false(800)(202)(410)(312)(202)(610)(215)(202)(202)10 South Dearborn Street500 North Wakefield Drive2 Center Plaza440 South LaSalle Street500 North Wakefield Drive300 Exelon WayP.O. Box 8699701 Ninth Street, N.W.701 Ninth Street, N.W.P.O. Box 805379110 West Fayette Street2301 Market StreetChicagoNewarkBaltimoreChicagoNewarkKennett SquarePhiladelphiaWashington, District of ColumbiaWashington, District of Columbia60680-53791970221201-370860605-10281970219348-247319101-86992006820068ILDEMDILDEPAPA000110935700000081920000009466000002260600000278790001168165000007810000011359710000079732PANJMDILDEVAPAPADEDCVA483-3220872-2000234-5000394-4321872-2000765-5959841-4000872-2000872-2000Common stock, without par valueCumulative Preferred Security, Series DNasdaqNYSEEXCEXC/28 0001109357 exc:ExelonGenerationCoLLCMember 2019-10-31 2019-10-31 0001109357 exc:CommonwealthEdisonCoMember 2019-10-31 2019-10-31 0001109357 exc:PotomacElectricPowerCompanyMember 2019-10-31 2019-10-31 0001109357 exc:BaltimoreGasAndElectricCompanyMember 2019-10-31 2019-10-31 0001109357 exc:PecoEnergyCoMember 2019-10-31 2019-10-31 0001109357 exc:AtlanticCityElectricCompanyMember 2019-10-31 2019-10-31 0001109357 2019-10-31 2019-10-31 0001109357 exc:PepcoHoldingsLLCMember 2019-10-31 2019-10-31 0001109357 exc:DelmarvaPowerandLightCompanyMember 2019-10-31 2019-10-31 0001109357 exc:DelmarvaPowerandLightCompanyMember stpr:VA 2019-10-31 2019-10-31 0001109357 exc:PotomacElectricPowerCompanyMember stpr:VA 2019-10-31 2019-10-31 0001109357 exc:PotomacElectricPowerCompanyMember stpr:DC 2019-10-31 2019-10-31 0001109357 exc:DelmarvaPowerandLightCompanyMember stpr:DE 2019-10-31 2019-10-31

	UNITED STATES SECURITIES AND EXCHANGE COMMISSION
	Washington, D.C. 20549
	FORM	8-K

	CURRENT REPORT
	Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
	October 31, 2019
	Date of Report (Date of earliest event reported)

Commission File Number		Name of Registrant; State or Other Jurisdiction of Incorporation; Address of Principal Executive Offices; and Telephone Number		IRS Employer Identification Number
001-16169		EXELON CORPORATION		23-2990190
		(a Pennsylvania corporation) 10 South Dearborn Street P.O. Box 805379 Chicago, Illinois 60680-5379 (800) 483-3220
333-85496		EXELON GENERATION COMPANY, LLC		23-3064219
		(a Pennsylvania limited liability company) 300 Exelon Way Kennett Square, Pennsylvania 19348-2473 (610) 765-5959
001-01839		COMMONWEALTH EDISON COMPANY		36-0938600
		(an Illinois corporation) 440 South LaSalle Street Chicago, Illinois 60605-1028 (312) 394-4321
000-16844		PECO ENERGY COMPANY		23-0970240
		(a Pennsylvania corporation) P.O. Box 8699 2301 Market Street Philadelphia, Pennsylvania 19101-8699 (215) 841-4000
001-01910		BALTIMORE GAS AND ELECTRIC COMPANY		52-0280210
		(a Maryland corporation) 2 Center Plaza 110 West Fayette Street Baltimore, Maryland 21201-3708 (410) 234-5000
001-31403		PEPCO HOLDINGS LLC		52-2297449
		(a Delaware limited liability company) 701 Ninth Street, N.W. Washington, District of Columbia 20068 (202) 872-2000
001-01072		POTOMAC ELECTRIC POWER COMPANY		53-0127880
		(a District of Columbia and Virginia corporation) 701 Ninth Street, N.W. Washington, District of Columbia 20068 (202) 872-2000
001-01405		DELMARVA POWER & LIGHT COMPANY		51-0084283
		(a Delaware and Virginia corporation) 500 North Wakefield Drive Newark, Delaware 19702 (202) 872-2000
001-03559		ATLANTIC CITY ELECTRIC COMPANY		21-0398280
		(a New Jersey corporation) 500 North Wakefield Drive Newark, Delaware 19702 (202) 872-2000

