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•	GAAP Net Income of $0.85 per share and Adjusted (non-GAAP) Operating Earnings of $0.85 per share for the third quarter of 2017

•	Narrowing guidance range for full year 2017 Adjusted (non-GAAP) Operating Earnings from $2.50 - $2.80 per share to $2.55 - $2.75 per share including the 9 cent impact from delays to the Illinois Zero Emission Credit (ZEC) contract signing from December 2017 to January 2018

•	Announcing another $250 million of cost reductions with full run-rate savings to be achieved in 2020

•	New Jersey Board of Public Utilities (NJBPU) approval of ACE’s $43 million settlement for its electric distribution rate case

•	Maryland Public Service Commission (MDPSC) order issued granting Pepco Maryland a $32 million increase for its electric distribution rate case

•	Record third-quarter production for Exelon Nuclear and fewer refueling outage days compared with a year ago

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•

ACE New Jersey Electric Distribution Rate Case: On September 22, 2017, the NJBPU approved ACE’s filed settlement for its pending electric distribution rate case, which provides for an increase in ACE annual electric distribution base rates of $43 million (before New Jersey sales and use tax) reflecting a ROE of 9.6 percent. Pursuant to the settlement agreement, ACE agreed to withdraw its request for approval of a System Renewal Recovery Charge without prejudice to its right to refile. The new rates were effective on October 1, 2017.

•

Pepco Maryland Electric Distribution Rate Case: On October 20, 2017, the MDPSC approved an increase in Pepco electric distribution rates of $34 million, reflecting a ROE of 9.5 percent. On October 27, 2017, the MDPSC issued an errata order revising the approved increase in Pepco electric distribution rates to $32 million. The errata order corrected a number of computational errors in the original order but did not alter any of the findings. The new rates became effective for services rendered on or after October 20, 2017. In its decision, the MDPSC denied Pepco’s request regarding the income tax adjustment without prejudice to Pepco filing another similar proposal with additional information. Requests for rehearing are due November 20, 2017.

•

DPL Delaware Electric and Natural Gas Distribution Rates Case: On August 17, 2017, DPL filed applications with the Delaware Public Service Commission (DPSC) to increase its annual electric and natural gas distribution base rates by $24 million, which was updated to $31 million on October 18, 2017, and $13 million, respectively, reflecting a requested ROE of 10.1 percent. DPL expects a decision in the electric proceeding and the gas proceeding in the third quarter of 2018, but cannot predict how much of the requested rate increases the DPSC will approve. While the DPSC is not

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Updated Cost Management Program: In November 2017, Exelon announced the elimination of approximately $250 million of annual ongoing costs, primarily at Generation, by 2020. This announcement is a result of Exelon’s continuous focus on improving its cost profile through enhanced efficiency and productivity. These cost reductions result in a cost profile that better aligns with current market conditions. The targeted cost savings are incremental to the expected savings from previous cost management initiatives.

•

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

•

Delay in Illinois ZEC Revenue Recognition: On October 27, 2017, the Illinois Power Agency (IPA) released the schedule for the ZEC procurement event indicating that contracts with zero emission facilities will be fully executed on January 30, 2018. It was anticipated that the procurement event and the execution of contracts with winning ZEC suppliers would occur in December 2017 and therefore Exelon would begin to recognize expected Illinois ZEC revenue retroactive to June 1, 2017, in the fourth quarter 2017. Exelon now expects to recognize Illinois ZEC revenue in the first quarter of 2018, effectively shifting $0.09 of EPS from 2017 into 2018. The delayed timing will have no impact on the amount of ZEC revenue.

•

Nuclear Operations: Generation’s nuclear fleet, including its owned output from the Salem Generating Station and 100 percent of the CENG units, produced 47,747 gigawatt-hours (GWhs) in the third quarter of 2017, compared with 44,709 GWhs in the third quarter of 2016. Excluding Salem, the Exelon-operated nuclear plants at ownership achieved a 96.1 percent capacity factor for the third quarter of 2017, compared with 96.3 percent for the third quarter of 2016. The number of planned refueling outage days in the third quarter of 2017 totaled 13, compared with 17 in the third quarter of 2016. There were 15 non-refueling outage days in the third quarter of 2017, compared with 0 days in the third quarter of 2016.

