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(a)

Exelon’s consolidated assets include $9,727 million and $9,597 million at March 31, 2018 and December 31, 2017, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $3,556 million and $3,618 million at March 31, 2018 and December 31, 2017, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 3 — Variable Interest Entities.

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(a)

Generation’s consolidated assets include $9,688 million and $9,556 million at March 31, 2018 and December 31, 2017, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $3,461 million and $3,516 million at March 31, 2018 and December 31, 2017, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 3 — Variable Interest Entities.

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(a)

PHI’s consolidated total assets include $39 million and $41 million at March 31, 2018 and December 31, 2017, respectively, of PHI's consolidated VIE that can only be used to settle the liabilities of the VIE. PHI’s consolidated total liabilities include $95 million and $102 million at March 31, 2018 and December 31, 2017, respectively, of PHI's consolidated VIE for which the VIE creditors do not have recourse to PHI. See Note 3 — Variable Interest Entities.

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(a)

ACE’s consolidated total assets include $27 million and $29 million at March 31, 2018 and December 31, 2017, respectively, of ACE's consolidated VIE that can only be used to settle the liabilities of the VIE. ACE’s consolidated total liabilities include $83 million and $90 million at March 31, 2018 and December 31, 2017, respectively, of ACE's consolidated VIE for which the VIE creditors do not have recourse to ACE. See Note 3 — Variable Interest Entities.

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•	Statement of Cash Flows: Classification of Restricted Cash. The Registrants applied the new guidance using the full retrospective method and, accordingly, have recasted the presentation of restricted cash in their Consolidated Statements of Cash Flows in the prior periods presented. See Note 18 — Supplemental Financial Information for further information.

•

Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income.  Exelon early adopted and retrospectively applied the new guidance to when the effects of the TCJA were recognized and, accordingly, recasted its December 31, 2017 AOCI and retained earnings in its Consolidated Balance Sheet and Consolidated Statement of Changes in Shareholders' Equity.  Exelon's accounting policy is to release the stranded tax effects from AOCI related to its pension and OPEB plans under a portfolio (or aggregate) approach as an entire pension or OPEB plan is liquidated or terminated. See Note 2 — New Accounting Standards for further information.

•

Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. Exelon applied this guidance retrospectively for the presentation of the service and other non-service costs components of net benefit cost and, accordingly, have recasted those amounts, which were not material, in its Consolidated Statement of Operations and Comprehensive Income in prior periods presented. As part of the adoption, Exelon elected the practical expedient that permits an employer to use the amounts disclosed in its pension and other postretirement benefit plan note for the comparative periods as the estimation basis for applying the retrospective presentation requirements. See Note 14 — Retirement Benefits for further information.

•	Revenue from Contracts with Customers. The Registrants applied the new guidance using the full retrospective method and, accordingly, have recasted certain amounts in their Consolidated

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•	Developing a complete lease inventory and abstracting the required data attributes into a lease accounting system that supports the Registrants' lease portfolios and integrates with existing systems.

•	Evaluating the transition practical expedients available under the guidance.

•	Identifying, assessing and documenting technical accounting issues, policy considerations and financial reporting implications which includes completing a detailed contract assessment for a sample of transactions to determine whether they are leases under the new guidance.

•	Identifying and implementing changes to processes and controls to ensure all impacts of the new guidance are effectively addressed.

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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 operating and capital funding to one of the energy related companies involved in backup generation.

•	Generation provides approximately $30 million in credit support for the retail power and gas companies for which Generation is the sole supplier of energy.

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•	Exelon and Generation, where indicated, provide the following support to CENG (see Note 26 — Related Party Transactions of the Exelon 2017 Form 10-K for additional information regarding Generation's and Exelon’s transactions with CENG):

•

under power purchase agreements 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 Reliability Support Services Agreement (RSSA), through the end of March 31, 2017. With the expiration of the RSSA, the PPA was reinstated beginning April 1, 2017 (see Note 6 — Regulatory Matters for additional details),

•	Generation provided a $400 million loan to CENG. As of March 31, 2018, the remaining obligation is $337 million, including accrued interest, which reflects the principal payment made in January 2015,

•

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 17 — Commitments and Contingencies for more details),

•	Generation and EDF share in the $637 million of contingent payment obligations for the payment of contingent retrospective premium adjustments for the nuclear liability insurance,

•	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 NJBPU in an amount sufficient to fund the principal and interest payments on transition bonds and related taxes, expenses and fees. During the three months ended March 31, 2018, ACE transferred $8 million to ATF. During the three months ended March 31, 2017, ACE transferred $19 million to ATF.

•	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

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•	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 on the unconsolidated VIE balance sheets, not on Exelon’s or Generation’s Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs.

(b)

These items represent amounts on Exelon’s and Generation’s Consolidated Balance Sheets related to the asset sale agreement with ZionSolutions, LLC. The net assets pledged for Zion Station decommissioning includes gross pledged assets of $30 million and $39 million as of March 31, 2018 and December 31, 2017, respectively; offset by payables to ZionSolutions, LLC of $28 million and $37 million as of March 31, 2018 and December 31, 2017, respectively. These items are included to provide information regarding the relative size of the ZionSolutions, LLC unconsolidated VIE. See Note 13 — Nuclear Decommissioning for additional details.

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(a)	Includes a $110 million asset associated with a contractual right to reimbursement from the New York Power Authority (NYPA), a prior owner of FitzPatrick, associated with the DOE one-time fee obligation. See Note 23-Commitments and Contingencies of the Exelon 2017 Form 10-K for additional background regarding SNF obligations to the DOE.

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(a)

Includes regulatory regulatory assets established at the Constellation and PHI merger dates of $427 million and $934 million, respectively, as of March 31, 2018 and $440 million and $953 million, respectively, as of December 31, 2017 related to the rate regulated portions of the deferred costs associated with legacy Constellation’s and PHI’s pension and other postretirement benefit plans that are being amortized and recovered over approximately 12 years and 3 to 15 years, respectively (as established at the respective acquisition dates). The Utility Registrants are not earning or paying a return on these amounts.

(b)

As of March 31, 2018, includes transmission-related income tax regulatory liabilities that require FERC approval separate from the transmission formula rate of $479 million, $135 million, $146 million, $147 million and $147 million for ComEd, BGE, Pepco, DPL and ACE, respectively. As of December 31, 2017, includes transmission-related income tax regulatory liabilities that require FERC approval separate from the transmission formula rate of $484 million, $137 million, $147 million, $148 million and $147 million for ComEd, BGE, Pepco, DPL and ACE, respectively.

