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(a)	The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was immaterial for the three months ended March 31, 2019 and approximately 5 million for the three months ended March 31, 2018.

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(a)

Exelon’s consolidated assets include $9,546 million and $9,667 million at March 31, 2019 and December 31, 2018, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $3,572 million and $3,548 million at March 31, 2019 and December 31, 2018, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 2 — Variable Interest Entities for additional information.

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(a)

Generation’s consolidated assets include $9,515 million and $9,634 million at March 31, 2019 and December 31, 2018, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $3,508 million and $3,480 million at March 31, 2019 and December 31, 2018, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 2 — Variable Interest Entities for additional information.

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(a)

PHI’s consolidated total assets include $31 million and $33 million at March 31, 2019 and December 31, 2018, respectively, of PHI's consolidated VIE that can only be used to settle the liabilities of the VIE. PHI’s consolidated total liabilities include $64 million and $69 million at March 31, 2019 and December 31, 2018, respectively, of PHI's consolidated VIE for which the VIE creditors do not have recourse to PHI. See Note 2 — Variable Interest Entities for additional information.

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(a)

ACE’s consolidated total assets include $22 million and $23 million at March 31, 2019 and December 31, 2018, respectively, of ACE's consolidated VIE that can only be used to settle the liabilities of the VIE. ACE’s consolidated total liabilities include $54 million and $59 million at March 31, 2019 and December 31, 2018, respectively, of ACE's consolidated VIE for which the VIE creditors do not have recourse to ACE. See Note 2 — Variable Interest Entities for additional information.

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•	a "package of three" expedients that must be taken together and allow entities to (1) not reassess whether existing contracts contain leases, (2) carryforward the existing lease classification, and (3) not reassess initial direct costs associated with existing leases,

•	an implementation expedient which allows the requirements of the standard in the period of adoption with no restatement of prior periods, and

•	a land easement expedient which allows entities to not evaluate land easements under the new standard at adoption if they were not previously accounted for as leases.

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•	energy related companies involved in distributed generation, backup generation and energy development

•	renewable energy project companies formed by Generation to build, own and operate renewable power facilities

•	certain retail power and gas companies for which Generation is the sole supplier of energy, and

•	CENG.

•	ATF, a special purpose entity formed by ACE for the purpose of securitizing authorized portions of ACE’s recoverable stranded costs through the issuance and sale of transition bonds.

•	Generation provides operating and capital funding to the renewable energy project companies and there is limited recourse to Generation related to certain renewable energy project companies.

•	Generation provides approximately $32 million in credit support for the retail power and gas companies for which Generation is the sole supplier of energy.

•	Exelon and Generation, where indicated, provide the following support to CENG:

•

under PPAs with CENG, Generation purchased or will purchase 50.01% of the available output generated by the CENG nuclear plants not subject to other contractual agreements from January 2015 through the end of the operating life of each respective plant. However, pursuant to amendments dated March 31, 2015, the energy obligations under the Ginna Nuclear Power Plant (Ginna) PPAs were suspended during the term of the RSSA, through the end of March 31, 2017. With the expiration of the RSSA, the PPA was reinstated beginning April 1, 2017,

•	Generation provided a $400 million loan to CENG. The loan balance was fully repaid by CENG in January 2019.

•

Generation executed an Indemnity Agreement pursuant to which Generation agreed to indemnify EDF against third-party claims that may arise from any future nuclear incident (as defined in the Price-Anderson Act) in connection with the CENG nuclear plants or their operations. Exelon guarantees Generation’s obligations under this Indemnity Agreement. (See Note 16 — Commitments and Contingencies for additional information),

•	Generation and EDF share in the $688 million of contingent payment obligations for the payment of contingent retrospective premium adjustments for the nuclear liability insurance, and

•	Exelon has executed an agreement to provide up to $245 million to support the operations of CENG as well as a $165 million guarantee of CENG’s cash pooling agreement with its subsidiaries.

