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•	Exelon's GAAP Net Income for the fourth quarter of 2018 decreased to $0.16 per share from $1.94 per share in the fourth quarter of 2017. Adjusted (non-GAAP) Operating Earnings increased to $0.58 per share in the fourth quarter of 2018 from $0.56 per share in the fourth quarter of 2017

•	Exelon introduces a 2019 adjusted (non-GAAP) operating earnings guidance range of $3.00-$3.30 per share, reflecting growth in Utilities, recognition of New Jersey Zero Emissions Credit (ZEC) revenues, and the impact of previously announced cost reduction initiatives

•	Exelon Utilities project capital expenditures of $23 billion over the next four years, supporting 7.8 percent annual rate base growth to the benefit of its customers

•	Exelon Generation projects available cash flow of $7.8 billion over the next four years, supporting Exelon’s priorities of Utility reinvestment and debt reduction

•	All four utilities ended the year in the top quartile for SAIFI (outage frequency) while most utilities demonstrated strong performance in CAIDI (outage duration) and customer satisfaction

•	Exelon Nuclear achieved the most nuclear power ever generated at 159 TWhs

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•	Mark-to-market adjustments from economic hedging activities;

•	Unrealized gains and losses from NDT funds to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements;

•	Certain costs incurred related to plant retirements;

•	Certain costs incurred to achieve cost management program savings;

•	Other unusual items; and

•	Generation's noncontrolling interest related to Constellation Energy Nuclear Group (CENG) exclusion items.

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•

Utility Capex and Rate Base Update: Exelon Utilities will invest nearly $23 billion of capital over the next four years. These investments will help ensure more reliable and efficient transmission and distribution of electricity and gas for our 10 million utility customers, while also preparing us for the future. The increased capital investments are expected to drive rate base growth 7.8 percent annually to $50.7 billion by 2022 and exceed the 7.4 percent growth expectations for 2017-2021 projected a year ago.

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Generation and Free Cash Flow Outlook: Cumulatively from 2019 through 2022, Generation projects $7.8 billion of available cash flow before growth capex, which is $0.2 billion higher than the prior 4-year outlook. This financial outlook accounts for the latest power price forwards at year-end, current gross margin outlook at Constellation, latest O&M forecast that reflects pension cost updates and the Everett Marine Terminal acquisition, benefits of previously announced cost reduction initiatives and the planned closure of TMI. The $7.8 billion will primarily support our strategic capital allocation priorities which entail: i) funding $4.0-$4.4 billion of growth capital at the utilities; ii) supporting our 5 percent annual dividend growth commitment; and iii) reducing debt by $2.5 billion.

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ComEd Distribution Rate Formula: On Dec. 4, 2018, the Illinois Commerce Commission (ICC) issued its final order approving ComEd’s 2018 annual distribution formula rate update. The final order resulted in a $24 million decrease to the revenue requirement, reflecting a $58 million decrease for the initial revenue requirement for 2018 and a $34 million increase related to the annual reconciliation for 2017. The increase was set using an allowed return on rate base of 6.52 percent for the initial revenue requirement and the annual reconciliation, inclusive of an allowed ROE of 8.69 percent. The rates took effect in January 2019.

•

PECO Electric Distribution Base Rate Case: On Dec. 20, 2018, the Pennsylvania Public Utility Commission (PAPUC) approved the partial settlement agreement with an effective date of Jan. 1, 2019, that provides for a $25 million net increase to PECO's annual electric distribution base rates, which includes $71 million in annual ongoing TCJA tax savings. In PECO's original filing with the PAPUC on March 29, 2018, PECO had requested a ROE of 10.95 percent. No approved ROE was specified in the PAPUC order.

•	BGE Maryland Natural Gas Distribution Base Rate Case: On Jan. 4, 2019, the Maryland Public Service Commission (MDPSC) issued its final order providing for a net increase to BGE's annual natural gas distribution base rates of $43 million and reflecting a ROE of 9.8 percent.

