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•	GAAP Net Income of $0.76 per share and Adjusted (non-GAAP) Operating Earnings of $0.88 per share for the third quarter of 2018

•	Raising the lower end of our guidance range for full year 2018 Adjusted (non-GAAP) Operating Earnings from $2.90 - $3.20 per share to $3.05 - $3.20 per share

•	Announcing additional annual cost savings of $200 million gross, and $150 million net, reflecting ongoing initiatives leveraging process efficiency and technology; full run-rate savings to be achieved in 2021

•	All Exelon Utilities achieved top quartile reliability performance in outage frequency and outage duration

•	PECO, along with interested parties, filed a partial settlement agreement for its distribution rate case on Aug. 28, 2018

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•

Cost Management Program: In Nov. 2018, Exelon announced the elimination of approximately $200 million in annual ongoing costs, through initiatives primarily at Generation and BSC, by 2021. Approximately $150 million is expected to be related to Generation, with the remaining amount related to the Utility Registrants. This announcement is a result of Exelon’s continuous focus on improving its cost profile through enhanced efficiency and productivity. The targeted cost savings are incremental to the expected savings from previous cost management initiatives.

•

Illinois and New York ZEC Programs: In Sept. 2018, the U.S. Court of Appeals for the Seventh Circuit and the Second Circuit affirmed dismissal of the complaints against Illinois’ and New York’s Zero Emissions Credit (ZEC) programs, respectively, which will allow them to continue supporting the clean, resilient electricity that nuclear power provides to each state’s residents. On Sept. 27, 2018, the plaintiffs filed a request for a panel rehearing with the U.S. Circuit Court of Appeals for the Seventh Circuit. On Oct. 9, 2018, the U.S. Circuit Court of Appeals for the Seventh Circuit panel denied the request for rehearing.

•

PECO Electric Distribution Base Rate Case: On Aug. 28, 2018, PECO and interested parties filed with the Pennsylvania Public Utility Commission (PAPUC) a petition for partial settlement for an increase of $25 million in annual electric distribution service revenues, which includes annual ongoing TCJA tax savings. No overall ROE was specified in the partial settlement. The requested ROE was 10.95 percent in the filing with the PAPUC on March 29, 2018. On Oct. 18, 2018, the Administrative Law Judges issued a Recommended Decision to the PAPUC that the partial settlement be approved without modification. A final ruling from the PAPUC is expected before Dec. 31, 2018, and if approved, the new electric distribution base rates will become effective on Jan. 1, 2019.

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Pepco District of Columbia Electric Distribution Base Rate Case: On Aug. 9, 2018, the District of Columbia Public Service Commission approved a settlement agreement with an effective date of Aug. 13, 2018 that provides for a net decrease to Pepco's annual electric distribution rates of $24 million, which includes annual ongoing TCJA tax savings, and reflects a ROE of 9.525 percent. On Sept. 7, 2018, Pepco submitted an updated filing for a one-time bill credit to customers of

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DPL Delaware Electric Distribution Base Rate Case: On Aug. 21, 2018, the Delaware Public Service Commission (DPSC) approved the settlement agreement, which provides for a net decrease to annual electric distribution base rates of $7 million, which includes annual ongoing TCJA tax savings, and reflects a ROE of 9.7 percent. In addition, the settlement agreement separately provides for a one-time bill credit to customers of approximately $3 million representing the TCJA benefits for the period Feb. 1, 2018 through March 17, 2018, when full interim rates were put into effect. DPL expects to issue the $3 million to customers in the fourth quarter of 2018.

•

DPL Delaware Gas Distribution Base Rate Case: On Sept. 7, 2018 (as amended and restated on Oct. 2, 2018), DPL entered into a partial settlement agreement with several parties in its pending gas distribution base rate case proceeding that provides for a net decrease to annual gas distribution base rates of $4 million, which includes annual ongoing TCJA tax savings, and reflects a ROE of 9.7 percent. In addition, the settlement agreement separately provides a one-time bill credit to customers of approximately $1 million representing the TCJA tax savings for the period Feb. 1, 2018 through March 17, 2018, when full interim rates were put into effect. DPL expects a decision on the settlement agreement in the fourth quarter of 2018 but cannot predict if the DPSC will approve the settlement agreement as filed.