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Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:
☐	Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
☐	Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
☐	Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
☐	Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Securities registered pursuant to Section 12(b) of the Act:
Title of each class		Trading Symbol(s)		Name of each exchange on which registered
EXELON CORPORATION:
Common Stock, without par value		EXC		The Nasdaq Stock Market LLC
PECO ENERGY COMPANY:
Trust Receipts of PECO Energy Capital Trust III, each representing a 7.38% Cumulative Preferred Security, Series D, $25 stated value, issued by PECO Energy Capital, L.P. and unconditionally guaranteed by PECO Energy Company		EXC/28		New York Stock Exchange

Indicate by check mark whether any of the registrants are emerging growth companies as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter).
Emerging growth company	☐

If an emerging growth company, indicate by check mark if any of the registrants have elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.

☐

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Section 2 - Financial Information

Item 2.02. Results of Operations and Financial Condition.

Section 7 - Regulation FD

Item 7.01. Regulation FD Disclosure.

 

On October 31, 2019, Exelon Corporation (Exelon) announced via press release its results for the third quarter ended September 30, 2019. A copy of the press release and related attachments is attached hereto as Exhibit 99.1. Also attached as Exhibits 99.2 and 99.3 to this Current Report on Form 8-K are the presentation slides to be used at the third quarter 2019 earnings conference call and the third quarter 2019 infographic. This Form 8-K and the attached exhibits are provided under Items 2.02, 7.01 and 9.01 of Form 8-K and are furnished to, but not filed with, the Securities and Exchange Commission.

Exelon has scheduled the conference call for 9:00 AM CT (10:00 AM ET) on October 31, 2019. The call-in number in the U.S. and Canada is 800-690-3108, and the international call-in number is 973-935-8753. If requested, the conference ID number is 4098913. Media representatives are invited to participate on a listen-only basis. The call will be web-cast and archived on Exelon’s Web site: www.exeloncorp.com. (Please select the Investors page.)

Telephone replays will be available until November 14, 2019. The U.S. and Canada call-in number for replays is 855-859-2056, and the international call-in number is 404-537-3406. The conference ID number is 4098913.

Section 9 - Financial Statements and Exhibits

Item 9.01. Financial Statements and Exhibits

(d)    Exhibits.

Exhibit No.	Description
99.1	Press release and earnings release attachments
99.2	Earnings conference call presentation slides
99.3	Infographic
101	Cover Page Interactive Data File - the cover page XBRL tags are embedded within the Inline XBRL document.
104	The cover page from the Current Report on Form 8-K, formatted as Inline XBRL.

* * * * *

This combined Current Report on Form 8-K is being furnished separately by Exelon, Exelon Generation Company, LLC, Commonwealth Edison Company, PECO Energy Company, Baltimore Gas and Electric Company, Pepco Holdings LLC, Potomac Electric Power Company, Delmarva Power & Light Company, and Atlantic City Electric Company (Registrants). Information contained herein relating to any individual Registrant has been furnished by such Registrant on its own behalf. No Registrant makes any representation as to information relating to any other Registrant.

This report contains certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are subject to risks and uncertainties. The factors that could cause actual results to differ materially from the forward-looking statements made by the Registrants include those factors discussed herein, as well as the items discussed in (1) the Registrants’ 2018 Annual Report on Form 10-K in (a) Part I, ITEM 1A. Risk Factors, (b) Part II, ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) Part II, ITEM 8. Financial Statements and Supplementary Data: Note 22, Commitments and Contingencies; (2) the Registrants’ Third Quarter 2019 Quarterly Report on Form 10-Q in (a) Part II, ITEM 1A. Risk Factors; (b) Part I, ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) Part I, ITEM 1. Financial Statements: Note 16, Commitments and Contingencies; and (3) other factors discussed in filings with the SEC by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this report. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this report.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, each Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

	EXELON CORPORATION
	/s/ Joseph Nigro
	Joseph Nigro
	Senior Executive Vice President and Chief Financial Officer
	Exelon Corporation
	EXELON GENERATION COMPANY, LLC
	/s/ Bryan P. Wright
	Bryan P. Wright
	Senior Vice President and Chief Financial Officer
	Exelon Generation Company, LLC
	COMMONWEALTH EDISON COMPANY
	/s/ Jeanne M. Jones
	Jeanne M. Jones
	Senior Vice President, Chief Financial Officer and Treasurer
	Commonwealth Edison Company
	PECO ENERGY COMPANY
	/s/ Robert J. Stefani
	Robert J. Stefani
	Senior Vice President, Chief Financial Officer and Treasurer
	PECO Energy Company
	BALTIMORE GAS AND ELECTRIC COMPANY
	/s/ David M. Vahos
	David M. Vahos
	Senior Vice President, Chief Financial Officer and Treasurer
	Baltimore Gas and Electric Company