•	In the case of ATF, proceeds from the sale of each series of transition bonds by ATF were transferred to ACE in exchange for the transfer by ACE to ATF of the right to collect a non-bypassable Transition Bond Charge from ACE customers pursuant to bondable stranded costs rate orders issued by the

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•	the assets of the VIEs are restricted and can only be used to settle obligations of the respective VIE;

•	Exelon, Generation, PHI and ACE did not provide any additional material financial support to the VIEs;

•	Exelon, Generation, PHI and ACE did not have any material contractual commitments or obligations to provide financial support to the VIEs; and

•	the creditors of the VIEs did not have recourse to Exelon’s, Generation’s, PHI's or ACE's general credit.

(a)	Includes certain purchase accounting adjustments not pushed down to the ACE standalone entity.

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(a)	Includes certain purchase accounting adjustments not pushed down to the ACE standalone entity.

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•	Energy purchase and sale agreements with VIEs for which Generation has concluded that consolidation is not required.

•	Asset sale agreement with ZionSolutions, LLC and EnergySolutions, Inc. in which Generation has a variable interest but has concluded that consolidation is not required.

•	Equity investments in distributed energy companies for which Generation has concluded that consolidation is not required.

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(a)	These items represent amounts in the unconsolidated VIE balance sheets, not in Exelon’s or Generation’s Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs.

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(a)	Excludes $3 million, $2 million, $1 million and $1 million of sublease income recorded at Exelon, Generation, PHI and DPL.

(a)	Exelon's and Generation's operating ROU assets and lease liabilities include $631 million and $778 million, respectively, related to contracted generation.

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(a)	Includes amounts related to shared use land arrangements.

(b)	Excludes Generation’s contingent operating lease payments associated with contracted generation.

(c)

Amounts related to certain real estate leases and railroad licenses effectively have indefinite payment periods. As a result, ComEd, PECO, BGE and DPL have excluded these payments from the remaining years as such amounts would not be meaningful. ComEd's, PECO’s, BGE’s and DPL's average annual obligation for these arrangements, included in each of the years 2019 - 2023, was $3 million, $5 million, $1 million and $1 million respectively. Also includes amounts related to shared use land arrangements.

(d)	Includes all future lease payments on a 99-year real estate lease that expires in 2106.

(e)	The BGE column above includes minimum future lease payments associated with a 6-year lease for the Baltimore City conduit system that became effective during the fourth quarter of 2016. BGE's total commitments under the lease agreement are $26 million, $28 million, $28 million and $14 million related to years 2019 - 2022, respectively.

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(a)	Requested and approved increases are before New Jersey sales and use tax.

(a)

Reflects an increase of $57 million for the initial revenue requirement for 2019 and a decrease of $63 million related to the annual reconciliation for 2018. The revenue requirement for 2019 and annual reconciliation for 2018 provides for a weighted average debt and equity return on distribution rate base of 6.53%. See Note 4 — Regulatory Matters of the Exelon 2018 Form 10-K for additional information on ComEd's distribution formula rate filings.

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(a)	Reflects ComEd's unrecognized equity returns earned for ratemaking purposes on its electric distribution formula rate regulatory assets.

(b)	BGE's authorized amounts capitalized for ratemaking purposes primarily relate to earnings on shareholders' investment on its AMI programs.

(c)	Pepco's and DPL's authorized amounts capitalized for ratemaking purposes relate to earnings on shareholders' investment on their respective AMI Programs and Energy Efficiency and Demand Response Programs. The earnings on energy efficiency are on Pepco DC and DPL DE programs only.

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(a)	Reflects incremental accelerated depreciation and amortization for TMI for the three months ended March 31, 2019. Reflects incremental accelerated depreciation for TMI and Oyster Creek for the three months ended March 31, 2018. The Oyster Creek amounts are from February 2, 2018 through March 31, 2018.

(b)	Reflects incremental accelerated depreciation of plant assets, including any ARC.