•

ACE New Jersey Electric Distribution Base Rate Case: On Aug. 21, 2018, ACE refiled its application with the New Jersey Board of Public Utilities (NJBPU), requesting an increase to its electric distribution rates of $109 million (before New Jersey sales and use tax), reflecting a requested ROE of 10.1 percent. Included in the $109 million request is $40 million of higher depreciation expense related to ACE's updated depreciation study. ACE currently expects a decision in this matter in the third quarter of 2019 but cannot predict if the NJBPU will approve the application as filed.

•	Acquisition of Distrigas Liquefied Natural Gas Terminal: On Oct. 1, 2018, Generation acquired the Distrigas liquefied natural gas import terminal to ensure the continued reliable supply of fuel to Mystic Units 8 and 9 while they remain operating.

•

Nuclear Operations: Generation’s nuclear fleet, including its owned output from the Salem Generating Station and 100 percent of the CENG units, produced 46,549 gigawatt-hours (GWhs) in the third quarter of 2018, compared with 47,747 GWhs in the third quarter of 2017. Excluding Salem, the Exelon-operated nuclear plants at ownership achieved a 93.6 percent capacity factor for the third quarter of 2018, compared with 96.1 percent for the third quarter of 2017. The number of planned refueling outage days in the third quarter of 2018 totaled 36, compared with 13 in the third quarter of 2017. There were 12 non-refueling outage days in the third quarter of 2018, compared with 15 in the third quarter of 2017.

•	Fossil and Renewables Operations: The Dispatch Match rate for Generation’s gas and hydro fleet was 95.8 percent in the third quarter of 2018, compared with 98.4 percent in the third quarter of 2017. The lower performance was primarily due to outages at combined cycle gas units in Alabama and Texas.

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•	Financing Activities:

◦	On Aug. 14, 2018, ComEd issued $550 million aggregate principal amount of its First Mortgage Bonds, 3.70 percent Series 125, due Aug. 15, 2028. ComEd used the proceeds to repay a portion of its outstanding commercial paper obligations and for general corporate purposes.

◦	On Sept. 11, 2018, PECO issued $325 million aggregate principal amount of its First and Refunding Mortgage Bonds, 3.90 percent due March 1, 2048. PECO used the proceeds to satisfy short-term borrowings from the Exelon intercompany money pool and for general corporate purposes.

◦	On Sept. 20, 2018, BGE issued $300 million aggregate principal amount of its 4.25 percent senior notes due Sept. 15, 2048. BGE used the proceeds to repay commercial paper obligations and for general corporate purposes.

◦	On Oct. 16, 2018, ACE issued $350 million aggregate principal amount of its First Mortgage Bonds, 4.00 percent due Oct. 15, 2028. ACE will use the proceeds to refinance its maturing 7.75 percent First Mortgage Bonds, repay outstanding commercial paper and for general corporate purposes.

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(a)	PHI includes the consolidated results of Pepco, DPL and ACE.

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

(c)	Certain immaterial prior year amounts in the Registrants' Consolidated Statements of Operations and Comprehensive Income have been recasted to reflect new accounting standards issued by the FASB and adopted as of January 1, 2018.

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(a)	PHI consolidated results includes Pepco, DPL and ACE.

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

(c)	Certain immaterial prior year amounts in the Registrants' Consolidated Statements of Operations and Comprehensive Income have been recasted to reflect new accounting standards issued by the FASB and adopted as of January 1, 2018.

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(a)	Certain immaterial prior year amounts in the Registrants' Consolidated Statements of Operations and Comprehensive Income have been recasted to reflect new accounting standards issued by the FASB and adopted as of January 1, 2018.

