EXELON CORP - Quarter Report: 2020 March (Form 10-Q)

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(a)	The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was immaterial for the three months ended March 31, 2020 and March 31, 2019.

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(a)

Exelon’s consolidated assets include $9,056 million and $9,532 million at March 31, 2020 and December 31, 2019, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $3,412 million and $3,473 million at March 31, 2020 and December 31, 2019, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 16 — Variable Interest Entities for additional information.

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(a)

Generation’s consolidated assets include $9,034 million and $9,512 million at March 31, 2020 and December 31, 2019, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $3,369 million and $3,429 million at March 31, 2020 and December 31, 2019, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 16 — Variable Interest Entities for additional information.

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(a)

PHI’s consolidated total assets include $22 million and $20 million at March 31, 2020 and December 31, 2019, respectively, of PHI's consolidated VIE that can only be used to settle the liabilities of the VIE. PHI’s consolidated total liabilities include $43 million and $44 million at March 31, 2020 and December 31, 2019, respectively, of PHI's consolidated VIE for which the VIE creditors do not have recourse to PHI. See Note 16 — Variable Interest Entities for additional information.

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(a)

ACE’s consolidated total assets include $15 million and $17 million at March 31, 2020 and December 31, 2019, respectively, of ACE's consolidated VIE that can only be used to settle the liabilities of the VIE. ACE’s consolidated total liabilities include $36 million and $41 million at March 31, 2020 and December 31, 2019, respectively, of ACE's consolidated VIE for which the VIE creditors do not have recourse to ACE. See Note 16 — Variable Interest Entities for additional information.

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(a)

Reflects an increase of $51 million for the initial revenue requirement for 2019 and a decrease of $68 million related to the annual reconciliation for 2018. The revenue requirement for 2019 and annual reconciliation for 2018 provides for a weighted average debt and equity return on distribution rate base of 6.51%, inclusive of an allowed ROE of 8.91%, reflecting the average rate on 30-year treasury notes plus 580 basis points.

(a)

Reflects an increase of $51 million for the initial revenue requirement for 2020 and a decrease of $62 million related to the annual reconciliation for 2019. The revenue requirement for 2020 and annual reconciliation for 2019 provides for a weighted average debt and equity return on distribution rate base of 6.28%, inclusive of an allowed ROE of 8.38%, reflecting the average rate on 30-year treasury notes plus 580 basis points.

(b)	Reflects a three-year cumulative multi-year plan and total requested revenue requirement increases of $77 million, $37 million and $33 million for years 2020, 2021, and 2022, respectively, to recover capital investments made in 2018 and 2019 and planned capital investments from 2020 to 2022.

(c)	The rates will go into effect on September 21, 2020, subject to refund.

(d)	The rates will go into effect on October 6, 2020, subject to refund.

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

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

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

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(a)	Revenues recognized in the three months ended March 31, 2019, which were included in contract liabilities at December 31, 2018, were approximately $5 million for both Exelon and Generation.

(b)	Revenues recognized in the three months ended March 31, 2020, which were included in contract liabilities at December 31, 2019, were approximately $9 million and $19 million for Exelon and Generation, respectively.

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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 and the United States footprint of MISO, excluding MISO’s Southern Region.

•	New York represents operations within NYISO.

•	ERCOT represents operations within Electric Reliability Council of Texas.

•	Other Power Regions:

•	New England represents the operations within ISO-NE.

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

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

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

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(a)	See Note 18 — Related Party Transactions for additional information on intersegment revenues.

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

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

(d)

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

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

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

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

(b)	Includes revenues from derivatives and leases.

(c)	Other represents activities not allocated to a region. See text above for a description of included activities. Includes unrealized mark-to-market gains of $179 million and losses of $52 million in 2020 and 2019, respectively, and elimination of intersegment revenues.

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

(b)	Other represents activities not allocated to a region. See text above for a description of included activities. Includes unrealized mark-to-market gains of $132 million and losses of $28 million in 2020 and 2019, respectively and the elimination of intersegment RNF.