(c)	In 2019, primarily reflects decrease to estimated decommissioning costs for TMI. See Note 13 — Nuclear Decommissioning for additional information on the first quarter 2019 TMI ARO update. In 2018, primarily reflects materials and supplies inventory reserve adjustments, employee related costs and CWIP impairments.

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(a)

Includes unamortized debt issuance costs which are not fair valued of $216 million, $49 million, $67 million, $22 million, $18 million, $14 million, $33 million, $12 million and $6 million for Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, as of March 31, 2019. Includes unamortized debt issuance costs which are not fair valued of $216 million, $51 million, $63 million, $23 million, $18 million, $14 million, $34 million, $12 million and $7 million for Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, as of December 31, 2018.

(b)	Includes unamortized debt issuance costs which are not fair valued of $1 million and $1 million for Exelon and ComEd, respectively, as of March 31, 2019. Includes unamortized debt issuance costs which are not fair valued of less than $1 million and $1 million for Exelon and ComEd, respectively, as of December 31, 2018.

•	Level 1 — quoted prices (unadjusted) in active markets for identical assets or liabilities that the Registrants have the ability to liquidate as of the reporting date.

•	Level 2 — inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data.

•	Level 3 — unobservable inputs, such as internally developed pricing models or third-party valuations for the asset or liability due to little or no market activity for the asset or liability.

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(a)

Generation excludes cash of $270 million and $283 million at March 31, 2019 and December 31, 2018 and restricted cash of $36 million and $39 million at March 31, 2019 and December 31, 2018.  Exelon excludes cash of $426 million and $458 million at March 31, 2019 and December 31, 2018 and restricted cash of $71 million and $80 million at March 31, 2019 and December 31, 2018 and includes long-term restricted cash of $211 million and $185 million at March 31, 2019 and December 31, 2018, which is reported in Other deferred debits in the Consolidated Balance Sheets.

(b)	Includes $43 million and $50 million of cash received from outstanding repurchase agreements at March 31, 2019 and December 31, 2018, respectively, and is offset by an obligation to repay upon settlement of the agreement as discussed in (d) below.

(c)

Includes derivative instruments of $7 million and $44 million, which have a total notional amount of $1,223 million and $1,432 million at March 31, 2019 and December 31, 2018, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do not represent the amount of Exelon and Generation's exposure to credit or market loss.

(d)

Excludes net liabilities of $94 million and $130 million at March 31, 2019 and December 31, 2018, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, repurchase agreement obligations, and payables related to pending securities purchases. The repurchase agreements are generally short-term in nature with durations generally of 30 days or less.

(e)	The amount of unrealized gains/(losses) at Generation totaled less than $1 million for the three months ended March 31, 2019 and March 31, 2018, respectively. The amount of unrealized gains/(losses) at Exelon totaled $1 million for the three months ended March 31, 2019 and March 31, 2018, respectively.

(f)

Collateral posted/(received) from counterparties totaled $52 million, $283 million and $157 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of March 31, 2019. Collateral posted/(received) from counterparties, net of collateral paid to counterparties, totaled $57 million, $224 million and $76 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2018.

(g)	Of the collateral posted/(received), $(33) million and $(94) million represents variation margin on the exchanges as of March 31, 2019 and December 31, 2018, respectively.

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(a)

ComEd excludes cash of $69 million and $93 million at March 31, 2019 and December 31, 2018 and restricted cash of $15 million and $28 million at March 31, 2019 and December 31, 2018 and includes long-term restricted cash of $193 million and $166 million at March 31, 2019 and December 31, 2018, which is reported in Other deferred debits in the Consolidated Balance Sheets.  PECO excludes cash of $31 million and $24 million at March 31, 2019 and December 31, 2018.  BGE excludes cash of $12 million and $7 million at March 31, 2019 and December 31, 2018 and restricted cash of $1 million and $2 million at March 31, 2019 and December 31, 2018.

(b)	The amount of unrealized gains/(losses) at ComEd, PECO and BGE totaled less than $1 million for the three months ended March 31, 2019 and March 31, 2018.

