EXELON CORP - Annual Report: 2019 (Form 10-K)

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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.

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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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•	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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•	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.

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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).

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(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.

(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.

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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.

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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.

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

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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.

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(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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(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.

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•	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.

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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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(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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(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.

(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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(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.

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(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.

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(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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(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.

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(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.

•	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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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.

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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.

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

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

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(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.

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(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.

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(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.

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

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(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.

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(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.

(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.

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(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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(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.

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(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.

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(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.

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

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

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(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.

(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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(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.

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

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(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.

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(a)	Represents cash settlements only.

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(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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(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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(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.

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(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.

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(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.

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(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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(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.

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(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.

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(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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(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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(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.

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(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.

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

(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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(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.

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•	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.

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(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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(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.

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(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.

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(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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(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.

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(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.

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

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(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.

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(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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(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.

(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.

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•	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.

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(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.

(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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(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.

(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.

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(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.

(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.

(a)	Includes stock options issued to retirement eligible employees.

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(a)	The difference between the market value on the date of exercise and the option exercise price.

(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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(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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•	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.

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(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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(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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(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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(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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(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.

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

(a)	The Registrants’ debt and equity security investments are recorded at fair market value.

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

(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.

(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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(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.

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(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.

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(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.

(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.

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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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(a)	Senior unsecured notes include mirror debt that is held on both Generation and Exelon Corporation's balance sheets.

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(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.

(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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(a)	Primarily reflects the reclassification of assets as held for sale.

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(a)	Primarily charges for late payments and non-service receivables.

(b)	Write-off of individual accounts receivable.

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(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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(a)	Write-off of individual accounts receivable.

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(a)	Primarily charges for late payments.

(b)	Write-off of individual accounts receivable.

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(a)	Primarily charges for late payments.

(b)	Write-off of individual accounts receivable.

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(a)	Primarily charges for late payments.

(b)	Write-off of individual accounts receivable.

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(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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