(c)

As of March 31, 2018, BGE's regulatory asset of $208 million includes $125 million of unamortized incremental deployment costs under the program, $51 million of unamortized costs of the non-AMI meters replaced under the AMI program, and $32 million related to post-test year incremental program deployment costs incurred prior to approval became effective June 2016. As of December 31, 2017, BGE's regulatory asset of $214 million includes $129 million of unamortized incremental deployment costs under the program, $53 million of unamortized costs of the non-AMI meters replaced under the AMI program, and $32 million related to post-test year incremental program deployment costs incurred prior to approval became effective June 2016. Recovery of the post-test year incremental deployment costs will be addressed in a future base rate proceeding.

(d)	As of March 31, 2018, ComEd’s regulatory asset of $256 million was comprised of $195 million for the 2016, 2017 and 2018 annual reconciliations and $61 million related to significant one-time events. As of December 31, 2017, ComEd’s regulatory asset of $244 million was comprised of $186 million for the 2016 and 2017 annual reconciliations and $58 million related to significant one-time events.

(e)

As of March 31, 2018, ComEd’s regulatory asset of $8 million represents transmission costs recoverable through its FERC approved formula rate. As of March 31, 2018, ComEd’s regulatory liability of $53 million included $21 million related to over-recovered energy costs and $32 million associated with revenues received for renewable energy requirements. As of December 31, 2017, ComEd’s regulatory asset of $6 million represents transmission costs recoverable through its FERC approved formula rate. As of December 31, 2017, ComEd’s regulatory liability of $47 million included $14 million related to over-recovered energy costs and $33 million associated with revenues received for renewable energy requirements.

(f)

As of March 31, 2018, PECO's regulatory liability of $56 million included $44 million related to over-recovered costs under the DSP program, $3 million related to the over-recovered transmission service charges and $9 million related to over-recovered non-bypassable transmission service charges. As of December 31, 2017, PECO's regulatory liability of $60 million included $36 million related to over-recovered costs under the DSP program, $12 million related to over-recovered non-bypassable transmission service charges and $12 million related to the over-recovered natural gas costs under the PGC.

(g)

As of March 31, 2018, BGE's regulatory asset of $21 million included $13 million of costs associated with transmission costs recoverable through its FERC approved formula rate, $5 million related to under-recovered electric energy costs and $3 million of abandonment costs to be recovered upon FERC approval. As of March 31, 2018, BGE's regulatory liability of $22 million related to over-recovered natural gas costs. As of December 31, 2017, BGE’s regulatory asset of $23 million included $7 million of costs associated with transmission costs recoverable through its FERC approved formula rate, $5 million related to under-recovered electric energy costs, $3 million of abandonment costs to be recovered upon FERC approval and $8 million of under-recovered natural gas costs.

(h)

As of March 31, 2018, Pepco's regulatory asset of $7 million included $4 million of transmission costs recoverable through its FERC approved formula rate and $3 million related to under-recovered electric energy costs. As of March 31, 2018, Pepco's regulatory liability of $4 million related to over-recovered electric energy costs. As of December 31, 2017, Pepco's regulatory asset of $11 million included $3 million of transmission costs recoverable through its FERC approved formula rate and $8 million of under-recovered electric energy costs.

(i)

As of March 31, 2018, DPL's regulatory asset of $14 million included $11 million of transmission costs recoverable through its FERC approved formula rate and $3 million related to under-recovered electric energy costs. As of March 31, 2018, DPL's regulatory liability of $6 million related to over-recovered electric energy and gas fuel costs. As of December 31, 2017, DPL's regulatory asset of $15 million included $8 million of transmission costs recoverable through its FERC approved formula rate and $7 million related to under-recovered electric energy costs. As of December 31, 2017, DPL's regulatory liability of $1 million related to over-recovered electric energy costs.

(j)

As of March 31, 2018, ACE's regulatory asset of $24 million included $9 million of transmission costs recoverable through its FERC approved formula rate and $15 million of under-recovered electric energy costs. As of March 31, 2018, ACE's regulatory liability of $12 million related to over-recovered electric energy costs. As of December 31, 2017, ACE's regulatory asset of $26 million included $11 million of transmission costs recoverable through its FERC approved formula rate and $15 million of under-recovered electric energy costs. As of December 31, 2017, ACE's regulatory liability of $3 million related to over-recovered electric energy costs.

(k)	As of March 31, 2018 and December 31, 2017, Pepco’s regulatory asset of $20 million represents previously incurred PHI integration costs, including $11 million authorized for recovery in Maryland and $9 million expected to be recovered in the District of Columbia service territory.

(l)

As of March 31, 2018, DPL’s regulatory asset of $11 million represents previously incurred PHI integration costs, including $4 million authorized for recovery in Maryland, $5 million authorized for recovery in Delaware electric rates and $2 million authorized for recovery in Delaware gas rates. As of March 31, 2018, DPL’s regulatory liability of $1 million represents net synergy savings incurred related to PHI integration costs that are expected to be returned in electric and gas rates in the Delaware service territory. As of December 31, 2017, DPL’s regulatory asset of $10 million represents previously incurred PHI integration costs, including $4 million authorized for recovery in Maryland, $5 million authorized for recovery in Delaware electric rates, and $1 million expected to be recovered in electric and gas rates in the Maryland and Delaware service territories.

(m)	As of March 31, 2018 and December 31, 2017, ACE’s regulatory asset of $10 million and $9 million, respectively, represents previously incurred PHI integration costs expected to be recovered in the New Jersey service territory.

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(n)

Represents the electric and natural gas distribution costs recoverable from customers under BGE’s decoupling mechanism. As of March 31, 2018, BGE had a regulatory asset of $6 million related to under-recovered electric revenue decoupling and a regulatory liability of $11 million related to over-recovered natural gas revenue decoupling. As of December 31, 2017, BGE had a regulatory asset of $10 million related to under-recovered electric revenue decoupling and $4 million related to under-recovered natural gas revenue decoupling.

(o)	Represents over-recoveries related to the change in the federal income tax rate with the enactment of the TCJA. These regulatory liabilities will be amortized as the TCJA income tax benefits are passed back to customers. See Tax Cuts and Jobs Act disclosures above for further details on the regulatory proceedings.