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(a)	Certain immaterial prior year amounts in the Registrants' Consolidated Statements of Operations and Comprehensive Income have been recasted to reflect new accounting standards issued by the FASB and adopted as of January 1, 2018.

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(a)	Certain immaterial prior year amounts in the Registrants' Consolidated Statements of Operations and Comprehensive Income have been recasted to reflect new accounting standards issued by the FASB and adopted as of January 1, 2018.

(b)	PHI consolidated results includes Pepco, DPL and ACE.

(c)	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)	Certain immaterial prior year amounts in the Registrants' Consolidated Balance Sheets have been recasted to reflect new accounting standards issued by the FASB and adopted as of January 1, 2018.

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(a)	Certain immaterial prior year amounts in the Registrants' Consolidated Statements of Cash Flows have been recasted to reflect new accounting standards issued by the FASB and adopted as of January 1, 2018.

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(a)	Certain immaterial prior year amounts in the Registrants' Consolidated Statements of Operations and Comprehensive Income have been recasted to reflect new accounting standards issued by the FASB and adopted as of January 1, 2018.

(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.

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(d)	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.

(e)	Adjustment to exclude the non-cash amortization of intangible assets, net, primarily related to commodity contracts recorded at fair value related to the ConEdison Solutions and FitzPatrick acquisitions.

(f)	Adjustment to exclude certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses and integration activities. Reflects costs related to the PHI and FitzPatrick acquisitions, offset at PHI by the anticipated recovery of previously incurred PHI acquisition costs.

(g)	Adjustment to exclude charges to earnings related to the impairment of EGTP assets held for sale in 2017.

(h)

Adjustment to exclude in 2017, primarily accelerated depreciation and amortization expenses associated with Generation's decision to early retire the Three Mile Island nuclear facility. In 2018, primarily 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 Asset Retirement Obligation (ARO).

(i)	Adjustment to exclude primarily severance and reorganization costs related to a cost management program.

(j)	Adjustment to exclude the excess of the fair value of assets and liabilities acquired over the purchase price for the FitzPatrick acquisition.

(k)	Adjustment to exclude in 2017, a non-cash benefit pursuant to the annual update of the Generation nuclear decommissioning obligation related to the non-regulatory units. In 2018, an increase at Pepco related primarily to asbestos identified at its Buzzard Point property.

(l)	Adjustment to exclude in 2017, the change in the Illinois statutory tax rate and changes in forecasted apportionment. In 2018, reflects an adjustment to the remeasurement of deferred income taxes as a result of TCJA and changes in forecasted apportionment.

(m)	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.

(n)	The effective tax rate related to Adjusted (non-GAAP) Operating Earnings is 18.7% and 35.6% for the three months ended September 30, 2018 and September 30, 2017, respectively.

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(a)	Certain immaterial prior year amounts in the Registrants' Consolidated Statements of Operations and Comprehensive Income have been recasted to reflect new accounting standards issued by the FASB and adopted as of January 1, 2018.

(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)	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.

(e)	Adjustment to exclude the non-cash amortization of intangible assets, net, primarily related to commodity contracts recorded at fair value related to the ConEdison Solutions and FitzPatrick acquisitions.

(f)

Adjustment to exclude certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses and integration activities. In 2017, reflects costs related to the PHI and FitzPatrick acquisitions, offset at PHI by the anticipated recovery of previously incurred PHI acquisition costs, and in 2018, reflects costs related to the PHI acquisition.

(g)	Adjustment to exclude a decrease in reserves for uncertain tax positions related to the deductibility of certain merger commitments associated with the 2012 CEG and 2016 PHI acquisitions.

(h)	Adjustment to exclude in 2017, primarily charges to earnings related to the impairment of EGTP assets held for sale. In 2018, primarily the impairment of certain wind projects at Generation.

