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 5 — ~~Regulatory Matters~~ ~~for additional details),~~

Generation provided a $400 million loan to CENG. As of September 30, 2017, the remaining obligation is $328 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 18 — ~~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,~~

Generation provides a guarantee of approximately $8 million associated with hazardous waste management facilities and underground storage tanks. In addition, EDF executed a reimbursement agreement that provides reimbursement to Exelon for 49.99% of any amounts paid by Generation under this guarantee,

Generation and EDF are the members-insured with Nuclear Electric Insurance Limited and have assigned the loss benefits under the insurance and the NEIL premium costs to CENG and guarantee the obligations of CENG under these insurance programs in proportion to their respective member interests (see Note 18 — ~~Commitments and Contingencies~~ ~~for more details), and~~

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— ~~(Continued)~~

(Dollars in millions, except per share data, unless otherwise noted)

Note 3 — Regulatory Matters

~~Exelon has executed an agreement to provide up to $245 million to support~~On April 27, 2021, the ~~operations of CENG as well as a $165 million guarantee of CENG’s cash pooling agreement with its subsidiaries.~~

~~As of September 30, 2017 and December 31, 2016, Exelon, PHI and ACE provided~~NJBPU approved the ~~following support to their respective consolidated VIE:~~

~~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~~settlement filed by ACE and the third parties to ~~ATF~~the proceeding. The approved settlement addresses all material aspects of ACE’s filing, including ACE’s ability to implement the CIP prospectively effective July 1, 2021. As a result of this decoupling mechanism, operating revenues will no longer be impacted by abnormal weather or usage for most customers. Starting in third quarter of 2021, ACE will record alternative revenue program revenues for its best estimate of the ~~right to collect a non-bypassable Transition Bond Charge~~distribution revenue impacts resulting from ~~ACE customers pursuant to bondable stranded costs rate orders issued~~future changes in CIP rates that it believes are probable of approval by the NJBPU in accordance with this mechanism.

Advanced Metering Infrastructure Filing (Exelon, PHI, and ACE). On August 26, 2020, ACE filed an ~~amount sufficient~~application with the NJBPU as was required seeking approval to ~~fund~~deploy a smart energy network in alignment with New Jersey’s Energy Master Plan and Clean Energy Act. The proposal consisted of estimated costs totaling $220 million with deployment taking place over a 3-year implementation period from approximately 2021 to 2024 that involves the ~~principal~~installation of an integrated system of smart meters for all customers accompanied by the requisite communications facilities and ~~interest payments on transition bonds~~data management systems.

On July 14, 2021, the NJBPU approved the settlement filed by ACE and ~~related taxes,~~the third parties to the proceeding. The approved settlement addresses all material aspects of ACE's smart energy network deployment plan, including cost recovery of the investment costs, incremental O&M expenses, and ~~fees. During~~ the ~~three~~unrecovered balance of existing infrastructure through future distribution rates.

Regulatory Assets and nine months ended September 30, 2017, ACE transferred $11 million and $39 million to ATF, respectively. During the three and nine months ended September 30, 2016, ACE transferred $20 million and $47 million to ATF, respectively.Liabilities

~~For each of the consolidated VIEs, except as otherwise noted:~~

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

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

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

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

The ~~carrying amounts and classification of the consolidated VIEs’~~Utility Registrants' regulatory assets and liabilities ~~included~~have not changed materially since December 31, 2020, unless noted below. See Note 3 — Regulatory Matters of the Exelon 2020 Form 10-K for additional information on the specific regulatory assets and liabilities.

ComEd. Regulatory assets increased $93 million primarily due to an increase of $47 million in the Electric Distribution Formula Rate Annual Reconciliations regulatory asset and $127 million in the Energy Efficiency Costs regulatory asset, partially offset by a decrease of $87 million in the renewable energy regulatory asset.

PECO. Regulatory assets increased $135 million primarily due to an increase of $123 million in the Deferred Income Taxes regulatory asset and $14 million in the Vacation Accrual regulatory asset. Regulatory liabilities increased by $66 million primarily due to an increase of $71 million in the Nuclear Decommissioning regulatory liability partially offset by a $18 million decrease in the Electric Energy and Natural Gas Costs regulatory liability.

BGE. Regulatory liabilities decreased $116 million primarily due to a decrease of $128 million in the Deferred Income Taxes regulatory liability offset by an increase of $12 million in Other regulatory liabilities.

Pepco. Regulatory liabilities decreased $108 million primarily due to a decrease of $89 million in the Deferred Income Taxes regulatory liability and $19 million in the Transmission Formula Rate regulatory liability.

DPL. Regulatory liabilities decreased $45 million primarily due to a decrease of $41 million in the Deferred Income Taxes regulatory liability.

ACE. Regulatory liabilities decreased $61 million primarily due to a decrease of $67 million in the Deferred Income Taxes regulatory liability partially offset by an increase of $14 million in the Stranded Costs regulatory liability.

Capitalized Ratemaking Amounts Not Recognized

The following table presents authorized amounts capitalized for ratemaking purposes related to earnings on shareholders’ investment that are not recognized for financial reporting purposes in Exelon's and the Utility Registrant's Consolidated Balance Sheets. These amounts will be recognized as revenues in the related Consolidated Statements of Operations and Comprehensive Income in the periods they are billable to the Utility Registrants' ~~consolidated financial statements at September 30, 2017 and December 31, 2016 are as follows:~~customers.

September 30, 2017 December 31, 2016
Successor Successor

Exelon^(a)
Generation
PHI ^(a)
ACE
Exelon^(a)(b)
Generation BGE
PHI^(a)
ACE
Current assets $ 657
$ 644
$ 13
$ 9
$ 954
$ 916
$ 23
$ 14
$ 9
Noncurrent assets 9,252
9,222
30
22
8,563
8,525
3
35
23
Total assets $ 9,909

$ 9,866

$ 43
$ 31

$ 9,517

$ 9,441

$ 26

$ 49
$ 32
Current liabilities $ 404
$ 367
$ 37
$ 33
$ 885
$ 802
$ 42
$ 42
$ 37
Noncurrent liabilities 3,290
3,215
75
67
2,713
2,612
—
101
89
Total liabilities $ 3,694

$ 3,582

$ 112
$ 100

$ 3,598

$ 3,414

$ 42

$ 143
$ 126

~~_________~~


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


~~(b)~~	~~Includes certain purchase accounting adjustments not pushed down to the BGE standalone entity.~~

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— ~~(Continued)~~

(Dollars in millions, except per share data, unless otherwise noted)

Note 3 — Regulatory Matters


	Exelon		ComEd(a)		PECO		BGE(b)		PHI		Pepco(c)		DPL(c)		ACE
September 30, 2021	$	44	$	—	$	—	$	39	$	5	$	3	$	2	$	—

December 31, 2020	51		(1)		—		45		7		4		3		—

__________

(a)Reflects ComEd's unrecognized equity returns/(losses) earned/(incurred) 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.

Generation Regulatory Matters (Exelon and Generation)

Impacts of the February 2021 Extreme Cold Weather Event and Texas-based Generating Assets ~~and Liabilities of Consolidated VIEs~~Outages

~~Included~~Beginning on February 15, 2021, Generation’s Texas-based generating assets within the ~~balances above are assets~~ERCOT market, specifically Colorado Bend II, Wolf Hollow II, and ~~liabilities~~Handley, experienced outages as a result of extreme cold weather conditions. In addition, those weather conditions drove increased demand for service, dramatically increased wholesale power prices, and also increased gas prices in certain ~~consolidated VIEs for which the assets can only be used to settle obligations of those VIEs, and liabilities that creditors or beneficiaries do not have recourse~~regions. In response to the ~~general~~high demand and significantly reduced total generation on the system, the PUCT directed ERCOT to use an administrative price cap of $9,000 per MWh during firm load shedding events.

Due to these events, a number of ERCOT market participants experienced bankruptcies or defaulted on payments to ERCOT, resulting in approximately a $3.0 billion payment shortfall in collections, which is allocated to the remaining ERCOT market participants. As of September 30, ~~2017 and December 31, 2016, these assets and liabilities primarily consisted~~2021, Generation has recorded its estimated portion of this obligation of approximately $17 million on a discounted basis, which is to be paid over a term of 83 years. ERCOT rules historically have limited recovery of default from market participants to $2.5 million per month market-wide. In February 2021, the PUCT gave ERCOT discretion to disregard those rules, but ERCOT has declined to exercise that discretion thus far. On March 8, 2021, a third party filed a notice of appeal in the Court of Appeals for the Third District of Texas challenging the validity of the ~~following:~~

September 30, 2017 December 31, 2016
Successor Successor

Exelon ^(a)

Generation
PHI ^(a)
ACE
Exelon^(a)(b)
Generation BGE
PHI^(a)
ACE
Cash and cash equivalents $ 130
$ 130
$ —
$ —
$ 150
$ 150
$ —
$ —
$ —
Restricted cash 85
76
9
9
59
27
23
9
9
Accounts receivable, net

Customer 139
139
—
—
371
371
—
—
—
Other 25
25
—
—
48
48
—
—
—
Mark-to-market derivatives assets —
—
—
—
31
31
—
—
—
Inventory

Materials and supplies 196
196
—
—
199
199
—
—
—
Other current assets 56
52
4
—
50
44
—
5
—
Total current assets 631

618

13
9
908

870

23

14
9
Property, plant and equipment, net 6,213
6,213
—
—
5,415
5,415
—
—
—
Nuclear decommissioning trust funds 2,415
2,415
—
—
2,185
2,185
—
—
—
Goodwill —
—
—
—
47
47
—
—
—
Mark-to-market derivative assets —
—
—
—
23
23
—
—
—
Other noncurrent assets 261
231
30
22
315
277
3
35
23
Total noncurrent assets 8,889

8,859

30
22
7,985

7,947

3

35
23
Total assets $ 9,520

$ 9,477

$ 43
$ 31
$ 8,893

$ 8,817

$ 26

$ 49
$ 32
Long-term debt due within one year $ 182
$ 146
$ 36
$ 32
$ 181
$ 99
$ 41
$ 40
$ 35
Accounts payable 104
104
—
—
269
269
—
—
—
Accrued expenses 90
89
1
1
119
116
1
2
2
Mark-to-market derivative liabilities —
—
—
—
60
60
—
—
—
Unamortized energy contract liabilities 17
17
—
—
15
15
—
—
—
Other current liabilities 11
11
—
—
30
30
—
—
—
Total current liabilities 404
367
37
33
674
589
42

42
37
Long-term debt 1,172
1,097
75
67
641
540
—
101
89
Asset retirement obligations 2,009
2,009
—
—
1,904
1,904
—
—
—
Pension obligation^(c)
—
—
—
—
9
9
—
—
—
Unamortized energy contract liabilities 9
9
—
—
22
22
—
—
—
Other noncurrent liabilities 94
94
—
—
106
106
—
—
—
Total noncurrent liabilities 3,284
3,209
75
67
2,682
2,581
—

101
89
Total liabilities $ 3,688
$ 3,576
$ 112
$ 100
$ 3,356
$ 3,170
$ 42

$ 143
$ 126

~~_________~~


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


~~(b)~~	~~Includes certain purchase accounting adjustments not pushed down to the BGE standalone entity.~~


~~(c)~~	Includes the retail gas pension obligation, which is presented as a net asset balance within the Prepaid pension asset line item on Generation’s Consolidated Balance Sheets. See Note 14 - Retirement Benefits for additional details.

~~Unconsolidated Variable Interest Entities~~

~~Exelon’s~~PUCT's order to ERCOT in February 2021. Generation intervened in that appeal and ~~Generation’s variable interests in unconsolidated VIEs generally include equity investments~~filed its initial brief on July 7, 2021. On May 7, 2021, Generation filed a declaratory action and ~~energy purchase and sale contracts. For the equity investments, the carrying amount~~request for judicial review of the ~~investments is reflected on Exelon’s~~PUCT's order in the District Court of Travis County, Texas. Generation subsequently requested that the District Court of Travis County, Texas stay its proceeding pending action by the Court of Appeals in the third party proceeding. Exelon and ~~Generation’s Consolidated Balance Sheets in Investments. For~~Generation cannot predict the ~~energy purchase and sale contracts (commercial agreements),~~outcome of these proceedings or the carrying amount of assets and liabilities in Exelon’s and Generation’s Consolidated Balance Sheets that relate to their involvement with the VIEs are predominantly related to working capital accounts

financial statement impact.