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Fossil and Renewables Operations: The dispatch match rate for Generation’s gas and hydro fleet was 98.4 percent in the third quarter of 2017, compared with 97.9 percent in the third quarter of 2016. The reported performance does not include Wolf Hollow II or Colorado Bend II, the two new combined-cycle gas turbine units that went into full commercial operation in the second quarter of 2017. Energy capture for the wind and solar fleet was 95.9 percent in the third quarter of 2017, compared with 95.2 percent in the third quarter of 2016.

•

State of Illinois Income Tax Rate Change: On July 6, 2017, Illinois enacted Senate Bill 9, which permanently increased Illinois’ total corporate income tax rate from 7.75 percent to 9.50 percent effective July 1, 2017. In addition, in the third quarter of 2017, Exelon updated its marginal state income tax rates based on 2016 state apportionment rates. As a result of these changes, Exelon, Generation and ComEd recorded a one-time increase to Deferred income taxes of approximately $250 million, $20 million and $270 million, respectively, on their Consolidated Balance Sheets in the third quarter of 2017. As income taxes are recovered through rates, each of Exelon and ComEd recorded a corresponding regulatory asset of $272 million. Further, Exelon recorded a decrease of approximately $20 million and Generation recorded an increase of approximately $20 million (each net of federal taxes) to Income tax expense in the third quarter of 2017. The income tax rate increase is not expected to have a material ongoing impact to Exelon’s, Generation’s or ComEd’s future results of operations.

•	Financing Activities:

◦

On August 23, 2017, ComEd issued $350 million aggregate principal amount of its First Mortgage 2.950 percent Bonds, due August 15, 2027 and $650 million aggregate principal amount of its First Mortgage 3.750 percent Bonds, due August 15, 2047. ComEd used the proceeds from the Bonds to refinance maturing First Mortgage Bonds, to repay a portion of ComEd’s outstanding commercial paper obligations and for general corporate purposes.

◦	On August 24, 2017, BGE issued $300 million aggregate principal amount of its 3.750 percent Notes due 2047. BGE used the proceeds from the Notes to redeem $250 million in principal amount of the 6.200 percent Deferrable Interest Subordinated Debentures due October 15, 2043 issued by BGE's affiliate BGE Capital Trust II, to repay commercial paper obligations and for general corporate purposes.

◦	On September 18, 2017, PECO issued $325 million aggregate principal amount of its First and Refunding Mortgage Bonds, 3.700 percent Series due September 15, 2047. PECO used the proceeds from the Bonds for general corporate purposes.

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(a)	PHI includes the consolidated results of Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company.

(b)	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)	PHI includes the consolidated results of Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company beginning on March 24, 2016, the day after the merger was completed.

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(a)	PHI includes the consolidated results of Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company beginning on March 24, 2016, the day after the merger was completed.

(b)	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)	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 the unrealized gains and losses on NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements.

(d)	Adjustment to exclude the non-cash amortization of intangible assets, net, primarily related to commodity contracts recorded at fair value related to the Integrys and ConEdison Solutions acquisitions in 2016, and in 2017, the ConEdison Solutions and FitzPatrick acquisitions.

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(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 in 2016, and in 2017, the PHI and FitzPatrick acquisitions, offset at PHI by the anticipated recovery of previously incurred PHI acquisition costs.

(f)	Adjustment to exclude costs incurred as part of the settlement orders approving the PHI acquisition.

(g)	Adjustment to exclude charges to earnings related to the impairment of upstream assets at Generation in 2016, and in 2017, impairments of the ExGen Texas Power, LLC assets held for sale.

(h)	Adjustment to exclude accelerated depreciation and amortization expenses associated with Generation's previous decision to early retire the Clinton and Quad Cities nuclear facilities in 2016, and Generation's decision to early retire the Three Mile Island nuclear facility in 2017.