(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)	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 its Purchase of Receivables with Consolidated Billing tariff.

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(a)	Reflects incremental accelerated depreciation and amortization for TMI for the quarter ended March 31, 2018, and for Oyster Creek from February 2, 2018 through March 31, 2018.

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

(c)	Primarily includes materials and supplies inventory reserve adjustments, employee related costs and CWIP impairments.

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(a)	Reflects incremental charges for TMI including incremental accelerated depreciation and amortization from May 30, 2017 through December 31, 2017.

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

(c)	Primarily includes materials and supplies inventory reserve adjustments, employee related costs and CWIP impairments.

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(a)	Reflects ending balances only as they relate to Mystic's Long-term Service Agreement.

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(a)	Level 1 securities consist of dividends payable (included in other current liabilities). Level 2 securities consist of short term borrowings.

(b)

Includes unamortized debt issuance costs which are not fair valued of $213 million, $57 million, $60 million, $20 million, $16 million, $6 million, $32 million, $11 million and $5 million for Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, as of March 31, 2018. Includes unamortized debt issuance costs which are not fair valued of $201 million, $60 million, $52 million, $17 million, $17 million, $6 million, $32 million, $11 million and $5 million for Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, as of December 31, 2017.

(c)	Level 2 securities consist of fixed-rate taxable debt securities, fixed-rate tax-exempt debt, variable rate tax-exempt debt and variable rate non-recourse debt. Level 3 securities consist of fixed-rate private placement taxable debt securities, fixed rate nonrecourse debt and government-backed fixed rate non-recourse debt.

(d)	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, 2018 and December 31, 2017.

•	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 $371 million and $259 million at March 31, 2018 and December 31, 2017 and restricted cash of $23 million and $127 million at March 31, 2018 and December 31, 2017.  Exelon excludes cash of $531 million and $389 million at March 31, 2018 and December 31, 2017 and restricted cash of $51 million and $145 million at March 31, 2018 and December 31, 2017 and includes long-term restricted cash of $103 million and $85 million at March 31, 2018 and December 31, 2017, which is reported in Other deferred debits on the Consolidated Balance Sheets.

(b)	Includes $53 million and $77 million of cash received from outstanding repurchase agreements at March 31, 2018 and December 31, 2017, respectively, and is offset by an obligation to repay upon settlement of the agreement as discussed in (d) below.

(c)

Includes derivative instruments of $2 million and less than $1 million, which have a total notional amount of $949 million and $811 million at March 31, 2018 and December 31, 2017, 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 the company's exposure to credit or market loss.

(d)

Excludes net liabilities of $84 million and $82 million at March 31, 2018 and December 31, 2017, 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)	Excludes net assets of $1 million at March 31, 2018. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases.

(f)	The amount of unrealized gains/(losses) at Generation totaled less than $1 million and $1 million for the three months ended March 31, 2018 and March 31, 2017, respectively. The amount of unrealized gains/(losses) at Exelon totaled $1 million and $2 million for the three months ended March 31, 2018 and March 31, 2017, respectively.

(g)

Collateral posted/(received) from counterparties totaled $80 million, $418 million and $186 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of March 31, 2018. Collateral posted/(received) from counterparties, net of collateral paid to counterparties, totaled $65 million, $320 million and $81 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2017.

(h)	Of the collateral posted/(received), $156 million represents variation margin on the exchanges as of March 31, 2018. Of the collateral posted/(received), $(117) million represents variation margin on the exchanges as of December 31, 2017.

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(a)	ComEd excludes cash of $69 million and $45 million at March 31, 2018 and December 31, 2017 and includes long-term restricted cash of $83 million and $62 million at March 31, 2018 and December 31, 2017, which is reported in Other deferred debits on the Consolidated Balance Sheets.  PECO excludes cash of $20 million and $47 million at March 31, 2018 and December 31, 2017.  BGE

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(b)	The amount of unrealized gains/(losses) at ComEd, PECO and BGE totaled less than $1 million for the three months ended March 31, 2018 and March 31, 2017, respectively.

(c)	The Level 3 balance consists of the current and noncurrent liability of $24 million and $243 million, respectively, at March 31, 2018, and $21 million and $235 million, respectively, at December 31, 2017, related to floating-to-fixed energy swap contracts with unaffiliated suppliers.

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(a)

PHI excludes cash of $36 million and $12 million at March 31, 2018 and December 31, 2017, respectively, and includes long-term restricted cash of $20 million and $23 million at March 31, 2018 and December 31, 2017, respectively, which is reported in Other deferred debits on the Consolidated Balance Sheets.  Pepco excludes cash of $15 million and $4 million at March 31, 2018 and December 31, 2017, respectively. DPL excludes cash of $7 million and $2 million at March 31, 2018 and December 31, 2017, respectively. ACE excludes cash of $10 million and $2 million at March 31, 2018 and December 31, 2017, respectively, and includes long-term restricted cash of $20 million and $23 million at March 31, 2018 and December 31, 2017, respectively, which is reported in Other deferred debits on the Consolidated Balance Sheets.

(b)	The amount of unrealized gains/(losses) at PHI, Pepco, DPL and ACE totaled less than $1 million for the three months ended March 31, 2018 and March 31, 2017.

(c)	Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC.

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(a)	Includes a reduction for the reclassification of $72 million and $102 million of realized gains due to the settlement of derivative contracts for the three months ended March 31, 2018 and March 31, 2017, respectively.

(b)

Includes $17 million of decreases 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. Includes $30 million of decreases 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, 2017.

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

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(a)	Other, net activity consists of realized and unrealized gains (losses) included in income for the NDT funds held by Generation, accrued interest on a convertible promissory note at Generation and the life insurance contracts held by PHI and Pepco.

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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 $186 million and $81 million as of March 31, 2018 and December 31, 2017, 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, Generation and DPL net all available amounts allowed under the derivative authoritative guidance on 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 $192 million and $103 million, respectively, and current and noncurrent liabilities are shown net of collateral of $220 million and $169 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $684 million at March 31, 2018.

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

(d)	Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC.

(e)	Of the collateral posted/(received), $156 million represents variation margin on the exchanges.

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(a)

Exelon, Generation and DPL net all available amounts allowed under the derivative authoritative guidance on 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 $169 million and $53 million, respectively, and current and noncurrent liabilities are shown net of collateral of $167 million and $77 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $466 million at December 31, 2017.