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— ~~(Continued)~~

(Dollars in millions, except per share data, unless otherwise noted)

Note 3 — Regulatory Matters

Additionally, several legislative proposals were introduced in the Texas legislature during February and ~~generally represent~~March 2021 concerning the amount, timing and allocation of recovery of the $3.0 billion shortfall, as well as recovery of other costs associated with the PUCT's directive to set prices at $9,000 per MWh. Two of these proposals were enacted into law in June 2021 and establish financing mechanisms that ERCOT and certain market participants can utilize to fund amounts owed to ERCOT. Generation participated in proceedings before the PUCT addressing the proposed allocation of the $2.1 billion in securitized funds for reliability and ancillary service charges over $9,000/MWh. In September 2021, Generation entered into a settlement agreement and stipulation to resolve the allocation issues. The PUCT approved the settlement agreement and stipulation on October 13, 2021.

In addition, other legislative proposals were introduced in the Texas legislature during February and March 2021 addressing cold-weather preparation for power plants and natural gas production and transportation infrastructure and the market structure for reliability services. The Texas legislature addressed these proposals by enacting a bill with a broad set of market reforms that, among other things, directed the PUCT to establish weatherization standards for electric generators within six months of enactment and gave the PUCT authority to impose administrative penalties if the new proposed standards, once adopted, are not met. On October 21, 2021, the PUCT adopted rule change requiring generators by December 1, 2021 to complete a number of specified winter readiness preparations and to submit to ERCOT a report describing and certifying the completion of those preparations. The PUCT described these requirements as the first phase of its actions with respect to winter preparedness, to be followed by a second phase consisting of a year-round set of weather preparedness standards to be informed by a weather study that is being conducted by ERCOT.

The legislation also directs the PUCT to evaluate whether additional ancillary services are needed for reliability in the ERCOT power region to provide adequate incentives for dispatchable generation. Exelon and others have submitted various proposals to the PUCT with respect to a range of potential market reforms, including the implementation of additional ancillary service products as well as changes to the high system-wide offer cap and operating reserve demand curve, which remain pending. On September 23, 2021, the PUCT solicited comments regarding whether it should set ERCOT’s high system-wide offer cap at $4,500/MWh if the PUCT takes action to amend its rules with respect to that cap. Exelon and others submitted comments to the PUCT, which remain pending. The PUCT is expected to address potential changes to ERCOT’s market rules later in 2021.

In February 2021, more than 70 local distribution companies (LDCs) and natural gas pipelines in multiple states throughout the mid-continent region, where Generation serves natural gas customers, issued operational flow orders (OFOs), curtailments or other limitations on natural gas transportation or use to manage the operational integrity of the applicable LDC or pipeline system. When in effect, gas transportation or use above these limitations is subject to significant penalties according to the applicable LDCs’ and natural gas pipelines’ tariffs. Gas transportation and supply in many states became restricted due to wells freezing and pipeline compression disruption, while demand was increasing due to the extreme cold temperatures, resulting in extremely high natural gas prices. Due to the extraordinary circumstances, many LDCs and natural gas pipelines have either voluntarily waived or have sought applicable regulatory approvals to waive the tariff penalties associated with the extreme weather event. During March 2021, three natural gas pipelines filed individual petitions with FERC requesting approval to waive OFO penalties. Generation also filed motions in March 2021 to intervene and filed comments in support of these FERC waiver requests. On March 25, 2021, FERC issued an order on one of the petitions approving a pipeline’s request for a limited waiver of penalties for February 15, 2021. On April 23, 2021, Generation and several other entities filed a request at FERC for rehearing of this order which was denied on May 24, 2021. Generation and the other entities filed an appeal of the rehearing of the order with the U.S. Court of Appeals for the D.C. Circuit on July 21, 2021. Additionally, Generation and the other entities filed a complaint requesting that FERC expand the order to include additional days of the weather event in February, from February 16 through February 19, 2021. On October 21, 2021, FERC denied the complaint finding that a pipeline has the discretion whether to waive penalties under its tariff. Generation is evaluating whether to seek rehearing and appeal of the FERC order. During April 2021, FERC issued orders on the remaining petitions approving the requests to waive the penalties. During May 2021, an LDC filed a motion with the Kansas Corporation Commission (KCC) requesting the KCC to grant a waiver from the tariff and allow the LDC to reduce the amounts ~~owed~~assessed by ~~or owed to,~~permitting the removal of a multiplier from the penalty calculation. On October 8, 2021, a settlement was filed with the KCC that, if approved, would resolve this matter. Exelon and Generation ~~for~~cannot predict the deliveries associated with the current billing cycles under the commercial agreements. Further, Exelon and Generation have not provided material debt or equity support, liquidity arrangements or performance guarantees associated with these commercial agreements.

~~As of September 30, 2017, Exelon's and Generation's unconsolidated VIEs consist of:~~

~~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 and energy generating facilities for which Generation has concluded that consolidation is not required.~~

~~As of September 30, 2017 and December 31, 2016, ComEd, PECO, BGE, PHI, Pepco, ACE, and DPL did not have any material unconsolidated VIEs.~~

As of September 30, 2017 and December 31, 2016, Exelon and Generation had significant unconsolidated variable interests in seven and eight VIEs, respectively, for which Exelon or Generation, as applicable, was not the primary beneficiary; including certain equity investments and certain commercial agreements. The decrease in the number of unconsolidated VIEs is due to the sale of an equity investment in an energy generating facility. Exelon and Generation only include unconsolidated VIEs that are individually material in the tables below. However, Generation has several individually immaterial VIEs that in aggregate represent a total investment of $17 million. These immaterial VIEs are equity and debt securities in energy development companies. The maximum exposure to loss related to these securities is limited to the $17 million included in Investments on Exelon’s and Generation’s Consolidated Balance Sheets. ~~The risk of a loss was assessed to be remote and, accordingly, Exelon and Generation have not recognized a liability associated with any portion~~outcome of the ~~maximum exposure to loss.~~

~~In June 2015, 2015 ESA Investco, LLC, then a wholly owned subsidiary of Generation, entered into an arrangement to purchase a 90% equity interest~~pending FERC complaint proceeding, the KCC proceeding, or the determinations made by the LDCs and 99% of the tax attributes of a distributed energy company, which is an unconsolidated VIE. In November 2015, Generation sold 69% of its equity interest in 2015 ESA Investco, LLC to a tax equity investor. Generation and the tax equity investor contributed a total of $227 million of equity incrementally from inception through the first quarter of 2017 in proportion of their ownership interests. Generation and the tax equity investor provided a parental guarantee of up to $275 million in proportion to their ownership interests in support of 2015 ESA Investco, LLC's obligation to make equity contributions to the distributed energy company. As all equity contributions were made as of the first quarter 2017, there is no further payment obligation under the parental guarantee.

natural gas pipelines.

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— ~~(Continued)~~

(Dollars in millions, except per share data, unless otherwise noted)

~~The following tables present summary information about Exelon's and Generation’s significant unconsolidated VIE entities:~~

September 30, 2017
Commercial
Agreement
VIEs

Equity
Investment
VIEs
Total
Total assets^(a)
$ 635
$ 519
$ 1,154
Total liabilities^(a)
39
229
268
Exelon's ownership interest in VIE^(a)
—
259
259
Other ownership interests in VIE^(a)
596
31
627
Registrants’ maximum exposure to loss:
Carrying amount of equity method investments —
259
259
Contract intangible asset 9
—
9
Debt and payment guarantees —
—
—
Net assets pledged for Zion Station decommissioning^(b)
4
—
4

December 31, 2016
Commercial
Agreement
VIEs

Equity
Investment
VIEs
Total
Total assets^(a)
$ 638
$ 567
$ 1,205
Total liabilities^(a)
215
287
502
Exelon's ownership interest in VIE^(a)
—
248
248
Other ownership interests in VIE^(a)
423
32
455
Registrants’ maximum exposure to loss:
Carrying amount of equity method investments —
264
264
Contract intangible asset 9
—
9
Debt and payment guarantees —
3
3
Net assets pledged for Zion Station decommissioning^(b)
9
—
9

~~_________~~


~~(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 $57 million and $113 million as of September 30, 2017 and December 31, 2016, respectively; offset by payables to ZionSolutions LLC of $53 million and $104 million as of September 30, 2017 and December 31, 2016, 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.

For each of the unconsolidated VIEs, Exelon and Generation have assessed the risk of a loss equal to their maximum exposure to be remote and, accordingly, Exelon and Generation have not recognized a liability associated with any portion of the maximum exposure to loss. In addition, there are no material agreements with, or commitments by, third parties that would affect the fair value or risk of their variable interests in these VIEs.

~~BGE~~

The financing trust of BGE, BGE Capital Trust II, was created in 2003 for the purpose of issuing mandatorily redeemable trust preferred securities. In the third quarter of 2017, BGE redeemed the securities pursuant to the optional redemption provisions of the Indenture, under which the subordinated debt securities were issued, and dissolved BGE Capital Trust II. Prior to dissolution the BGE Capital Trust II was not consolidated in Exelon's or BGE's financial statements. BGE concluded it did not have a significant variable interest in BGE Capital Trust II as BGE financed its equity interest in the financing trust through the issuance of subordinated debt and, therefore, had no equity at risk. See Note ~~14 - Debt and Credit Agreements of the Exelon 2016 Form 10-K for additional information.~~

~~Table of Contents~~

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ 3 — ~~(Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

~~4. Mergers, Acquisitions and Dispositions (Exelon, Generation, PHI, Pepco and DPL)~~

~~Acquisition of James A. FitzPatrick Nuclear Generating Station (Exelon and Generation)~~

On March 31, 2017, Generation acquired the 838 MW single-unit James A. FitzPatrick (FitzPatrick) nuclear generating station located in Scriba, New York from Entergy Nuclear FitzPatrick LLC (Entergy) for a total purchase price of $289 million, which consisted of a cash purchase price of $110 million and a net cost reimbursement to and on behalf of Entergy of $179 million. As part of the acquisition agreements, Generation provided nuclear fuel and reimbursed Entergy for incremental costs to prepare for and conduct a plant refueling outage; and Generation reimbursed Entergy for incremental costs to operate and maintain the plant for the period after the refueling outage through the acquisition closing date. These reimbursements covered costs that Entergy otherwise would have avoided had it shut down the plant as originally intended in January 2017. The amounts reimbursed by Generation were offset by FitzPatrick's electricity and capacity sales revenues for this same post-outage period. As part of the transaction, Generation received the FitzPatrick NDT fund assets and assumed the obligation to decommission FitzPatrick. The NRC license for FitzPatrick expires in 2034. As of September 30, 2017, Generation had remitted purchase price consideration of $289 million (including $235 million of cash and $54 million of nuclear fuel) to and on behalf of Entergy.

The fair values of FitzPatrick’s assets and liabilities were determined based on significant estimates and assumptions that are judgmental in nature, including projected future cash flows (including timing), discount rates reflecting risk inherent in the future cash flows and future power and fuel market prices. The valuations performed in the first quarter of 2017 to determine the fair value of the FitzPatrick assets acquired and liabilities assumed were preliminary. Accounting guidance provides that the allocation of the purchase price may be modified up to one year from the date of the acquisition to the extent that additional information is obtained about the facts and circumstances that existed as of the acquisition date.

During the third quarter of 2017, certain modifications were made to the initial preliminary valuation amounts for acquired property, plant and equipment, the decommissioning ARO, pension and OPEB obligations and related deferred tax liabilities, resulting in a $3 million net increase in assets acquired and liabilities assumed. Additionally, in the third quarter a purchase price settlement payment of $4 million was received from Entergy. Consequently, Exelon and Generation recorded an additional after-tax bargain purchase gain of $7 million for the three months ended September 30, 2017. For the nine months ended September 30, 2017, the after-tax bargain purchase gain of $233 million is included within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income and primarily reflects differences in strategies between Generation and Entergy for the intended use and ultimate decommissioning of the plant. There are no further adjustments expected to be made to the allocation of the purchase price. See Note 13 - Nuclear Decommissioning and Note 14 - Retirement Benefits for additional information regarding the FitzPatrick decommissioning ARO and pension and OPEB updates.

~~Table of Contents~~

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

The following table summarizes the acquisition-date fair value of the consideration transferred and the assets and liabilities assumed for the FitzPatrick acquisition by Generation as of September 30, 2017:

Cash paid for purchase price $ 110
Cash paid for net cost reimbursement 125
Nuclear fuel transfer 54
Total consideration transferred $ 289

Identifiable assets acquired and liabilities assumed
Current assets $ 60
Property, plant and equipment 298
Nuclear decommissioning trust funds 807
Other assets^(a)
114
Total assets $ 1,279

Current liabilities $ 6
Nuclear decommissioning ARO 444
Pension and OPEB obligations 33
Deferred income taxes 149
Spent nuclear fuel obligation 110
Other liabilities 15
Total liabilities $ 757
Total net identifiable assets, at fair value $ 522

Bargain purchase gain (after-tax) $ 233

~~_________~~


~~(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 24-Commitments and Contingencies of the Exelon 2016 Form 10-K for additional background regarding SNF obligations to the DOE.

