				22				(1		)		(1		)
Discrete impacts from EIMA and FEJA(d)	28				—				28				—				—				—				—				—				—
Long-term incentive plan	140				—				—				—				—				—				—				—				—
For the year ended December 31, 2017
Pension and non-pension postretirement benefit costs	$	643			$	227			$	176			$	29			$	62			$	94			$	25			$	13			$	13
Provision for uncollectible accounts	125				38				34				26				8				19				8				3				8
Other decommissioning-related activity(a)	(313		)		(313		)		—				—				—				—				—				—				—
Energy-related options(b)	7				7				—				—				—				—				—				—				—
Amortization of rate stabilization deferral	(3		)		—				—				—				7				(10		)		(10		)		—				—
Discrete impacts from EIMA and FEJA(d)	(52		)		—				(52		)		—				—				—				—				—				—
Vacation accrual adjustment(e)	(68		)		(35		)		(12		)		—				—				(8		)		(8		)		—				—
Long-term incentive plan	109				—				—				—				—				—				—				—				—
Change in environmental liabilities	44				44				—				—				—				—				—				—				—

__________

(a)	Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income and income taxes related to all NDT fund activity for these units. See Note 9 — Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning.

(b)	Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations.

(c)	See Note 2 - Mergers, Acquisitions and Dispositions for additional information.

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(d)	Reflects the change in ComEd's distribution and energy efficiency formula rates . See Note 3 — Regulatory Matters for additional information.

(e)	On December 1, 2017, Exelon adopted a single, standard vacation accrual policy for all non-represented, non-craft (represented and craft policies remained unchanged) employees effective January 1, 2018.  To reflect the new policy, Exelon recorded a one-time, $68 million pre-tax credit to expense to reverse 2018 vacation cost originally accrued throughout 2017 that was accrued ratably during 2018.

The following tables provide a reconciliation of cash, cash equivalents and restricted cash reported within the Registrants' Consolidated Balance Sheets that sum to the total of the same amounts in their Consolidated Statements of Cash Flows.

	Exelon				Generation				ComEd				PECO				BGE				PHI				Pepco				DPL				ACE
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
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
December 31, 2017
Cash and cash equivalents	$	898			$	416			$	76			$	271			$	17			$	30			$	5			$	2			$	2
Restricted cash	207				138				5				4				1				42				35				—				6
Restricted cash included in other long-term assets	85				—				63				—				—				23				—				—				23
Total cash, cash equivalents and restricted cash	$	1,190			$	554			$	144			$	275			$	18			$	95			$	40			$	2			$	31
December 31, 2016
Cash and cash equivalents	$	635			$	290			$	56			$	63			$	23			$	170			$	9			$	46			$	101
Restricted cash	253				158				2				4				24				43				33				—				9
Restricted cash included in other long-term assets	26				—				—				—				3				23				—				—				23
Total cash, cash equivalents and restricted cash	$	914			$	448			$	58			$	67			$	50			$	236			$	42			$	46			$	133

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Supplemental Balance Sheet Information

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

	Unbilled customer revenues(a)
	Exelon				Generation				ComEd				PECO				BGE				PHI				Pepco				DPL				ACE
December 31, 2019	$	1,535			$	807			$	218			$	146			$	170			$	194			$	100			$	61			$	33
December 31, 2018	1,656				965				223				114				168				186				97				59				30

__________

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

	Investments
	Exelon				Generation				ComEd				PECO				BGE				PHI				Pepco				DPL				ACE
December 31, 2019
Equity method investments:
Other equity method investments	$	92			$	71			$	6			$	8			$	—			$	—			$	—			$	—			$	—
Other investments:
Employee benefit trusts and investments(a)	262				54				—				19				7				135				110				—				—
Equity investments without readily determinable fair values	69				69				—				—				—				—				—				—				—
Other available for sale debt security investments	41				41				—				—				—				—				—				—				—
Total investments	$	464			$	235			$	6			$	27			$	7			$	135			$	110			$	—			$	—
December 31, 2018
Equity method investments:
Distributed energy companies	$	180			$	180			$	—			$	—			$	—			$	—			$	—			$	—			$	—
Other equity method investments	87				71				6				8				—				—				—				—				—
Total equity method investments	267				251				6				8				—				—				—				—				—
Other investments:
Employee benefit trusts and investments(a)	244				49				—				17				5				130				105				—				—
Equity investments without readily determinable fair values	72				72				—				—				—				—				—				—				—
Other available for sale debt security investments	40				40				—				—				—				—				—				—				—
Other	2				2				—				—				—				—				—				—				—
Total investments	$	625			$	414			$	6			$	25			$	5			$	130			$	105			$	—			$	—

__________

(a)	The Registrants’ debt and equity security investments are recorded at fair market value.

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	Accrued expenses
	Exelon				Generation				ComEd				PECO				BGE				PHI				Pepco				DPL				ACE
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
December 31, 2018
Compensation-related accruals(a)	$	1,191			$	479			$	187			$	49			$	68			$	99			$	29			$	19			$	12
Taxes accrued	412				226				71				28				46				74				58				4				5
Interest accrued	334				77				105				33				39				50				25				8				12

__________

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

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:

	For the Years Ended December 31,
	2019				2018				2017
Operating revenues from affiliates:
ComEd (a)(b)	$	369			$	523			$	121
PECO (c)	158				128				138
BGE (d)	289				260				388
PHI	353				355				463
Pepco (e)	264				206				255
DPL (f)	70				120				179
ACE (g)	19				29				29
Other	3				2				5
Total operating revenues from affiliates (Generation)	$	1,172			$	1,268			$	1,115

__________

(a)	Generation has an ICC-approved RFP contract with ComEd to provide a portion of ComEd’s electricity supply requirements. Generation also sells RECs and ZECs to ComEd.