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

(d)	Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC.

(e)	Of the collateral posted/(received), $(117) 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 on 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 counterparty exposures subject to a master netting or similar agreement, such as accrued interest, transactions that do not qualify as derivatives, letters of credit and other forms of non-cash collateral, which are not reflected in the table above.

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(a)

Exelon and Generation net all available amounts allowed under the derivative authoritative guidance on 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 counterparty exposures subject to a master netting or similar agreement, such as accrued interest, transactions that do not qualify as derivatives, letters of credit and other forms of non-cash collateral, which are not reflected in the table above.

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(a)	Amount is net of related income tax expense of $3 million for the three months ended March 31, 2017.

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(a)	As of March 31, 2018, credit collateral held from counterparties where Generation had credit exposure included $41 million of cash and $23 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)	PHI reflects the commercial paper borrowings outstanding of Pepco, DPL and ACE.

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(a)	Reflects the net regulatory liabilities recorded on a pre-tax basis before taking into consideration the income tax benefits associated with the ultimate settlement with customers.

(b)	Amounts do not sum across due to deferred tax adjustments recorded at the Exelon Corporation parent company, primarily related to certain employee compensation plans.

(c)	Given the regulatory treatment of income tax benefits related to electric and gas distribution repairs, PECO remains in an overall net regulatory asset position as of December 31, 2017 after recording the impacts related to the TCJA. Refer to Note 3 - Regulatory Matters for additional information.

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(a)

Given the regulatory treatment of income tax benefits related to electric and gas distribution repairs, PECO remains in an overall net regulatory asset position as of December 31, 2017 after recording the impacts related to the TCJA. As a result, the amount of customer benefits resulting from the TCJA subject to the discretion of PECO's rate regulators are lower relative to the other Utility Registrants. Refer to Note 3 - Regulatory Matters for additional information.

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(a)	Exelon retrospectively adopted the new standard Revenue from Contracts with Customers. The standard was adopted as of January 1, 2018. The effective income tax rates are recast to reflect the impact of the new standard.

(b)	Includes a remeasurement of uncertain state income tax positions for Pepco and DPL.

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(a)	Includes $64 million and $13 million for the current portion of the ARO at March 31, 2018 and December 31, 2017, respectively, which is included in Other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets.

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

(b)	Excludes $(2) million and $(1) million of net unrealized losses related to the Zion Station pledged assets for the three months ended March 31, 2018 and 2017, respectively. Net unrealized losses related to Zion Station pledged assets are included in Other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets in 2018 and 2017, respectively.

(c)	Net unrealized gains (losses) related to Generation’s NDT funds with Non-Regulatory Agreement Units are included in Other, net on Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

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(a)	Included in Other current assets within Exelon's and Generation's Consolidated Balance sheets.

(b)	Excludes a liability recorded within Exelon’s and Generation’s Consolidated Balance Sheets related to the tax obligation on the unrealized activity associated with the Zion Station NDT funds. The NDT funds will be utilized to satisfy the tax obligations as gains and losses are realized.

(c)	Included in Other current liabilities within Exelon’s and Generation’s Consolidated Balance Sheets.

(d)	Includes project expenses to decommission Zion Station and estimated tax payments on Zion Station NDT fund earnings.

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(a)	FitzPatrick net benefit costs are included for the period after the acquisition date of March 31, 2017.

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(a)	Exelon reflects the consolidated pension and other postretirement benefit costs of Generation, ComEd, PECO, BGE, BSC, and PHI. PHI reflects the consolidated pension and other postretirement benefit costs of Pepco, DPL, ACE, and PHISCO.

(b)	FitzPatrick net benefit costs are included for the period after the acquisition date of March 31, 2017.

(c)	These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO, BGE, PHI, Pepco, DPL or ACE amounts above.

(d)	These amounts represent amounts billed to Pepco, DPL and ACE through intercompany allocations. These amounts are not included in Pepco, DPL or ACE amounts above.

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(a)	Exelon reflects the consolidated savings plan matching contributions of Generation, ComEd, PECO, BGE, BSC, and PHI. PHI reflects the consolidated savings plan matching contributions of Pepco, DPL, and PHISCO.

(b)	FitzPatrick net benefit costs are included for the period after the acquisition date of March 31, 2017.

(c)	These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO, BGE, PHI, Pepco or DPL amounts above.

(d)	These amounts represent amounts billed to Pepco and DPL through intercompany allocations. These amounts are not included in Pepco or DPL amounts above.

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(a)	All amounts are net of tax and noncontrolling interest. 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, $3 million and $1 million for Exelon, Generation and PECO, respectively. The amounts reclassified related to Rabbi Trusts. See Note 2 — New Accounting Standards 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 2 — New Accounting Standards 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 details).

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(a)	Letters of credit (non-debt) - Exelon and certain of its subsidiaries maintain non-debt letters of credit to provide credit support for certain transactions as requested by third parties. Includes letters of credits issued under credit facility agreements arranged at minority and community banks and nonrecourse debt letters of credits.

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

(c)

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 $58 million, $17 million of which is a guarantee by Pepco, $24 million by DPL and $16 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, 20 of which have been remediated and approved by the Illinois EPA or the U.S. EPA and 22 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 2022.

•	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 former gas manufacturing or purification sites, 9 of which the remediation has been completed and approved by the MDE and 4 that require some level of remediation and/or ongoing activity. BGE has determined that a loss associated with these sites is probable and has recorded an estimated liability, which is included in the table below. However, it is reasonably possible that BGE’s cost of remediation for one of its sites could be up to $13 million.

•	DPL has identified 3 sites, 2 of which remediation has been completed and approved by the MDE or the Delaware Department of Natural Resources and Environmental Control.

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(a)	Includes investment income and realized gains and losses on sales of investments of the trust funds.

(b)	Includes the elimination of NDT fund activity 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 2017 Form 10-K for additional information regarding the accounting for nuclear decommissioning.

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

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

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

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

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(a)

Includes the elimination of NDT fund 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 2017 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.

(c)

Reflects the change in distribution rates pursuant to EIMA and FEJA, which allows for the recovery of distribution costs by a utility through a pre-established performance-based formula rate tariff. Beginning June 1, 2017, also reflects the change in energy efficiency rates pursuant to FEJA, which allows for the recovery of energy efficiency costs by a utility through a pre-established performance-based formula rate tariff. See Note 6 — Regulatory Matters for more information.