(i)

Adjustment to exclude in 2017, primarily accelerated depreciation and amortization expenses and one-time charges associated with Generation's previous decision to early retire the Three Mile Island nuclear facility. In 2018, primarily accelerated depreciation and amortization expenses and one-time charges associated with Generation's decision to early retire the Oyster Creek nuclear facility, a charge associated with a remeasurement of the Oyster Creek Asset Retirement Obligation (ARO) and accelerated depreciation and amortization expenses associated with the 2017 decision to early retire the Three Mile Island nuclear facility, partially offset by a gain associated with Generation's sale of its electrical contracting business.

(j)	Adjustment to exclude primarily severance and reorganization costs related to a cost management program.

(k)	Adjustment to exclude the excess of the fair value of assets and liabilities acquired over the purchase price for the FitzPatrick acquisition.

(l)	Adjustment to exclude in 2017, a non-cash benefit pursuant to the annual update of the Generation nuclear decommissioning obligation related to the non-regulatory units. In 2018, an increase at Pepco related primarily to asbestos identified at its Buzzard Point property.

(m)	Adjustment to exclude adjustments to income tax, penalties and interest expenses in the second quarter of 2017 as a result of the finalization of the IRS tax computation related to Exelon’s like-kind exchange tax position.

(n)	Adjustment to exclude in 2017, the changes in the Illinois and District of Columbia statutory tax rate and changes in forecasted apportionment. In 2018, an adjustment to the remeasurement of deferred income taxes as a result of TCJA and changes in forecasted apportionment.

(o)	Adjustment to exclude benefits related to the favorable settlement in 2017 of certain income tax positions related to PHI's unregulated business interests.

(p)	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.

(q)	The effective tax rate related to Adjusted (non-GAAP) Operating Earnings is 18.7% and 35.6% for the nine months ended September 30, 2018 and September 30, 2017, respectively.

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(a)	PHI consolidated results includes Pepco, DPL and ACE.

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

(c)	Certain immaterial prior year amounts in the Registrants' Consolidated Statements of Operations and Comprehensive Income have been recasted to reflect new accounting standards issued by the FASB and adopted as of January 1, 2018.

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

(e)	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)	Represents the non-cash amortization of intangible assets, net, primarily related to commodity contracts recorded at fair value related to the ConEdison Solutions and FitzPatrick acquisitions.

(3)	Reflects certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses and integration activities. Reflects costs related to the PHI and FitzPatrick acquisitions, offset at PHI by the anticipated recovery of previously incurred PHI acquisition costs.

(4)	Primarily reflects charges to earnings related to the impairment of the ExGen Texas Power, LLC (EGTP) assets held for sale in 2017.

(5)

In 2017, primarily reflects accelerated depreciation and amortization expenses associated with Generation's decision to early retire the Three Mile Island nuclear facility. 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 Asset Retirement Obligation (ARO).

(6)	Primarily represents severance and reorganization costs related to a cost management program.

(7)	Represents the excess of the fair value of assets and liabilities acquired over the purchase price for the FitzPatrick acquisition.

(8)	In 2017, reflects a non-cash benefit pursuant to the annual update of the Generation nuclear decommissioning obligation related to the non-regulatory units. In 2018, reflects an increase at Pepco related primarily to asbestos identified at its Buzzard Point property.

(9)	In 2017, reflects the change in the Illinois statutory tax rate and changes in forecasted apportionment. In 2018, reflects an adjustment to the remeasurement of deferred income taxes as a result of the Tax Cuts and Jobs Act (TCJA) and changes in forecasted apportionment.

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

(11)	For all utilities, primarily reflects lower revenues resulting from the anticipated pass back of TCJA tax savings through customer rates. Additionally, for ComEd, increased electric distribution and energy efficiency revenues due to higher rate base. For BGE and PHI, reflects increased revenue as a result of rate increases.

(12)	Primarily reflects an increase in nuclear outage days.