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	PEPCO HOLDINGS LLC
	/s/ Phillip S. Barnett
	Phillip S. Barnett
	Senior Vice President, Chief Financial Officer and Treasurer
	Pepco Holdings LLC
	POTOMAC ELECTRIC POWER COMPANY
	/s/ Phillip S. Barnett
	Phillip S. Barnett
	Senior Vice President, Chief Financial Officer and Treasurer
	Potomac Electric Power Company
	DELMARVA POWER & LIGHT COMPANY
	/s/ Phillip S. Barnett
	Phillip S. Barnett
	Senior Vice President, Chief Financial Officer and Treasurer
	Delmarva Power & Light Company
	ATLANTIC CITY ELECTRIC COMPANY
	/s/ Phillip S. Barnett
	Phillip S. Barnett
	Senior Vice President, Chief Financial Officer and Treasurer
	Atlantic City Electric Company

October 31, 2019

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EXHIBIT INDEX

Exhibit No.	Description
99.1	Press release and earnings release attachments
99.2	Earnings conference call presentation slides
99.3	Infographic
101	Cover Page Interactive Data File - the cover page XBRL tags are embedded within the Inline XBRL document.
104	The cover page from the Current Report on Form 8-K, formatted as Inline XBRL.

•	GAAP Net Income of $0.79 per share and Adjusted (non-GAAP) Operating Earnings of $0.92 per share for the third quarter of 2019

•	Narrowing guidance range for full year 2019 Adjusted (non-GAAP) Operating Earnings from $3.00- $3.30 per share to $3.05 - $3.20 per share

•	Announcing additional annual cost savings of $100 million; savings of $75 million of operating and maintenance expenses and $25 million of other expenses; full run-rate savings to be achieved in 2022

•	New York’s Supreme Court rejected challenges to New York’s Zero Emissions Credit (ZEC) Program

•	Strong utility customer operations performance - every utility achieved top quartile in Service Level and Abandon Rate

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•

Cost Management Programs: Exelon continues to be committed to managing its costs. On Oct. 31 2019, Exelon announced additional annual cost savings of approximately $100 million, at Generation, to be achieved by 2022. These actions are in response to the continuing economic challenges confronting Generation’s business, necessitating continued focus on cost management through enhanced efficiency and productivity.

•

Conowingo Hydroelectric Project: In connection with Generation’s pursuit of a new Federal Energy Regulatory Commission (FERC) license for the Conowingo Hydroelectric Project, on Oct. 29, 2019, Generation and Maryland Department of the Environment (MDE) entered into a settlement agreement that would resolve all outstanding issues between the parties, effective upon and subject to approval by FERC and incorporation of the terms into the new license when issued. The financial impact of this settlement, along with other anticipated and prior license commitments, would be recognized over the term of the new 50-year license and is estimated to be, on average, $11 million to $14 million per year, including capital and operating costs. The actual timing and amount of a majority of these costs are not currently fixed and will vary from year to year throughout the life of the new license. Generation cannot currently predict when FERC will issue the new license.

•	New York State Court Upholds New York ZECs: On Oct. 8, 2019, the New York State Court dismissed all remaining claims of plaintiffs' petition seeking to invalidate the ZEC program. The petitioners have until Nov. 11, 2019 to file a notice of appeal.

•

BGE Electric and Natural Gas Distribution Base Rate Case: On May 24, 2019 (as amended Oct. 4, 2019), BGE filed an application with the Maryland Public Service Commission (MDPSC) to increase its annual electric and natural gas distribution base rates by $74 million and $59 million, respectively, reflecting a requested ROE of 10.3%. On Oct. 25, 2019, BGE filed a settlement agreement with the MDPSC. The settlement provides for an increase to BGE’s annual electric and natural gas distribution rates of $18 million and $45 million, respectively. A final order from the MDPSC is expected by Dec. 2019.