For the three and nine months ended September 30, 2017, Exelon and Generation incurred $6 million and $53 million, respectively, of merger and integration related costs which are included within Operating and maintenance expense in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.

~~Acquisition of ConEdison Solutions (Exelon and Generation)~~

On September 1, 2016, Generation acquired the competitive retail electricity and natural gas business of Consolidated Edison Solutions, Inc. (ConEdison Solutions), a subsidiary of Consolidated Edison, Inc. for a purchase price of $257 million including net working capital of $204 million. The renewable energy, sustainable services and energy efficiency businesses of ConEdison Solutions are excluded from the transaction.

The fair values of ConEdison Solutions' assets and liabilities were determined based on significant estimates and assumptions that are judgmental in nature, including projected future cash flows (including timing), discount rates reflecting risk inherent in the future cash flows and future power and fuel market prices. The purchase price equaled the estimated fair value of the net assets acquired and the liabilities assumed and, therefore, no goodwill or bargain purchase was recorded as of the acquisition date. The purchase price allocation is now final.

~~Table of Contents~~

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

~~The following table summarizes the final acquisition-date fair value of the consideration transferred and the assets and liabilities assumed for the ConEdison Solutions acquisition by Generation:~~

Total consideration transferred $ 257

Identifiable assets acquired and liabilities assumed
Working capital assets $ 204
Property, plant and equipment 2
Mark-to-market derivative assets 6
Unamortized energy contract assets 100
Customer relationships 9
Other assets 1
Total assets $ 322

Mark-to-market derivative liabilities $ 65
Total liabilities $ 65
Total net identifiable assets, at fair value $ 257

~~Merger with Pepco Holdings, Inc. (Exelon)~~

~~Description of Transaction~~

On March 23, 2016, Exelon completed the merger contemplated by the Merger Agreement among Exelon, Purple Acquisition Corp., a wholly owned subsidiary of Exelon (Merger Sub) and Pepco Holdings, Inc. (PHI). As a result of that merger, Merger Sub was merged into PHI (the PHI Merger) with PHI surviving as a wholly owned subsidiary of Exelon and Exelon Energy Delivery Company, LLC (EEDC), a wholly owned subsidiary of Exelon which also owns Exelon's interests in ComEd, PECO and BGE (through a special purpose subsidiary in the case of BGE). Following the completion of the PHI Merger, Exelon and PHI completed a series of internal corporate organization restructuring transactions resulting in the transfer of PHI’s unregulated business interests to Exelon and Generation and the transfer of PHI, Pepco, DPL and ACE to a special purpose subsidiary of EEDC.

Regulatory Matters

Approval of the merger in Delaware, New Jersey, Maryland and the District of Columbia was conditioned upon Exelon and PHI agreeing to certain commitments including where applicable: customer rate credits, funding for energy efficiency and delivery system modernization programs, a green sustainability fund, workforce development initiatives, charitable contributions, renewable generation and other required commitments. In addition, the orders approving the merger in Delaware, New Jersey, and Maryland include a “most favored nation” provision which, generally, requires allocation of merger benefits proportionally across all the jurisdictions.

During the third and fourth quarters of 2016, Exelon and PHI filed proposals in Delaware, New Jersey and Maryland for amounts and allocations reflecting the application of the most favored nation provision, resulting in a total nominal cost of commitments of $513 million, excluding renewable generation commitments (approximately $444 million on a net present value basis amount, excluding renewable generation commitments and charitable contributions). These filings reflected agreements reached with certain parties to the merger proceedings in these jurisdictions. In 2016, the DPSC and NJBPU approved the amounts and allocations of the additional merger benefits for Delaware and New Jersey, respectively. On April 12, 2017, the MDPSC issued an order approving the amounts of the additional merger benefits for Maryland, but amending the proposed allocations of the benefits. The amended allocations do not have a material effect on any of the Registrants' financial statements. No changes in commitment cost levels are required in the District of Columbia.

During the second quarter of 2017, Exelon finalized the application of $8 million funding for low- and moderate-income customers in the Pepco Maryland and DPL Maryland service territories. This resulted in an adjustment to merger commitment costs recorded at Exelon Corporate, Pepco, and DPL. Exelon Corporate recorded an increase of $8 million and Pepco and DPL recorded a decrease of $6 million and $2 million, respectively, in Operating and maintenance expense.

~~Table of Contents~~

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

~~The following amounts represent total commitment costs for Exelon, PHI, Pepco, DPL and ACE that have been recorded since the acquisition date:~~

Expected Payment Period Successor
Description Pepco DPL ACE PHI Exelon
Rate credits 2016 - 2017 $ 91
$ 67
$ 101
$ 259
$ 259
Energy efficiency 2016 - 2021 —
—
—
—
122
Charitable contributions 2016 - 2026 28
12
10
50
50
Delivery system modernization Q2 2017 —
—
—
—
22
Green sustainability fund Q2 2017 —
—
—
—
14
Workforce development 2016 - 2020 —
—
—
—
17
Other 1
5
—
6
29
Total $ 120
$ 84
$ 111
$ 315
$ 513

Pursuant to the orders approving the merger, Exelon made $73 million, $46 million and $49 million of equity contributions to Pepco, DPL and ACE, respectively, in the second quarter of 2016 to fund the after-tax amounts of the customer bill credit and the customer base rate credit commitments.

In addition, Exelon is committed to develop or to assist in the commercial development of approximately 37 MWs of new generation in Maryland, District of Columbia, and Delaware, 27 MWs of which are expected to be completed by 2018. These investments are expected to total approximately $137 million, are expected to be primarily capital in nature, and will generate future earnings at Exelon and Generation. Investment costs will be recognized as incurred and recorded on Exelon's and Generation's financial statements. Exelon has also committed to purchase 100 MWs of wind energy in PJM, to procure 120 MWs of wind RECs for the purpose of meeting Delaware's renewable portfolio standards, and to maintain and promote energy efficiency and demand response programs in the PHI jurisdictions.

Pursuant to the various jurisdictions' merger approval conditions, over specified periods Pepco, DPL and ACE are not permitted to reduce employment levels due to involuntary attrition associated with the merger integration process and have made other commitments regarding hiring and relocation of positions.

In July 2015, the OPC, Public Citizen, Inc., the Sierra Club and the Chesapeake Climate Action Network (CCAN) filed motions to stay the MDPSC order approving the merger. The Circuit Court judge issued an order denying the motions for stay on August 12, 2015. On January 8, 2016, the Circuit Court judge affirmed the MDPSC’s order approving the merger and denied the petitions for judicial review filed by the OPC, the Sierra Club, CCAN and Public Citizen, Inc. On January 19, 2016, the OPC filed a notice of appeal to the Maryland Court of Special Appeals, and on January 21, the Sierra Club and CCAN filed notices of appeal. On January 27, 2017, the Maryland Court of Special Appeals affirmed the Circuit Court's judgment that the MDPSC did not err in approving the merger. The OPC and Sierra Club filed petitions seeking further review in the Court of Appeals of Maryland, which is the highest court in Maryland. On June 21, 2017, the Court of Appeals granted discretionary review of the January 27, 2017 decision by the Maryland Court of Special Appeals. The Maryland Court of Appeals will review the OPC argument that the MDPSC did not properly consider the acquisition premium paid to PHI shareholders under Maryland’s merger approval standard and the Sierra Club’s argument that the merger would harm the renewable and distributed generation markets. The two lower courts examining these issues rejected these arguments, which Exelon believes are without merit. All briefs have been filed and oral arguments were presented to the court on October 10, 2017.

Between March 25, 2016 and April 22, 2016, various parties filed motions with the DCPSC to reconsider its March 23, 2016 order approving the merger. On June 17, 2016, the DCPSC denied all motions. In August 2016, the District of Columbia Office of People’s Counsel, the District of Columbia Government, and Public Citizen jointly with DC Sun each filed petitions for judicial review of the DCPSC’s March 23, 2016 order with the District of Columbia Court of Appeals. On July 20, 2017, the Court issued an opinion rejecting all of appellants’ arguments and affirming the Commission’s decision approving the merger.

~~Table of Contents~~

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

~~Accounting for the Merger Transaction~~

The total purchase price consideration of approximately $7.1 billion for the PHI Merger consisted of cash paid to PHI shareholders, cash paid for PHI preferred securities and cash paid for PHI stock-based compensation equity awards as follows:

(In millions of dollars, except per share data) Total Consideration
Cash paid to PHI shareholders at $27.25 per share (254 million shares outstanding at March 23, 2016) $ 6,933
Cash paid for PHI preferred stock 180
Cash paid for PHI stock-based compensation equity awards^(a)
29
Total purchase price $ 7,142

~~_________~~

~~(a)~~

PHI’s unvested time-based restricted stock units and performance-based restricted stock units issued prior to April 29, 2014 were immediately vested and paid in cash upon the close of the merger. PHI’s remaining unvested time-based restricted stock units as of the close of the merger were cancelled. There were no remaining unvested performance-based restricted stock units as of the close of the merger.

PHI shareholders received $27.25 of cash in exchange for each share of PHI common stock outstanding as of the effective date of the merger. In connection with the Merger Agreement, Exelon entered into a Subscription Agreement under which it purchased $180 million of a new class of nonvoting, nonconvertible and nontransferable preferred securities of PHI prior to December 31, 2015. On March 23, 2016, the preferred securities were cancelled for no consideration to Exelon, and accordingly, the $180 million cash consideration previously paid to acquire the preferred securities was treated as purchase price consideration.

The preliminary valuations performed in the first quarter of 2016 were updated in the second, third, and fourth quarters of 2016. There were no adjustments to the purchase price allocation in the first quarter of 2017 and the purchase price allocation is now final.

Exelon applied push-down accounting to PHI, and accordingly, the PHI assets acquired and liabilities assumed were recorded at their estimated fair values on Exelon’s and PHI's Consolidated Balance Sheets as follows:

Purchase Price Allocation^(a)

Current assets $ 1,441
Property, plant and equipment 11,088
Regulatory assets 5,015
Other assets 248
Goodwill 4,005
Total assets $ 21,797

Current liabilities $ 2,752
Unamortized energy contracts 1,515
Regulatory liabilities 297
Long-term debt, including current maturities 5,636
Deferred income taxes 3,447
Pension and OPEB obligations 821
Other liabilities 187
Total liabilities $ 14,655
Total purchase price $ 7,142

~~_________~~


~~(a)~~	Amounts shown reflect the final purchase price allocation and the correction of a reporting error identified and corrected in the second quarter of 2016. The error had resulted in a gross up of certain assets and liabilities related to legacy PHI intercompany and income tax receivable and payable balances.

~~Table of Contents~~

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

On its successor financial statements, PHI has recorded, beginning March 24, 2016, Membership interest equity of $7.2 billion, which is greater than the total $7.1 billion purchase price, reflecting the impact of a $59 million deferred tax liability recorded only at Exelon Corporate to reflect unitary state income tax consequences of the merger.

The excess of the purchase price over the estimated fair value of the assets acquired and the liabilities assumed totaled $4.0 billion, which was recognized as goodwill by PHI and Exelon at the acquisition date, reflecting the value associated with enhancing Exelon's regulated utility portfolio of businesses, including the ability to leverage experience and best practices across the utilities and the opportunities for synergies. For purposes of future required impairment assessments, the goodwill has been assigned to PHI's reportable units Pepco, DPL and ACE in the amounts of $1.7 billion, $1.1 billion and $1.2 billion, respectively. None of this goodwill is expected to be tax deductible.

Immediately following closing of the merger, $235 million of net assets included in the table above associated with PHI's unregulated business interests were distributed by PHI to Exelon. Exelon contributed $163 million of such net assets to Generation.

The fair values of PHI's assets and liabilities were determined based on significant estimates and assumptions that are judgmental in nature, including projected future cash flows (including timing), discount rates reflecting risk inherent in the future cash flows, future market prices and impacts of utility rate regulation. There were also judgments made to determine the expected useful lives assigned to each class of assets acquired.

Through its wholly owned rate regulated utility subsidiaries, most of PHI’s assets and liabilities are subject to cost-of-service rate regulation. Under such regulation, rates charged to customers are established by a regulator to provide for recovery of costs and a fair return on invested capital, or rate base, generally measured at historical cost. In applying the acquisition method of accounting, for regulated assets and liabilities included in rate base or otherwise earning a return (primarily property, plant and equipment and regulatory assets earning a return), no fair value adjustments were recorded as historical cost is viewed as a reasonable proxy for fair value.