(13)	Primarily reflects decreased fuel prices and decreased nuclear output.

(14)	Primarily reflects increased capacity prices in the Mid-Atlantic and Midwest regions, partially offset by a decrease in capacity prices in New England.

(15)	Reflects the impact of the Illinois Zero Emission Standard.

(16)	Primarily reflects the absence of EGTP revenues net of purchased power and fuel expense resulting from its deconsolidation in the fourth quarter of 2017, lower realized energy prices, lower energy efficiency revenues and decreased revenues related to the sale of Generation's electrical contracting business.

(17)	For Generation, primarily reflects decreased spending related to energy efficiency projects and decreased costs related to the sale of Generation's electrical contracting business.

(18)	Primarily reflects an increase in the number of nuclear outage days in 2018, excluding Salem.

(19)	For PECO, primarily reflects an increase in uncollectible accounts expense.

(20)

Reflects ongoing capital expenditures across all operating companies. In addition, for ComEd, reflects higher amortization of deferred energy efficiency costs pursuant to the Illinois Future Energy Jobs Act (FEJA). For BGE, reflects certain regulatory assets that became fully amortized as of December 31, 2017. For PHI, reflects increased amortization of Pepco's DC PLUG regulatory asset, which is offset in Other Energy and Delivery.

(21)	Reflects the benefit of lower federal income tax rates and the settlement of a portion of the deferred income tax regulatory liabilities established upon enactment of TCJA, which is predominantly offset at the utilities in Other Energy Delivery as these tax benefits are anticipated to be passed back through customer rates.

(22)	For Generation, primarily reflects one-time tax adjustments and a reduction in renewable tax credits.

(23)	Reflects elimination from Generation’s results of activity attributable to noncontrolling interests, primarily for CENG and the Renewables Joint Venture.

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(a)	PHI consolidated results includes Pepco, DPL and ACE.

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

(c)	Certain immaterial prior year amounts in the Registrants' Consolidated Statements of Operations and Comprehensive Income have been recasted to reflect new accounting standards issued by the FASB and adopted as of January 1, 2018.

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

(e)	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)	Represents the non-cash amortization of intangible assets, net, primarily related to commodity contracts recorded at fair value related to the ConEdison Solutions and FitzPatrick acquisitions.

(3)	Reflects certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses and integration activities. In 2017, reflects costs related to the PHI and FitzPatrick acquisitions, offset at PHI by the anticipated recovery of previously incurred PHI acquisition costs. In 2018, reflects costs related to the PHI acquisition.

(4)	Primarily reflects a decrease in reserves for uncertain tax positions related to the deductibility of certain merger commitments associated with the 2012 CEG and 2016 PHI acquisitions.

(5)	In 2017, primarily reflects charges to earnings related to the impairment of the ExGen Texas Power, LLC (EGTP) assets held for sale. In 2018, primarily reflects the impairment of certain wind projects at Generation.

(6)

In 2017, primarily reflects accelerated depreciation and amortization expenses and one-time charges associated with Generation's previous decision to early retire the Three Mile Island nuclear facility. In 2018, primarily reflects accelerated depreciation and amortization expenses and one-time charges associated with Generation's decision to early retire the Oyster Creek nuclear facility, a charge associated with a remeasurement of the Oyster Creek Asset Retirement Obligation (ARO) and accelerated depreciation and amortization expenses associated with the 2017 decision to early retire the Three Mile Island nuclear facility, partially offset by a gain associated with Generation's sale of its electrical contracting business.

(7)	Primarily represents severance and reorganization costs related to a cost management program.

(8)	Represents the excess of the fair value of assets and liabilities acquired over the purchase price for the FitzPatrick acquisition.

(9)	In 2017, reflects a non-cash benefit pursuant to the annual update of the Generation nuclear decommissioning obligation related to the non-regulatory units. In 2018, reflects an increase at Pepco related primarily to asbestos identified at its Buzzard Point property.