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

(j)	Adjustment to exclude the recognition of a penalty and associated interest expense in the third quarter of 2016, as a result of a tax court decision on Exelon’s like-kind exchange tax position.

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

(l)	Adjustment to exclude a measurement period adjustment to the bargain purchase gain for the FitzPatrick acquisition.

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

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

(o)	The effective tax rate related to Adjusted (non-GAAP) Operating Earnings is 35.6% and 34.3% for the three months ended September 30, 2017 and September 30, 2016, respectively.

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

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

(c)	Adjustment to exclude the unrealized gains on NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements.

(d)	Adjustment to exclude the non-cash amortization of intangible assets, net, primarily related to commodity contracts recorded at fair value related to the Integrys and ConEdison Solutions acquisitions in 2016, and in 2017, the ConEdison Solutions and FitzPatrick acquisitions.

(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 in 2016, partially offset at ComEd, BGE and PHI by the anticipated recovery of previously incurred PHI acquisition costs, and in 2017, the PHI and FitzPatrick acquisitions, partially offset at PHI by the anticipated recovery of previously incurred PHI acquisition costs.

(f)	Adjustment to exclude in 2016 costs incurred as part of the settlement orders approving the PHI acquisition, and in 2017, 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.

(g)	Adjustment to exclude charges to earnings related to the impairment of upstream assets and certain wind projects at Generation in 2016, and in 2017, impairments as a result of the ExGen Texas Power, LLC assets held for sale.

(h)

Adjustment to exclude accelerated depreciation and amortization expenses, increases to materials and supplies inventory reserves, charges for severance reserves and construction work in progress impairments associated with Generation's previous decision to early retire the Clinton and Quad Cities nuclear facilities in 2016, and Generation's decision to early retire the Three Mile Island nuclear facility in 2017, partially offset in 2016 by a gain associated with Generation’s sale of the New Boston generating site.

(i)	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 the PHI acquisition in 2016, and in 2017, changes in the Illinois and District of Columbia statutory tax rates and changes in forecasted apportionment.

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

(k)	Adjustment to exclude the recognition of a penalty and associated interest expense in 2016 as a result of a tax court decision on Exelon’s like-kind exchange tax position, and adjustments to income tax, penalties and interest expenses in 2017 as a result of the finalization of the IRS tax computation related to Exelon’s like-kind exchange tax position.

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

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

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

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

(p)	The effective tax rate related to Adjusted (non-GAAP) Operating Earnings is 35.7% and 33.4% for the nine months ended September 30, 2017 and September 30, 2016, respectively.

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(a)	PHI consolidated results includes Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company.

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

(c)

As approved by the Maryland PSC and District of Columbia PSC, customer rates for BGE, Pepco and DPL Maryland are adjusted to eliminate the favorable and unfavorable impacts of weather and usage patterns per customer on distribution volumes. Pursuant to the Illinois Future Energy Jobs Act, beginning in 2017, customer rates for ComEd are adjusted to eliminate the favorable and unfavorable impacts of weather and customer usage patterns on distribution volumes.

(d)	For regulatory recovery mechanisms, including ComEd’s distribution formula rate, ComEd, 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 unrealized gains on NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements.

(2)	Represents the non-cash amortization of intangible assets, net, primarily related to commodity contracts recorded at fair value related to the Integrys and ConEdison Solutions acquisitions in 2016, and in 2017, 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 related to the PHI acquisition in 2016, and in 2017, the PHI and FitzPatrick acquisitions, offset at PHI by the anticipated recovery of previously incurred PHI acquisition costs.

(4)	Represents costs incurred as part of the settlement orders approving the PHI acquisition.

(5)	Primarily reflects charges to earnings related to the impairment of upstream assets at Generation in 2016, and in 2017, impairments of the ExGen Texas Power, LLC assets held for sale.

(6)	Primarily reflects accelerated depreciation and amortization expenses associated with Generation's previous decision to early retire the Clinton and Quad Cities nuclear facilities in 2016, and Generation's decision to early retire the Three Mile Island nuclear facility in 2017.