Fair value adjustments were applied to the historical cost bases of other assets and liabilities subject to rate regulation but not earning a return (including debt instruments and pension and OPEB obligations). In these instances, a corresponding offsetting regulatory asset or liability was also established, as the underlying utility asset and liability amounts are recoverable from or refundable to customers at historical cost (and not at fair value) through the rate setting process. Similar treatment was applied for fair value adjustments to record intangible assets and liabilities, such as for electricity and gas energy supply contracts as further described below. Regulatory assets and liabilities established to offset fair value adjustments are amortized in amounts and over time frames consistent with the realization or settlement of the fair value adjustments, with no impact on reported net income. See Note 5 - Regulatory Matters for additional information regarding the fair value of regulatory assets and liabilities established by Exelon and PHI.

Fair value adjustments were recorded at Exelon and PHI for the difference between the contract price and the market price of electricity and gas energy supply contracts of PHI’s wholly owned rate regulated utility subsidiaries. These adjustments are intangible assets and liabilities classified as unamortized energy contracts on Exelon’s and PHI’s Consolidated Balance Sheets as of September 30, 2017. The difference between the contract price and the market price at the acquisition date of the Merger was recognized for each contract as either an intangible asset or liability. In total, Exelon and PHI recorded a net $1.5 billion liability reflecting out-of-the-money contracts. The valuation of the acquired intangible assets and liabilities was estimated by applying either the market approach or the income approach depending on the nature of the underlying contract. The market approach was utilized when prices and other relevant information generated by market transactions involving comparable transactions were available. Otherwise the income approach, which is based upon discounted projected future cash flows associated with the underlying contracts, was utilized. In certain instances, the valuations were based upon certain unobservable inputs, which are considered Level 3 inputs, pursuant to applicable accounting guidance. Key estimates and inputs include forecasted power prices and the discount rate. The unamortized energy contract fair value adjustment amounts and the corresponding offsetting regulatory asset and liability amounts are amortized through Purchase power and fuel expense or Operating revenues, as applicable, over the life of the applicable contract in relation to the present value of the underlying cash flows as of the merger date.

As mentioned, under cost-of-service rate regulation, rates charged to customers are established by a regulator to provide for recovery of costs and a fair return on invested capital, or rate base, generally measured at historical cost. Historical cost information therefore is the most relevant presentation for the financial statements of PHI’s rate regulated utility subsidiary registrants, Pepco, DPL and ACE. As such, Exelon and PHI did not push-down the application of acquisition accounting to PHI's utility registrants, and therefore the financial statements of Pepco, DPL and ACE do not reflect the revaluation of any assets and liabilities.

~~Table of Contents~~

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

~~The current impact of PHI, including its unregulated businesses, on Exelon's Consolidated Statements of Operations and Comprehensive Income includes:~~

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Operating revenues $ 1,347
$ 1,437
$ 3,679
$ 2,656
Net income (loss) 176
169
382
(92 )

~~For the three and nine months ended September 30, 2017 and 2016, the Registrants have recognized costs to achieve the PHI acquisition as follows:~~

Three Months Ended
September 30, Nine Months Ended
September 30,
Acquisition, Integration and Financing Costs^(a)
2017 2016 2017 2016
Exelon $ (8 ) $ 20
$ 10
$ 123
Generation 5
9
18
29
ComEd^(b)
—
—
1
(6 )
PECO 1
1
3
3
BGE^(c)
1
1
3
(3 )
Pepco^(d)
(8 ) 3
(6 ) 26
DPL^(e)
1
2
(6 ) 18
ACE^(f)
(8 ) 2
(6 ) 17

Successor Predecessor
Acquisition, Integration and Financing Costs^(a)
Three Months Ended September 30, 2017 Three Months Ended September 30, 2016 Nine Months Ended September 30, 2017 March 24, 2016 to September 30, 2016 January 1, 2016 to March 23, 2016
PHI^(g)
$ (15 ) $ 7
$ (17 ) $ 63
$ 29

~~_________~~


~~(a)~~	The costs incurred are classified primarily within Operating and maintenance expense in the Registrants’ respective Consolidated Statements of Operations and Comprehensive Income, with the exception of the financing costs, which are included within Interest expense. Costs do not include merger commitments discussed above.


~~(b)~~	For the nine months ended September 30, 2016, includes the reversal of previously incurred acquisition, integration and financing costs of $8 million, incurred at ComEd that have been deferred and recorded as a regulatory asset for anticipated recovery. See Note 5—Regulatory Matters for more information.


~~(c)~~	For the nine months ended September 30, 2016, includes the reversal of previously incurred acquisition, integration and financing costs of $6 million incurred at BGE that have been deferred and recorded as a regulatory asset for anticipated recovery. See Note 5—Regulatory Matters for more information.

~~(d)~~

For the three and nine months ended September 30, 2017, includes the reversal of previously incurred acquisition, integration and financing costs of $8 million incurred at Pepco that have been deferred and recorded as a regulatory asset for anticipated recovery. For the nine months ended September 30, 2016, includes the reversal of previously incurred acquisition, integration and financing costs of $10 million incurred at Pepco that have been deferred and recorded as a regulatory asset for anticipated recovery. See Note 5—Regulatory Matters for more information.

~~(e)~~

For the nine months ended September 30, 2017, includes the reversal of previously incurred acquisition, integration and financing costs of $8 million incurred at DPL that have been deferred and recorded as a regulatory asset for anticipated recovery. For the nine months ended September 30, 2016, includes the reversal of previously incurred acquisition, integration and financing costs of $3 million incurred at DPL that have been deferred and recorded as a regulatory asset for anticipated recovery. See Note 5—Regulatory Matters for more information.


~~(f)~~	For the three and nine months ended September 30, 2017, includes the reversal of previously incurred acquisition, integration and financing costs of $8 million incurred at ACE that have been deferred and recorded as a regulatory asset for anticipated recovery. See Note 5—Regulatory Matters for more information.

~~(g)~~

For the three and nine months ended September 30, 2017, includes the reversal of previously incurred acquisition, integration and financing costs of $16 million and $24 million, respectively, incurred at PHI that have been deferred and recorded as a regulatory asset for anticipated recovery. For the Successor period March 24, 2016 to September 30, 2016, includes the reversal of previously incurred acquisition, integration and financing costs of $13 million incurred at PHI that have been deferred and recorded as a regulatory asset for anticipated recovery. See Note 5—Regulatory Matters for more information.

~~Table of Contents~~

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

~~Pro-forma Impact of the Merger~~

The following unaudited pro-forma financial information reflects the consolidated results of operations of Exelon as if the merger with PHI had taken place on January 1, 2015. The unaudited pro-forma information was calculated after applying Exelon’s accounting policies and adjusting PHI’s results to reflect purchase accounting adjustments.

The unaudited pro-forma financial information has been presented for illustrative purposes only and is not necessarily indicative of results of operations that would have been achieved had the merger events taken place on the dates indicated, or the future consolidated results of operations of the combined company.

Three Months Ended
September 30, Nine Months Ended
September 30,
Year Ended
December 31,

2016^(a)

2016^(a)

2016^(b)
Total operating revenues $ 9,002
$ 24,468
$ 32,342
Net income attributable to common shareholders 501
1,346
1,562

Basic earnings per share $ 0.54
$ 1.46
$ 1.69
Diluted earnings per share 0.54
1.45
1.69

~~_________~~


~~(a)~~	The amounts above include adjustments for non-recurring costs directly related to the merger of $20 million and $660 million for the three and nine months ended September 30, 2016, respectively, and intercompany revenue of $171 million for the nine months ended September 30, 2016.


~~(b)~~	~~The amounts above include adjustments for non-recurring costs directly related to the merger of $680 million and intercompany revenue of $171 million for the year ended December 31, 2016.~~

~~Asset Divestitures (Exelon, Generation, PHI, Pepco and DPL)~~

EGTP, a Delaware limited liability company, was formed in 2014 with the purpose of financing a portfolio of assets comprised of two combined-cycle gas turbines (CCGTs) and three peaking/simple cycle facilities consisting of approximately 3.4 GW of generation capacity in ERCOT North and Houston Zones. EGTP is an indirect wholly owned subsidiary of Exelon and Generation. Each of the aforementioned facilities are held through a wholly owned direct subsidiary of EGTP. EGTP also owns two equity method investments in shared facility companies. EGTP, its direct parent and its wholly owned subsidiaries secured a nonrecourse senior secured term loan facility, a revolving loan facility and certain commodity and interest rate swaps.

On May 2, 2017, EGTP entered into a consent agreement with its lenders to permit EGTP to draw on its revolving credit facility and initiate an orderly sales process to sell the assets of its wholly owned subsidiaries, the proceeds from which will first be used to pay the administrative costs of the sale, the normal and ordinary costs of operating the plants and repayment of the secured debt of EGTP, including the revolving credit facility. See Note 11 - Debt and Credit Agreements for details regarding the nonrecourse debt associated with EGTP. As a result, as of September 30, 2017, certain EGTP assets and liabilities were classified as held for sale at their respective fair values less costs to sell and included in the other current assets and other current liabilities balances on Exelon's and Generation's Consolidated Balance Sheets. See Note 6 - Impairment of Long-Lived Assets for further information.

~~In July 2016, DPL completed the sale of a 9~~acre land parcel located on South Madison Street in Wilmington, DE, resulting in a pre-tax gain of approximately $4 million. Due to the fair value adjustments recorded at Exelon and PHI as part of purchase accounting, no gain was recorded in the Exelon and PHI Consolidated Statements of Operations and Comprehensive Income.

On June 16, 2016, Generation initiated the sales process of its Upstream business by executing a forbearance agreement with the lenders of the nonrecourse debt. See Note 11 - Debt and Credit Agreements for more information. In December 2016, Generation sold substantially all of the Upstream assets, see Note 4 - Mergers, Acquisitions and Dispositions of the Combined Notes to the Consolidated Financial Statements in the Exelon 2016 Form 10-K for further information.

On May 2, 2016, Pepco completed the sale of the New York Avenue land parcel, located in Washington D.C., resulting in a pre-tax gain of approximately $8 million at Pepco. Due to the fair value adjustments recorded at Exelon and PHI as part of purchase accounting, no gain was recorded in the Exelon and PHI Consolidated Statements of Operations and Comprehensive Income.

~~Table of Contents~~

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

~~On April 21, 2016, Generation completed the sale of the retired New Boston generating site, located in Boston, Massachusetts, resulting in a pre-tax gain of approximately $32 million.~~

~~5. Regulatory Matters (All Registrants)~~

Except for the matters noted below, the disclosures set forth in Note 3 - Regulatory Matters of the Exelon 2016 Form 10-K reflect, in all material respects, the current status of regulatory and legislative proceedings of the Registrants. The following is an update to that discussion.

~~Illinois Regulatory Matters~~Energy Efficiency

~~Distribution~~The Clean Energy Law extends ComEd’s current cumulative annual energy efficiency MWh savings goals through 2040, adds expanded electrification measures to those goals, increases low-income commitments and adds a new performance adjustment to the energy efficiency formula rate. ComEd expects its annual spend to increase in 2022 through 2040 to achieve these energy efficiency MWh savings goals, which will be deferred as a separate regulatory asset that will be recovered through the energy efficiency formula rate over the weighted average useful life, as approved by the ICC, of the related energy efficiency measures.

Energy Efficiency Formula Rate (Exelon and ComEd). ~~On April 13, 2017,~~ ComEd filed its annual ~~distribution~~energy efficiency formula rate update with the ICC ~~pursuant to EIMA.~~on June 1, 2021. The filing establishes the revenue requirement used to set the rates that will take effect in January ~~2018~~2022 after the ICC’s review and ~~approval, which is due by December 2017.~~approval. The requested revenue requirement ~~requested~~update is based on ~~2016~~a reconciliation of the 2020 actual costs plus projected ~~2017 capital additions as well as an annual reconciliation of the~~2022 expenditures.


Initial Revenue Requirement Increase		Annual Reconciliation Decrease		Total Revenue Requirement Increase		Requested Return on Rate Base(a)		Requested ROE
$	55	$	(1)	$	54	5.72	%	7.36	%

__________

(a)The requested revenue requirement ~~in effect in 2016 to the actual costs incurred that year. ComEd's 2017 filing request includes a total~~ increase to the revenue requirement of $96 million, reflecting an increase of $78 million for the initial revenue requirement for 2017 and an increase of $18 million related to the annual reconciliation for 2016. The revenue requirement for 2017 provides for a weighted average debt and equity return on ~~distribution~~the energy efficiency regulatory asset and rate base of ~~6.47%~~5.72% inclusive of an allowed ROE of ~~8.40%~~7.36%, reflecting the monthly average ~~rate on~~yields for 30-year treasury ~~notes~~bonds plus 580 basis points. ~~The annual~~For the 2020 reconciliation ~~for 2016 provided~~year, the requested revenue requirement provides for a weighted average debt and equity return on ~~distribution~~the energy efficiency regulatory asset and rate base of ~~6.45%~~6.26% inclusive of an allowed ROE of ~~8.34%~~8.46%, ~~reflecting~~which includes an upward performance adjustment that increased the ~~average rate on 30-year treasury notes plus 580 basis points less a~~ROE. The performance ~~metrics penalty~~adjustment can either increase or decrease the ROE based upon the achievement of ~~6 basis points. See table below for ComEd's regulatory assets associated with its distribution formula rate. For additional information on ComEd's distribution formula rate filings see Note 3 —~~energy efficiency savings goals.