(b)	For 2019, ComEd’s Purchased power from Generation of $376 million is recorded as Operating revenues from ComEd of $369 million and Purchased power and fuel from ComEd of $7 million at Generation. For 2018, ComEd’s Purchased power from Generation of $529 million is recorded as Operating revenues from ComEd of $523 million and Purchased power and fuel from ComEd of $6 million at Generation.

(c)	Generation provides electric supply to PECO under contracts executed through PECO’s competitive procurement process. In addition, Generation has a ten-year agreement with PECO to sell solar AECs.

(d)	Generation provides a portion of BGE’s energy requirements under its MDPSC-approved market-based SOS and gas commodity programs.

(e)	Generation provides electric supply to Pepco under contracts executed through Pepco's competitive procurement process approved by the MDPSC and DCPSC.

(f)	Generation provides a portion of DPL's energy requirements under its MDPSC and DPSC approved market based SOS and gas commodity programs.

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(g)	Generation provides electric supply to ACE under contracts executed through ACE's competitive procurement process.

PHI

PHI’s Operating revenues from affiliates are primarily with BSC for services that PHISCO provides to BSC.

Operating and maintenance expense from affiliates

The Registrants receive a variety of corporate support services from BSC. Pepco, DPL and ACE also receive corporate support services from PHISCO. See Note 1 - Significant Accounting Policies for additional information regarding BSC and PHISCO.

The following table presents the service company costs allocated to the Registrants:

		Operating and maintenance from affiliates												Operating and maintenance				Capitalized costs
		For the years ended December 31,												For the years ended December 31,				For the years ended December 31,
		2019				2018				2017				2017				2019				2018				2017
Exelon
BSC																		$	516			$	448			$	330
PHISCO																		72				79				—
Generation
BSC		$	570			$	652			$	689			$	—			66				67				98
ComEd
BSC		263				265				270				—				148				135				118
PECO
BSC		149				146				146				—				88				64				59
BGE
BSC		157				157				152				—				126				79				54
PHI
BSC		139				147				145				—				88				102				—
PHISCO (a)		—				—				—				—				72				79				—
Pepco
BSC		85				89				53				—				38				40				—
PHISCO (a)		124				137				5				219				33				32				—
PES (b)		—				—				—				29				—				—				—
DPL
BSC		52				51				31				—				25				28				—
PHISCO (a)		100				111				—				165				20				25				—
PES (b)		—				—				—				9				—				—				—
ACE
BSC		42				42				25				—				19				20				—
PHISCO (a)		90				98				—				135				19				21				—

__________

(a)	Due to the PHI entities' system conversion to Exelon's accounting systems on January 1, 2018, corporate support services received from PHISCO are reported in Operating and maintenance from affiliates and in Capitalized costs beginning in 2018.

(b)	PES performed underground transmission, distribution construction and maintenance services, including services that are treated as capital costs, for Pepco and DPL.

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Current Receivables from/Payables to affiliates

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

December 31, 2019

		Receivables from affiliates:
Payables to affiliates:		Generation				Comed				PECO				BGE				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

December 31, 2018

		Receivables from affiliates:
Payables to affiliates:		Generation				Comed				BGE				Pepco				ACE				BSC				PHISCO				Other				Total
Generation						$	19			$	—			$	—			$	—			$	95			$	—			$	25			$	139
ComEd		$	69		(a)					—				—				—				56				—				8				133
PECO		30				—				—				—				—				26				—				3				59
BGE		24				—								—				—				38				—				3				65
PHI		—				—				—				—				—				3				—				9				12
Pepco		28				—				—								—				19				14				1				62
DPL		7				—				—				1				1				11				12				1				33
ACE		5				—				—				—								8				13				2				28
Other		10				1				1				—				—				—				—								12
Total		$	173			$	20			$	1			$	1			$	1			$	256			$	39			$	52			$	543

__________

(a)

At December 31, 2019 and 2018, Generation also had a contract liability with ComEd for $37 million and $14 million, respectively, that was included in Other liabilities on Generation’s Consolidated Balance Sheets. At December 31, 2019 and 2018, ComEd had a Current Payable to Generation of $41 million and $55 million, respectively, on its Consolidated Balance Sheets, which consisted of Generation’s Current Receivable from ComEd, partially offset by Generation’s contract liability with ComEd.

---

Borrowings from Exelon/PHI intercompany money pool

To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing both Exelon and PHI operate an intercompany money pool. Generation, ComEd, PECO, and PHI Corporate participate in the Exelon money pool. Pepco, DPL and ACE participate in the PHI intercompany money pool.

Noncurrent Receivables from/Payables to affiliates

Generation has long-term payables to ComEd and PECO as a result of the nuclear decommissioning contractual construct whereby, to the extent NDT funds are greater than the underlying ARO at the end of decommissioning, such amounts are due back to ComEd and PECO, as applicable, for payment to their respective customers. See Note 9 — Asset Retirement Obligations for additional information.