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(a)	Includes accumulated amortization of nuclear fuel in the reactor core of $3,263 million.

(b)	Includes accumulated amortization of nuclear fuel in the reactor core of $3,159 million.

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•	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, which includes portions of Illinois, Pennsylvania, Indiana, Ohio, Michigan, Kentucky and Tennessee, and the United States footprint of MISO, excluding MISO’s Southern Region, which covers all or most of North Dakota, South Dakota, Nebraska, Minnesota, Iowa, Wisconsin, the remaining parts of Illinois, Indiana, Michigan and Ohio not covered by PJM, and parts of Montana, Missouri and Kentucky.

•	New England represents the operations within ISO-NE covering the states of Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont.

•	New York represents operations within ISO-NY, which covers the state of New York in its entirety.

•	ERCOT represents operations within Electric Reliability Council of Texas, covering most of the state of Texas.

•	Other Power Regions:

•

South represents operations in the FRCC, MISO’s Southern Region, and the remaining portions of the SERC not included within MISO or PJM, which includes all or most of Florida, Arkansas, Louisiana, Mississippi, Alabama, Georgia, Tennessee, North Carolina, South Carolina and parts of Missouri, Kentucky and Texas. Generation’s South region also includes operations in the SPP, covering Kansas, Oklahoma, most of Nebraska and parts of New Mexico, Texas, Louisiana, Missouri, Mississippi and Arkansas.

•	West represents operations in the WECC, which includes California ISO, and covers the states of California, Oregon, Washington, Arizona, Nevada, Utah, Idaho, Colorado and parts of New Mexico, Wyoming and South Dakota.

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

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(a)

Generation includes the six reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions. Intersegment revenues for Generation for the three months ended March 31, 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. For the three months ended March 31, 2017, intersegment revenues for Generation include revenue from sales to PECO of $45 million, sales to BGE of $134 million, sales to Pepco of $83 million, sales to DPL of $51 million and sales to ACE of $9 million in the Mid-Atlantic region, and sales to ComEd of $5 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 on the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 18 — Supplemental Financial Information for total utility taxes for the three months ended March 31, 2018 and 2017.

(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.

(a)	Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses on the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 18 — Supplemental Financial Information for total utility taxes for the three months ended March 31, 2018 and 2017.

(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 a $3 million decrease to revenues for the amortization of intangible assets and liabilities related to commodity contracts recorded at fair value for the three months ended March 31, 2017, unrealized mark-to-market losses of $98 million and gains of $44 million for the three months ended March 31, 2018 and 2017, 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 a $3 million decrease to RNF for the amortization of intangible assets and liabilities related to commodity contracts for the three months ended March 31, 2017, unrealized mark-to-market losses of $266 million and $49 million for the three months ended March 31, 2018 and 2017, respectively, accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 7 - Early Nuclear Plant Retirements of the Combined Notes to Consolidated Financial Statements of $15 million decrease to revenue net of purchased power and fuel expense for the three months ended March 31, 2018, and the elimination of intersegment revenue net of purchased power and fuel expense.

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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 $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, for the three months ended March 31, 2018 and $5 million, $1 million, $2 million, $1 million, $1 million, $2 million, and $1 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, for the three months ended March 31, 2017.

(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, for the three months ended March 31, 2018 and less than $1 million and $3 million at PECO and BGE, respectively, for the three months ended March 31, 2017.

(e)	Includes late payment charge revenues.

(f)	Includes operating revenues from affiliates of $11 million at PHI for the three months ended March 31, 2017.

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

•	Generation, whose integrated business consists of the generation, physical delivery and marketing of power across multiple geographical regions through its customer-facing business, Constellation, which sells electricity and natural gas to both wholesale and retail customers. Generation also sells renewable energy and other energy-related products and services.

•	ComEd, whose business consists of the purchase and regulated retail sale of electricity and the provision of electricity transmission and distribution services in northern Illinois, including the City of Chicago.

•	PECO, whose business consists of the purchase and regulated retail sale of electricity and the provision of electricity distribution and transmission services in southeastern Pennsylvania, including the City of Philadelphia, and the purchase and regulated retail sale of natural gas and the provision distribution services in the Pennsylvania counties surrounding the City of Philadelphia.

•	BGE, whose business consists of the purchase and regulated retail sale of electricity and natural gas and the provision of electricity distribution and transmission and gas distribution services in central Maryland, including the City of Baltimore.

•	Pepco, whose business consists of the purchase and regulated retail sale of electricity and the provision of electricity distribution and transmission in the District of Columbia and major portions of Prince George's County and Montgomery County in Maryland.

•	DPL, whose business consists of the purchase and regulated retail sale of electricity and the provision of electricity distribution and transmission services in portions of Maryland and Delaware, and the purchase and regulated retail sale of natural gas and the provision of natural gas distribution services in northern Delaware.

•	ACE, whose business consists of the purchase and regulated retail sale of electricity and the provision of electricity transmission and distribution services in southern New Jersey.

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(a)

The Registrants evaluate operating performance using the measure of revenues net of purchased power and fuel expense. The Registrants believe that revenues net of purchased power and fuel expense is a useful measurement because it provides information that can be used to evaluate their operational performance. Revenues net of purchased power and fuel expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.

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•

Increase of $390 million at Generation primarily due to impact of the New York CES and Illinois ZES (including the impact of zero emission credits generated in Illinois from June 1, 2017 through December 31, 2017), increased nuclear volumes primarily as a result of the acquisition of FitzPatrick, decreased nuclear outage days, increased capacity prices and the addition of two combined-cycle gas turbines in Texas, partially offset by the conclusion of the Ginna Reliability Support Services Agreement and lower realized energy prices;

•	Increase of $44 million at PECO, DPL and ACE primarily due to favorable weather conditions within their respective service territories; and

•	Increase of $33 million due to higher mutual assistance revenues across all Utility Registrants, primarily at ComEd.

•	Decrease of $217 million at Generation due to mark-to-market losses of $266 million in 2018 compared to $49 million in 2017; and

•	Decrease of $57 million at ComEd primarily due to lower revenues resulting from the change to defer and recover over time energy efficiency costs pursuant to FEJA;

•	Decrease of $85 million in electric and gas revenues across all Utility Registrants, primarily reflecting lower revenues resulting from the anticipated pass back of TCJA tax savings through customer rates, partially offset by higher utility earnings due to regulatory rate increases at ComEd, BGE and PHI.