Maryland Regulatory Matters

Maryland Order Directing the Distribution of Energy Assistance Funds (Exelon, BGE, PHI, Pepco, and DPL). On June 15, 2021, the ~~Exelon 2016 Form 10-K.~~

On December 6, 2016, the ICC issued a final order approving the 2016 distribution formula rate, which included a total increase to the revenue requirement of $127 million, reflecting an increase of $134 million for the initial revenue requirement for 2016 and a decrease of $7 million related to the annual reconciliation for 2015. On December 20, 2016, the ICC granted ComEd's and other parties' joint application for rehearing on the impact that changing ComEd’s OSHA recordable rate for 2014 and 2015 had on the revenue requirement approved in this order. On March 22, 2017, the ICCMDPSC issued an order ~~approving ComEd's proposal~~authorizing the disbursal of funds to utilities in accordance with Maryland COVID-19 relief legislation. Under this order, BGE, Pepco, and DPL received funds of $50 million, $12 million, and $8 million, respectively, in July 2021. The funds have been used to reduce or eliminate certain qualifying past-due residential customer receivables.

New Jersey Regulatory Matters

Conservation Incentive Program (CIP) (Exelon, PHI, and ACE). On September 25, 2020, ACE filed an application with the ~~2016 revenue requirement by $18 million, which~~NJBPU as was ~~reflected in customer rates beginning in April 2017.~~

~~Illinois Future Energy Jobs Act (Exelon, Generation and ComEd)~~

~~Background~~

~~On December 7, 2016, FEJA was signed into law by the Governor~~required seeking approval to implement a portfolio of Illinois. FEJA was effective June 1, 2017, and includes, among other provisions, (1) a Zero Emission Standard (ZES) providing compensation for certain nuclear-powered generating facilities, (2) an extension of and certain adjustments to ComEd’s electric distribution formula rate, (3) new cumulative persisting annual energy efficiency ~~MWh savings goals~~programs pursuant to New Jersey’s clean energy legislation. The filing included a request to implement a CIP that would eliminate the favorable and unfavorable impacts of weather and customer usage patterns on distribution revenues for ~~ComEd, (4) revisions~~most customers. The CIP compares current distribution revenues by customer class to the Illinois RPS requirements, (5) provisions for adjustments to or termination of FEJA programs if the average impact on ComEd’s customer rates exceeds specified limits, (6) revisions to the existing net metering statuteapproved target revenues established in ACE’s most recent distribution base rate case. The CIP is calculated annually and ~~(7) support for low income rooftop and community solar programs~~.

~~Zero Emission Standard~~

FEJA includes a ZES that provides compensation through the procurement of ZECs targeted at preserving the environmental attributes of zero-emissions nuclear-powered generating facilities that meet specific eligibility criteria.

On September 11, 2017, the ICC approved the IPA's ZES Procurement Plan filed with the ICC on July 31, 2017. Bidders interested in participating in the procurement process had 14 days following the ICC's approval of the plan to submit the required eligibility information and become qualified bidders. Generation’s Clinton and Quad Cities nuclear plants timely submitted the required eligibility information to the ICC and responded to follow up questions. Winning bidders will contract directly with Illinois utilities, including ComEd, for 10-year terms extending through May 31, 2027. The ZEC price will be based upon the current social cost of carbon as determined by the Federal government andrecovery is ~~initially established at $16.50 per MWh of production,~~ subject to ~~annual future adjustments determined by the IPA for specified escalation~~certain conditions, including an earnings test and ~~pricing adjustment mechanisms designed to lower the ZEC price based~~ceilings on increases in underlying energy and capacity prices. Illinois utilities will be required to purchase all ZECs delivered by the zero-emissions nuclear-powered generating facilities, subject to annual cost caps. For the initial delivery year, June 1, 2017

customer rate increases.

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— ~~(Continued)~~

(Dollars in millions, except per share data, unless otherwise noted)

Note 3 — Regulatory Matters

~~- May 31, 2018,~~On April 27, 2021, the ~~ZEC annual cost cap, is set at $235 million (ComEd’s share is approximately $170 million). For subsequent delivery years,~~NJBPU approved the ~~IPA-approved targeted ZEC procurement amounts~~settlement filed by ACE and the third parties to the proceeding. The approved settlement addresses all material aspects of ACE’s filing, including ACE’s ability to implement the CIP prospectively effective July 1, 2021. As a result of this decoupling mechanism, operating revenues will ~~change based on forward energy and capacity prices. ZECs delivered to Illinois utilities~~no longer be impacted by abnormal weather or usage for most customers. Starting in ~~excess~~third quarter of 2021, ACE will record alternative revenue program revenues for its best estimate of the ~~annual cost cap will be paid~~distribution revenue impacts resulting from future changes in ~~subsequent years if~~CIP rates that it believes are probable of approval by the ~~payments do not exceed~~NJBPU in accordance with this mechanism.

Advanced Metering Infrastructure Filing (Exelon, PHI, and ACE). On August 26, 2020, ACE filed an application with the ~~prescribed annual cost cap~~NJBPU as was required seeking approval to deploy a smart energy network in alignment with New Jersey’s Energy Master Plan and Clean Energy Act. The proposal consisted of estimated costs totaling $220 million with deployment taking place over a 3-year implementation period from approximately 2021 to 2024 that involves the installation of an integrated system of smart meters for ~~that year.~~all customers accompanied by the requisite communications facilities and data management systems.

On ~~October 27, 2017,~~July 14, 2021, the ~~IPA released~~NJBPU approved the ~~schedule for~~settlement filed by ACE and the ZEC procurement event indicating that contracts with zero emission facilities will be fully executed on January 30, 2018. Winning bidders will be entitled to compensation for the sale of ZECs retroactivethird parties to the ~~June 1, 2017 effective date~~proceeding. The approved settlement addresses all material aspects of ~~FEJA. To~~ACE's smart energy network deployment plan, including cost recovery of the ~~extent Generation is selected as a winning bidder, revenue retroactive~~investment costs, incremental O&M expenses, and the unrecovered balance of existing infrastructure through future distribution rates.

Regulatory Assets and Liabilities

The Utility Registrants' regulatory assets and liabilities have not changed materially since December 31, 2020, unless noted below. See Note 3 — Regulatory Matters of the Exelon 2020 Form 10-K for additional information on the specific regulatory assets and liabilities.

ComEd. Regulatory assets increased $93 million primarily due to ~~the effective date~~an increase of ~~FEJA would be recognized~~$47 million in the ~~period~~Electric Distribution Formula Rate Annual Reconciliations regulatory asset and $127 million in the ~~contracts are executed. Upon~~Energy Efficiency Costs regulatory asset, partially offset by a decrease of $87 million in the ~~execution~~renewable energy regulatory asset.

PECO. Regulatory assets increased $135 million primarily due to an increase of $123 million in the ~~contracts, ComEd will record~~Deferred Income Taxes regulatory asset and $14 million in the Vacation Accrual regulatory asset. Regulatory liabilities increased by $66 million primarily due to an ~~associated obligation and expense for the procurement of ZEC's.~~

ComEd will recover all costs associated with purchasing ZECs through a new rate rider that provides for an annual reconciliation and true-up to actual costs incurred by ComEd to purchase ZECs, with any difference to be credited to or collected from ComEd’s retail customers in subsequent periods with interest. ComEd began billing its retail customers under its new ZEC rate rider on June 1, 2017 and recorded a regulatory liabilityincrease of $71 million in the Nuclear Decommissioning regulatory liability partially offset by a $18 million decrease in the Electric Energy and Natural Gas Costs regulatory liability.

DPL. Regulatory liabilities decreased $45 million primarily due to a decrease of $41 million in the Deferred Income Taxes regulatory liability.

Capitalized Ratemaking Amounts Not Recognized

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Note 3 — Regulatory Matters


	Exelon		ComEd(a)		PECO		BGE(b)		PHI		Pepco(c)		DPL(c)		ACE
September 30, 2021	$	44	$	—	$	—	$	39	$	5	$	3	$	2	$	—

December 31, 2020	51		(1)		—		45		7		4		3		—

__________

(a)Reflects ComEd's unrecognized equity returns/(losses) earned/(incurred) 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.

Generation Regulatory Matters (Exelon and Generation)

Impacts of the February 2021 Extreme Cold Weather Event and Texas-based Generating Assets Outages

Beginning on February 15, 2021, Generation’s Texas-based generating assets within the ERCOT market, specifically Colorado Bend II, Wolf Hollow II, and Handley, experienced outages as a result of extreme cold weather conditions. In addition, those weather conditions drove increased demand for service, dramatically increased wholesale power prices, and also increased gas prices in certain regions. In response to the high demand and significantly reduced total generation on the system, the PUCT directed ERCOT to use an administrative price cap of $9,000 per MWh during firm load shedding events.

The estimated impact to Exelon’s and Generation’s Net income for the nine months ended September 30, ~~2017~~2021 arising from these market and weather conditions was a reduction of approximately $880 million. The estimated impact to Exelon's and Generation's Net income for ~~revenues recorded in advance~~the three months ended September 30, 2021 was not material. The ultimate impact to Exelon’s and Generation’s consolidated financial statements for the full year 2021 may be affected by a number of ~~incurring expenses.~~factors, including the impacts of customer and counterparty credit losses, any state or federal solutions to address the financial challenges caused by the event, and related litigation and contract disputes.

During February and March 2021, various parties with differing interests, including generators and retail providers, filed requests with the PUCT to void the PUCT’s orders setting prices at $9,000 per MWh during firm load shedding events. Other requests were made for the PUCT to enforce its order and reduce prices for 33 hours between February 18 and February 19 after firm load shedding ceased, and to cap ancillary services at $9,000 per MWh.On ~~February 14, 2017, two lawsuits were~~March 2, 2021, a third party filed a notice of appeal in the ~~Northern~~Court of Appeals for the Third District of ~~Illinois against~~Texas challenging the ~~IPA alleging~~validity of the PUCT’s actions. Generation intervened in that appeal and filed its initial brief on June 2, 2021. On April 19, 2021, Generation filed a declaratory action and request for judicial review of the PUCT’s orders setting prices at $9,000 per MWh in District Court of Travis County, Texas. Generation subsequently requested that the ~~state’s ZEC program violates certain provisions~~District Court of ~~the U.S. Constitution. One lawsuit was filed by customers of ComEd, led~~Travis County, Texas stay its proceeding pending action by the ~~Village~~Court of ~~Old Mill Creek,~~Appeals in the third party proceeding. On May 17, 2021, Generation amended its petition for declaratory action and request for judicial review pending in the ~~other was brought by the EPSA~~District Court of Travis County, Texas. Exelon and three other electric suppliers. Both lawsuits argue that the Illinois ZEC program will distort PJM's FERC-approved energy and capacity market auction system of setting wholesale prices, and seek a permanent injunction preventing the implementation of the program. Exelon intervened and filed motions to dismiss in both lawsuits. In addition, on March 31, 2017, plaintiffs in both lawsuits filed motions for preliminary injunction with the court; the court stayed briefing on the motions for preliminary injunction until the resolution of the motions to dismiss.On July 14, 2017, the district court granted the motions to dismiss. On July 17, 2017, the plaintiffs appealed the decision to the Seventh Circuit. Plaintiffs-Appellants initial brief was filed on August 28, 2017 and the state’s and Exelon’s briefs were filed on October 27, 2017. Reply briefs are due on December 12, 2017. ExelonGeneration cannot predict the outcome of these ~~lawsuits. It~~proceedings or the financial statement impact.

Due to these events, a number of ERCOT market participants experienced bankruptcies or defaulted on payments to ERCOT, resulting in approximately a $3.0 billion payment shortfall in collections, which is ~~possible that resolution of these matters could have a material, unfavorable impact on Exelon’s and Generation’s results of operations, financial positions and cash flows.~~

See Note 7 - Early Nuclear Plant Retirements for additional information regarding the economic challenges facing Generation’s Clinton and Quad Cities nuclear plants and the expected benefits of the ZES.