(c)	The Level 3 balance consists of the current and noncurrent liability of $27 million and $213 million, respectively, at March 31, 2019, and $26 million and $223 million, respectively, at December 31, 2018, related to floating-to-fixed energy swap contracts with unaffiliated suppliers.

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(a)

PHI excludes cash of $29 million and $39 million at March 31, 2019 and December 31, 2018, respectively, and includes long-term restricted cash of $19 million at both March 31, 2019 and December 31, 2018, which is reported in Other deferred debits in the Consolidated Balance Sheets.  Pepco excludes cash of $11 million and $15 million at March 31, 2019 and December 31, 2018, respectively. DPL excludes cash of $6 million and $8 million at March 31, 2019 and December 31, 2018, respectively. ACE excludes cash of $7 million at both March 31, 2019 and December 31, 2018, and includes long-term restricted cash of $19 million at both March 31, 2019 and December 31, 2018, which is reported in Other deferred debits in the Consolidated Balance Sheets.

(b)	The amount of unrealized gains/(losses) at PHI totaled less than $1 million for both the three months ended March 31, 2019 and 2018. The amount of unrealized gains/(losses) at Pepco totaled less than $1 million for both the three months ended March 31, 2019 and 2018.

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(a)	Includes a reduction for the reclassification of $80 million and $72 million of realized gains due to the settlement of derivative contracts for the three months ended March 31, 2019 and 2018, respectively.

(b)

Includes $14 million of decreases in fair value and an increase for realized losses due to settlements of $5 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended March 31, 2019. Includes $17 million of increases in fair value and an increase for realized losses due to settlements of $6 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended March 31, 2018.

(c)	The amounts represented are life insurance contracts at Pepco.

(d)	Transfers into and out of Level 3 generally occur when the contract tenor becomes less and more observable respectively, primarily due to changes in market liquidity or assumptions for certain commodity contracts.

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(a)	The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions.

(b)	The fair values do not include cash collateral posted on level three positions of $157 million and $76 million as of March 31, 2019 and December 31, 2018, respectively.

(c)	Quoted forward natural gas rates are utilized to project the forward power curve for the delivery of energy at specified future dates. The natural gas curve is extrapolated beyond its observable period to the end of the contract’s delivery.

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(a)

Exelon and Generation net all available amounts allowed under the derivative authoritative guidance in the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, letters of credit and other forms of non-cash collateral. These are not reflected in the table above.

(b)	Current and noncurrent assets are shown net of collateral of $152 million and $63 million, respectively, and current and noncurrent liabilities are shown net of collateral of $177 million and $100 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $492 million at March 31, 2019.

(c)	Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.

(d)	Of the collateral posted/(received), $(33) million represents variation margin on the exchanges.

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(a)

Exelon and Generation net all available amounts allowed under the derivative authoritative guidance in the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, and letters of credit and other forms of non-cash collateral. These are not reflected in the table above.

(b)	Current and noncurrent assets are shown net of collateral of $121 million and $51 million, respectively, and current and noncurrent liabilities are shown net of collateral of $125 million and $60 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $357 million at December 31, 2018.

(c)	Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.

(d)	Of the collateral posted/(received), $(94) million represents variation margin on the exchanges.

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(a)	As of March 31, 2019, credit collateral held from counterparties where Generation had credit exposure included $37 million of cash and $19 million of letters of credit. The credit collateral does not include non-liquid collateral.

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(a)	Amount represents the gross fair value of out-of-the-money derivative contracts containing credit-risk related contingent features ignoring the effects of master netting agreements.

(b)	Amount represents the offsetting fair value of in-the-money derivative contracts under legally enforceable master netting agreements with the same counterparty, which reduces the amount of any liability for which a Registrant could potentially be required to post collateral.

(c)	Amount represents the net fair value of out-of-the-money derivative contracts containing credit-risk related contingent features after considering the mitigating effects of offsetting positions under master netting arrangements and reflects the actual net liability upon which any potential contingent collateral obligations would be based.