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

(8)	Represents the recognition of a penalty and associated interest expense in the third quarter of 2016, as a result of a tax court decision on Exelon’s like-kind exchange tax position.

(9)	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.

(10)	Reflects the non-cash impact of the remeasurement of state deferred income taxes, primarily as a result of a change in the Illinois statutory tax rate and changes in forecasted apportionment.

(11)	Represents a measurement period adjustment to the bargain purchase gain for the FitzPatrick acquisition.

(12)	Primarily reflects a non-cash benefit pursuant to the annual update of the Generation nuclear decommissioning obligation related to the non-regulatory units.

(13)

For ComEd, primarily reflects increased electric distribution and transmission formula rate revenues (due to increased capital investments and higher electric distribution ROE, which is due to an increase in treasury rates), partially offset by lower revenues resulting from the change to defer and recover over time energy efficiency costs pursuant to the Illinois Future Energy Jobs Act. For BGE and PHI, primarily reflects increased revenue as a result of rate increases.

(14)	Primarily reflects the acquisition of the FitzPatrick nuclear facility and a decrease in nuclear outage days.

(15)	Primarily reflects increased nuclear output, partially offset by a decrease in fuel prices.

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

(17)	Reflects the impact of the New York Clean Energy Standard.

(18)	Primarily reflects the impacts of lower load volumes delivered due to mild weather and lower realized energy prices related to Exelon's ratable hedging strategy, partially offset by the addition of two combined-cycle gas turbines in Texas.

(19)	Primarily reflects a decrease in the number of nuclear outage days in 2017, excluding Salem.

(20)	Primarily reflects the unfavorable impact of lower pension and OPEB discount rates, partially offset by the favorable impact of lower health care claims experience.

(21)	For ComEd, primarily reflects the change to defer and recover over time energy efficiency costs pursuant to the Illinois Future Energy Jobs Act.

(22)	For Generation, reflects increased depreciation for the addition of two combined-cycle gas turbines in Texas, partially offset by the absence of depreciation due to the EGTP assets held for sale. Additionally, primarily reflects increased depreciation from ongoing capital expenditures across all operating companies.

(23)	For Generation, primarily reflects the impact of project in-service dates on the capitalization of interest and higher outstanding debt.

(24)	For ComEd, reflects the 2017 increase in the Illinois statutory income tax rate. For PECO, primarily reflects an increase in the repairs tax deduction.

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

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

(27)	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)

For the nine months ended September 30, 2016, includes financial results for PHI beginning on March 24, 2016, the day after the merger was completed. Therefore, the results of operations from 2017 and 2016 are not comparable for PHI and Exelon. The explanations below identify any other significant or unusual items affecting the results of operations. PHI consolidated results includes Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company.

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

(c)

As approved by the Maryland PSC and District of Columbia PSC, customer rates for BGE, Pepco and DPL Maryland are adjusted to eliminate the favorable and unfavorable impacts of weather and usage patterns per customer on distribution volumes. Pursuant to the Illinois Future Energy Jobs Act, beginning in 2017, customer rates for ComEd are adjusted to eliminate the favorable and unfavorable impacts of weather and customer usage patterns on distribution volumes.

(d)	For regulatory recovery mechanisms, including ComEd’s distribution formula rate, ComEd, 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 unrealized gains on NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements.

(2)	Represents the non-cash amortization of intangible assets, net, primarily related to commodity contracts recorded at fair value related to the Integrys and ConEdison Solutions acquisitions in 2016, and in 2017, 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 related to the PHI acquisition in 2016, partially offset at ComEd, BGE and PHI by the anticipated recovery of previously incurred PHI acquisition costs, and in 2017, the PHI and FitzPatrick acquisitions, partially offset at PHI by the anticipated recovery of previously incurred PHI acquisition costs.

(4)	Primarily reflects in 2016 costs incurred as part of the settlement orders approving the PHI acquisition, and in 2017, 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)	Primarily reflects charges to earnings related to the impairment of upstream assets and certain wind projects at Generation in 2016, and in 2017, impairments as a result of the ExGen Texas Power, LLC assets held for sale.