(10)	Represents adjustments to income tax, penalties and interest expenses in the second quarter of 2017 as a result of the finalization of the IRS tax computation related to Exelon’s like-kind exchange tax position.

(11)	In 2017, reflects the changes in the Illinois and District of Columbia statutory tax rate and changes in forecasted apportionment. In 2018, reflects an adjustment to the remeasurement of deferred income taxes as a result of the Tax Cuts and Jobs Act (TCJA) and changes in forecasted apportionment.

(12)	Reflects benefits related to the favorable settlement in 2017 of certain income tax positions related to PHI's unregulated business interests.

(13)	Represents 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.

(14)

For all utilities, primarily reflects lower revenues resulting from the anticipated pass back of TCJA tax savings through customer rates, partially offset by higher mutual assistance revenues. Additionally, for ComEd, reflects decreased revenues resulting from the change, effective June 1, 2017, to defer and recover over time energy efficiency costs pursuant to the Illinois Future Energy Jobs Act (FEJA), partially offset by increased electric distribution and energy efficiency revenues due to higher rate base. For BGE and PHI, reflects increased revenue as a result of rate increases.

(15)	Primarily reflects the acquisition of the FitzPatrick nuclear facility and decreased nuclear outage days.

(16)	Primarily reflects a decrease in fuel prices, partially offset by increased nuclear output as a result of the FitzPatrick acquisition.

(17)	Primarily reflects increased capacity prices in the Mid-Atlantic, New England and Midwest regions.

(18)	Reflects the impact of the New York Clean Energy and Illinois Zero Emission Standards, including the impact of zero emission credits generated in Illinois from June 1, 2017 through December 31, 2017.

(19)

Primarily reflects lower realized energy prices, the absence of EGTP revenues net of purchased power and fuel expense resulting from its deconsolidation in the fourth quarter of 2017, lower energy efficiency revenues and decreased revenues related to the sale of Generation's electrical contracting business, partially offset by the addition of two combined-cycle gas turbines in Texas and the impacts of Generation's natural gas portfolio.

(20)	For Generation, primarily reflects decreased spending related to energy efficiency projects and decreased costs related to the sale of Generation's electrical contracting business. Additionally, for the utilities, primarily reflects increased mutual assistance expenses.

(21)	Primarily reflects a decrease in the number of nuclear outage days in 2018, excluding Salem.

(22)

For Generation, primarily reflects the impact of a supplemental NEIL insurance distribution and fewer outage days at Salem. For ComEd, primarily reflects the change, effective June 1, 2017, to defer and recover over time energy efficiency costs pursuant to FEJA and decreased storm costs. For PECO, primarily reflects increased storm costs related to the March 2018 winter storms and an increase in uncollectible accounts expense. For BGE, primarily reflects increased storm costs related to the March 2018 winter storms. For PHI, primarily reflects an increase in uncollectible accounts expense. Additionally, for the utilities, reflects increased mutual assistance expenses.

(23)

Reflects ongoing capital expenditures across all operating companies. For ComEd, primarily reflects the amortization of deferred energy efficiency costs pursuant to FEJA. For BGE, primarily reflects certain regulatory assets that became fully amortized as of December 31, 2017. For PHI reflects increased amortization of Pepco's DC PLUG regulatory asset, which is offset in Other Energy and Delivery.

(24)	Reflects the benefit of lower federal income tax rates and the settlement of a portion of the deferred income tax regulatory liabilities established upon enactment of TCJA, which is predominantly offset at the utilities in Other Energy Delivery as these tax benefits are anticipated to be passed back through customer rates.

(25)	For Generation, primarily reflects one-time tax adjustments and a reduction in renewable tax credits. For PECO, primarily reflects an increase in the repairs tax deduction.

(26)	Reflects elimination from Generation’s results of activity attributable to noncontrolling interests, primarily for CENG and the Renewables Joint Venture.