~~ComEd Electric Distribution Rates~~

~~FEJA extends the sunset date for ComEd’s performance-based electric distribution formula rate from 2019~~allocated to the end of 2022, allows ComEd to revise the electric distribution formula rate to eliminate the ROE collar, and allows ComEd to implement a decoupling tariff if the electric distribution formula rate is terminated at any time. ComEd will revise its electric distribution formula rate to eliminate the ROE collar beginning with the reconciliation filed in 2018 for the 2017 calendar year. Elimination of the ROE collar effectively offsets the favorable or unfavorable impacts to ComEd's electric distribution formula rate revenues associated with variations in delivery volumes associated with above or below normal weather, numbers of customers or usage per customer. ComEd began reflecting the impacts of this change in its electric distribution services costs regulatory asset in first quarter 2017.remaining ERCOT market participants. As of September 30, ~~2017, ComEd~~2021, Generation has recorded ~~an increase to~~ its ~~electric distribution services costs regulatory asset~~estimated portion of this obligation of approximately ~~$21~~$17 million ~~for this change.~~

~~FEJA requires ComEd~~on a discounted basis, which is to ~~make non-recoverable contributions~~be paid over a term of 83 years. ERCOT rules historically have limited recovery of default from market participants to ~~low income energy assistance programs of $10~~$2.5 million per ~~year~~month market-wide. In February 2021, the PUCT gave ERCOT discretion to disregard those rules, but ERCOT has declined to exercise that discretion thus far. On March 8, 2021, a third party filed a notice of appeal in the Court of Appeals for ~~5 years~~the Third District of Texas challenging the validity of the PUCT's order to ERCOT in February 2021. Generation intervened in that appeal and filed its initial brief on July 7, 2021. On May 7, 2021, Generation filed a declaratory action and request for judicial review of the PUCT's order in the District Court of Travis County, Texas. Generation subsequently requested that the District Court of Travis County, Texas stay its proceeding pending action by the Court of Appeals in the third party proceeding. Exelon and Generation cannot predict the outcome of these proceedings or the financial statement impact.

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Note 3 — Regulatory Matters

Additionally, several legislative proposals were introduced in the Texas legislature during February and March 2021 concerning the amount, timing and allocation of recovery of the $3.0 billion shortfall, as ~~long~~well as recovery of other costs associated with the PUCT's directive to set prices at $9,000 per MWh. Two of these proposals were enacted into law in June 2021 and establish financing mechanisms that ERCOT and certain market participants can utilize to fund amounts owed to ERCOT. Generation participated in proceedings before the PUCT addressing the proposed allocation of the $2.1 billion in securitized funds for reliability and ancillary service charges over $9,000/MWh. In September 2021, Generation entered into a settlement agreement and stipulation to resolve the allocation issues. The PUCT approved the settlement agreement and stipulation on October 13, 2021.

In addition, other legislative proposals were introduced in the Texas legislature during February and March 2021 addressing cold-weather preparation for power plants and natural gas production and transportation infrastructure and the market structure for reliability services. The Texas legislature addressed these proposals by enacting a bill with a broad set of market reforms that, among other things, directed the PUCT to establish weatherization standards for electric generators within six months of enactment and gave the PUCT authority to impose administrative penalties if the new proposed standards, once adopted, are not met. On October 21, 2021, the PUCT adopted rule change requiring generators by December 1, 2021 to complete a number of specified winter readiness preparations and to submit to ERCOT a report describing and certifying the completion of those preparations. The PUCT described these requirements as the ~~electric~~first phase of its actions with respect to winter preparedness, to be followed by a second phase consisting of a year-round set of weather preparedness standards to be informed by a weather study that is being conducted by ERCOT.

In February 2021, more than 70 local distribution ~~formula rate remains~~companies (LDCs) and natural gas pipelines in ~~effect. With~~multiple states throughout the ~~exception~~mid-continent region, where Generation serves natural gas customers, issued operational flow orders (OFOs), curtailments or other limitations on natural gas transportation or use to manage the operational integrity of the applicable LDC or pipeline system. When in effect, gas transportation or use above these limitations is subject to significant penalties according to the applicable LDCs’ and natural gas pipelines’ tariffs. Gas transportation and supply in many states became restricted due to wells freezing and pipeline compression disruption, while demand was increasing due to the extreme cold temperatures, resulting in extremely high natural gas prices. Due to the extraordinary circumstances, many LDCs and natural gas pipelines have either voluntarily waived or have sought applicable regulatory approvals to waive the tariff penalties associated with the extreme weather event. During March 2021, three natural gas pipelines filed individual petitions with FERC requesting approval to waive OFO penalties. Generation also filed motions in March 2021 to intervene and filed comments in support of these ~~contributions, ComEd will recover~~FERC waiver requests. On March 25, 2021, FERC issued an order on one of the petitions approving a pipeline’s request for a limited waiver of penalties for February 15, 2021. On April 23, 2021, Generation and several other entities filed a request at FERC for rehearing of this order which was denied on May 24, 2021. Generation and the other entities filed an appeal of the rehearing of the order with the U.S. Court of Appeals for the D.C. Circuit on July 21, 2021. Additionally, Generation and the other entities filed a complaint requesting that FERC expand the order to include additional days of the weather event in February, from ~~customers, subject~~February 16 through February 19, 2021. On October 21, 2021, FERC denied the complaint finding that a pipeline has the discretion whether to ~~certain caps explained below,~~waive penalties under its tariff. Generation is evaluating whether to seek rehearing and appeal of the ~~costs it incurs pursuant~~FERC order. During April 2021, FERC issued orders on the remaining petitions approving the requests to ~~FEJA either through its electric distribution formula rate~~waive the penalties. During May 2021, an LDC filed a motion with the Kansas Corporation Commission (KCC) requesting the KCC to grant a waiver from the tariff and allow the LDC to reduce the amounts assessed by permitting the removal of a multiplier from the penalty calculation. On October 8, 2021, a settlement was filed with the KCC that, if approved, would resolve this matter. Exelon and Generation cannot predict the outcome of the pending FERC complaint proceeding, the KCC proceeding, or ~~other recovery mechanisms.~~the determinations made by the LDCs and natural gas pipelines.

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Note 3 — Regulatory Matters

Energy Efficiency

Prior to FEJA, Illinois law required ComEd to implement cost-effective energy efficiency measures and, for a 10-year period ending May 31, 2018, cost-effective demand response measures to reduce peak demand by 0.1% over the prior year for eligible retail customers.

~~Beginning January 1, 2018, FEJA provides for new~~The Clean Energy Law extends ComEd’s current cumulative annual energy efficiency MWh savings goals ~~for ComEd, which are designed~~through 2040, adds expanded electrification measures to ~~achieve 21.5% of cumulative persisting annual MWh savings by 2030, as compared~~

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~~(Dollars in millions, except per share data, unless otherwise noted)~~

those goals, increases low-income commitments and adds a new performance adjustment to the ~~deemed baseline of 88 million MWhs of electric power and~~ energy ~~sales. FEJA deems the cumulative persisting annual MWh savings to be 6.6% from 2012 through the end of 2017.~~efficiency formula rate. ComEd expects its annual spend to ~~spend approximately $250 million to $400 million annually from 2017~~increase in 2022 through ~~2030~~2040 to achieve these energy efficiency MWh savings goals. In addition, FEJA extends the peak demand reduction requirement from 2018 to 2026. Because the new requirements apply beginning in 2018, FEJA extends the existing energy efficiency plans, which were due to end on May 31, 2017, through December 31, 2017. FEJA also exempts customers with demands over 10 MW from energy efficiency plans and requirements beginning June 1, 2017. On September 11, 2017, the ICC approved ComEd's 2018 - 2021 energy efficiency plan with minor modifications filed by ComEd with the ICC on June 30, 2017.

FEJA allows ComEd to cancel its existing energy efficiency rate rider and replace it with an energy efficiency formula rate, and to defer energy efficiency costs (except for any voltage optimization costsgoals, which will be ~~recovered through the electric distribution formula rate)~~deferred as a separate regulatory asset that will be recovered through the energy efficiency formula rate over the weighted average useful life, as approved by the ICC, of the related energy efficiency measures.

Energy Efficiency Formula Rate (Exelon and ComEd). ComEd will earn a return on the energy efficiency regulatory asset at a rate equal to its weighted average cost of capital, which is based on a year-end capital structure and calculated using the same methodology applicable to ComEd’s electric distribution formula rate. Beginning January 1, 2018 through December 31, 2030, the return on equity that ComEd earns on its energy efficiency regulatory asset is subject to a maximum downward or upward adjustment of 200 basis points if ComEd’s cumulative persisting annual MWh savings falls short of or exceeds specified percentage benchmarks offiled its annual ~~incremental savings goal. ComEd will be required to file an update to its~~ energy efficiency formula rate ~~on or before June 1 each year, with resulting rates effective in January of the following year. The annual~~ update will be based on projected current year energy efficiency costs, PJM capacity revenues, and the projected year-end regulatory asset balance less any related deferred income taxes. The update will also include a reconciliation of any differences between the revenue requirement in effect for the prior year and the revenue requirement based on actual prior year costs and actual year-end energy efficiency regulatory asset balances less any related deferred income taxes. ComEd records a regulatory asset or liability and corresponding increase or decrease to Operating revenues for any differences between the revenue requirement in effect and ComEd’s best estimate of the revenue requirement expected to be approved by the ICC for that year’s reconciliation.

ComEd cancelled its existing energy efficiency rate rider effective June 2, 2017. On August 1, 2017, ComEd filed with the ICC a reconciliation of revenues and costs incurred through the cancellation date. On August 30, 2017, the ICC approved ComEd's request, filed on August 1, 2017, to issue an $80 million credit on retail customers' bills in October 2017 for the majority of the over-recoveries with any final adjustment applicable to the over-recoveries to be billed or credited in the future. As of September 30, 2017, ComEd’s over-recoveries associated with its former energy efficiency rate rider were $33 million.

~~Initial Energy Efficiency Formula Rate Filing~~

~~On August 15, 2017, the ICC approved ComEd's new initial energy efficiency formula rate filed~~ with the ICC on June ~~9, 2017 pursuant to FEJA.~~1, 2021. The filing establishes ~~the formula under which energy efficiency rates will be calculated going forward and~~ the revenue requirement used to set the ~~initial~~ rates ~~for~~that will take effect in January 2022 after the ~~period October 1, 2017 through December 31, 2017.~~ICC’s review and approval. The ~~initial~~requested revenue requirement update is based on a reconciliation of the 2020 actual costs plus projected costs and projected PJM capacity revenues for the period from June 1, 2017 through December 31, 2017, and projected year-end 2017 energy efficiency regulatory asset balances (less any related deferred income taxes). ComEd2022 expenditures.


Initial Revenue Requirement Increase		Annual Reconciliation Decrease		Total Revenue Requirement Increase		Requested Return on Rate Base(a)		Requested ROE
$	55	$	(1)	$	54	5.72	%	7.36	%

__________

(a)The requested ~~an initial decrease in~~ revenue requirement ~~of $7 million reflecting higher projected PJM capacity revenues compared to projected energy efficiency costs and~~increase provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of ~~6.47%~~5.72% inclusive of an allowed ROE of ~~8.40%~~7.36%, reflecting the monthly average ~~rate on~~yields for 30-year treasury ~~notes~~bonds plus 580 basis points. ~~The annual~~For the 2020 reconciliation ~~for 2017 will be included in ComEd’s 2018 energy efficiency formula rate filing and reflected in customer rates beginning January 2019. The approved energy efficiency formula rate also provides for~~year, the requested revenue decoupling to effectively offset the favorable or unfavorable impacts to ComEd's energy efficiency formula rate revenues associated with variations in delivery volumes associated with above or below normal weather, numbers of customers or usage per customer.

As of September 30, 2017, Exelon and ComEd recorded a regulatory asset of $78 million under the energy efficiency formula, reflecting $83 million of deferred energy efficiency costs partially offset by $5 million of over recoveries for the initial energy efficiency formula rate reconciliation.