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

(b)	Includes operating revenues from affiliates of $5 million, $2 million, $6 million, $3 million, $1 million, $2 million and $1 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2020 and $4 million, $1 million, $2 million, $3 million, $2 million, $2 million and $1 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2019.

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

(d)	Includes operating revenues from affiliates of less than $1 million and $3 million at PECO and BGE, respectively, in 2020 and less than $1 million and $4 million at PECO and BGE, respectively, in 2019.

(e)	Includes late payment charge revenues.

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(a)	Unbilled customer revenues are classified in customer accounts receivables, net in the Registrants' Consolidated Balance Sheets.

(a)	Recoveries were not material to the Registrants.

(a)	Recoveries were not material to the Registrants.

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(a)	Primarily reflects the net impacts associated with the remeasurement of the TMI ARO. See Note 9 — Asset Retirement Obligations of the 2019 Form 10-K for additional information.

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(a)	Includes $107 million and $112 million as the current portion of the ARO at March 31, 2020 and December 31, 2019, respectively, which is included in Other current liabilities in Exelon’s and Generation’s Consolidated Balance Sheets.

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(a)	Generation recognized a loss before income taxes for the quarter ended March 31, 2020. As a result, positive percentages represent an income tax benefit for the period presented. At the consolidated level, positive percentages represent income tax expense.

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(a)	The unrecognized tax benefit related to ACE, if recognized, may be included in future base rates and that portion would have no impact to the effective tax rate.

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(a)	See Note 2 - Regulatory Matters for additional information.

(b)	As part of its hedging program, PECO enters into electric supply procurement contracts that do not meet the definition of a derivative instrument.

(c)	The fair value of the DPL economic hedge is not material as of March 31, 2020 and December 31, 2019 and is not presented in the fair value tables below.

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(a)

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

(b)	Of the collateral posted/(received), $644 million and $511 million represents variation margin on the exchanges at March 31, 2020 and December 31, 2019 respectively.

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(a)	As of March 31, 2020, credit collateral held from counterparties where Generation had credit exposure included $29 million of cash and $65 million of letters of credit. The credit collateral does not include non-liquid collateral.

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

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

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

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(a)	Includes outstanding commercial paper at Exelon Corporate of $135 million and $136 million with average interest rates on commercial paper borrowings of 4.20% and 1.92% at March 31, 2020 and December 31, 2019, respectively.

(b)	Includes the consolidated amounts of Pepco, DPL, and ACE.

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(a)	For Energy Efficiency Project Financing, the maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt.

(b)	On February 25, 2020, Pepco entered into a purchase agreement of First Mortgage Bonds for $150 million at 3.28% due on September 23, 2050. The closing date of the issuance is expected to occur in September 2020.

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•	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)	Includes unamortized debt issuance costs which are not fair valued.

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(a)

Exelon excludes cash of $483 million and $373 million at March 31, 2020 and December 31, 2019, respectively, and restricted cash of $110 million at both March 31, 2020 and December 31, 2019, and includes long-term restricted cash of $121 million and $177 million at March 31, 2020 and December 31, 2019, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. Generation excludes cash of $317 million and $177 million at March 31, 2020 and December 31, 2019, respectively, and restricted cash of $63 million and $58 million at March 31, 2020 and December 31, 2019, respectively.

(b)	Includes $78 million and $90 million of cash received from outstanding repurchase agreements at March 31, 2020 and December 31, 2019, respectively, and is offset by an obligation to repay upon settlement of the agreement as discussed in (d) below.

(c)

Includes a derivative liability of $2 million and a derivative asset of $2 million, which have total notional amounts of $826 million and $724 million at March 31, 2020 and December 31, 2019, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do not represent the amount of Exelon and Generation's exposure to credit or market loss.

