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•	GAAP Net Income of $0.50 per share and Adjusted (non-GAAP) Operating Earnings of $0.60 per share for the second quarter of 2019

•	Reaffirming full year 2019 Adjusted Operating Earnings guidance of $3.00 to $3.30 per share

•	Delmarva Power achieved the number one ranking by J.D. Power in its 2019 Electric Utility Residential Customer Satisfaction Study - first Exelon utility to rank first

•	Strong utility customer operations performance - every utility achieved top quartile in Service Level and Abandon Rate, with ComEd and PHI demonstrating top decile performance

•	On July 25, 2019, FERC released an order directing PJM not to hold the Base Residual Auction in August 2019

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BGE Maryland Electric and Natural Gas Rate Case: On May 24, 2019, BGE filed an application with the Maryland Public Service Commission (MDPSC) to increase its annual electric and natural gas distribution base rates by $74 million and $59 million, respectively, reflecting a requested ROE of 10.3%. BGE currently expects a decision in the fourth quarter of 2019 but cannot predict if the MDPSC will approve the application as filed.

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Pepco District of Columbia Electric Base Rate Case: On May 30, 2019, Pepco filed an application for a multi-year plan with the Public Service Commission of the District of Columbia (DCPSC) to increase its annual electric distribution base rates by $85 million, $40 million and $37 million for years 2020, 2021, and 2022, respectively, to recover capital investments made in 2018 and 2019 and planned capital investments from 2020 to 2022, reflecting a requested ROE of 10.3%. Pepco has requested a decision by the second quarter of 2020 but cannot predict if the DCPSC will approve the application as filed or the requested schedule.

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Pending PECO Transmission Formula Rate: On May 1, 2017, PECO filed a request with the Federal Energy Regulatory Commission (FERC) seeking approval to update its transmission rates and change the manner in which PECO’s transmission rate is determined from a fixed rate to a formula rate. On July 22, 2019, PECO and other parties filed with FERC a settlement agreement, which includes a ROE of 10.35%, inclusive of a 50-basis point adder for being a member of a regional transmission organization (RTO). The impact of the settlement is not expected to be material. A final order from FERC is not expected prior to the fourth quarter of 2019. PECO cannot predict the outcome of this proceeding, or the transmission formula FERC may approve.

•

Sale of Oyster Creek: On July 31, 2018, Generation entered into an agreement with Holtec International (Holtec) and its indirect wholly owned subsidiary, Oyster Creek Environmental Protection, LLC (OCEP), for the sale and decommissioning of Oyster Creek located in Forked River, New Jersey, which permanently ceased generation operations on Sep 17, 2018. As a result of the transaction, in the third quarter of 2018, Generation reclassified certain Oyster Creek assets and liabilities as held for sale at their respective fair values. Generation had $863 million and $759 million of assets and liabilities held for sale, respectively, at June 30, 2019. Completion of the transaction contemplated by the sale agreement was subject to the satisfaction of several closing conditions, including approval of the license transfer from the Nuclear Regulatory Commission and other regulatory approvals, and a private letter ruling from the Internal Revenue Service (IRS), which were satisfied in the second quarter 2019. The sale was completed on July 1, 2019. Under the terms of the transaction, Generation transferred to OCEP substantially all the assets associated with Oyster Creek, including assets held in Nuclear Decommissioning Trust (NDT) funds, along with the assumption of liability for all responsibility for the site, including full decommissioning and ongoing management of spent fuel until the spent fuel is moved offsite. Generation expects the loss on the sale, which will be recognized in the third quarter of 2019, to be immaterial.

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Complaints and PJM Filing at FERC Seeking to Mitigate ZEC Programs: On April 10, 2019, PJM Interconnection, LLC (PJM) notified FERC of its intent to proceed with the next capacity auction in August 2019 under the existing market rules and asked FERC to clarify that it would not require PJM to re-run the auction in the event FERC alters market rules in its decision on the Minimum Offer Price Rule complaint. On July 25, 2019, FERC issued an order denying PJM’s request to clarify that any alteration of PJM’s existing market rules would operate prospectively and, therefore, directed PJM to not conduct the capacity auction in August 2019. It is too early to predict the final outcome of each of these proceedings or their potential financial impact, if any, on Exelon or Generation.