(27)	For Generation, primarily reflects higher realized NDT fund gains.

(28)	Reflects the impact on earnings per share due to the increase in Exelon’s average diluted common shares outstanding as a result of the June 2017 common stock issuance.

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

(b)	Certain immaterial prior year amounts in the Registrants' Consolidated Statements of Operations and Comprehensive Income have been recasted to reflect new accounting standards issued by the FASB and adopted as of January 1, 2018.

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

(d)	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.

(e)	Adjustment to exclude the non-cash amortization of intangible assets, net, primarily related to commodity contracts recorded at fair value related to the ConEdison Solutions and FitzPatrick acquisitions.

(f)	Adjustment to exclude certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses and integration activities. In 2017, reflects costs related to the PHI and FitzPatrick acquisitions. In 2018, reflects costs related to the PHI acquisition.

(g)	Adjustment to exclude a non-cash benefit pursuant to the annual update of the Generation nuclear decommissioning obligation related to the non-regulatory units in 2017.

(h)	Adjustment to exclude charges to earnings related to the impairment of the EGTP assets held for sale in 2017, and in 2018 the impairment of certain wind projects.

(i)

Adjustment to exclude accelerated depreciation and amortization expenses and one-time charges associated with Generation's previous decision to early retire the Three Mile Island nuclear facility in 2017. In 2018, primarily reflects accelerated depreciation and amortization expenses and one-time charges associated with Generation's decision to early retire the Oyster Creek nuclear facility, a charge associated with a remeasurement of the Oyster Creek ARO and accelerated depreciation and amortization expenses associated with the 2017 decision to early retire the Three Mile Island nuclear facility, partially offset by a gain associated with Generation's sale of its electrical contracting business.

(j)	Adjustment to exclude primarily severance and reorganization costs related to a cost management program.

(k)	Adjustment to exclude the excess of the fair value of assets and liabilities acquired over the purchase price for the FitzPatrick acquisition.

(l)	Adjustment to exclude the changes in the Illinois and District of Columbia statutory tax rate and changes in forecasted apportionment in 2017, and in 2018, an adjustment to the remeasurement of deferred income taxes as a result of the TCJA. and changes in forecasted apportionment.

(m)	Adjustment to exclude benefits related to the favorable settlement in 2017 of certain income tax positions related to PHI's unregulated business interests.

(n)	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.

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

(b)	Certain immaterial prior year amounts in the Registrants' Consolidated Statements of Operations and Comprehensive Income have been recasted to reflect new accounting standards issued by the FASB and adopted as of January 1, 2018.

(c)	Adjustment to exclude the non-cash impact of the remeasurement of state deferred income taxes, primarily as a result of changes in forecasted apportionment related to changes in the Illinois statutory tax rate and changes in forecasted apportionment.

(d)	Adjustment to exclude adjustments to income tax, penalties and interest expenses in the second quarter of 2017 as a result of the finalization of the IRS tax computation related to Exelon’s like-kind exchange tax position.

(e)	Adjustment to exclude certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses and integration activities related to the PHI acquisition, partially offset in 2016 at ComEd by the anticipated recovery of previously incurred PHI acquisition costs.

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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 a cost management program.

(c)	Adjustment to exclude certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses and integration activities 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)	Certain immaterial prior year amounts in the Registrants' Consolidated Statements of Operations and Comprehensive Income have been recasted to reflect new accounting standards issued by the FASB and adopted as of January 1, 2018.

(c)	Adjustment to exclude reorganization costs related to a cost management program.

(d)	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)	Certain immaterial prior year amounts in the Registrants' Consolidated Statements of Operations and Comprehensive Income have been recasted to reflect new accounting standards issued by the FASB and adopted as of January 1, 2018.

(c)	PHI consolidated results includes Pepco, DPL and ACE.

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

(e)	Adjustment to exclude an adjustment to the remeasurement of deferred income taxes as a result of TCJA.