~~2017 Energy Efficiency Formula Rate Filing~~

~~On September 11, 2017, the ICC approved ComEd's annual energy efficiency formula rate filed with the ICC on June 30, 2017 pursuant to FEJA. The filing establishes the revenue~~ requirement ~~used to set rates that will take effect~~

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in January 2018. The revenue requirement for 2018 is based on projected 2018 energy efficiency costs and PJM capacity revenues, and year-end 2018 energy efficiency regulatory asset balances (less any related deferred income taxes). In its 2017 filing ComEd requested a total increase to the revenue requirement of $12 million and provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of ~~6.47%~~6.26% inclusive of an allowed ROE of ~~8.40%~~8.46%, ~~reflecting~~which includes an upward performance adjustment that increased the ~~average rate on 30-year treasury notes plus 580 basis points.~~ROE. The ~~annual reconciliation for 2018 will be included in ComEd’s 2019 energy efficiency formula rate filing, and reflected in customer rates beginning January 2020.~~

~~Renewable Portfolio Standard~~

~~Existing Illinois law requires ComEd to purchase each year an increasing percentage~~performance adjustment can either increase or decrease the ROE based upon the achievement of renewable energy resources for the customers for which it supplies electricity. This obligation is satisfied through the procurement of RECs. FEJA revises the Illinois RPS to require ComEd to procure RECs for all retail customers by June 2019, regardless of the customers’ electricity supplier, and provides support for low-income rooftop and community solar programs, which will be funded by the existing Renewable Energy Resources Fund and ongoing RPS collections. FEJA also requires ComEd to use RPS collections to fund utility job training and workforce development programs in the amounts of $10 million in each of the years 2017, 2021, and 2025. ComEd recorded a $10 million and $20 million current and noncurrent liability, respectively, as of September 30, 2017 associated with this obligation. ComEd will recover all costs associated with purchasing RECs and funding utility job training and workforce development programs through a new RPS rate rider that provides for a reconciliation and true-up to actual costs, with any difference between revenues and expenses to be credited to or collected from ComEd’s retail customers in subsequent periods with interest. The first reconciliation and true-up for RECs will occur in 2021 and cover revenues and costs for the four year period beginning June 1, 2017 through May 31, 2021. Subsequently, the RPS rate rider will provide for an annual reconciliation and true-up. ComEd began billing its retail customers under its new RPS rate rider on June 1, 2017 and recorded a related regulatory liability of $7 million as of September 30, 2017. ComEd also recorded a regulatory liability of $38 million for alternative compliance payments received from RES to purchase RECs on behalf of the RES in the future.

~~As of September 30, 2017, ComEd had received $45 million~~ of over-recovered RPS costs and alternative compliance payments from RES, which are deposited into a separate interest bearing bank account pursuant to FEJA and are classified as Restricted cash on Exelon's and ComEd's Balance Sheets.

~~Customer Rate Increase Limitations~~

FEJA includes provisions intended to limit the average impact on ComEd customer rates for recovery of costs incurred under FEJA as follows: (1) for a typical ComEd residential customer, the average impact must be less than $0.25 cents per month, (2) for nonresidential customers with a peak demand less than 10 MW, the average annual impact must be less than 1.3% of the average amount paid per kWh for electric service by Illinois commercial retail customers during 2015, and (3) for nonresidential customers with a peak demand greater than 10 MW, the average annual impact must be less than 1.3% of the average amount paid per kWh for electric service by Illinois industrial retail customers during 2015.

~~On June 30, 2017, ComEd submitted a 10-year projection to the ICC of customer rate impacts for residential customers and nonresidential customers with a peak demand less than 10 MW~~. Such projections indicate that customer rate impacts will not exceed the limitations set by FEJA discussed below. Thereafter, beginning in 2018, ComEd must submit a report to the ICC for residential customers and nonresidential customers with a peak demand less than 10 MW by February 15th and June 30th of each year, respectively. For nonresidential customers with a peak demand greater than 10 MW, ComEd must submit a report to the ICC by May 1 of each year if a rate reduction will be necessary in the following year. For residential customers, the reports will include the actual costs incurred under FEJA during the preceding year and a rolling 10-year customer rate impact projection. The reports for nonresidential customers with a peak demand less than 10 MW will also include the actual costs incurred under FEJA during the preceding year, as well as the average annual rate increase from January 1, 2017 through the end of the preceding year and the average annual rate increase projected for the remainder of the 10-year period.

If the projected residential customer or nonresidential customer with a peak demand less than 10 MW rate increase exceeds the limitations during the first four years, ComEd is required to decrease costs associated with FEJA investments, including reductions to ZEC contract quantities. If the projected residential customer or nonresidential customer with a peak demand less than 10 MW rate increase exceeds the limitations during the last six years, ComEd is required to demonstrate how it will reduce FEJA investments to ensure compliance. If the actual residential customer or nonresidential customer with a peak demand less than 10 MW rate increase exceeds the limitations for any one year, ComEd is required to submit a corrective action plan to decrease future year costs to reduce customer rates to

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~~(Dollars in millions, except per share data, unless otherwise noted)~~

ensure future compliance. If the actual residential customer or nonresidential customer rate exceeds the limitations for two consecutive years, ComEd can offer to credit customers for amounts billed in excess of the limitations or ComEd can terminate FEJA investments. If ComEd chooses to terminate FEJA investments, the ICC shall order termination of ZEC contracts and further initiate proceedings to reduce energy efficiency savings ~~goals and terminate support for low-income rooftop and community solar programs~~. ~~ComEd is allowed to fully recover all costs incurred as of and up to the date of the programs’ termination.~~goals.

For the energy efficiency formula, ComEd records a regulatory asset or liability and corresponding increase or decrease to Operating revenues for any differences between the revenue requirement in effect and ComEd’s best estimate of the revenue requirement expected to be approved by the ICC for that year’s reconciliation. For the other rate riders established under FEJA, ComEd records a regulatory asset or liability for any differences between revenues and incurred expenses.

~~Renewable Energy Resources (Exelon and ComEd).~~ In accordance with legislation in effect on December 31, 2016, the IPA's Procurement Plans include the procurement of cost-effective renewable energy resources in amounts that equal or exceed a minimum target percentage of the total electricity that each electric utility supplies to its eligible retail customers. The June 1, 2016 target renewable energy resources obligation for the utilities was at least 11.5%. This obligation increases by at least 1.5% each year thereafter to an ultimate target of at least 25% by June 1, 2025. All goals are subject to rate impact criteria set forth by Illinois legislation. As of September 30, 2017, ComEd had purchased renewable energy resources or equivalents, such as RECs, in accordance with the IPA Procurement Plan. ComEd currently retires all RECs upon transfer and acceptance. ComEd is permitted to recover procurement costs of RECs from retail customers without mark-up through rates.

In accordance with FEJA that took effect on June 1, 2017, beginning with the plan or plans to be implemented in the 2017 delivery year, the IPA shall develop a long term renewable resources procurement plan (LT Plan). The RPS target percentages for the overall service territory have not changed through June 1, 2025 although FEJA extended the 25% RPS target to delivery years after 2025. Currently, each RES and each utility is responsible for the renewable resource obligation of the customers it supplies power for. Over time, this will change and the utility will procure renewable resources based on the retail load of substantially all customers in its service territory. For the delivery year beginning June 1, 2017, the LT Plan shall include cost effective renewable energy resources procured by the utility for the retail load the utility supplies and for 50% of the retail customer load supplied by Retail Electric Suppliers in the utility service territory on February 28, 2017. Utility procurement for RES supplied retail customer load will increase to 75% June 1, 2018 and to 100% beginning June 1, 2019.

~~Pennsylvania Regulatory Matters~~

~~Pennsylvania Procurement Proceedings (Exelon and PECO).~~ ~~Through PECO’s PAPUC approved DSP Programs, PECO procures electric supply for its default electric customers through PAPUC approved competitive procurements.~~

On March 17, 2016, PECO filed its fourth DSP Program with the PAPUC proposing a 24-month term from June 1, 2017 through May 31, 2019, in compliance with electric generation procurement guidelines set forth in Act 129. On December 8, 2016, the PAPUC approved the fourth DSP Program for the modified 48-month term and deferred CAP Shopping to another proceeding. Office of Consumer Advocate and Low Income Advocates subsequently filed a Petition for Reconsideration and Clarification related to CAP Shopping. On March 16, 2017, the PAPUC granted reconsideration and consolidated the proceeding with the DSP II docket, which includes the pending CAP Shopping plan that would allow low-income CAP customers to purchase their generation supply from EGSs. PAPUC referred the consolidated proceedings to the Office of Administrative Law Judge for hearing and decision.

~~Pennsylvania Act 11 of 2012 (Exelon and PECO).~~ In February 2012, Act 11 was signed into law, which provided the PAPUC authority to approve the implementation of a distribution system improvement charge (DSIC) in rates designed to recover capital project costs incurred to repair, improve or replace utilities’ aging electric and natural gas distribution systems in Pennsylvania. Prior to recovering costs pursuant to a DSIC, the PAPUC's implementation order requires a utility to have a Long Term Infrastructure Improvement Plan (LTIIP) approved by the Commission, which outlines how the utility is planning to increase its investment for repairing, improving or replacing aging infrastructure. The PAPUC approved PECO’s petition for its proposed electric DSIC and LTIIP on October 22, 2015 for spending of $275 million over a 5 year period through 2020. The PAPUC approved PECO's petition for its proposed modified gas LTIIP on June 14, 2017 for spending of $762 million over a 10 year period through 2022.

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~~(Dollars in millions, except per share data, unless otherwise noted)~~

Maryland Regulatory Matters

~~2017~~ Maryland ~~Electric~~Order Directing the Distribution ~~Rates~~of Energy Assistance Funds (Exelon, BGE, PHI, Pepco, and DPL). On June 15, 2021, the MDPSC issued an order authorizing the disbursal of funds to utilities in accordance with Maryland COVID-19 relief legislation. Under this order, BGE, Pepco, and DPL received funds of $50 million, $12 million, and $8 million, respectively, in July 2021. The funds have been used to reduce or eliminate certain qualifying past-due residential customer receivables.

New Jersey Regulatory Matters

Conservation Incentive Program (CIP) (Exelon, PHI, and ~~Pepco)~~ACE).On ~~March 24, 2017, Pepco~~September 25, 2020, ACE filed an application with the ~~MDPSC~~NJBPU as was required seeking approval to ~~increase its annual electric distribution base rates by $69 million, which was updated~~implement a portfolio of energy efficiency programs pursuant to ~~$67 million on August 24, 2017, reflecting a requested ROE of 10.1%.~~New Jersey’s clean energy legislation. The ~~application~~filing included a request to implement a CIP that would eliminate the favorable and unfavorable impacts of weather and customer usage patterns on distribution revenues for ~~an income tax adjustment~~most customers. The CIP compares current distribution revenues by customer class to ~~reflect full normalization of removal costs associated with pre-1981 property, which accounted for $18 million of the requested increase. On October 20, 2017, the MDPSC~~ approved ~~an increase~~target revenues established in Pepco electric distribution rates of $34 million, reflecting a ROE of 9.5%. On October 27, 2017, the MDPSC issued an errata order revising the approved increase in Pepco electric distribution rates to $32 million. The errata order corrected a number of computational errors in the original order but did not alter any of the findings. The new rates became effective for services rendered on or after October 20, 2017. In its decision, the MDPSC denied Pepco’s request regarding the income tax adjustment without prejudice to Pepco filing another similar proposal with additional information. Requests for rehearing are due November 20, 2017.

~~2017 Maryland Electric Distribution Rates (Exelon, PHI and DPL).~~ ~~On July 14, 2017, DPL filed an application with the MDPSC to increase its annual electric~~ACE’s most recent distribution base rates by $27 million, which was updated to $22 million on September 28, 2017, reflecting a requested ROE of 10.1%. DPL expects a decision in the matter in the first quarter of 2018, but cannot predict how much of the requested increase the MDPSC will approve.

~~2016 Maryland Electric Distribution Rates (Exelon, PHI and DPL).~~ On February 15, 2017, the MDPSC approved an increase in DPL electric distribution rates of $38 million reflecting a ROE of 9.6%. The new rates became effective for services rendered on or after February 15, 2017. The MDPSC also denied DPL’s request to continue its Grid Resiliency Program, through which DPL proposed to invest $5 million a year for two years to improve priority feeders and install single-phase reclosing fuse technology. The final order did not result in the recognition of any incremental regulatory assets or liabilities.

~~Cash Working Capital Order (Exelon and BGE).~~ On November 17, 2016, the MDPSC rendered a decision in the proceeding to review BGE’s request to recover its cash working capital (CWC) requirement for its Provider of Last Resort service, also known as Standard Offer Service (SOS), as well as other components that make up the Administrative Charge, the mechanism that enables BGE to recover all of its SOS-related costs. The Administrative Charge is now comprised of five components: CWC, uncollectibles, incremental costs, return, and an administrative adjustment, which is an adder to the utility’s SOS rate to act as a proxy for retail suppliers’ costs. The Commission accepted BGE's positions on recovery of CWC and pass-through recovery of BGE’s actual uncollectibles and incremental costs. The order also grants BGE a return on the SOS. The Commission ruled that the level of the administrative adjustment will be determined in BGE’s next rate case. On December 16, 2016, MDPSC Staff requested clarification concerning the amount of return on the SOS awarded to BGE and on December 19, 2016, the residential consumer advocate sought rehearing of the return awarded. On January 24, 2017, the MDPSC issued an order denying the MDPSC Staff request for clarification and the residential consumer advocate request for rehearing. On February 22, 2017, the residential consumer advocate filed an appeal of the MDPSC's orders with the Circuit Court for Baltimore City. The residential consumer advocate filed its Memorandum on Appeal on June 5, 2017 and subsequent Reply Memoranda were filed by BGE and the MDPSC on July 7, 2017 and July 12, 2017, respectively. On August 7, 2017, following oral argument by the parties, a decision was issued from the Circuit Court affirming the decision of the MDPSC. On September 5, 2017, the residential consumer advocate filed an appeal of the Circuit Court's decision to the Maryland Court of Special Appeals. BGE cannot predict the outcome of this appeal.