•	Pepco Maryland Electric Distribution Base Rate Case: On Jan. 15, 2019, Pepco filed an application with the MDPSC, requesting a $30 million increase to its electric distribution base rates and a 10.3 percent ROE. Pepco currently expects a decision in the third quarter of 2019 but cannot predict if the MDPSC will approve the application as filed.

•

DPL Delaware Natural Gas Distribution Base Rate Case: On Nov. 8, 2018, the Delaware Public Service Commission (DPSC) approved the settlement agreement, providing for a $4 million net decrease to DPL's annual natural gas distribution base rates, which includes annual ongoing TCJA tax savings and reflects a 9.7 percent ROE. 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.

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Mystic Cost-of-Service Federal Energy Regulatory Commission (FERC) Filing: On Dec. 20, 2018, FERC issued an order accepting Generation’s cost of service agreement reflecting a number of adjustments to the annual fixed revenue requirement and allowing for recovery of a substantial portion of the costs associated with the Everett Marine Terminal. FERC also directed a paper hearing on ROE using a new methodology. Initial and reply briefs on ROE will be due on April 18, 2019, and July 18, 2019, respectively. These will be reflected in a compliance filing due Feb. 18, 2019. On Jan. 4, 2019, Generation notified ISO-NE that it will participate in the Forward Capacity Market auction for the 2022-2023 capacity commitment period. In addition, on Jan. 22, 2019, Exelon and several other parties filed requests for rehearing of certain findings of the Dec. 20, 2018, order. The request for rehearing does not alter Generation's commitment to participate in the Forward Capacity Auction for the 2022-2023 capacity commitment period.

•

District of Columbia Clean Energy Act: On Dec. 18, 2018, the Council of the District of Columbia passed the Clean Energy District of Columbia Omnibus Amendment Act of 2018 (the Act), which was subsequently signed by the Mayor of the District of Columbia on Jan. 18, 2019. The Act is expected to take effect in February 2019 following the expiration of a 30-day review process by the U.S. House of Representatives. Among other things, the Act would increase electric load by requiring all public buses, taxis and other specified fleets to be solely zero-emissions vehicles by 2045. The Act would also clarify that, under certain circumstances, the gas and electric utilities may offer and receive cost recovery, including a return on investment on capital and related costs for energy efficiency programs in the District of Columbia.

•

Pension Plan Merger: Effective Jan. 1, 2019, Exelon is merging the Exelon Corporation Cash Balance Pension Plan (CBPP) into the Exelon Corporation Retirement Program (ECRP). The merging of the plans is not changing the benefits offered to the plan participants and, thus, has no impact on Exelon's pension obligation. However, beginning in 2019, actuarial losses and gains related to the CBPP and ECRP will be amortized over participants’ average remaining service period of the merged ECRP rather than each individual plan, which will lower Exelon’s 2019 pre-tax pension cost by approximately $90 million.

•

Nuclear Operations: Generation’s nuclear fleet, including its owned output from the Salem Generating Station and 100 percent of the CENG units, produced 45,809 gigawatt-hours (GWhs) in the fourth quarter of 2018, compared with 47,528 GWhs in the fourth quarter of 2017. Excluding Salem, the Exelon-operated nuclear plants at ownership achieved a 95.1 percent capacity factor for the fourth quarter of 2018, compared with 95.3 percent for the fourth quarter of 2017. Excluding Salem, the number of planned refueling outage days in the fourth quarter of 2018 totaled 76, compared with 60 in the fourth quarter of 2017. There were 18 non-refueling outage days in both the fourth quarter of 2018 and 2017.

•	Fossil and Renewables Operations: The Dispatch Match rate for Generation’s gas and hydro fleet was 99.3 percent in the fourth quarter of 2018, compared with 98.4 percent in the fourth quarter of 2017.

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•	Financing Activities: On Nov. 11, 2018, Pepco issued $100 million aggregate principal amount of its First Mortgage Bonds, 4.31 percent due Nov. 1, 2048. Pepco used the proceeds to 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 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)	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)	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)	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 Statement 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)	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 Exelon’s economic hedging activities, net of intercompany eliminations.