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(a)	Includes $41 million and $22 million as the current portion of the ARO at March 31, 2019 and December 31, 2018, respectively, which is included in Other current liabilities in Exelon’s and Generation’s Consolidated Balance Sheets.

(b)	Includes $760 million and $772 million of ARO related to Oyster Creek which is classified as Liabilities held for sale in Exelon's and Generation's Consolidated Balance Sheets at March 31, 2019 and December 31, 2018, respectively. See Note 3 — Mergers, Acquisitions and Dispositions for additional information.

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(a)	All amounts are net of tax and noncontrolling interests. Amounts in parenthesis represent a decrease in AOCI.

(b)	See next tables for details about these reclassifications.

(c)

Exelon prospectively adopted the new standard Recognition and Measurement of Financial Assets and Liabilities. The standard was adopted as of January 1, 2018, which resulted in an increase to Retained earnings and Accumulated other comprehensive loss of $10 million and $3 million for Exelon and Generation, respectively. The amounts reclassified related to Rabbi Trusts. See Note 1 — Significant Accounting Policies of the Exelon 2018 Form 10-K for additional information.

(d)

Exelon early adopted the new standard Reclassification of Certain Tax Effects from AOCI. The standard was adopted retrospectively as of December 31, 2017, which resulted in an increase to Exelon’s Retained earnings and Accumulated other comprehensive loss of $539 million, primarily related to deferred income taxes associated with Exelon’s pension and OPEB obligations. See Note 1 — Significant Accounting Policies of the Exelon 2018 Form 10-K for additional information.

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(a)	Amounts in parenthesis represent a decrease in net income.

(b)	This AOCI component is included in the computation of net periodic pension and OPEB cost. See Note 14 — Retirement Benefits for additional information.

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(a)	Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.

(b)

Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $68 million, $22 million of which is a guarantee by Pepco, $28 million by DPL and $17 million by ACE. The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.

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•	ComEd has identified 42 sites, 21 of which have been remediated and approved by the Illinois EPA or the U.S. EPA and 21 that are currently under some degree of active study and/or remediation. ComEd expects the majority of the remediation at these sites to continue through at least 2023.

•	PECO has identified 26 sites, 17 of which have been remediated in accordance with applicable PA DEP regulatory requirements and 9 that are currently under some degree of active study and/or remediation. PECO expects the majority of the remediation at these sites to continue through at least 2022.

•	BGE has identified 13 sites, 9 of which have been remediated and approved by the MDE and 4 that require some level of remediation and/or ongoing activity. BGE expects the majority of the remediation at these sites to continue through at least 2019.

•	DPL has identified 3 sites, for 2 of which remediation has been completed and approved by the MDE or the Delaware Department of Natural Resources and Environmental Control. The remaining site is under study and the required cost at the site is not expected to be material.

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(a)	Realized income includes interest, dividends and realized gains and losses on sales of NDT fund investments.

(b)	Net realized and unrealized gains (losses) related to Generation’s NDT funds associated with Regulatory Agreement Units are included in Regulatory liabilities in Exelon’s Consolidated Balance Sheets and Noncurrent payables to affiliates in Generation’s Consolidated Balance Sheets.

(c)	Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units, including the elimination of net income taxes related to all NDT fund activity for those units. See Note 15 — Asset Retirement Obligations of the Exelon 2018 Form 10-K for additional information regarding the accounting for nuclear decommissioning.

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(a)	Included in Depreciation and amortization in the Registrants' Consolidated Statements of Operations and Comprehensive Income.

(b)	Included in Operating revenues or Purchased power and fuel expense in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.

(c)	Included in Purchased power and fuel expense in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.

(d)	Included in Operating and maintenance expense in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.

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(a)

Includes the elimination of decommissioning-related activity for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income and income taxes related to all NDT fund activity for these units. See Note 15 — Asset Retirement Obligations of the Exelon 2018 Form 10-K for additional information regarding the accounting for nuclear decommissioning.

(b)	Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded in Operating revenues and expenses.