The following table presents noncurrent receivables from affiliates at ComEd and PECO which are recorded as noncurrent payables to affiliates at Generation:

	December 31,
	2019				2018
ComEd	$	2,622			$	2,217
PECO	480				389
Other	1				—
Total:	$	3,103			$	2,606

Long-term debt to financing trusts

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

	As of December 31,
	2019												2018
	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.

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Exelon

The data shown below, which may not equal the total for the year due to the effects of rounding and dilution, includes all adjustments that Exelon considers necessary for a fair presentation of such amounts:

	Operating Revenues								Operating Income								Net Income Attributable to Common Shareholders
	2019				2018				2019				2018				2019				2018
Quarter ended:
March 31	$	9,477			$	9,691			$	1,218			$	1,099			$	907			$	583
June 30	7,689				8,074				841				940				484				537
September 30	8,929				9,401				1,353				1,144				772				731
December 31(a)	8,343				8,812				962				706				773				152

	Net Income per Basic Share								Net Income per Diluted Share
	2019				2018				2019				2018
Quarter ended:
March 31	$	0.93			$	0.60			$	0.93			$	0.60
June 30	0.50				0.56				0.50				0.55
September 30	0.79				0.76				0.79				0.75
December 31	0.79				0.16				0.79				0.16

__________

(a)	Operating revenues, Operating income and Net income attributable to common shareholders for the quarter ended December 31, 2019 include a $6 million reduction related to a correction for Pepco’s decoupling mechanism for the 2019 interim periods. See Note 1 — Significant Accounting Policies for additional information.

Generation

The data shown below includes all adjustments that Generation considers necessary for a fair presentation of such amounts:

	Operating Revenues								Operating Income								Net Income (Loss) Attributable to Membership Interest
	2019				2018				2019				2018				2019				2018
Quarter ended:
March 31	$	5,296			$	5,512			$	333			$	347			$	363			$	136
June 30	4,210				4,579				147				282				108				178
September 30	4,774				5,278				482				311				257				234
December 31	4,644				5,069				362				35				397				(178		)

---

ComEd

The data shown below includes all adjustments that ComEd considers necessary for a fair presentation of such amounts:

	Operating Revenues								Operating Income								Net Income
	2019				2018				2019				2018				2019				2018
Quarter ended:
March 31	$	1,408			$	1,512			$	276			$	292			$	157			$	165
June 30	1,351				1,398				311				288				186				164
September 30	1,583				1,598				328				323				200				193
December 31	1,405				1,373				255				242				144				141

PECO

The data shown below includes all adjustments that PECO considers necessary for a fair presentation of such amounts:

	Operating Revenues								Operating Income								Net Income
	2019				2018				2019				2018				2019				2018
Quarter ended:
March 31	$	900			$	866			$	222			$	142			$	168			$	113
June 30	655				653				145				127				102				96
September 30	778				757				183				154				140				126
December 31	766				765				162				165				118				124

BGE

The data shown below includes all adjustments that BGE considers necessary for a fair presentation of such amounts:

	Operating Revenues								Operating Income								Net Income
	2019				2018				2019				2018				2019				2018
Quarter ended:
March 31	$	976			$	977			$	220			$	177			$	160			$	128
June 30	649				662				80				85				45				51
September 30	703				731				91				103				55				63
December 31	779				799				142				109				99				71

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PHI

The data shown below includes all adjustments that PHI considers necessary for a fair presentation of such amounts:

	Operating Revenues								Operating Income								Net Income
	2019				2018				2019				2018				2019				2018
Quarter ended:
March 31	$	1,228			$	1,249			$	175			$	124			$	117			$	63
June 30	1,091				1,074				165				151				106				82
September 30	1,380				1,359				256				243				189				185
December 31(a)	1,107				1,115				128				124				65				62

__________

(a)	Operating revenues, Operating income and Net income attributable to common shareholders for the quarter ended December 31, 2019 include a $6 million reduction related to a correction for Pepco’s decoupling mechanism for the 2019 interim periods. See Note 1 — Significant Accounting Policies for additional information.

Pepco

The data shown below includes all adjustments that Pepco considers necessary for a fair presentation of such amounts:

	Operating Revenues								Operating Income								Net Income
	2019				2018				2019				2018				2019				2018
Quarter ended:
March 31	$	575			$	555			$	84			$	54			$	55			$	29
June 30	531				521				93				83				64				52
September 30	642				626				127				110				98				87
December 31(a)	513				529				57				63				26				36

_________

(a)	Operating revenues, Operating income and Net income attributable to common shareholders for the quarter ended December 31, 2019 include a $6 million reduction related to a correction for Pepco’s decoupling mechanism for the 2019 interim periods. See Note 1 — Significant Accounting Policies for additional information.

DPL

The data shown below includes all adjustments that DPL considers necessary for a fair presentation of such amounts:

	Operating Revenues								Operating Income								Net Income
	2019				2018				2019				2018				2019				2018
Quarter ended:
March 31	$	380			$	384			$	72			$	49			$	53			$	31
June 30	287				289				44				42				30				26
September 30	319				328				51				51				33				33
December 31	319				331				50				48				31				30

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ACE

The data shown below includes all adjustments that ACE considers necessary for a fair presentation of such amounts:

	Operating Revenues								Operating Income								Net Income (Loss)
	2019				2018				2019				2018				2019				2018
Quarter ended:
March 31	$	273			$	310			$	21			$	23			$	10			$	7
June 30	274				265				28				25				14				8
September 30	419				406				79				84				63				61
December 31	274				254				23				14				12				(1		)

---

---

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(1)