•

Nuclear Operations: Generation’s nuclear fleet, including its owned output from the Salem Generating Station and 100% of the CENG units, produced 44,748 gigawatt-hours (GWhs) in the second quarter of 2019, compared with 45,723 GWhs in the second quarter of 2018. Excluding Salem, the Exelon-operated nuclear plants at ownership achieved a 95.1% capacity factor for the second quarter of 2019, compared with 93.2% for the second quarter of 2018. The number of planned refueling outage days in the second quarter of 2019 totaled 56, compared with 94 in the second quarter of 2018. There were 28 non-refueling outage days in the second quarter of 2019, compared with two in the second quarter of 2018.

•	Fossil and Renewables Operations: The Dispatch Match rate for Generation’s gas and hydro fleet was 99.7% in the second quarter of 2019, compared with 97.8% in the second quarter of 2018. Energy Capture for the wind and solar fleet was 96.0% in the second quarter of 2019, compared with 95.1% in the second quarter of 2018.

•	Financing Activities:

◦	On May 21, 2019, ACE issued $100 million in aggregate principal amount of its First Mortgage Bonds, 3.50% due May 21, 2029 and $50 million in aggregate principal amount of its First Mortgage Bonds, 4.14% due May 21, 2049. ACE used the proceeds to repay existing indebtedness and for general corporate purposes.

◦	On June 13, 2019, Pepco issued $150 million aggregate principal amount of its First Mortgage Bonds, 3.45% due June 13, 2029. Pepco used the proceeds of to repay existing indebtedness and for general corporate purposes.

◦	On June 27, 2019, Pepco issued $110 million of tax-exempt bonds, 1.70% due Sep 1, 2022. Pepco used the proceeds repay existing indebtedness.

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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.

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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.

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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.

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

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

(c)	In 2018, adjustment to exclude the impairment of certain wind projects at Generation.

(d)

In 2018, adjustment to exclude accelerated depreciation and amortization expense associated with Generation's decision to early retire the Oyster Creek and Three Mile Island nuclear facilities. In 2019, adjustment to exclude net realized gains related to Oyster Creek's NDT fund investments in conjunction with the Holtec sale on July 1, 2019 and a gain on the sale of certain wind assets, partially offset by accelerated depreciation and amortization expenses associated with Generation's previous decision to early retire the TMI nuclear facility.

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

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

(g)	Adjustment to exclude costs related to the PHI acquisition.

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(h)	Adjustment to exclude charges to adjust an environmental reserve.

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

(j)	The effective tax rate related to Adjusted (non-GAAP) Operating Earnings is 20.8% and 20.9% for the three months ended June 30, 2019 and June 30, 2018, respectively.

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

(l)	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.

(m)	Amounts may not sum due to rounding.

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

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

(c)

In 2018, adjustment to exclude accelerated depreciation and amortization expenses and one-time charges associated with Generation's decision to early retire the Oyster Creek nuclear facility, as well as 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. In 2019, adjustment to exclude net realized gains related to Oyster Creek's NDT fund investments in conjunction with the Holtec sale on July 1, 2019, a benefit associated with a remeasurement in the first quarter 2019 of the TMI asset retirement obligation and a gain on the sale of certain wind assets in the second quarter of 2019, partially offset by accelerated depreciation and amortization expenses associated with Generation's previous decision to early retire the TMI nuclear facility.

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(d)	In 2018, adjustment to exclude the impairment of certain wind projects at Generation. In 2019, adjustment to exclude the impairment of a fossil asset at Generation.

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

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

(g)	Adjustment to exclude costs related to the PHI acquisition.

(h)	Adjustment to exclude charges to adjust an environmental reserve.

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

(j)	The effective tax rate related to Adjusted (non-GAAP) Operating Earnings is 18.5% and 18.7% for the six months ended June 30, 2019 and June 30, 2018, respectively.

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

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

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

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

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

(2)	In 2018, primarily reflects the impairment of certain wind projects at Generation.

(3)

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. In 2019, primarily reflects net realized gains related to Oyster Creek's NDT fund investments in conjunction with the Holtec sale on July 1, 2019 and a gain on the sale of certain wind assets, partially offset by accelerated depreciation and amortization expenses associated with Generation's previous decision to early retire the TMI nuclear facility.

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

(5)	Reflects an adjustment to the remeasurement of deferred income taxes as a result of the TCJA.