(c)	Reflects the change in ComEd's distribution and energy efficiency formula rates. See Note 6 — Regulatory Matters for additional information.

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(a)	Includes accumulated amortization of nuclear fuel in the reactor core of $3,040 million.

(b)	Includes accumulated amortization of nuclear fuel in the reactor core of $2,969 million.

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(a)	For ComEd, BGE, Pepco and DPL, reflects the incremental allowance for uncollectible accounts recorded, which is in addition to the purchase discount. For ComEd, the incremental uncollectible accounts expense is recovered through a rate rider. BGE, Pepco and DPL recover actual write-offs which are reflected in the POR discount rate.

•	Mid-Atlantic represents operations in the eastern half of PJM, which includes New Jersey, Maryland, Virginia, West Virginia, Delaware, the District of Columbia and parts of Pennsylvania and North Carolina.

•	Midwest represents operations in the western half of PJM and the United States footprint of MISO, excluding MISO’s Southern Region.

•	New York represents operations within ISO-NY.

•	ERCOT represents operations within Electric Reliability Council of Texas.

•	Other Power Regions:

•	New England represents the operations within ISO-NE.

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•	South represents operations in the FRCC, MISO’s Southern Region, and the remaining portions of the SERC not included within MISO or PJM.

•	West represents operations in the WECC, which includes California ISO.

•	Canada represents operations across the entire country of Canada and includes AESO, OIESO and the Canadian portion of MISO.

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(a)

Intersegment revenues for Generation in 2019 include revenue from sales to PECO of $45 million, sales to BGE of $76 million, sales to Pepco of $70 million, sales to DPL of $23 million and sales to ACE of $8 million in the Mid-Atlantic region, and sales to ComEd of $94 million in the Midwest region, which eliminate upon consolidation. Intersegment revenues for Generation in 2018 include revenue from sales to PECO of $37 million, sales to BGE of $65 million, sales to Pepco of $52 million, sales to DPL of $46 million and sales to ACE of $6 million in the Mid-Atlantic region, and sales to ComEd of $194 million in the Midwest region, which eliminate upon consolidation.

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

(c)	Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 17 — Supplemental Financial Information for additional information on total utility taxes.

(d)

Intersegment revenues exclude sales to unconsolidated affiliates. The intersegment profit associated with Generation’s sale of certain products and services by and between Exelon’s segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income.

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(a)	Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 17 — Supplemental Financial Information for additional information on total utility taxes.

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

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(a)	Includes all wholesale and retail electric sales to third parties and affiliated sales to the Utility Registrants.

(b)	Includes revenues from derivatives and leases.

(c)	Other represents activities not allocated to a region. See text above for a description of included activities. Includes unrealized mark-to-market losses of $52 million and $98 million in 2019 and 2018, respectively, and elimination of intersegment revenues.

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(a)	Includes purchases and sales from/to third parties and affiliated sales to the Utility Registrants.

(b)

Other represents activities not allocated to a region. See text above for a description of included activities. Includes unrealized mark-to-market losses of $28 million and $266 million in 2019 and 2018, respectively, accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 8 — Early Plant Retirements of $5 million and $15 million decrease to RNF in 2019 and 2018, respectively, and the elimination of intersegment RNF.

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

(b)	Includes operating revenues from affiliates of $4 million, $1 million, $2 million, $3 million, $2 million, $2 million and $1 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2019 and $14 million, $2 million, $2 million, $4 million $2 million, $2 million and 1 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2018.

(c)	Includes revenues from off-system natural gas sales.

(d)	Includes operating revenues from affiliates of less than $1 million and $4 million at PECO and BGE, respectively, in 2019 and 2018.

(e)	Includes late payment charge revenues.

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Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations

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

•	Net unrealized gains on NDT funds in 2019 compared to losses in 2018;

•	Decreased mark-to-market losses;

•	A benefit associated with the remeasurement of the TMI ARO;

•	Increased capacity prices;

•	Regulatory rate increases at PECO, BGE, Pepco and DPL; and

•	Lower storms costs at PECO and BGE.