•	Decrease of $57 million at ComEd primarily due to the change to defer and recover over time energy efficiency costs pursuant to FEJA;

•	Decrease of $38 million at Generation due to lower merger and integration costs primarily related to the FitzPatrick acquisition;

•	Decrease of $33 million at Generation due to lower nuclear refueling outage costs; and

•	Decrease of $32 million related to a supplemental NEIL insurance distribution at Generation in the first quarter of 2018.

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•	Increase of $86 million at PECO and BGE due to increased storm costs;

•	Increase of $33 million due to higher mutual assistance expenses across all Utility Registrants, primarily at ComEd; and

•	Increase of $22 million at PHI due to uncollectible accounts expense.

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(a)	Reflects the impact of net gains and losses on Generation’s economic hedging activities. See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional detail related to Generation’s hedging activities.

(b)	Reflects the impact of net unrealized gains and losses on Generation’s NDT fund investments for Non-Regulatory Agreement Units. See Note 13 — Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements for additional detail related to Generation’s NDT fund investments.

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

(d)	Primarily reflects certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses and integration activities related to the PHI and FitzPatrick acquisitions in 2017, and the PHI acquisition

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(e)	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.

(f)

Primarily reflects accelerated depreciation and amortization expenses and increases to materials and supplies inventory reserves associated with Generation’s 2018 decision to early retire the Oyster Creek nuclear facility, as well as the accelerated depreciation and amortization expense associated with Generation’s 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

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

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

(i)	Reflects the change in the District of Columbia statutory tax rate.

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

(k)	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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(a)	Actual results may differ based on incremental future capital additions, actual units of production for nuclear fuel amortization, future revised ARO assumptions, etc.

(b)	Reflects incremental accelerated depreciation and amortization for TMI for the quarter ended March 31, 2018, and Oyster Creek from February 2, 2018 through March 31, 2018.

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

(d)	Primarily includes materials and supplies inventory reserve adjustments, employee-related costs and CWIP impairments.

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(a)	PHI reflects the consolidated customer outages, incremental operating & maintenance and incremental capital expenditures of Pepco, DPL and ACE.

(b)	Excludes amounts that were deferred and recognized as regulatory assets at Exelon, PHI, Pepco, DPL and ACE of $22 million, $22 million, $5 million, $1 million and $16 million, respectively.

•	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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(a)

Generation evaluates its operating performance using the measure of revenue net of purchased power and fuel expense. Generation believes that revenue net of purchased power and fuel expense is a useful measurement because it provides information that can be used to evaluate its operational performance. Revenue net of purchased power and fuel expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.

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•	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, which includes portions of Illinois, Pennsylvania, Indiana, Ohio, Michigan, Kentucky and Tennessee, and the United States footprint of MISO, excluding MISO’s Southern Region, which covers all or most of North Dakota, South Dakota, Nebraska, Minnesota, Iowa, Wisconsin, the remaining parts of Illinois, Indiana, Michigan and Ohio not covered by PJM, and parts of Montana, Missouri and Kentucky.

•	New England represents the operations within ISO-NE covering the states of Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont.

•	New York represents operations within ISO-NY, which covers the state of New York in its entirety.

•	ERCOT represents operations within Electric Reliability Council of Texas, covering most of the state of Texas.

•	Other Power Regions:

•

South represents operations in the FRCC, MISO’s Southern Region, and the remaining portions of the SERC not included within MISO or PJM, which includes all or most of Florida, Arkansas, Louisiana, Mississippi, Alabama, Georgia, Tennessee, North Carolina, South Carolina and parts of Missouri, Kentucky and Texas. Generation’s South region also includes operations in the SPP, covering Kansas, Oklahoma, most of Nebraska and parts of New Mexico, Texas, Louisiana, Missouri, Mississippi and Arkansas.

•	West represents operations in the WECC, which includes California ISO, and covers the states of California, Oregon, Washington, Arizona, Nevada, Utah, Idaho, Colorado, and parts of New Mexico, Wyoming and South Dakota.

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

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(a)	Results of transactions with PECO and BGE are included in the Mid-Atlantic region. Results of transactions with Pepco, DPL and ACE are included in the Mid-Atlantic region.

(b)	Results of transactions with ComEd are included in the Midwest region.

(c)

Other represents activities not allocated to a region. See text above for a description of included activities. Includes amortization of intangible assets related to commodity contracts recorded at fair value of a $3 million decrease to revenue net of purchased power and fuel expense for the three months ended March 31, 2017, and accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 8 — Early Plant Retirements of the Combined Notes to Consolidated Financial Statements of a $15 million decrease to revenue net of purchased power and fuel expense for the three months ended March 31, 2018.

(d)	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 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.

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

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(a)	Excludes Salem, which is operated by PSEG Nuclear, LLC. Reflects ownership percentage of stations operated by Exelon. Includes the ownership of the FitzPatrick nuclear facility from March 31, 2017.

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(a)	The financial results include Generation's acquisition of the FitzPatrick nuclear generating station from March 31, 2017.

(b)	Primarily reflects decreased spending related to energy efficiency projects.

(c)	Primarily reflects a decrease in the number of nuclear outage days for the three months ended March 31, 2018 compared to 2017.

(d)	Primarily reflects the impact of a supplemental NEIL insurance distribution.

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

(f)

Primarily reflects accelerated depreciation and amortization expenses and increases to materials and supplies inventory reserves associated with Generation’s 2018 decision to early retire the Oyster Creek nuclear facility, as well as the accelerated depreciation and amortization expense associated with Generation’s 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.

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(a)

ComEd evaluates its operating performance using the measure of Revenue net of purchased power expense. ComEd believes that Revenue net of purchased power expense is a useful measurement because it provides information that can be used to evaluate its operational performance. In general, ComEd only earns margin based on the delivery and transmission of electricity. ComEd has included its discussion of Revenue net of purchased power expense below as a complement to the financial information provided in accordance with GAAP. However, Revenue net of purchased power expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.

(b)	For regulatory recovery mechanisms, including ComEd’s electric distribution and transmission formula rates, and riders, 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).

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(a)	Beginning on June 1, 2017, ComEd is deferring energy efficiency costs as a regulatory asset that will be recovered through the energy efficiency formula rate over the weighted average useful life of the related energy efficiency measures.