Balance includes stock options, unvested performance shares, and unvested restricted shares granted under the Exelon LTIP or predecessor company plans including shares awarded under those plans and deferred into the stock deferral plan, and deferred stock units granted to directors as part of their compensation. Unvested performance shares are subject to performance metrics ranging from 0% to 150% of target award values and to a total shareholder return modifier. For performance shares granted in 2017, 2018 and 2019, the total includes the number of shares that could be issued pursuant to the terms of the Exelon LTIP plan, which provides that final payouts are made 50% in shares of stock and 50% in cash, and if the performance and total shareholder return modifier metrics were both at maximum, representing a best case performance scenario, for a total of 4,005,200 shares. If the performance and total shareholder return modifier metrics were at target, the number of securities to be issued for such awards would be 2,002,600. The deferred stock units granted to directors includes 467,218 shares to be issued upon the conversion of deferred stock units awarded to members of the Exelon Board of Directors. Conversion of the deferred stock units to shares occurs after a director terminates service to the Exelon board or the board of any of its subsidiary companies. See Note 20 — Stock-Based Compensation Plans of the Combined Notes to Consolidated Financial Statements for additional information about the material features of the plans.

(2)	The weighted-average price reported in column B does not take the performance shares and shares credited to deferred compensation plans into account.

(3)	Includes 17,125,705 shares remaining available for issuance from the employee stock purchase plan.

---

---

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(a)	The following documents are filed as a part of this report:

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Exelon Corporation and Subsidiary Companies

 Schedule I – Condensed Financial Information of Parent (Exelon Corporate)

Condensed Statements of Operations and Other Comprehensive Income

 

	For the Years Ended December 31,
(In millions)	2019				2018				2017
Operating expenses
Operating and maintenance	$	33			$	(5	)		$	10
Operating and maintenance from affiliates	9				9				25
Other	1				4				4
Total operating expenses	43				8				39
Operating loss	(43		)		(8		)		(39		)
Other income and (deductions)
Interest expense, net	(321		)		(312		)		(315		)
Equity in earnings of investments	3,254				2,183				4,407
Interest income from affiliates, net	39				42				40
Other, net	14				3				1
Total other income	2,986				1,916				4,133
Income before income taxes	2,943				1,908				4,094
Income taxes	7				(97		)		315
Net income	$	2,936			$	2,005			$	3,779
Other comprehensive income (loss)
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic costs	$	(64	)		$	(66	)		$	(56	)
Actuarial loss reclassified to periodic cost	148				247				197
Pension and non-pension postretirement benefit plan valuation adjustment	(289		)		(143		)		10
Unrealized gain on cash flow hedges	1				12				3
Unrealized gain on marketable securities	—				—				6
Unrealized gain on equity investments	—				1				6
Unrealized (loss) gain on foreign currency translation	—				(10		)		7
Other comprehensive income (loss)	(204		)		41				173
Comprehensive income	$	2,732			$	2,046			$	3,952

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Exelon Corporation and Subsidiary Companies

Schedule I – Condensed Financial Information of Parent (Exelon Corporate)

Condensed Statements of Cash Flows

 

	For the Years Ended December 31,
(In millions)	2019				2018				2017
Net cash flows provided by operating activities	$	1,948			$	2,576			$	1,914
Cash flows from investing activities
Changes in Exelon intercompany money pool	95				1				(129		)
Investment in affiliates	(1,071		)		(1,231		)		(1,710		)
Other investing activities	—				—				(5		)
Net cash flows used in investing activities	(976		)		(1,230		)		(1,844		)
Cash flows from financing activities
Changes in short-term borrowings	136				—				—
Proceeds from short-term borrowings with maturities greater than 90 days	—				—				500
Retirement of long-term debt	—				—				(569		)
Common stock issued from treasury stock	—				—				1,150
Dividends paid on common stock	(1,408		)		(1,332		)		(1,236		)
Proceeds from employee stock plans	112				105				150
Other financing activities	—				(4		)		(9		)
Net cash flows used in financing activities	(1,160		)		(1,231		)		(14		)
(Decrease) Increase in cash, cash equivalents and restricted cash	(188		)		115				56
Cash, cash equivalents and restricted cash at beginning of period	189				74				18
Cash, cash equivalents and restricted cash at end of period	$	1			$	189			$	74

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Exelon Corporation and Subsidiary Companies

Schedule I – Condensed Financial Information of Parent (Exelon Corporate)

Condensed Balance Sheets

 

	December 31,
(In millions)	2019				2018
ASSETS
Current assets
Cash and cash equivalents	$	1			$	189
Accounts receivable, net
Other accounts receivable	168				48
Accounts receivable from affiliates	41				44
Mark-to-market derivative assets	3				—
Notes receivable from affiliates	679				216
Regulatory assets	253				182
Other	4				4
Total current assets	1,149				683
Property, plant and equipment, net	47				48
Deferred debits and other assets
Regulatory assets	3,772				3,742
Investments in affiliates	42,245				40,425
Deferred income taxes	1,524				1,455
Notes receivable from affiliates	329				898
Other	308				235
Total deferred debits and other assets	48,178				46,755
Total assets	$	49,374			$	47,486

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Exelon Corporation and Subsidiary Companies

Schedule I – Condensed Financial Information of Parent (Exelon Corporate)

Condensed Balance Sheets

 