•	Lower realized energy prices and

•	The absence of the revenue recognized in the first quarter 2018 related to ZECs generated in Illinois from June through December 2017.

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(a)	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.

(b)

In 2018, primarily reflects accelerated depreciation and amortization expenses and one-time charges associated with Generation's decision to early retire the Oyster Creek nuclear facility and accelerated depreciation and amortization expenses associated with the 2017 decision to early retire the TMI nuclear facility, partially offset by a gain associated with Generation's sale of its electrical contracting business. In 2019, primarily reflects accelerated depreciation and amortization expenses associated with Generation's previous decision to early retire the TMI nuclear facility and a benefit associated with a remeasurement of the TMI ARO.

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

(d)	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.

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•	The Utility Registrants provide a foundation for steadily growing earnings, which translates to a stable currency in our stock.

•	Generation’s competitive businesses provide free cash flow to invest primarily in the utilities and in long-term, contracted assets and to reduce debt.

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•	Net unrealized gains on NDT funds in 2019 compared to losses in 2018;

•	Decreased mark-to-market losses;

•	A benefit associated with the remeasurement of the TMI ARO; and

•	Increased capacity prices.

•	Lower realized energy prices and

•	The absence of the revenues recognized in the first quarter 2018 related to ZECs generated in Illinois from June through December 2017.

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(a)	Includes results of transactions with PECO, BGE, Pepco, DPL and ACE.

(b)	Includes results of transactions with ComEd.

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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 and BGE in the Mid-Atlantic region, affiliate sales to ComEd in the Midwest region and affiliate sales to Pepco, DPL and ACE in the Mid-Atlantic region.

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(a)	See Note 10 — Derivative Financial Instruments for additional information on mark-to-market losses.

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(a)	Primarily reflects decreased costs related to the permanent cease of generation operations at Oyster Creek in the third quarter of 2018.

(b)	Primarily reflects the absence of a supplemental NEIL insurance distribution received in the first quarter 2018.

(c)	Primarily due to the benefit recorded in 2019 for the remeasurement of the TMI ARO and the increase to materials and supplies inventory reserves in 2018 associated with Generation’s decision to early retire the Oyster Creek nuclear facility.

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(a)	Reflects absence of mutual assistance expenses. An equal and offsetting decrease has been recognized in Operating revenues for the period presented.

(b)	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.

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(a)	Reflects ongoing capital expenditures and higher depreciation rates effective January 2019.

(b)	Includes amortization of ComEd's energy efficiency formula rate regulatory asset.

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(a)	Reflects delivery volumes from customers purchasing electricity directly from PECO and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges.

(b)	Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.

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(a)	Reflects delivery volumes 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.

(a)	Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.

(a)	Reflects decreased storm costs due to the March 2018 winter storms.

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(a)	Depreciation and amortization increased primarily due to ongoing capital expenditures.

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(a)	Reflects decreased storm costs due to the March 2018 winter storms.

(a)	Depreciation and amortization increased primarily due to ongoing capital expenditures.

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(a)	Primarily includes eliminating and consolidating adjustments, PHI's corporate operations, shared service entities and other financing and investing activities.

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(a)	Depreciation and amortization increased primarily due to ongoing capital expenditures.

(b)	Depreciation and amortization expenses for regulatory required programs are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues.

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(a)	Reflects delivery volumes from customers purchasing electricity directly from DPL and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges.

(b)	Reflects the change in delivery volumes assuming normalized weather based on the historical 20-year average.

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(a)	Reflects delivery volumes 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.

(b)	Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.

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(a)	Depreciation and amortization increased primarily due to ongoing capital expenditures.

(b)	Depreciation and amortization expenses for regulatory required programs are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues.

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(a)	Reflects delivery volumes from customers purchasing electricity directly from ACE and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges.

(b)	Reflects the change in delivery volumes assuming normalized weather based on the historical 20-year average.