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(a)	Operating and maintenance expense for regulatory required programs are costs for various legislative and/or regulatory programs that 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)	Includes additional costs associated with mutual assistance programs. An equal and offsetting decrease has been recognized in Operating revenues for the period presented.

(b)

ComEd is allowed to recover from or refund to customers the difference between the utility’s annual uncollectible accounts expense and the amounts collected in rates annually through a rider mechanism. During the three months ended March 31, 2018, ComEd recorded a net increase in Operating and maintenance expense related to uncollectible accounts due to the timing of regulatory cost recovery. An equal and offsetting decrease has been recognized in Operating revenues for the period presented.

(c)	Beginning on June 1, 2017, ComEd is deferring energy efficiency costs as a regulatory asset that will be recovered through the energy efficiency formula rate over the weighted average useful life of the related energy efficiency measures.

(a)	Primarily reflects ongoing capital expenditures for the three months ended March 31, 2018.

(b)	Beginning in June 2017, includes amortization of ComEd's energy efficiency formula rate regulatory asset.

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(a)	Reflects delivery volume from customers purchasing electricity directly from ComEd and customers purchasing electricity from a competitive electric generation supplier, as all customers are assessed delivery charges.

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(a)

PECO evaluates its operating performance using the measures of revenue net of purchased power expense for electric sales and revenue net of fuel expense for gas sales. PECO believes revenue net of purchased power expense and revenue net of fuel expense are useful measurements of its performance because they provide information that can be used to evaluate its net revenue from operations. PECO has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, revenue net of purchased power expense and revenue net of fuel expense figures are not presentations defined under GAAP and may not be comparable to other companies’ presentations or more useful than the GAAP information provided elsewhere in this report.

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(a)	Operating and maintenance expenses for regulatory required programs are costs for various legislative and/or regulatory programs that 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 increased costs incurred from the Q1 2018 winter storms.

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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.

(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.

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(a)

BGE evaluates its operating performance using the measures of revenue net of purchased power expense for electric sales and revenue net of fuel expense for gas sales. BGE believes revenues net of purchased power and fuel expense are useful measurements of its performance because they provide information that can be used to evaluate its net revenue from operations. BGE has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, revenues net of purchased power and fuel expense figures are not a presentation defined under GAAP and may not be comparable to other companies’ presentations or more useful than the GAAP information provided elsewhere in this report.

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(a)	Operating and maintenance expense for regulatory required programs are costs for various legislative and/or regulatory programs that 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 increased storm restoration costs incurred from the Q1 2018 winter storms.

(a)	Depreciation expense increased due to ongoing capital expenditures.

(b)	Regulatory asset amortization decreased for the three months ended March 31, 2018 compared to the same period in 2017 primarily due to certain regulatory assets that became fully amortized as of December 31, 2017. See Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

(c)	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 BGE and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges.

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(a)	Reflects delivery volumes 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.

(b)	Other natural gas revenue includes off-system sales of 5,378 mmcfs and 2,279 mmcfs for the three months ended March 31, 2018 and 2017, respectively.

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(a)

PHI evaluates its operating performance using the measure of revenue net of purchased power and fuel expense for electric and natural gas sales. PHI believes revenue net of purchased power and fuel expense is a useful measurement because it provides information that can be used to evaluate its operational performance. PHI has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, Revenue net of purchased power and fuel expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.

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Increase of $11 million at Pepco primarily related to the impact of the new electric distribution base rates charged to customers in Maryland that became effective in October 2017, the impact of new electric distribution base rates charged to customers in the District of Columbia effective August 2017, and the impact of an increase in the Maryland surcharge rate (which is substantially offset in Taxes other than income), partially offset by the impact of reduced distribution rates to reflect the lower federal income tax rate;

•	Increase of $11 million at ACE primarily related to higher average residential and commercial customer usage, favorable weather related sales, and the impact of the new electric distribution base rate charged to customers that became effective in October 2017, partially offset by the impact of reduced distribution rates to reflect the lower federal income tax rate;

•	Increase of $2 million at DPL primarily related to favorable weather related sales, partially offset by the impact of reduced distribution base rates to reflect the lower federal income tax rate; and

•	Decrease of $8 million at PHI Corporate primarily related to lower affiliate revenues at PHISCO as a result of the completion of integration transition activities.

•	Increase of $25 million at DPL primarily due to a write-off of construction work-in-progress, higher uncollectible accounts expense as a result of higher accounts receivable, and the absence of integration cost deferrals from 2017;

•	Increase of $17 million at Pepco primarily due to higher uncollectible accounts expense as a result of higher accounts receivable;

•	Increase of $14 million at ACE primarily due to an increase in labor and contracting expense; and

•	Decrease of $5 million at PHI Corporate primarily related to lower labor expense at PHISCO as a result of the completion of integration transition activities.

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(a)

Pepco evaluates its operating performance using the measure of revenue net of purchased power expense for electric sales. Pepco believes revenue net of purchased power expense is a useful measurement because it provides information that can be used to evaluate its operational performance. Pepco has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, Revenue net of purchased power expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.

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(a)	Operating and maintenance expenses for regulatory required programs are costs for various legislative and/or regulatory programs that 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.

(a)	Depreciation expense increased due to ongoing capital expenditures.

(b)	Regulatory asset amortization increased for the three months ended March 31, 2018 compared to the same period in 2017, primarily due to higher amortization of DC PLUG regulatory asset. An equal and offsetting amount has been reflected in Operating revenues.

(c)	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 and Operating and maintenance expense.

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

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(a)

DPL evaluates its operating performance using the measure of revenue net of purchased power expense for electric sales and revenue net of fuel expense for natural gas sales. DPL believes revenue net of purchased power expense and revenue net of fuel expense are useful measurements because they provide information that can be used to evaluate its operational performance. DPL has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, Revenue net of purchased power expense and Revenue net of fuel expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.

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(a)	Reflects accumulated integration costs that were deferred as regulatory assets in 2017.

(a)	Reflects an absence of integration cost deferrals from 2017.

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(a)	Depreciation expense increased due to ongoing capital expenditures.

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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.

(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.

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(a)

ACE evaluates its operating performance using the measure of revenue net of purchased power expense for electric sales. ACE believes Revenue net of purchased power expense is a useful measurement of its performance because it provides information that can be used to evaluate its operational performance. ACE has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, Revenue net of purchased power expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.