(d)	Adjustment to exclude impact of net unrealized gains and losses on Generation’s NDT funds 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 primarily charges to earnings related to the PHI impairment of the District of Columbia sponsorship intangible asset.

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(g)	Adjustment to exclude primarily accelerated depreciation and amortization expenses associated with Generation's decision to early retire the Three Mile Island nuclear facility.

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

(i)	Adjustment to exclude the reversal of previously accrued vacation expenses as a result of a change in Exelon's vacation vesting policy.

(j)	Adjustment to exclude the gain recorded upon deconsolidation of ExGen Texas Power, LLC (EGTP) net liabilities, which included the previously impaired assets and related debt, as a result of the November 2017 bankruptcy filing.

(k)	Adjustment to exclude the gain on the settlement of a long-term gas supply agreement at Generation.

(l)	Adjustment to exclude in 2017, the one-time non-cash impacts associated with the Tax Cuts and Jobs Act (TCJA) (including impacts on pension obligations contained within Other) and in 2018, an adjustment to the remeasurement of deferred income taxes as a result of TCJA and changes in forecasted apportionment.

(m)	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 funds at CENG.

(n)	The effective tax rate related to GAAP Net Income for the three months ended December 31, 2018 includes the impact of the Tax Cuts and Jobs Act.

(o)	The effective tax rate related to Adjusted (non-GAAP) Operating Earnings is 15.6% and 39.9% for the three months ended December 31, 2018 and 2017, respectively.

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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 Exelon’s economic hedging activities, net of intercompany eliminations.

(d)	Adjustment to exclude impact of net unrealized gains and losses on Generation’s NDT funds 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.

(g)	Adjustment to exclude in 2017, primarily 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 the ExGen Texas Power, LLC (EGTP) assets held for sale and PHI District of Columbia sponsorship intangible asset and 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 for Pepco, an increase related to asbestos identified at its Buzzard Point property.

(l)	Adjustment to exclude the reversal of previously accrued vacation expenses as a result of a change in Exelon's vacation vesting policy.

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

(n)	Adjustment to exclude the gain recorded upon deconsolidation of EGTP's net liabilities, which included the previously impaired assets and related debt, as a result of the November 2017 bankruptcy filing.

(o)	Adjustment to exclude the gain on the settlement of a long-term gas supply agreement at Generation.

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

(q)

Adjustment to exclude in 2017, one-time non-cash impacts associated with remeasurements of deferred income taxes as a result of the Tax Cuts and Jobs Act (TCJA) (including impacts on pension obligations contained within Other), changes in the Illinois and District of Columbia statutory tax rates and changes in forecasted apportionment. In 2018, an adjustment to the remeasurement of deferred income taxes as a result of the TCJA and changes in forecasted apportionment.

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

(s)	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 funds at CENG.

(t)	The effective tax rate related to GAAP Net Income for the twelve months ended December 31, 2018 includes the impact of the TCJA.

(u)	The effective tax rate related to Adjusted (non-GAAP) Operating Earnings is 18.2% and 36.6% for the twelve months ended December 31, 2018 and 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 funds 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)	Primarily reflects charges to earnings related to the PHI impairment of the District of Columbia sponsorship intangible asset.

(4)	Primarily reflects accelerated depreciation and amortization expenses associated with Generation's decision to early retire the Three Mile Island nuclear facility.

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

(6)	Represents the reversal of previously accrued vacation expenses as a result of a change in Exelon's vacation vesting policy.

(7)	Represents the gain recorded upon deconsolidation of ExGen Texas Power, LLC (EGTP) net liabilities, which included the previously impaired assets and related debt, as a result of the November 2017 bankruptcy filing.

(8)	In 2017, reflects the one-time non-cash impacts associated with the Tax Cuts and Jobs Act (TCJA) (including impacts on pension obligations contained within Other). In 2018, reflects an adjustment to the remeasurement of deferred income taxes as a result of TCJA and changes in forecasted apportionment.

(9)	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 funds at CENG.

(10)	Represents the gain on the settlement of a long-term gas supply agreement at Generation.

(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 PHI, reflects increased revenue as a result of rate increases.