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(a)	ACE is allowed to recover from or refund to customers the difference between its annual uncollectible accounts expense and the amounts collected in rates annually through a rider mechanism. An equal and offsetting amount has been recognized in Operating revenues.

(a)	Depreciation and amortization increased primarily due to ongoing capital expenditures.

(b)	Depreciation and amortization expenses for regulatory required programs are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues.

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•	See Note 17 — Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements and the Registrants’ Consolidated Statement of Cash Flows for additional information on non-cash operating activity.

•	Depending upon whether Generation is in a net mark-to-market liability or asset position, collateral may be required to be posted with or collected from its counterparties. In addition, the collateral posting and collection requirements differ depending on whether the transactions are on an exchange or in the OTC markets.

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•	Variances in capital expenditures are primarily due to the timing of cash expenditures for capital projects. Refer to Liquidity and Capital Resources of the Exelon 2018 Form 10-K for additional information on projected capital expenditure spending.

•	During the three months ended March 31, 2018, Exelon and Generation had proceeds of $79 million relating to the sale of its interest in an electrical contracting business.

•	Changes in short-term borrowings, net, is driven by repayments on and issuances of notes due in less than 90 days. Refer to 11 — Debt and Credit Agreements of the Consolidated Financial Statements for additional information on short-term borrowings.

•	Long-term debt, net, varies due to debt issuances and redemptions each year. Refer to 11 — Debt and Credit Agreements of the Consolidated Financial Statements for additional information on debt issuances. Refer to debt redemptions tables below for more information.

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•	Changes in intercompany money pool are driven by short-term borrowing needs. Refer to more information regarding the intercompany money pool below.

•

Exelon’s ability to pay dividends on its common stock depends on the receipt of dividends paid by its operating subsidiaries. The payments of dividends to Exelon by its subsidiaries in turn depend on their results of operations and cash flows and other items affecting retained earnings. See Note 16 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements of the Exelon 2018 Form 10-K for additional information on dividend restrictions. See below for quarterly dividends declared.

(a)	Exelon's Board of Directors approved an updated dividend policy providing an increase of 5% each year for the period covering 2018 through 2020.

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(a)	Represents incremental collateral related to natural gas procurement contracts.

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(a)	Generation currently has blanket financing authority it received from FERC in connection with its market-based rate authority.

(b)	ComEd had $440 million available in long-term debt refinancing authority and $693 million available in new money long-term debt financing authority from the ICC as of March 31, 2019 and has an expiration date of June 1, 2019 and August 1, 2021, respectively.

(c)	On April 18, 2019, ACE received approval from the NJBPU for $350 million long-term financing authority, expiring on December 31, 2020.

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(a)	Amounts are shown net of collateral paid to and received from counterparties.

(b)

For ComEd, the changes in fair value are recorded as a change in regulatory assets or liabilities. As of March 31, 2019, ComEd recorded a regulatory liability of $240 million related to its mark-to-market derivative liabilities with Generation and unaffiliated suppliers. For the three months ended March 31, 2019, ComEd also recorded $9 million of decreases in fair value and an increase for realized losses due to settlements of $80 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers.

(c)	Includes derivative contracts acquired or sold by Generation through upfront payments or receipts of cash, excluding option premiums, and the associated amortizations

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(a)	Mark-to-market gains and losses on other economic hedge and trading derivative contracts that are recorded in results of operations.

(b)	Amounts are shown net of collateral paid to and received from counterparties (and offset against mark-to-market assets and liabilities) of $492 million at March 31, 2019.

(c)	Includes ComEd’s net assets (liabilities) associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.

(a)	Mark-to-market gains and losses on other economic hedge and trading derivative contracts that are recorded in the results of operations.

(b)	Amounts are shown net of collateral paid to and received from counterparties (and offset against mark-to-market assets and liabilities) of $492 million at March 31, 2019.

(a)	Represents ComEd’s net liabilities associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.

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(a)	As of March 31, 2019, credit collateral held from counterparties where Generation had credit exposure included $37 million of cash and $19 million of letters of credit.

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