(6)

Primarily reflects accelerated depreciation and amortization expenses, increases to materials and supplies inventory reserves, charges for severance reserves and construction work in progress impairments associated with Generation's previous decision to early retire the Clinton and Quad Cities nuclear facilities in 2016, and Generation's decision to early retire the Three Mile Island nuclear facility in 2017, partially offset in 2016 by a gain associated with Generation’s sale of the New Boston generating site.

(7)	Reflects the non-cash impact of the remeasurement of state deferred income taxes, primarily as a result of changes in forecasted apportionment related to the PHI acquisition in 2016, and in 2017, changes in the Illinois and District of Columbia statutory tax rates and changes in forecasted apportionment.

(8)	Represents severance and reorganization costs related to a cost management program.

(9)	Represents the recognition of a penalty and associated interest expense in 2016 as a result of a tax court decision on Exelon’s like-kind exchange tax position, and adjustments to income tax, penalties and interest expenses in 2017 as a result of the finalization of the IRS tax computation related to Exelon’s like-kind exchange tax position.

(10)	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.

(11)	Primarily reflects a non-cash benefit pursuant to the annual update of the Generation nuclear decommissioning obligation related to the non-regulatory units.

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

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

(14)

For ComEd, primarily reflects increased electric distribution and transmission formula rate revenues (due to increased capital investments and higher electric distribution ROE, which is due to an increase in treasury rates), partially offset by lower revenues resulting from the change to defer and recover over time energy efficiency costs pursuant to the Illinois Future Energy Jobs Act. For BGE and PHI, primarily reflects increased revenue as a result of rate increases.

(15)	Primarily reflects the acquisition of the FitzPatrick nuclear facility.

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

(17)	Primarily reflects increased capacity prices in the New England region, partially offset by decreased capacity prices in the Mid-Atlantic region.

(18)	Reflects the impact of the New York Clean Energy Standard.

(19)

Primarily reflects the conclusion of the Ginna Reliability Support Services Agreement, the impact of declining natural gas prices on Generation’s natural gas portfolio, the impacts of lower load volumes delivered due to mild weather and lower realized energy prices related to Exelon's ratable hedging strategy, partially offset by the addition of two combined-cycle gas turbines in Texas and the absence of oil inventory write downs in 2017.

(20)	For Generation, primarily reflects increased salaries, wages and contracting costs related to the acquisition of the FitzPatrick nuclear facility.

(21)	Primarily reflects an increase in the number of nuclear outage days in 2017, excluding Salem.

(22)	Primarily reflects the unfavorable impact of lower pension and OPEB discount rates, partially offset by the favorable impact of lower health care claims experience.

(23)

For Generation, includes an increase in nuclear decommissioning obligation expense related to the FitzPatrick nuclear facility. For ComEd, primarily reflects the change to defer and recover over time energy efficiency costs pursuant to the Illinois Future Energy Jobs Act. For PECO, primarily reflects decreased fully recoverable costs associated with regulatory programs. For BGE, primarily reflects certain disallowances contained in 2016 rate case orders and decreased storm costs in the BGE service territory.

(24)

For Generation, reflects increased depreciation for the addition of two combined-cycle gas turbines in Texas, offset by the absence of depreciation due to the EGTP assets held for sale. For BGE, primarily reflects increased amortization due to the initiation of cost recovery of the AMI programs and increased depreciation from AMI program capital expenditures. Additionally, primarily reflects increased depreciation from ongoing capital expenditures across all operating companies.

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(25)	For Generation, primarily reflects the impact of project in-service dates on the capitalization of interest and higher outstanding debt. For Corporate, primarily reflects increased interest expense due to higher outstanding debt, as well as debt issuance costs related to the April 2017 remarketing of Junior Subordinated Notes due in 2024.