	December 31,
(In millions)	2019				2018
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings	$	636			$	500
Long-term debt due within one year	1,458				—
Accounts payable	1				1
Accrued expenses	131				184
Payables to affiliates	363				360
Regulatory liabilities	13				15
Pension obligations	77				63
Other	10				14
Total current liabilities	2,689				1,137
Long-term debt	5,717				7,147
Deferred credits and other liabilities
Regulatory liabilities	31				32
Pension obligations	7,960				7,795
Non-pension postretirement benefit obligations	403				199
Deferred income taxes	263				233
Other	87				202
Total deferred credits and other liabilities	8,744				8,461
Total liabilities	17,150				16,745
Commitments and contingencies
Shareholders’ equity
Common stock (No par value, 2,000 shares authorized, 973 shares and 968 shares outstanding at December 31, 2019 and 2018, respectively)	19,274				19,116
Treasury stock, at cost (2 shares at December 31, 2019 and 2018)	(123		)		(123		)
Retained earnings	16,267				14,743
Accumulated other comprehensive loss, net	(3,194		)		(2,995		)
Total shareholders’ equity	32,224				30,741
Total liabilities and shareholders’ equity	$	49,374			$	47,486

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Exelon Corporate is a holding company that conducts substantially all of its business operations through its subsidiaries. These condensed financial statements and related footnotes have been prepared in accordance with Rule 12-04, Schedule I of Regulation S-X. These statements should be read in conjunction with the consolidated financial statements and notes thereto of Exelon Corporation.

Short-Term Borrowings

Exelon Corporate meets its short-term liquidity requirements primarily through the issuance of commercial paper. Exelon Corporate had $136 million of outstanding commercial paper borrowings at December 31, 2019 and no outstanding commercial paper borrowings at December 31, 2018.

Short-Term Loan Agreements

On March 23, 2017, Exelon Corporate entered into a $500 million term loan agreement, which was renewed on March 22, 2018 with an expiration of March 21, 2019. The loan agreement was renewed on March 20, 2019 and will expire on March 19, 2020. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.95% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Exelon’s Consolidated Balance Sheet within Short-Term borrowings.

Revolving Credit Agreements

On May 26, 2016, Exelon Corporate amended its syndicated revolving credit facility with aggregate bank commitments of $600 million through May 26, 2021. On May 26, 2018, Exelon Corporate had its maturity date extended to May 26, 2023. As of December 31, 2019, Exelon Corporation had available capacity under those commitments of $458 million. See Note 16—Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information regarding Exelon Corporation’s credit agreement.

Long-Term Debt

The following tables present the outstanding long-term debt for Exelon Corporate as of December 31, 2019 and December 31, 2018:

							Maturity Date		December 31,
	Rates								2019				2018
Long-term debt
Junior subordinated notes				3.50	%		2022		$	1,150			$	1,150
Senior unsecured notes(a)	2.45	%	-	7.60	%		2020 - 2046		5,889				5,889
Total long-term debt									7,039				7,039
Unamortized debt discount and premium, net									(7		)		(7		)
Unamortized debt issuance costs									(39		)		(47		)
Fair value adjustment									182				162
Long-term debt due within one year									(1,458		)		—
Long-term debt									$	5,717			$	7,147

__________

(a)	Senior unsecured notes include mirror debt that is held on both Generation and Exelon Corporation's balance sheets.

The debt maturities for Exelon Corporate for the periods 2020, 2021, 2022, 2023, 2024 and thereafter are as follows:

---

2020	$	1,458
2021	300
2022	1,150
2023	—
2024	—
Remaining years	4,131
Total long-term debt	$	7,039

See Note 18—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for Exelon Corporate’s commitments and contingencies related to environmental matters and fund transfer restrictions.

The financial statements of Exelon Corporate include related party transactions as presented in the tables below:

	For the Years Ended December 31,
(In millions)	2019				2018				2017
Operating and maintenance from affiliates:
BSC(a)	$	9			$	11			$	23
Other	—				(2		)		2
Total operating and maintenance from affiliates:	$	9			$	9			$	25
Interest income from affiliates, net:
Generation	$	36			$	36			$	37
BSC	3				4				3
Exelon Energy Delivery Company, LLC(b)	—				2				—
Total interest income from affiliates, net:	$	39			$	42			$	40
Equity in earnings (losses) of investments:
Exelon Energy Delivery Company, LLC(b)	$	2,054			$	1,830			$	1,663
Generation	1,125				369				2,710
UII, LLC	97				—				41
PCI	1				(17		)		1
BSC	—				—				1
Exelon Enterprises	(16		)		—				1
Exelon INQB8R	(8		)		—				—
Exelon Transmission Company, LLC	(2		)		1				(10		)
Other	3				—				—
Total equity in earnings of investments:	$	3,254			$	2,183			$	4,407
Cash contributions received from affiliates	$	2,514			$	2,302			$	1,879

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	December 31,
(in millions)	2019				2018
Accounts receivable from affiliates (current):
BSC(a)	$	11			$	13
Generation	13				17
ComEd	2				4
PECO	2				2
BGE	1				2
PHISCO	7				6
Exelon VTI, LLC	5				—
Total accounts receivable from affiliates (current):	$	41			$	44
Notes receivable from affiliates (current):
BSC(a)	$	109			$	116
Generation(c)	558				100
PHI	12				—
Total notes receivable from affiliates (current):	$	679			$	216
Investments in affiliates:
BSC(a)	$	197			$	197
Exelon Energy Delivery Company, LLC(b)	28,147				26,679
Generation	13,484				13,204
PCI	62				61
UII, LLC	365				268
Exelon Transmission Company, LLC	—				1
Voluntary Employee Beneficiary Association trust	(4		)		(1		)
Exelon Enterprises	6				22
Exelon INQB8R, LLC	(8		)		—
Other	(4		)		(6		)
Total investments in affiliates:	$	42,245			$	40,425
Notes receivable from affiliates (non-current):
Generation(c)	$	329			$	898
Accounts payable to affiliates (current):
UII, LLC	$	360			$	360
Exelon Enterprises	3				—
Total accounts payable to affiliates (current):	$	363			$	360

__________

(a)	Exelon Corporate receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead.