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(a)	Operating and maintenance expenses for regulatory required programs are costs for various legislative and/or regulatory programs that 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.

(a)	The uncollectible accounts expense is offset in Operating revenues.

(a)	Depreciation expense increased due to ongoing capital expenditures.

(b)

Regulatory required programs decreased for the three months ended March 31, 2018 compared to the same period in 2017 as a result of lower revenue due to rate decreases effective October 2017 for the ACE Transition Bonds. 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 and Operating and maintenance expense.

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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.

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(a)

Represents depreciation, amortization and accretion, net fair value changes related to derivatives, deferred income taxes, provision for uncollectible accounts, pension and other postretirement benefit expense, equity in earnings and losses of unconsolidated affiliates and investments, decommissioning-related items, stock compensation expense, impairment of long-lived assets and other non-cash charges. See Note 18 — Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements for further detail on non-cash operating activity.

(b)	Changes in working capital and other noncurrent assets and liabilities exclude the changes in commercial paper, income taxes and the current portion of long-term debt.

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•	Pursuant to the TCJA, beginning in 2018 Generation is expected to have higher operating cash flows in the range of approximately $1.2 billion to $1.6 billion for the period from 2018 to 2021, reflecting the reduction in the corporate federal income tax rate and full expensing of capital investments.

(a)

Given the regulatory treatment of income tax benefits related to electric and gas distribution repairs, PECO remains in an overall net regulatory asset position as of December 31, 2017 after recording the impacts related to the TCJA. As a result, the amount of customer benefits resulting from the TCJA subject to the discretion of PECO's rate regulators are lower relative to the other Utility Registrants. Refer to Note 3 - Regulatory Matters for additional information.

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•	State and local governments continue to face increasing financial challenges, which may increase the risk of additional income tax, property taxes and other taxes or the imposition, extension or permanence of temporary tax increases.

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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. During the three months ended March 31, 2018 and 2017, Generation had net payments of counterparty cash collateral of $214 million and $102 million, respectively, primarily due to market conditions that resulted in changes to Generation’s net mark-to-market position.

•	During the three months ended March 31, 2018 and 2017, Generation had net payments of approximately $27 million and $6 million, respectively, related to purchases and sales of options. The level of option activity in a given period may vary due to several factors, including changes in market conditions as well as changes in hedging strategy.

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During each of the three months ended March 31, 2018 and 2017, ComEd posted approximately $8 million of cash collateral with PJM, respectively.  As of March 31, 2018 and 2017, ComEd had approximately $59 million and $32 million cash collateral posted with PJM, respectively. ComEd’s total collateral posted with PJM has increased year over year primarily due to an increase in ComEd’s RPM credit requirements and peak market activity with PJM.

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•	During the three months ended March 31, 2018, Exelon had proceeds of $79 million relating to the sale of its interest in an electrical contracting business that primarily installs, maintains and repairs underground and high-voltage cable transmission and distribution services.

•	During the three months ended March 31, 2017, Exelon had expenditures of $23 million and $182 million relating to the acquisitions of ConEdison Solutions and the FitzPatrick facility, respectively.

(a)	Total projected capital expenditures do not include adjustments for non-cash activity.

(b)	Includes corporate operations, BSC, and PHISCO rounded to the nearest $25 million.

(c)	The capital expenditures and 2018 projections include approximately $86 million of expected incremental spending pursuant to EIMA, ComEd has committed to invest approximately $2.6 billion over a ten-year period, through 2021, to modernize and storm-harden its distribution system and to implement smart grid technology.

(d)	Includes PHISCO rounded to the nearest $25 million.

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(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, beginning with the March 2018 dividend.

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(a)	Additional contributions from parent or external debt financing may be required as a result of increased capital investment in infrastructure improvements and modernization pursuant to EIMA and transmission upgrades.

(b)	Contribution paid by Exelon.

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

(a)	Excludes $545 million bilateral credit facilities that do not back Generation's commercial paper program.

(b)

Excludes additional credit facility agreements for Generation, ComEd, PECO, BGE, Pepco, DPL and ACE with aggregate commitments of $49 million, $34 million, $34 million, $5 million, $2 million, $2 million and $2 million, respectively, arranged with minority and community banks located primarily within utilities' service territories. These facilities expire on October 12, 2018. These facilities are solely utilized to issue letters of credit. As of March 31, 2018, letters of credit issued under these agreements for Generation and BGE totaled $5 million and $2 million, respectively.

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(a)	Excludes $128 million of credit facility agreements arranged at minority and community banks at Generation, ComEd, PECO, BGE, Pepco, DPL and ACE. These facilities expire on October 12, 2018. These facilities are solely utilized to issue letters of credit. As of March 31, 2018, letters of credit issued under these agreements for Generation and BGE totaled $5 million and $2 million, respectively.

(b)

Pepco, DPL and ACE's revolving credit facility is subject to available borrowing capacity. The borrowing capacity may be increased or decreased during the term of the facility, except that (i) the sum of the borrowing capacity must equal the total amount of the facility, and (ii) the aggregate amount of credit used at any given time by each of Pepco, DPL or ACE may not exceed $900 million or the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the borrowing reallocations may not exceed eight per year during the term of the facility

(c)	Excludes nonrecourse debt letters of credit, see Note 13 — Debt and Credit Agreements in the Exelon 2017 Form 10-K for further information.

(d)	Excludes $545 million bilateral credit facilities that do not back Generation’s commercial paper program.

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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 $143 million available in new money long term debt financing authority from the ICC as of March 31, 2018 and has an expiration date of June 1, 2019 and March 1, 2019, respectively. On April 9, 2018, ComEd filed an application for $1.5 billion in new money long-term debt financing authority from the ICC and expects approval by August 1, 2018.

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

(b)

For ComEd and DPL, the changes in fair value are recorded as a change in regulatory assets or liabilities. As of March 31, 2018, ComEd recorded a regulatory liability of $267 million related to its mark-to-market derivative liabilities with Generation and unaffiliated suppliers. For the three months ended March 31, 2018, ComEd also recorded $17 million of decreases 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.

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

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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 $684 million at March 31, 2018.

(c)	Includes ComEd’s net 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 $684 million at March 31, 2018.

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(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, 2018, credit collateral held from counterparties where Generation had credit exposure included $41 million of cash and $23 million of letters of credit.

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