•	Pepco Maryland Electric Distribution Base Rate Case: On Aug. 12, 2019, the MDPSC approved a settlement agreement with an effective date of Aug. 13, 2019 that provides for a net increase to Pepco's annual electric distribution rates of $10 million and reflects a ROE of 9.6%.

•

Nuclear Operations: Generation’s nuclear fleet, including its owned output from the Salem Generating Station and 100% of the CENG units, produced 46,215 gigawatt-hours (GWhs) in the third quarter of 2019, compared with 46,549 GWhs in the third quarter of 2018. Excluding Salem, the Exelon-operated nuclear plants at ownership achieved a 95.5% capacity factor for the third quarter of 2019, compared with 93.6% for the third quarter of 2018. The number of planned refueling outage days in the third quarter of 2019 totaled 15, compared with 36 in the third quarter of 2018. There were

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•	Fossil and Renewables Operations: The Dispatch Match rate for Generation’s fossil and hydro fleet was 97.5% in the third quarter of 2019, compared with 95.8% in the third quarter of 2018. Energy Capture for the wind and solar fleet was 96.5% in the third quarter of 2019, compared with 95.7% in the third quarter of 2018.

•	Financing Activities:

◦	On Sept. 10, 2019, PECO issued $325 million aggregate principal amount of its First and Refunding Mortgage Bonds, 3.00% Series due Sept. 15, 2049. PECO used the proceeds to satisfy short-term borrowings and for general corporate purposes.

◦	On Sept. 12, 2019, BGE issued $400 million aggregate principal amount of its 3.20% senior notes due Sept. 15, 2049. BGE used the proceeds to repay outstanding commercial paper obligations and for general corporate purposes.

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

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

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

(b)	For ComEd, BGE, Pepco and DPL Maryland, customer rates are adjusted to eliminate the impacts of weather and customer usage on distribution volumes.

(c)	For regulatory recovery mechanisms, including ComEd’s distribution formula rate, ComEd, PECO, BGE and PHI utilities transmission formula rates, and riders across all utilities, revenues increase and decrease i) as fully recoverable costs fluctuate (with no impact on net earnings), and ii) pursuant to changes in rate base, capital structure and ROE (which impact net earnings).

(1)	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.

(2)

In 2018, primarily reflects accelerated depreciation and amortization expense associated with Generation's decision to early retire the Oyster Creek and Three Mile Island nuclear facilities and a charge associated with a remeasurement of the Oyster Creek ARO. In 2019, primarily reflects accelerated depreciation and amortization expenses associated with the early retirement of the TMI nuclear facility and certain fossil sites, a charge associated with a remeasurement of the TMI ARO and the loss on sale of Oyster Creek to Holtec.

(3)	Primarily represents reorganization costs related to cost management programs.

(4)	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.

(5)	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.

(6)

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

(7)	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.

(8)

For ComEd, reflects increased electric distribution, energy efficiency and transmission revenues (due to higher rate base and fully recoverable costs, partially offset by lower electric distribution ROE due to decreased treasury rates). For PECO, BGE, and PHI, primarily reflects increased revenue as a result of rate increases. For PECO, also reflects increased revenue as a result of the absence in 2019 of the 2010 and 2011 electric and gas distribution tax repair credits fully refunded in 2018. For PHI, the rate increases were partially offset by the accelerated amortization of certain deferred income tax regulatory liabilities established upon the enactment of TCJA as the result of regulatory settlements.

(9)	Primarily reflects the permanent cease of generation operations at Oyster Creek in September 2018, partially offset by a decrease in nuclear outage days.

(10)	Reflects decreased capacity prices in the Mid-Atlantic, Midwest, New York, and Other power regions.

(11)	Primarily reflects an increase in New York ZEC prices and the approval of the New Jersey ZEC Program in the second quarter of 2019.

(12)	Primarily reflects lower realized energy prices.

(13)	For Generation, primarily reflects decreased costs related to the permanent cease of generation operations at Oyster Creek and lower labor costs resulting from previous cost management programs.

(14)	Primarily reflects a decrease in the number of nuclear outage days in 2019, excluding Salem.

(15)	Primarily reflects an increase in discount rates and the favorable impacts of the merger of two of Exelon’s pension plans effective in January 2019, partially offset by lower than expected asset returns in 2018.

(16)	For Generation, primarily reflects primarily reflects decreased costs related to the permanent cease of generation operations at Oyster Creek.