(26)	For Generation, primarily reflects the favorable settlement of certain income tax positions in 2016. For ComEd, reflects the 2017 increase in the Illinois statutory income tax rate. For PECO, primarily reflects an increase in the repairs tax deduction. For BGE, primarily reflects a 2016 cumulative adjustment to tax expense for transmission-related regulatory assets.

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

(28)	For Generation, primarily reflects higher realized NDT fund gains, partially offset by increased real estate taxes as a result of the FitzPatrick acquisition.

(29)	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 GAAP.

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

(c)	Adjustment to exclude the unrealized gains on NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements.

(d)	Adjustment to exclude the non-cash amortization of intangible assets, net, primarily related to commodity contracts recorded at fair value related to the Integrys and ConEdison Solutions acquisitions in 2016, and in 2017, the ConEdison Solutions and FitzPatrick acquisitions.

(e)

Adjustment to exclude costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses and integration activities related to the PHI acquisition in 2016, partially offset at ComEd, BGE and PHI by the anticipated recovery of previously incurred PHI acquisition costs, and in 2017, the PHI and FitzPatrick acquisitions, partially offset at PHI by the anticipated recovery of previously incurred PHI acquisition costs.

(f)	Adjustment to exclude 2016 costs incurred as part of the settlement orders approving the PHI acquisition, and in 2017, 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.

(g)	Adjustment to exclude charges to earnings related to the impairment of upstream assets and certain wind projects at Generation in 2016, and in 2017, impairments as a result of the ExGen Texas Power, LLC assets held for sale.

(h)

Adjustment to exclude accelerated depreciation and amortization expenses, increases to materials and supplies inventory reserves, charges for severance reserves and construction work in progress impairments associated with Generation's previous decision to early retire the Clinton and Quad Cities nuclear facilities in 2016, and Generation's decision to early retire the Three Mile Island nuclear facility in 2017, partially offset in 2016 by a gain associated with Generation’s sale of the New Boston generating site.

(i)	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 the PHI acquisition in 2016, and in 2017, changes in the Illinois and District of Columbia statutory tax rates and changes in forecasted apportionment.

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

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

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

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

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

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(a)	Results reported in accordance with GAAP.

(b)	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.

(c)	Adjustment to exclude the recognition of a penalty and associated interest expense in 2016 as a result of a tax court decision on Exelon's like-kind exchange tax position, and adjustments to income tax, penalties and interest expenses in 2017 as a result of the finalization of the IRS tax computation related toExelon's like-kind exchange tax position.

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(d)	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.

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(a)	Results reported in accordance with GAAP.

(b)	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.

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

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(a)	Results reported in accordance with GAAP.

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(b)	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 BGE by the anticipated recovery of previously incurred PHI acquisition costs.

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

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(a)	Results reported in accordance with GAAP.

(b)

For the nine months ended September 30, 2016, includes financial results for PHI beginning on March 24, 2016, the day after the merger was completed. Therefore, the results of operations from 2017 and 2016 are not comparable for PHI and Exelon. The explanations below identify any other significant or unusual items affecting the results of operations. PHI consolidated results includes Potomac Electric Power Company, Delmarva Power & Light Company, and Atlantic City Electric Company.

(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, partially offset in 2016 and 2017 at PHI by the anticipated recovery of previously incurred acquisition costs.

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(d)	Adjustment to exclude in 2016 costs incurred as part of the settlement orders approving the PHI acquisition, and in 2017, a decrease in reserves for uncertain tax positions related to the deductibility of certain merger commitments associated with the 2016 PHI acquisition.

(e)	Adjustment to exclude the non-cash impact of the remeasurement of state deferred income taxes, primarily as a result of changes in forecasted apportionment.

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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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(b)	Results reported in accordance with GAAP.

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

(d)	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.

(e)	Adjustment to exclude in 2016 costs incurred as part of the settlement orders approving the PHI acquisition, and in 2017, a decrease in reserves for uncertain tax positions related to the deductibility of certain merger commitments associated with the 2016 PHI acquisition.

(f)	Adjustment to exclude the impact of charges to earnings related to the impairment of upstream assets and certain wind projects at Generation in 2016, and in 2017, impairments as a result of the ExGen Texas Power, LLC assets held for sale.