(d)

Excludes net liabilities of $110 million and $147 million at March 31, 2020 and December 31, 2019, 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)

Collateral posted/(received) from counterparties totaled $126 million, $548 million and $215 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of March 31, 2020. Collateral posted/(received) from counterparties, net of collateral paid to counterparties, totaled $163 million, $551 million and $214 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2019.

(f)	Of the collateral posted/(received), $644 million and $511 million represents variation margin on the exchanges as of March 31, 2020 and December 31, 2019, respectively.

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(a)

ComEd excludes cash of $67 million and $90 million at March 31, 2020 and December 31, 2019, respectively, and restricted cash of $38 million and $33 million at March 31, 2020 and December 31, 2019, respectively, and includes long-term restricted cash of $108 million and $163 million at March 31, 2020 and December 31, 2019, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets.  PECO excludes cash of $30 million and $12 million at March 31, 2020 and December 31, 2019, respectively.  BGE excludes cash of $11 million and $24 million at March 31, 2020 and December 31, 2019, respectively, and restricted cash of $1 million at both March 31, 2020 and December 31, 2019.

(b)	The Level 3 balance consists of the current and noncurrent liability of $36 million and $278 million, respectively, at March 31, 2020, and $32 million and $269 million, respectively, at December 31, 2019, related to floating-to-fixed energy swap contracts with unaffiliated suppliers.

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(a)

PHI excludes cash of $35 million and $57 million at March 31, 2020 and December 31, 2019, respectively, and includes long-term restricted cash of $12 million and $14 million at March 31, 2020 and December 31, 2019, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets.  Pepco excludes cash of $17 million and $29 million at March 31, 2020 and December 31, 2019, respectively. DPL excludes cash of $6 million and $13 million at March 31, 2020 and December 31, 2019, respectively. ACE excludes cash of $8 million and $12 million at March 31, 2020 and December 31, 2019, respectively, and includes long-term restricted cash of $12 million and $14 million at March 31, 2020 and December 31, 2019, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets.

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(a)	Includes a reduction for the reclassification of $177 million and $80 million of realized losses due to the settlement of derivative contracts for the three months ended March 31, 2020 and 2019, respectively.

(b)

Includes $23 million of decreases in fair value and an increase for realized losses due to settlements of $10 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended March 31, 2020. Includes $14 million of decreases in fair value and an increase for realized losses due to settlements of $5 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended March 31, 2019.

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

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

(b)	The fair values do not include cash collateral posted on level three positions of $215 million and $214 million as of March 31, 2020 and December 31, 2019, 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)	Remaining commitments extend through 2026 and include rate credits, energy efficiency programs and delivery system modernization.

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

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(b)

Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The lease term associated with these assets ranges from 1 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $72 million guaranteed by Exelon and PHI, of which $24 million, $30 million and $18 million is guaranteed by Pepco, DPL and ACE, respectively. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.

•	ComEd has 21 sites 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 2025.

•	PECO has 8 sites 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 4 sites that currently require some level of remediation and/or ongoing activity. BGE expects the majority of the remediation at these sites to continue through at least 2021.

•	DPL has 1 site that is currently under study and the required cost at the site is not expected to be material.

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(a)	AOCI amounts are included in the computation of net periodic pension and OPEB cost. See Note 10 — Retirement Benefits for additional information. See Exelon's Statements of Operations and Comprehensive Income for individual components of AOCI.

(b)	All amounts are net of noncontrolling interests.

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

(b)	These are unrestricted assets to Exelon and Generation.

(c)	Exelon’s and Generation’s balances include unrestricted assets of $20 million as of March 31, 2020 and December 31, 2019.

(d)	Exelon’s and Generation’s balances include liabilities with recourse of $4 million and $3 million as of March 31, 2020 and December 31, 2019, respectively.

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•

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 18 — Commitments and Contingencies of the Exelon 2019 Form 10-K for more details,

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

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

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(a)

These items represent amounts on the unconsolidated VIE balance sheets, not in Exelon’s or Generation’s Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs. Exelon and Generation do not have any exposure to loss as they do not have a carrying amount in the equity investment VIEs as of March 31, 2020 and December 31, 2019.