(17)	Reflects ongoing capital expenditures across all utilities. For ComEd, also reflects higher depreciation rates effective January 2019. For PHI, the impact of ongoing capital expenditures is partially offset by decreased regulatory asset amortization.

(18)

For Generation, primarily reflects renewable tax credits and one-time adjustments. For PECO, primarily reflects decreased amortization of income tax regulatory liabilities established in 2010 and 2011 for electric and gas repair deductions that were fully refunded to customers in 2018. For PHI, primarily reflects the accelerated amortization of certain deferred income tax regulatory liabilities established upon the enactment of TCJA as the result of regulatory settlements.

(19)	Reflects elimination from Generation’s results of activity attributable to noncontrolling interests, primarily for CENG.

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

(b)	For ComEd, BGE, Pepco and DPL Maryland, customer rates are adjusted to eliminate the impacts of weather and customer usage on distribution volumes.

(c)	For regulatory recovery mechanisms, including ComEd’s distribution formula rate, ComEd, PECO, BGE and PHI utilities transmission formula rates, and riders across all utilities, revenues increase and decrease i) as fully recoverable costs fluctuate (with no impact on net earnings), and ii) pursuant to changes in rate base, capital structure and ROE (which impact net earnings).

(1)	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.

(2)	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.

(3)

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.

(4)	Primarily represents reorganization costs related to cost management programs.

(5)	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.

(6)	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.

(7)

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.

(8)

For ComEd, reflects increased electric distribution, energy efficiency and transmission revenues (due to higher rate base and fully recoverable costs, partially offset by lower electric distribution ROE due to decreased treasury rates). For PECO, BGE, and PHI, reflects increased revenue as a result of rate increases. For PECO, also reflects increased revenue as a result of the absence in 2019 of the 2010 and 2011 electric and gas distribution tax repair credits fully refunded in 2018. For PHI, the rate increases were partially offset by the accelerated amortization of certain deferred income tax regulatory liabilities established upon the enactment of TCJA as the result of regulatory settlements. Additionally, for all utilities, reflects decreased mutual assistance revenues.

(9)	Primarily reflects the permanent cease of generation operations at Oyster Creek in September 2018, partially offset by a decrease in nuclear outage days.

(10)	Primarily reflects a decrease in fuel prices and decreased nuclear output as a result of the permanent cease of generation operations at Oyster Creek.

(11)	Reflects decreased capacity prices in the Mid-Atlantic, Midwest, New York, and Other Power Regions.

(12)	Primarily reflects the absence of the revenue recognized in the first quarter 2018 related to zero emissions credits generated in Illinois from June through December 2017, partially offset by an increase in New York ZEC prices and the approval of the New Jersey ZEC Program in the second quarter of 2019.

(13)	Primarily reflects lower realized energy prices and the impacts of Generation's natural gas portfolio.

(14)	For Generation, primarily reflects decreased costs related to the permanent cease of generation operations at Oyster Creek and lower labor costs resulting from previous cost management programs. For PHI, primarily reflects decreased contracting costs. Additionally, for all utilities, reflects decreased mutual assistance expenses.

(15)	Primarily reflects a decrease in the number of nuclear outage days in 2019, excluding Salem.

(16)	Primarily reflects an increase in discount rates and the favorable impacts of the merger of two of Exelon’s pension plans effective in January 2019, partially offset by lower than expected asset returns in 2018.

(17)

For Generation, primarily reflects the absence of a supplemental NEIL insurance distribution received in the first quarter 2018, an increase in planned nuclear outage days at Salem in 2019. For ComEd, primarily reflects increased storm costs. For PECO and BGE, primarily reflects decreased storm costs related to March 2018 winter storms. For PHI, primarily reflects a decrease in uncollectible accounts expense.

(18)	Reflects ongoing capital expenditures across all utilities. For ComEd, also reflects higher depreciation rates effective January 2019 and increased amortization of deferred energy efficiency costs pursuant to FEJA. For PHI, the impact of ongoing capital expenditures is partially offset by decreased regulatory asset amortization.

(19)

For Generation, primarily reflects renewable tax credits and one-time adjustments. For PECO, primarily reflects decreased amortization of income tax regulatory liabilities established in 2010 and 2011 for electric and gas repair deductions that were fully refunded to customers in 2018. For PHI, primarily reflects the accelerated amortization of certain deferred income tax regulatory liabilities established upon the enactment of TCJA as the result of regulatory settlements.

(20)	Reflects elimination from Generation’s results of activity attributable to noncontrolling interests, primarily for CENG.