(12)	Primarily reflects the permanent cease of generation operations at Oyster Creek and an increase in nuclear outage days.

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

(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 lower realized energy prices and decreased revenues related to the sale of Generation's electrical contracting business.

(17)

For Generation, primarily reflects decreased costs related to the permanent cease of generation operations at Oyster Creek and the sale of Generation's electrical contracting business, decreased spending related to energy efficiency projects and the absence of EGTP costs resulting from its deconsolidation in the fourth quarter of 2017. For ComEd, primarily reflects increased variable compensation costs.

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

(19)	For Generation, primarily reflects the absence of EGTP costs resulting from its deconsolidation in the fourth quarter of 2017.

(20)

Reflects ongoing capital expenditures across all operating companies. For ComEd, also reflects higher amortization of deferred energy efficiency costs pursuant to the Illinois Future Energy Jobs Act (FEJA), which is offset in Other Energy and Delivery. For BGE, also reflects certain regulatory assets that became fully amortized as of December 31, 2017. For PHI, also 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, partially offset by a reduction in renewable tax credits. For ComEd, reflects increased income tax expense due to an increase in the Illinois income tax rate in July of 2017. For PECO, primarily reflects an increase in the repairs tax deduction. For ComEd, BGE and PHI, also reflects the absence of the 2017 impairments of certain transmission-related income tax regulatory assets.

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

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

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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 funds 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)	In 2017, 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 and PHI District of Columbia sponsorship intangible asset. 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 reversal of previously accrued vacation expenses as a result of a change in Exelon's vacation vesting policy.

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

(10)	Represents the gain recorded upon deconsolidation of EGTP's net liabilities, which included the previously impaired assets and related debt, as a result of the November 2017 bankruptcy filing.

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

(12)

In 2017, one-time non-cash impacts associated with remeasurements of deferred income taxes as a result of the Tax Cuts and Jobs Act (TCJA) (including impacts on pension obligations contained within Other), changes in the Illinois and District of Columbia statutory tax rates and changes in forecasted apportionment. In 2018, reflects an adjustment to the remeasurement of deferred income taxes as a result of the TCJA and changes in forecasted apportionment.

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

(14)	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 funds at CENG.

(15)	For Pepco, reflects an increase related to asbestos identified at its Buzzard Point property.

(16)	Represents the gain on the settlement of a long-term gas supply agreement at Generation.

(17)

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, 2018, 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 PECO, BGE and PHI, reflects increased revenue as a result of rate increases.

(18)	Primarily reflects the acquisition of the FitzPatrick nuclear facility and decreased nuclear outage days, partially offset by the permanent cease of generation operations at Oyster Creek.

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

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

(21)	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.

(22)

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.

(23)

For Generation, primarily reflects decreased spending related to energy efficiency projects, decreased costs related to the sale of Generation's electrical contracting business, the absence of EGTP costs resulting from its deconsolidation in the fourth quarter of 2017 and the permanent cease of generation operations at Oyster Creek. For ComEd, primarily reflects increased variable compensation costs. Additionally, for all utilities, reflects increased mutual assistance expenses.

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

(25)

For Generation, primarily reflects the impact of a supplemental NEIL insurance distribution and the absence of EGTP costs resulting from its deconsolidation in the fourth quarter of 2017. 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 and BGE, primarily reflects increased storm costs related to the March 2018 winter storms. Additionally, for all utilities, reflects increased mutual assistance expenses.

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(26)

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

(27)	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.

(28)

For Generation, primarily reflects a reduction in renewable tax credits, partially offset by one-time tax adjustments. For ComEd, reflects increased income tax expense due to an increase in the Illinois income tax rate in July of 2017. For PECO, primarily reflects an increase in the repairs tax deduction. For ComEd, BGE and PHI, also reflects the absence of the 2017 impairments of certain transmission-related income tax regulatory assets.

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

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

(31)	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).

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(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 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 funds 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, costs related to the PHI and FitzPatrick acquisitions, offset at PHI by the anticipated recovery of previously incurred PHI acquisition costs and in 2018, costs related to the PHI acquisition.