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(f)	Adjustment to exclude certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses and integration activities. In 2017, reflects costs related to the PHI acquisition, partially offset at PHI by the anticipated recovery of previously incurred PHI acquisition costs.

(g)	Adjustment to exclude a decrease in reserves for uncertain tax positions related to the deductibility of certain merger commitments associated with the 2016 PHI acquisition.

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

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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)	Certain immaterial prior year amounts in the Registrants' Consolidated Statements of Operations and Comprehensive Income have been recasted to reflect new accounting standards issued by the FASB and adopted as of January 1, 2018.

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

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

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

(f)	Adjustment to exclude primarily a decrease in reserves for uncertain tax positions related to the deductibility of certain merger commitments associated with the 2016 PHI acquisitions.

(g)	Adjustment to exclude charges to earnings related to the impairment of EGTP assets held for sale in 2017.

(h)

Adjustment to exclude accelerated depreciation and amortization expenses and one-time charges associated with Generation's previous decision to early retire the Three Mile Island nuclear facility in 2017. In 2018, primarily reflects accelerated depreciation and amortization expenses and one-time charges associated with Generation's decision to early retire the Oyster Creek nuclear facility and accelerated depreciation and amortization expenses associated with the 2017 decision to early retire the Three Mile Island nuclear facility, partially offset by a gain associated with Generation's sale of its electrical contracting business.

(i)	Adjustment to exclude primarily severance and reorganization costs related to a cost management program.

(j)	Adjustment to exclude adjustments to income tax, penalties and interest expenses in the second quarter of 2017 as a result of the finalization of the IRS tax computation related to Exelon’s like-kind exchange tax position.

(k)	Adjustment to exclude in 2017, the changes in the Illinois and District of Columbia statutory tax rate and changes in forecasted apportionment. In 2018, an adjustment to the remeasurement of deferred income taxes as a result of TCJA and changes in forecasted apportionment.

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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, 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.

(e)	Includes the ownership of the FitzPatrick nuclear facility from March 31, 2017.

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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.

(c)	Includes the ownership of the FitzPatrick nuclear facility from March 31, 2017.

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(a)	Reflects delivery volumes and 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, revenue also reflects the cost of energy and transmission.

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

(c)	Includes operating revenues from affiliates totaling $4 million and $3 million for the three months ended September 30, 2018 and 2017, respectively, and $23 million and $12 million for the nine months ended September 30, 2018 and 2017, 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, revenue also reflects the cost of energy and transmission.

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

(c)	Includes operating revenues from affiliates totaling $2 million and $1 million for the three months ended September 30, 2018 and 2017, respectively, and $5 million and $4 million for the nine months ended September 30, 2018 and 2017, 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 both the three and nine months ended September 30, 2018 and 2017.

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

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

(c)	Includes operating revenues from affiliates totaling $1 million for both the three months ended September 30, 2018 and 2017, and $5 million for both the nine months ended September 30, 2018 and 2017.

(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 $5 million and $2 million for the three months ended September 30, 2018 and 2017, respectively, and $13 million and $7 million for the nine months ended September 30, 2018 and 2017, respectively.

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

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

(c)	Includes operating revenues from affiliates totaling $2 million and $1 million for the three months ended September 30, 2018 and 2017, respectively, and $5 million and $4 million for nine months ended September 30, 2018 and 2017, 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 DPL and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from DPL, revenue also reflects the cost of energy and transmission.

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

(c)	Includes operating revenues from affiliates totaling $2 million for both three months ended September 30, 2018 and 2017 and $6 million for both nine months ended September 30, 2018 and 2017.

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

(e)	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.

(f)	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, revenue also reflects the cost of energy and transmission.

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

(c)	Includes operating revenues from affiliates totaling $1 million and less than $1 million for the three months ended September 30, 2018 and 2017, respectively, and $2 million for both the nine months ended September 30, 2018 and 2017.

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