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(a)

Generation’s utility tax represents gross receipts tax related to its retail operations, and the Utility Registrants' utility taxes represents municipal and state utility taxes and gross receipts taxes related to their operating revenues. The offsetting collection of utility taxes from customers is recorded in revenues in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.

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

(b)	Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units, including the elimination of income taxes related to all NDT fund activity for those units. See Note 9 — Asset Retirement Obligations of the Exelon 2019 Form 10-K for additional information regarding the accounting for nuclear decommissioning.

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

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

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

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

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(a)

Includes the elimination of decommissioning-related activities 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 9 — Asset Retirement Obligations of the Exelon 2019 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 to results of operations.

(c)	Reflects the change in ComEd's distribution and energy efficiency formula rates. See Note 2 — Regulatory Matters for additional information.

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(a)	Primarily includes accrued payroll, bonuses and other incentives, vacation and benefits.

(a)	Generation has an ICC-approved RFP contract with ComEd to provide a portion of ComEd’s electricity supply requirements. Generation also sells RECs and ZECs to ComEd.

(b)

For the three months ended March 31, 2020, ComEd’s Purchased power from Generation of $97 million is recorded as Operating revenues from ComEd of $90 million and Purchased power and fuel from ComEd of $7 million at Generation. For the three months ended March 31, 2019, ComEd’s Purchased power from Generation of $97 million is recorded as Operating revenues from ComEd of $94 million and Purchased power and fuel from ComEd of $3 million at Generation.

(c)	Generation provides electric supply to PECO under contracts executed through PECO’s competitive procurement process. In addition, Generation has a ten-year agreement with PECO to sell solar AECs.

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(d)	Generation provides a portion of BGE’s energy requirements under its MDPSC-approved market-based SOS and gas commodity programs.

(e)	Generation provides electric supply to Pepco under contracts executed through Pepco's competitive procurement process approved by the MDPSC and DCPSC.

(f)	Generation provides a portion of DPL's energy requirements under its MDPSC and DPSC approved market based SOS and gas commodity programs.

(g)	Generation provides electric supply to ACE under contracts executed through ACE's competitive procurement process.

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(a)

At March 31, 2020 and December 31, 2019, Generation also had a contract liability with ComEd for $27 million and $37 million, respectively, that was included in Other liabilities on Generation’s Consolidated Balance Sheets. At March 31, 2020 and December 31, 2019, ComEd had a Current Payable to Generation of $42 million and $41 million, respectively, on its Consolidated Balance Sheets, which consisted of Generation’s Current Receivable from ComEd, partially offset by Generation’s contract liability with ComEd.

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

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

•	Lower capacity revenue;

•	Lower realized energy prices;

•	Higher nuclear outage days;

•	Higher net unrealized and realized losses NDT funds; and

•	Unfavorable weather conditions at PECO, DPL Delaware and ACE.

•	Higher mark-to-market gains;

•	The approval of the New Jersey ZEC program in the second quarter of 2019;

•	An income tax settlement at Generation;

•	Regulatory rate increases at BGE, DPL, and ACE; and

•	Higher electric distribution earnings at ComEd primarily due to distribution formula rate timing, partially offset by lower allowed electric distribution ROE due to a decrease in treasury rates.

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

(b)	In 2019, primarily reflects accelerated depreciation and amortization expenses associated with the early retirement of the TMI nuclear facility and a benefit associated with a remeasurement of the TMI ARO. In 2020, primarily reflects accelerated depreciation and amortization expenses associated with the early retirement of certain fossil sites.

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

(d)	Represents elimination from Generation’s results of the noncontrolling interests related to certain exclusion items, primarily related to unrealized gains and losses on NDT fund investments for CENG units.