(b)	Exelon Energy Delivery Company, LLC consists of ComEd, PECO, BGE, PHI, Pepco, DPL and ACE.

(c)

In connection with the debt obligations assumed by Exelon as part of the Constellation merger, Exelon and subsidiaries of Generation (former Constellation subsidiaries) assumed intercompany loan agreements that mirror the terms and amounts of the third-party debt obligations of Exelon, resulting in intercompany notes payable included in Long-Term Debt to affiliates in Generation’s Consolidated Balance Sheets and intercompany notes receivable at Exelon Corporate, which are eliminated in consolidation in Exelon’s Consolidated Balance Sheets.

Exelon Corporation and Subsidiary Companies 

Schedule II – Valuation and Qualifying Accounts

Column A		Column B				Column C								Column D				Column E
						Additions and adjustments
Description		Balance at Beginning of Period				Charged to Costs and Expenses				Charged to Other Accounts				Deductions				Balance at End of Period
		(in millions)
For the year ended December 31, 2019
Allowance for uncollectible accounts(a)		$	319			$	119			$	26		(c)	$	170		(e)	$	294
Deferred tax valuation allowance		35				—				(9		)		—				26
Reserve for obsolete materials		156				6				—			(d)	7				155
For the year ended December 31, 2018
Allowance for uncollectible accounts(a)		$	322			$	159			$	35		(c)	$	197		(e)	$	319
Deferred tax valuation allowance		37				—				5				7				35
Reserve for obsolete materials		174				25				(31		)		12				156
For the year ended December 31, 2017
Allowance for uncollectible accounts(a)		$	334			$	126			$	27		(b)(c)	$	165		(e)	$	322
Deferred tax valuation allowance		20				—				17			(b)	—				37
Reserve for obsolete materials		113				56				10			(b)	5				174

__________

(a)	Excludes the non-current allowance for uncollectible accounts related to PECO’s installment plan receivables of $9 million, $13 million, and $15 million for the years ended December 31, 2019, 2018 and 2017, respectively.

(b)	Primarily represents the addition of PHI's results as of March 23, 2016, the date of the merger.

(c)	Includes charges for late payments and non-service receivables.

(d)	Primarily reflects the reclassification of assets as held for sale.

(e)	Write-off of individual accounts receivable.

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Exelon Generation Company, LLC and Subsidiary Companies

(2) Generation

(i)		Financial Statements (Item 8):
		Report of Independent Registered Public Accounting Firm dated February 11, 2020 of PricewaterhouseCoopers LLP
		Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2019, 2018 and 2017
		Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 2018 and 2017
		Consolidated Balance Sheets at December 31, 2019 and 2018
		Consolidated Statements of Changes in Equity for the Years Ended December 31, 2019, 2018 and 2017
		Notes to Consolidated Financial Statements
(ii)		Financial Statement Schedule:
		Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2019, 2018 and 2017
		Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto

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Exelon Generation Company, LLC and Subsidiary Companies

Schedule II – Valuation and Qualifying Accounts

Column A		Column B				Column C								Column D				Column E
						Additions and adjustments
Description		Balance at Beginning of Period				Charged to Costs and Expenses				Charged to Other Accounts				Deductions				Balance at End of Period
		(in millions)
For the year ended December 31, 2019
Allowance for uncollectible accounts		$	104			$	27			$	(11	)		$	39			$	81
Deferred tax valuation allowance		26				—				(2		)		—				24
Reserve for obsolete materials		145				—				—				2				143
For the year ended December 31, 2018
Allowance for uncollectible accounts		$	114			$	44			$	4			$	58			$	104
Deferred tax valuation allowance		23				—				3				—				26
Reserve for obsolete materials		166				20				(32		)	(a)	9				145
For the year ended December 31, 2017
Allowance for uncollectible accounts		$	91			$	34			$	—			$	11			$	114
Deferred tax valuation allowance		9				—				14				—				23
Reserve for obsolete materials		106				51				9				—				166

__________

(a)	Primarily reflects the reclassification of assets as held for sale.

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Commonwealth Edison Company and Subsidiary Companies

(3) ComEd

(i)		Financial Statements (Item 8):
		Report of Independent Registered Public Accounting Firm dated February 11, 2020 of PricewaterhouseCoopers LLP
		Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2019, 2018 and 2017
		Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 2018 and 2017
		Consolidated Balance Sheets at December 31, 2019 and 2018
		Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2019, 2018 and 2017
		Notes to Consolidated Financial Statements
(ii)		Financial Statement Schedule:
		Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2019, 2018 and 2017
		Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto

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Commonwealth Edison Company and Subsidiary Companies

Schedule II – Valuation and Qualifying Accounts

Column A		Column B				Column C								Column D				Column E
						Additions and adjustments
Description		Balance at Beginning of Period				Charged to Costs and Expenses				Charged to Other Accounts				Deductions				Balance at End of Period
		(in millions)
For the year ended December 31, 2019
Allowance for uncollectible accounts		$	81			$	35			$	20		(a)	$	57		(b)	$	79
Reserve for obsolete materials		6				6				—				5				7
For the year ended December 31, 2018
Allowance for uncollectible accounts		$	73			$	44			$	23		(a)	$	59		(b)	$	81
Reserve for obsolete materials		5				3				1				3				6
For the year ended December 31, 2017
Allowance for uncollectible accounts		$	70			$	39			$	20		(a)	$	56		(b)	$	73
Reserve for obsolete materials		4				3				1				3				5

__________

(a)	Primarily charges for late payments and non-service receivables.