(6)	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.

(7)

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

(8)	Primarily reflects the permanent cease of generation operations at Oyster Creek in September 2018.

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

(10)	Primarily reflects decreased capacity prices in New York and Other Power Regions.

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

(12)	Primarily reflects lower realized energy prices.

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

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

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

(16)	For Generation, primarily reflects an increase in planned nuclear outage days at Salem in 2019.

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

(18)

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

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

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

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

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

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

(2)	In 2018, primarily reflects the impairment of certain wind projects at Generation.

(3)

In 2018, primarily reflects accelerated depreciation and amortization expenses and one-time charges associated with Generation's decision to early retire the Oyster Creek nuclear facility, as well as 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. In 2019, primarily reflects net realized gains related to Oyster Creek's NDT fund investments in conjunction with the Holtec sale on July 1, 2019, a benefit associated with a remeasurement in the first quarter 2019 of the TMI asset retirement obligation and a gain on the sale of certain wind assets in the second quarter of 2019, partially offset by accelerated depreciation and amortization expenses associated with Generation's previous decision to early retire the TMI nuclear facility.

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

(5)	Reflects an adjustment to the remeasurement of deferred income taxes as a result of the TCJA.

(6)	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.

(7)

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

(8)	Primarily reflects the permanent cease of generation operations at Oyster Creek in September 2018.

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

(10)	Primarily reflects increased capacity prices in the Mid-Atlantic and Midwest regions, partially offset by decreased capacity prices in New York and Other Power Regions.

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

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

(13)	For Generation, primarily reflects decreased costs related to the permanent cease of generation operations at Oyster Creek. For PHI, primarily reflects decreased contracting costs. Additionally, for all utilities, reflects decreased mutual assistance expenses.

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

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

(16)

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

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

(18)

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

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

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

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

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

(c)	In 2018, adjustment to exclude accelerated depreciation and amortization expenses and one-time charges associated with Generation's decision to early retire the Oyster Creek nuclear facility, as well as accelerated depreciation and amortization expenses associated with the 2017 decision to early retire

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

(e)	Adjustment to exclude the impairment of certain wind projects.

(f)	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.

(g)	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.

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

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

(j)	Adjustment to exclude charges to adjust the environmental reserve.

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

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

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

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

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(a)	Results reported in accordance with GAAP.

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

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

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

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

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

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

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(d)

In 2018, adjustment to exclude accelerated depreciation and amortization expense associated with Generation's decision to early retire the Oyster Creek and Three Mile Island nuclear facilities. In 2019, adjustment to exclude net realized gains related to Oyster Creek's NDT fund investments in conjunction with the Holtec sale on July 1, 2019, partially offset by accelerated depreciation and amortization expenses associated with Generation's previous decision to early retire the TMI nuclear facility.

(e)	In 2018, an adjustment to the remeasurement of deferred income taxes as a result of TCJA.

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

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

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

(d)	Outage days exclude Salem.

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

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

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

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

(c)	Includes operating revenues from affiliates totaling $5 million and $5 million three months ended June 30, 2019 and 2018, respectively, and $9 million and $19 million for the six months ended June 30, 2019 and 2018, respectively.

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

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

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

(c)	Includes operating revenues from affiliates totaling $1 million and $2 million for the three months ended June 30, 2019 and 2018, respectively, and $2 million and $3 million for the six months ended June 30, 2019 and 2018, respectively.

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

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

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

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

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

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

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(c)	Includes operating revenues from affiliates totaling $1 million and $2 million for the three months ended June 30, 2019 and 2018, respectively, and $3 million for both the six months ended June 30, 2019 and 2018.

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

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

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

(g)	Includes operating revenues from affiliates totaling $4 million for both the three months ended June 30, 2019 and 2018, and $9 million for both the six months ended June 30, 2019 and 2018.

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

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

(c)	Includes operating revenues from affiliates totaling $1 million and $2 million for the three months ended June 30, 2019 and 2018 respectively, and $3 million for both the six months ended June 30, 2019 and 2018.

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

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

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

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

(d)	Includes operating revenues from affiliates totaling $2 million for both the three months ended June 30, 2019 and 2018 and $3 million and $4 million for the six months ended June 30, 2019 and 2018.

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

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

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

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

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

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

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