(21)	For Generation, primarily reflects lower realized NDT fund gains.

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(a)	Results reported in accordance with accounting principles generally accepted in the United States (GAAP).

(b)	Adjustment to exclude the mark-to-market impact of Exelon’s economic hedging activities, net of intercompany eliminations.

(c)	Adjustment to exclude a change in environmental liabilities.

(d)

In 2018, adjustment to exclude accelerated depreciation and amortization expense associated with Generation's decision to early retire the Oyster Creek and Three Mile Island nuclear facilities and a charge associated with a remeasurement of the Oyster Creek ARO. In 2019, adjustment to exclude accelerated depreciation and amortization expenses associated with the early retirement of the TMI nuclear facility and certain fossil sites, a charge associated with the remeasurement of the TMI ARO and the loss on sale of Oyster Creek to Holtec.

(e)	Adjustment to exclude reorganization costs related to cost management programs.

(f)	In 2019, adjustment to exclude impairment of equity investments in certain distributed energy companies.

(g)	Adjustment to exclude elimination from Generation’s results of the noncontrolling interest related to certain exclusion items, primarily related to the impact of unrealized gains and losses on NDT fund investments at CENG.

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

(i)	Adjustment to exclude 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.

(j)	The effective tax rate related to Adjusted (non-GAAP) Operating Earnings is 18.3% and 18.7% for the three months ended September 30, 2019 and September 30, 2018, respectively.

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

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(a)	Results reported in accordance with accounting principles generally accepted in the United States (GAAP).

(b)	Adjustment to exclude the mark-to-market impact of Exelon’s economic hedging activities, net of intercompany eliminations.

(c)

In 2018, adjustment to exclude 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, adjustment to exclude net realized gains related to Oyster Creek's NDT fund investments, a net benefit associated with a remeasurement of the TMI asset retirement obligation and a gain on the sale of certain wind assets, partially offset by accelerated depreciation and amortization expenses associated with Generation's previous decision to early retire the TMI nuclear facility and certain fossil sites as well as the loss on sale of Oyster Creek to Holtec.

(d)	Adjustment to exclude changes to environmental liabilities.

(e)	Adjustment to exclude reorganization costs related to cost management programs.

(f)	Adjustment to exclude a gain related to a litigation settlement.

(g)	In 2018, adjustment to exclude costs related to the PHI acquisition.

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

(i)	In 2018, adjustment to exclude the impairment of certain wind projects at Generation. In 2019, adjustment to exclude the impairment of equity investments in certain distributed energy companies.

(j)	Adjustment to exclude 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.

(k)	The effective tax rate related to Adjusted (non-GAAP) Operating Earnings is 18.4% and 18.7% for the nine months ended September 30, 2019 and September 30, 2018, respectively.

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

(m)	Adjustment to exclude elimination from Generation’s results of the noncontrolling interests related to certain exclusion items, primarily related to the impact of unrealized gains and losses on NDT fund investments at CENG.

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(a)	Results reported in accordance with accounting principles generally accepted in the United States (GAAP).

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(a)	Results reported in accordance with accounting principles generally accepted in the United States (GAAP).

(b)	Adjustment to exclude reorganization costs related to cost management programs.

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(a)	Results reported in accordance with GAAP.

(b)	Adjustment to exclude reorganization costs related to cost management programs.

(c)	Adjustment to exclude certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses, integration activities, and upfront credit facilities fees related to the PHI acquisition.

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(a)	Results reported in accordance with accounting principles generally accepted in the United States (GAAP).

(b)	Adjustment to exclude an increase at Pepco related primarily to asbestos identified at its Buzzard Point property.

(c)	Adjustment to exclude an increase at Pepco related primarily to an increase in environmental liabilities.

(d)	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.

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(a)	Results reported in accordance with accounting principles generally accepted in the United States (GAAP).

(b)	Adjustment to exclude the mark-to-market impact of Generation’s economic hedging activities, net of intercompany eliminations.

(c)	In 2018, adjustment to exclude 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

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(d)	Adjustment to exclude reorganization costs related to cost management programs.

(e)	In 2018, adjustment to exclude impairment of certain wind projects at Generation. In 2019, adjustment to exclude the impairment of equity investments in certain distributed energy companies.

(f)	Adjustment to exclude a benefit related to Generation's annual nuclear ARO update for non-regulatory units.

(g)	Adjustment to exclude 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.