(b)	Write-off of individual accounts receivable.

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PECO Energy Company and Subsidiary Companies

(4) PECO

(i)		Financial Statements (Item 8):
		Report of Independent Registered Public Accounting Firm dated February 11, 2020 of PricewaterhouseCoopers LLP
		Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2019, 2018 and 2017
		Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 2018 and 2017
		Consolidated Balance Sheets at December 31, 2019 and 2018
		Consolidated Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2019, 2018 and 2017
		Notes to Consolidated Financial Statements
(ii)		Financial Statement Schedule:
		Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2019, 2018 and 2017
		Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto

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PECO Energy Company and Subsidiary Companies

Schedule II – Valuation and Qualifying Accounts

Column A		Column B				Column C								Column D				Column E
						Additions and adjustments
Description		Balance at Beginning of Period				Charged to Costs and Expenses				Charged to Other Accounts				Deductions				Balance at End of Period
		(in millions)
For the year ended December 31, 2019
Allowance for uncollectible accounts(a)		$	61			$	31			$	3		(b)	$	33		(c)	$	62
Reserve for obsolete materials		2				—				—				—				2
For the year ended December 31, 2018
Allowance for uncollectible accounts(a)		$	56			$	33			$	3		(b)	$	31		(c)	$	61
Reserve for obsolete materials		2				—				—				—				2
For the year ended December 31, 2017
Allowance for uncollectible accounts(a)		$	61			$	26			$	4		(b)	$	35		(c)	$	56
Reserve for obsolete materials		2				—				—				—				2

__________

(a)	Excludes the non-current allowance for uncollectible accounts related to PECO’s installment plan receivables of $9 million, $13 million, and $15 million for the years ended December 31, 2019, 2018, and 2017, respectively.

(b)	Primarily charges for late payments.

(c)	Write-off of individual accounts receivable.

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Baltimore Gas and Electric Company and Subsidiary Companies

(5) BGE

(i)		Financial Statements (Item 8):
		Report of Independent Registered Public Accounting Firm dated February 11, 2020 of PricewaterhouseCoopers LLP
		Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2019, 2018 and 2017
		Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 2018 and 2017
		Consolidated Balance Sheets at December 31, 2019 and 2018
		Consolidated Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2019, 2018 and 2017
		Notes to Consolidated Financial Statements
(ii)		Financial Statement Schedule:
		Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2019, 2018 and 2017
		Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto

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Baltimore Gas and Electric Company and Subsidiary Companies

Schedule II – Valuation and Qualifying Accounts

Column A		Column B				Column C								Column D				Column E
						Additions and adjustments
Description		Balance at Beginning of Period				Charged to Costs and Expenses				Charged to Other Accounts				Deductions				Balance at End of Period
		(in millions)
For the year ended December 31, 2019
Allowance for uncollectible accounts		$	20			$	8			$	7			$	18		(a)	$	17
Deferred tax valuation allowance		1				—				—				—				1
Reserve for obsolete materials		1				—				—				—				1
For the year ended December 31, 2018
Allowance for uncollectible accounts		$	24			$	10			$	(2	)		$	12		(a)	$	20
Deferred tax valuation allowance		1				—				—				—				1
Reserve for obsolete materials		—				1				—				—				1
For the year ended December 31, 2017
Allowance for uncollectible accounts		$	32			$	8			$	(3	)		$	13		(a)	$	24
Deferred tax valuation allowance		1				—				—				—				1
Reserve for obsolete materials		—				—				—				—				—

__________

(a)	Write-off of individual accounts receivable.

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Pepco Holdings LLC and Subsidiary Companies

(6) PHI

(i)		Financial Statements (Item 8):
		Report of Independent Registered Public Accounting Firm dated February 11, 2020 of PricewaterhouseCoopers LLP
		Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2019, 2018 and 2017
		Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 2018 and 2017
		Consolidated Balance Sheets at December 31, 2019 and 2018
		Consolidated Statements of Changes in Equity for the Years Ended December 31, 2019, 2018 and 2017
		Notes to Consolidated Financial Statements
(ii)		Financial Statement Schedule:
		Schedule II – Valuation and Qualifying Accounts for the Years Ended December 31, 2019, 2018 and 2017
		Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto

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Pepco Holdings LLC and Subsidiary Companies

Schedule II – Valuation and Qualifying Accounts

Column A		Column B				Column C								Column D				Column E
						Additions and adjustments
Description		Balance at Beginning of Period				Charged to Costs and Expenses				Charged to Other Accounts				Deductions				Balance at End of Period
		(in millions)
For the Year Ended December 31, 2019
Allowance for uncollectible accounts		$	53			$	17			$	7		(a)	$	24		(b)	$	53
Deferred tax valuation allowance		8				—				(8		)		—				—
Reserve for obsolete materials		2				1				—				—				3
For the Year Ended December 31, 2018
Allowance for uncollectible accounts		$	55			$	28			$	7		(a)	$	37		(b)	$	53
Deferred tax valuation allowance		13				—				2				7				8
Reserve for obsolete materials		2				—				—				—				2
For the Year Ended December 31, 2017
Allowance for uncollectible accounts		$	80			$	19			$	6		(a)	$	50		(b)	$	55
Deferred tax valuation allowance		10				—				3				—				13
Reserve for obsolete materials		2				2				—				2				2

__________

(a)	Primarily charges for late payments.