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

(h)	Adjustment to exclude charges to earnings related to the impairment of the EGTP assets held for sale and PHI District of Columbia sponsorship intangible asset. 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 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 severance and reorganization costs related to a cost management program.

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

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

(m)	Adjustment to exclude the gain recorded upon deconsolidation of EGTP's net liabilities, which included the previously impaired assets and related debt, as a result of the November 2017 bankruptcy filing.

(n)	Adjustment to exclude the reversal of previously accrued vacation expenses as a result of a change in Exelon's vacation vesting policy.

(o)

Adjustments to exclude one-time non-cash impacts associated with remeasurements of deferred income taxes as a result of TCJA (including impacts on pension obligations contained within Other), changes in the Illinois and District of Columbia statutory tax rates 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.

(p)	Adjustment to exclude the 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 funds at CENG.

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

(r)	Adjustment to exclude the gain on the settlement of a long-term gas supply agreement.

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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 one-time non-cash impacts associated with remeasurements of deferred income taxes as a result of TCJA and a change in the Illinois statutory tax rate.

(d)	Adjustments to exclude income tax and interest expenses 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.

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(a)	Results reported in accordance with accounting principles generally accepted in the United States (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 one-time non-cash impacts associated with remeasurements of deferred income taxes as a result of TCJA.

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

(e)	Adjustment to exclude the reversal of previously accrued vacation expenses as a result of a change in Exelon's vacation vesting policy.

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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 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.

(d)	Adjustment to exclude one-time non-cash impacts associated with remeasurements of deferred income taxes as a result of TCJA.

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

(f)	Adjustment to exclude the reversal of previously accrued vacation expenses as a result of a change in Exelon's vacation vesting policy.

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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 an increase at Pepco related primarily to asbestos identified at its Buzzard Point property.

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

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

(f)	Adjustment to exclude the impairment of the District of Columbia sponsorship intangible asset.

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(g)	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 2017 by the anticipated recovery of previously incurred PHI acquisition costs.

(h)	Adjustment to exclude in 2017, one-time non-cash impacts associated with remeasurements of deferred income taxes as a result of TCJA. In 2018, the remeasurement of deferred income taxes as a result of TCJA and changes in forecasted apportionment.

(i)	Adjustment to exclude the reversal of previously accrued vacation expenses as a result of a change in Exelon's vacation vesting policy.

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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)	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)	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 in 2017, 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.

(g)

Adjustment to exclude 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 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.

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

(i)	Adjustment to exclude the gain on the settlement of a long-term gas supply agreement at Generation.

(j)	Adjustment to exclude adjustments to income tax, penalties and interest expenses 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, one-time non-cash impacts associated with remeasurements of deferred income taxes as a result of TCJA (including impacts on pension obligations contained within Other), changes in the Illinois and District of Columbia statutory tax rates 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.

(l)	Adjustment to exclude costs related to impairments at corporate.

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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 December 31, 2018 and 2017, respectively, and $27 million and $15 million for the twelve months ended December 31, 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 for both the three months ended December 31, 2018 and 2017, and $7 million and $6 million for the twelve months ended December 31, 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 months ended December 31, 2018 and 2017, and $1 million for both the twelve months ended December 31, 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 $3 million and $1 million for the three months ended December 31, 2018 and 2017, respectively, and $8 million and $5 million for the twelve months ended December 31, 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 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 $8 million and $4 million for the three months ended December 31, 2018 and 2017, respectively, and $21 million and $11 million for the twelve months ended December 31, 2018 and 2017, respectively.

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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, 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 $2 million for three months ended December 31, 2018 and 2017, respectively, and $6 million for both twelve months ended December 31, 2018 and 2017.

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

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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, revenue also reflects the cost of energy and transmission.

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

(d)	Includes operating revenues from affiliates totaling $2 million for both three months ended December 31, 2018 and 2017 and $8 million for both twelve months ended December 31, 2018 and 2017.

(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, 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 three months ended December 31, 2018 and 2017, and $3 million and $2 million for the twelve months ended December 31, 2018 and 2017, respectively.

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