(g)	Adjustment to exclude the impact associated with Generation's decision to early retire the Three Mile Island nuclear facility in 2017.

(h)	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 the PHI acquisition in 2016, and in 2017, changes in the Illinois and District of Columbia statutory tax rates and changes in forecasted apportionment.

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

(j)	Adjustment to exclude the recognition of a penalty and associated interest expense in 2016 as a result of a tax court decision on Exelon's like-kind exchange tax position, and adjustments to income tax, penalties and interest expenses in 2017 as a result of the finalization of the IRS tax computation related to Exelon's like-kind exchange tax position.

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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)	Excludes physical proprietary trading volumes of 2,601 GHhs, 2,312 GWhs, 1,850 GWhs, 2,164 GWhs, and 1,506 GWhs for the three months ended September 30, 2017, June 30, 2017, March 31, 2017, December 31, 2016, and September 30, 2016, respectively.

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

(e)	Outage days exclude Salem.

(f)	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)	Excludes physical proprietary trading volumes of 6,763 GWh and 4,015 GWh for the nine months ended September 30, 2017 and 2016, respectively.

(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)	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)	Other revenue primarily includes transmission revenue from PJM. Other revenue includes rental revenues, revenues related to late payment charges, revenues from other utilities for mutual assistance programs and recoveries of remediation costs associated with MGP sites.

(c)	Includes operating revenues from affiliates totaling $3 million and $4 million for the three months ended September 30, 2017 and 2016, respectively, and $12 million and $12 million for the nine months ended September 30, 2017 and 2016, respectively.

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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)	Other revenue includes transmission revenue from PJM and wholesale electric revenues.

(c)	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.

(d)

Total electric revenue includes operating revenues from affiliates totaling $1 million and $2 million for the three months ended September 30, 2017 and 2016, respectively, and $4 million and $5 million for the nine months ended September 30, 2017 and 2016, respectively.  Total natural gas revenues includes operating revenues from affiliates totaling less than $1 million for both the three and nine months ended September 30, 2017 and 2016.

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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)	Other revenue primarily includes wholesale transmission revenue and late payment charges.

(c)	Includes operating revenues from affiliates totaling $1 million for both the three months ended September 30, 2017 and 2016 and $5 million for both the nine months ended September 30, 2017 and 2016.

(d)	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.

(e)	Transportation and other natural gas revenue includes off-system revenue of 68 mmcfs ($1 million) and 1,311 mmcfs ($4 million) for the three months ended September 30, 2017 and 2016, respectively, and 2,463 mmcfs ($15 million) and 4,078 mmcfs ($14 million) for the nine months ended September 30, 2017 and 2016, respectively.

(f)	Includes operating revenues from affiliates totaling $2 million and $6 million for the three months ended September 30, 2017 and 2016, respectively, and $7 million and $11 million for the nine months ended September 30, 2017 and 2016, 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)	Other revenue includes transmission revenue from PJM and wholesale electric revenues.

(c)	Includes operating revenues from affiliates totaling $1 million and $1 million for the three months ended September 30, 2017 and 2016, respectively, and $4 million and $3 million for the nine months ended September 30, 2017 and 2016, respectively.

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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)	Other revenue includes transmission revenue from PJM and wholesale electric revenues.

(c)	Includes operating revenues from affiliates totaling $2 million and $2 million for the three months ended September 30, 2017 and 2016, respectively, and $6 million and $6 million for the nine months ended September 30, 2017 and 2016, respectively.

(d)	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.

(e)	Transportation and other revenue includes off-system natural gas sales and the short-term release of interstate pipeline transportation and storage capacity not needed to serve customers.

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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)	Other revenue includes transmission revenue from PJM and wholesale electric revenues.

(c)	Includes operating revenues from affiliates totaling $0 million and $1 million for the three months ended September 30, 2017 and 2016, respectively, and $2 million and $3 million for the nine months ended September 30, 2017 and 2016, respectively.