(b)	Write-off of individual accounts receivable.

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Potomac Electric Power Company

(7) Pepco

(i)		Financial Statements (Item 8):
		Report of Independent Registered Public Accounting Firm dated February 11, 2020 of PricewaterhouseCoopers LLP
		Statements of Operations and Comprehensive Income for the Years Ended December 31, 2019, 2018 and 2017
		Statements of Cash Flows for the Years Ended December 31, 2019, 2018 and 2017
		Balance Sheets at December 31, 2019 and 2018
		Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2019, 2018 and 2017
		Notes to Financial Statements
(ii)		Financial Statement Schedule:
		Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2019, 2018 and 2017
		Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto

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Potomac Electric Power Company

Schedule II – Valuation and Qualifying Accounts

Column A		Column B				Column C								Column D				Column E
						Additions and adjustments
Description		Balance at Beginning of Period				Charged to Costs and Expenses				Charged to Other Accounts				Deductions				Balance at End of Period
		(in millions)
For the year ended December 31, 2019
Allowance for uncollectible accounts		$	21			$	7			$	2		(a)	$	10		(b)	$	20
Reserve for obsolete materials		1				—				—				—				1
For the year ended December 31, 2018
Allowance for uncollectible accounts		$	21			$	11			$	3		(a)	$	14		(b)	$	21
Reserve for obsolete materials		1				—				—				—				1
For the year ended December 31, 2017
Allowance for uncollectible accounts		$	29			$	8			$	2		(a)	$	18		(b)	$	21
Reserve for obsolete materials		1				1				—				1				1

__________

(a)	Primarily charges for late payments.

(b)	Write-off of individual accounts receivable.

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Delmarva Power & Light Company

(8) DPL

(i)		Financial Statements (Item 8):
		Report of Independent Registered Public Accounting Firm dated February 11, 2020 of PricewaterhouseCoopers LLP
		Statements of Operations and Comprehensive Income for the Years Ended December 31, 2019, 2018 and 2017
		Statements of Cash Flows for the Years Ended December 31, 2019, 2018 and 2017
		Balance Sheets at December 31, 2019 and 2018
		Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2019, 2018 and 2017
		Notes to Financial Statements
(ii)		Financial Statement Schedule:
		Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2019, 2018 and 2017
		Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto

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Delmarva Power & Light Company

Schedule II – Valuation and Qualifying Accounts

Column A		Column B				Column C								Column D				Column E
						Additions and adjustments
Description		Balance at Beginning of Period				Charged to Costs and Expenses				Charged to Other Accounts				Deductions				Balance at End of Period
		(in millions)
For the year ended December 31, 2019
Allowance for uncollectible accounts		$	13			$	4			$	3		(a)	$	5		(b)	$	15
Reserve for obsolete materials		—				—				—				—				—
For the year ended December 31, 2018
Allowance for uncollectible accounts		$	16			$	6			$	2		(a)	$	11		(b)	$	13
Reserve for obsolete materials		—				—				—				—				—
For the year ended December 31, 2017
Allowance for uncollectible accounts		$	24			$	3			$	2		(a)	$	13		(b)	$	16
Reserve for obsolete materials		—				1				—				1				—

__________

(a)	Primarily charges for late payments.

(b)	Write-off of individual accounts receivable.

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Atlantic City Electric Company and Subsidiary Company

(9) ACE

(i)		Financial Statements (Item 8):
		Report of Independent Registered Public Accounting Firm dated February 11, 2020 of PricewaterhouseCoopers LLP
		Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2019, 2018 and 2017
		Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 2018 and 2017
		Consolidated Balance Sheets at December 31, 2019 and 2018
		Consolidated Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2019, 2018 and 2017
		Notes to Consolidated Financial Statements
(ii)		Financial Statement Schedule:
		Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2019, 2018 and 2017
		Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto

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Atlantic City Electric Company and Subsidiary Company

Schedule II – Valuation and Qualifying Accounts

Column A		Column B				Column C								Column D				Column E
						Additions and adjustments
Description		Balance at Beginning of Period				Charged to Costs and Expenses				Charged to Other Accounts				Deductions				Balance at End of Period
		(in millions)
For the year ended December 31, 2019
Allowance for uncollectible accounts		$	19			$	5			$	2		(a)	$	8		(b)	$	18
Reserve for obsolete materials		1				—				—				—				1
For the year ended December 31, 2018
Allowance for uncollectible accounts		$	18			$	11			$	2		(a)	$	12		(b)	$	19
Reserve for obsolete materials		1				—				—				—				1
For the year ended December 31, 2017
Allowance for uncollectible accounts		$	27			$	8			$	2		(a)	$	19		(b)	$	18
Reserve for obsolete materials		1				—				—				—				1

__________

(a)	Primarily charges for late payments.

(b)	Write-off of individual accounts receivable.

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(a)	These filings are not available electronically on the SEC website as they were filed in paper previous to the electronic system that is currently in place.

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