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•	Lower capacity revenue;

•	Lower realized energy prices;

•	Higher nuclear outage days; and

•	Higher net unrealized and realized losses on NDT funds;

•	Higher mark-to-market gains;

•	The approval of the New Jersey ZEC program in the second quarter of 2019; and

•	An income tax settlement.

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

(b)	Includes results of transactions with ComEd.

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

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

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(a)	See Note 11 — Derivative Financial Instruments for additional information on mark-to-market gains (losses).

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(a)	Primarily reflects increase from prior year due to the benefit recorded in the first quarter of 2019 for the remeasurement of the TMI ARO.

(b)	Primarily reflects decreased costs related to the permanent cease of generation operations at TMI and lower labor costs resulting from previous cost management programs.

(a)	Unrealized gains (losses), realized gains and interest and dividend income on the NDT funds are associated with the Non-Regulatory Agreement units.

(b)	Contractual elimination of income tax expense is associated with the income taxes on the NDT funds of the Regulatory Agreement units.

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(a)

ComEd is allowed to recover from or refund to customers the difference between its annual credit loss expense and the amounts collected in rates annually through a rider mechanism. During the three months ended March 31, 2020, ComEd recorded a net decrease in credit losses account due to the timing of regulatory cost recovery. An equal and offsetting amount has been recognized in Operating revenues for the period presented.

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(a)	Reflects ongoing capital expenditures.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

•	See Note 9 — Income Taxes of the Combined Notes to Consolidated Financial Statements and the Registrants' Consolidated Statement of Cash Flows for additional information on income taxes.

•	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.

•	Variances in capital expenditures are primarily due to the timing of cash expenditures for capital projects. Refer below for additional information on projected capital expenditure spending.

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

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•	Changes in short-term borrowings, net, is driven by repayments on and issuances of notes due in less than 365 days. Refer to 12 — Debt and Credit Agreements of the Consolidated Financial Statements for additional information on short-term borrowings.

•	Long-term debt, net, varies due to debt issuances and redemptions each year. Refer to 12 — Debt and Credit Agreements of the Consolidated Financial Statements for additional information on debt issuances. Refer to debt redemptions tables below for more information.

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

•	Exelon’s ability to pay dividends on its common stock depends on the receipt of dividends paid by its operating subsidiaries. The payments of dividends to Exelon by its subsidiaries in turn depend on their results of operations and cash flows and other items affecting retained earnings. See Note 14 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements

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•	For the three months ended March 31, 2020, other financing activities primarily consist of debt issuance costs. See Note 12 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants’ debt issuances.

(a)	On April 1, 2020, Generation repurchased $188 million of tax-exempt bonds.

(b)	See Note 12 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of nonrecourse debt.

(c)

Antelope Valley’s nonrecourse debt of approximately $479 million was reclassified as current in Exelon’s and Generation’s Consolidated Balance Sheets in the first quarter of 2019 and continues to be classified as current as of March 31, 2020 as a result of the PG&E bankruptcy filing on January 29, 2019. See Note 12 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.

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

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

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

(b)	On April 23, 2020, BGE received approval from the MDPSC for $1.5 billion long-term financing authority.

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

(b)

For ComEd, the changes in fair value are recorded as a change in regulatory assets. As of March 31, 2020, ComEd recorded a regulatory asset of $314 million related to its mark-to-market derivative liabilities with unaffiliated suppliers. For the three months ended March 31, 2020, ComEd recorded $23 million of decreases in fair value and an increase for realized losses due to settlements of $10 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers.

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

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

(b)	Amounts are shown net of collateral paid to and received from counterparties (and offset against mark-to-market assets and liabilities) of $889 million at March 31, 2020.

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

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

(b)	Amounts are shown net of collateral paid to and received from counterparties (and offset against mark-to-market assets and liabilities) of $889 million at March 31, 2020.

(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, 2020, credit collateral held from counterparties where Generation had credit exposure included $29 million of cash and $65 million of letters of credit.

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