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

(i)	Adjustment to exclude the elimination from Generation’s results of the noncontrolling interest related to certain exclusion items, primarily related to the impact of unrealized gains and losses on NDT fund investments at CENG.

(j)	In 2018, adjustment to exclude certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses and integration activities.

(k)	Adjustment to exclude a change in environmental liabilities.

(l)	Adjustment to exclude a gain related to a litigation settlement.

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

(b)	Results reported in accordance with accounting principles generally accepted in the United States (GAAP).

(c)	Adjustment to exclude the mark-to-market impact of Exelon’s economic hedging activities, net of intercompany eliminations.

(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

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

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(a)	Reflects revenues from customers purchasing electricity directly from ComEd and customers purchasing electricity from a competitive electric generation supplier, as all customers are assessed delivery charges. For customers purchasing electricity from ComEd, revenues also reflect the cost of energy and transmission.

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

(c)	Includes operating revenues from affiliates totaling $4 million for the three months ended September 30, 2019 and 2018, and $13 million and $23 million for the nine months ended September 30, 2019 and 2018, respectively.

(d)	Includes alternative revenue programs and late payment charges.

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(a)	Reflects delivery volumes and revenues from customers purchasing electricity directly from PECO and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from PECO, revenues also reflect the cost of energy and transmission.

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

(c)	Includes operating revenues from affiliates totaling $1 million and $2 million for the three months ended September 30, 2019 and 2018, respectively, and $4 million and $5 million for the nine months ended September 30, 2019 and 2018, respectively.

(d)	Includes alternative revenue programs and late payment charges.

(e)	Reflects delivery volumes and revenues from customers purchasing natural gas directly from PECO and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges. For customers purchasing natural gas from PECO, revenue also reflects the cost of natural gas.

(f)	Includes revenues primarily from off-system sales.

(g)	Includes operating revenues from affiliates totaling less than $1 million for the three months ended September 30, 2019 and 2018, and less than $1 million for the both nine months ended September 30, 2019 and 2018.

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(a)	Reflects revenues from customers purchasing electricity directly from BGE and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from BGE, revenues also reflect the cost of energy and transmission.

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

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(c)	Includes operating revenues from affiliates totaling $2 million and $1 million for the three months ended September 30, 2019 and 2018, respectively, and $5 million for both the nine months ended September 30, 2019 and 2018.

(d)	Includes alternative revenue programs and late payment charges.

(e)	Reflects delivery volumes and revenues from customers purchasing natural gas directly from BGE and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges. For customers purchasing natural gas from BGE, revenue also reflects the cost of natural gas.

(f)	Includes revenues primarily from off-system sales.

(g)	Includes operating revenues from affiliates totaling $4 million and $5 million for the three months ended September 30, 2019 and 2018, respectively, and $13 million for both the nine months ended September 30, 2019 and 2018.

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(a)	Reflects revenues from customers purchasing electricity directly from Pepco and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from Pepco, revenues also reflect the cost of energy and transmission.

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

(c)	Includes operating revenues from affiliates totaling $2 million for the three months ended September 30, 2019 and 2018 respectively, and $5 million for the nine months ended September 30, 2019 and 2018.

(d)	Includes alternative revenue programs and late payment charge revenues.

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(a)	Includes revenues from distribution customers in the Maryland and Delaware service territories.

(b)	Reflects delivery volumes and revenues from customers purchasing electricity directly from DPL and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from DPL, revenues also reflect the cost of energy and transmission.

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

(d)	Includes operating revenues from affiliates totaling $1 million and $2 million for the three months ended September 30, 2019 and 2018 and $5 million and $6 million for the nine months ended September 30, 2019 and 2018.

(e)	Includes alternative revenue programs and late payment charges.

(f)	Reflects delivery volumes and revenues from customers purchasing natural gas directly from DPL and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges. For customers purchasing natural gas from DPL, revenue also reflects the cost of natural gas.

(g)	Includes revenues primarily from off-system sales.

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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. For customers purchasing electricity from ACE, revenues also reflect the cost of energy and transmission.

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

(c)	Includes operating revenues from affiliates totaling $1 million for both the three months ended September 30, 2019 and 2018 and $2 million for both the nine months ended September 30, 2019 and 2018.

(d)	Includes alternative revenue programs and late payment charge revenues.

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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)	Other Power Regions includes New England, South, West and Canada.

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

(d)	Outage days exclude Salem.