~~Smart Meter and Smart Grid Investments (Exelon and BGE).~~ In August 2010, the MDPSC approved a comprehensive smart grid initiative for BGE that included the planned installation of 2 million residential and commercial electric and natural gas smart meters at an expected total cost of $480 million of which $200 million was funded by SGIG. The MDPSC’s approval ordered BGE to defer the associated incremental costs, depreciation and amortization, and an appropriate return, in a regulatory asset until such time as a cost-effective advanced metering system is implemented. As of September 30, 2017 and December 31, 2016, the balance of BGE's regulatory asset was $219 million and $230 million, respectively, representing incremental program deployment costs. The current quarter balance of $219 million consists of three major components, including $133 million of unamortized incremental deployment costs of the AMI program, $54 million of unamortized costs of the non-AMI meters replaced under the program, and $32 million related to post-test year incremental program deployment costs incurred prior to approval became effective June 2016. The balance as of September 30, 2017 reflects the impact of the cost disallowances and adjustments in BGE's 2015 electric and natural gas distribution rate case. The ~~incremental deployment costs for the AMI program~~CIP is calculated annually and ~~the non-AMI meter components of the regulatory asset are being recovered through rates~~recovery is subject to certain conditions, including an earnings test and ~~amortized to expense~~

ceilings on customer rate increases.

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(Dollars in millions, except per share data, unless otherwise noted)

Note 3 — Regulatory Matters

On April 27, 2021, the NJBPU approved the settlement filed by ACE and the third parties to the proceeding. The approved settlement addresses all material aspects of ACE’s filing, including ACE’s ability to implement the CIP prospectively effective July 1, 2021. As a result of this decoupling mechanism, operating revenues will no longer be impacted by abnormal weather or usage for most customers. Starting in third quarter of 2021, ACE will record alternative revenue program revenues for its best estimate of the distribution revenue impacts resulting from future changes in CIP rates that it believes are probable of approval by the NJBPU in accordance with this mechanism.

Advanced Metering Infrastructure Filing (Exelon, PHI, and ACE). On August 26, 2020, ACE filed an application with the NJBPU as was required seeking approval to deploy a smart energy network in alignment with New Jersey’s Energy Master Plan and Clean Energy Act. The proposal consisted of estimated costs totaling $220 million with deployment taking place over a ~~10 year~~3-year implementation period ~~while~~from approximately 2021 to 2024 that involves the ~~post-test year~~installation of an integrated system of smart meters for all customers accompanied by the requisite communications facilities and data management systems.

On July 14, 2021, the NJBPU approved the settlement filed by ACE and the third parties to the proceeding. The approved settlement addresses all material aspects of ACE's smart energy network deployment plan, including cost recovery of the investment costs, incremental ~~program deployment costs~~O&M expenses, and the unrecovered balance of existing infrastructure through future distribution rates.

Regulatory Assets and Liabilities

The Utility Registrants' regulatory assets and liabilities have not ~~yet been approved~~changed materially since December 31, 2020, unless noted below. See Note 3 — Regulatory Matters of the Exelon 2020 Form 10-K for ~~recovery by the MDPSC. A return~~additional information on the specific regulatory assets and liabilities.

ComEd. Regulatory assets increased $93 million primarily due to an increase of $47 million in the Electric Distribution Formula Rate Annual Reconciliations regulatory asset ~~is currently included~~and $127 million in ~~rates, except~~the Energy Efficiency Costs regulatory asset, partially offset by a decrease of $87 million in the renewable energy regulatory asset.

DPL. Regulatory liabilities decreased $45 million primarily due to a decrease of $41 million in the Deferred Income Taxes regulatory liability.

Capitalized Ratemaking Amounts Not Recognized

The following table presents authorized amounts capitalized for ~~the $54 million portion representing the unamortized cost of the retired non-AMI meters and a $32 million portion~~ratemaking purposes related to ~~post-test year incremental program deployment costs.~~

~~As a combined result of~~earnings on shareholders’ investment that are not recognized for financial reporting purposes in Exelon's and the ~~MDPSC orders~~Utility Registrant's Consolidated Balance Sheets. These amounts will be recognized as revenues in ~~BGE's 2015 electric and natural gas distribution rate case, BGE recorded a $52 million charge in June 2016 to Operating and maintenance expense in Exelon’s and BGE’s~~the related Consolidated Statements of Operations and Comprehensive Income reducing certain regulatory assets and other long-lived assets and reclassified $56 million of non-AMI plant costs from Property, plant and equipment, net to Regulatory assets on Exelon's and BGE's Consolidated Balance Sheets. For further information, see Note 3 - Regulatory Matters of the Exelon 2016 Form 10-K.

~~Delaware Regulatory Matters~~

~~2017 Electric and Natural Gas Distribution Rates (Exelon, PHI and DPL).~~ On August 17, 2017, DPL filed applications with the DPSC to increase its annual electric and natural gas distribution base rates by $24 million, which was updated to $31 million on October 18, 2017, and $13 million, respectively, reflecting a requested ROE of 10.1%. DPL expects a decision in the electric proceeding and the gas proceeding in the third quarter of 2018, but cannot predict how much of the requested rate increases the DPSC will approve. While the DPSC is not required to issue a decision on the application within a specified period of time, Delaware law allows DPL to put into effect $2.5 million of the rate increase two months after filing the application and the entire requested rate increase seven months after filing, subject to a cap and a refund obligation based on the final DPSC order. On October 24, 2017, the Staff of the DPSC and the Public Advocate filed a joint motion to dismiss DPL's electric distribution base rate application without prejudice to refiling, arguing that the amount of the requested increase to $31 million required additional time to review and additional public notice. The DPSC is expected to decide at its meeting on November 9, 2017. DPL cannot predict the outcome of this matter.

~~2016 Electric and Natural Gas Distribution Rates (Exelon, PHI and DPL).~~ On May 17, 2016, DPL filed applications with the DPSC to increase its annual electric and natural gas distribution base rates by $63 million, which was updated to $60 million on March 8, 2017, and $22 million, respectively, reflecting a requested ROE of 10.6%. Delaware law allowed DPL to put into effect $2.5 million of each of the rate increases effective July 16, 2016. On December 17, 2016, the DPSC approved an additional $30 million in electric distribution rates and an additional $10 million in natural gas distribution rates effective December 17, 2016, subject to refund based on the final DPSC orders.

On March 8, 2017, DPL entered into a settlement agreement with the Division of the Public Advocate, Delaware Electric Users Group and the DPSC Staff in its electric distribution rate proceeding, which provides for an increase in DPL annual electric distribution base rates of $31.5 million reflecting a ROE of 9.7% comparedperiods they are billable to the $32 million increase previously put into effect. On May 23, 2017, the DPSC issued an order approving the settlement agreement, with the new rates effective June 1, 2017. Pursuant to the settlement agreement, no refund of the interim rates put into effect on July 16, 2016 and December 17, 2016 (as discussed above) is required.

On April 6, 2017, DPL entered into a settlement agreement with the Division of the Public Advocate and the DPSC Staff in its natural gas distribution rate proceeding, which provides for an increase in DPL annual natural gas distribution base rates of $4.9 million reflecting a ROE of 9.7%. The settlement agreement also provides that DPL will refund amounts collected under the temporary rates effective July 16, 2016 and December 17, 2016 (as discussed above) in excess of the $4.9 million, and that the new rates will be effective within thirty days of DPSC approval of the settlement agreement. On June 6, 2017, the DPSC issued an order approving the settlement agreement, with the new rates effective July 1, 2017. Pursuant to the settlement agreement, a rate refund plus interest of approximately $5 million was issued to customers beginning in August 2017 for which a regulatory liability has been recorded as of September 30, 2017. This is a one-time refund and was included on customer bills from mid-August through mid-September.

~~District of Columbia Regulatory Matters~~

~~2016 Electric Distribution Rates (Exelon, PHI and Pepco).~~ On June 30, 2016, Pepco filed an application with the DCPSC to increase its annual electric distribution base rates by $86 million, which was updated to $77 million on February 1, 2017, reflecting a requested ROE of 10.6%.

On July 25, 2017, the DCPSC approved an increase in Pepco electric distribution base rates of $37 million reflecting a ROE of 9.5%. The new rates became effective for services rendered on or after August 15, 2017. In its

Utility Registrants' customers.

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(Dollars in millions, except per share data, unless otherwise noted)

Note 3 — Regulatory Matters

~~decision,~~


	Exelon		ComEd(a)		PECO		BGE(b)		PHI		Pepco(c)		DPL(c)		ACE
September 30, 2021	$	44	$	—	$	—	$	39	$	5	$	3	$	2	$	—

December 31, 2020	51		(1)		—		45		7		4		3		—

__________

(a)Reflects ComEd's unrecognized equity returns/(losses) earned/(incurred) 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.

Generation Regulatory Matters (Exelon and Generation)

Impacts of the ~~DCPSC ordered that~~February 2021 Extreme Cold Weather Event and Texas-based Generating Assets Outages

Beginning on February 15, 2021, Generation’s Texas-based generating assets within the ~~$26 million customer rate credit created~~ERCOT market, specifically Colorado Bend II, Wolf Hollow II, and Handley, experienced outages as a result of extreme cold weather conditions. In addition, those weather conditions drove increased demand for service, dramatically increased wholesale power prices, and also increased gas prices in certain regions. In response to the ~~Exelon~~high demand and ~~PHI merger will~~significantly reduced total generation on the system, the PUCT directed ERCOT to use an administrative price cap of $9,000 per MWh during firm load shedding events.

During February and March 2021, various parties with differing interests, including generators and retail providers, filed requests with the PUCT to ~~offset~~void the ~~impact~~PUCT’s orders setting prices at $9,000 per MWh during firm load shedding events. Other requests were made for the PUCT to enforce its order and reduce prices for 33 hours between February 18 and February 19 after firm load shedding ceased, and to cap ancillary services at $9,000 per MWh.On March 2, 2021, a third party filed a notice of ~~this increase until that amount has been exhausted, which is expected to take approximately two years. Additionally,~~appeal in the ~~Commission is holding approximately $6 million to $7 million~~Court of Appeals for the Third District of Texas challenging the validity of the ~~customer rate credit~~PUCT’s actions. Generation intervened in that appeal and filed its initial brief on June 2, 2021. On April 19, 2021, Generation filed a declaratory action and request for ~~use toward a possible new class~~judicial review of ~~customers for certain senior citizens and disabled persons. The DCPSC also held that Pepco's bill stabilization adjustment, which decouples distribution revenues from utility customers from~~ the ~~amount~~PUCT’s orders setting prices at $9,000 per MWh in District Court of ~~electricity delivered, will continue to be in place and that no refund of previously collected funds is required. Several parties filed requests~~Travis County, Texas. Generation subsequently requested that the ~~DCPSC reconsider~~District Court of Travis County, Texas stay its proceeding pending action by the ~~order on various issues, and on October 6, 2017,~~Court of Appeals in the ~~Commission issued an order denying each of the requests.~~

~~District of Columbia Power Line Undergrounding Initiative (Exelon, PHI and Pepco).~~ ~~The District of Columbia government enacted on an emergency basis (effective~~third party proceeding. On May 17, ~~2017)~~2021, Generation amended its petition for declaratory action and thereafter on a permanent basis (effective July 11, 2017) legislation to amend the Electric Company Infrastructure Improvement Financing Act of 2014 (as amended) (the Infrastructure Improvement Financing Act) to authorize the District of Columbia Power Line Undergrounding (DC PLUG) initiative, a projected six year, $500 million project to place underground some of the District of Columbia’s most outage-prone power lines with $250 million of the project costs funded by Pepco and $250 million funded by the District of Columbia.

~~The $250 million of project costs funded by Pepco will be recovered through a volumetric surcharge on the electric bill of substantially all of Pepco's customers~~request for judicial review pending in the District Court of ~~Columbia. Pepco will earn~~Travis County, Texas. Exelon and Generation cannot predict the outcome of these proceedings or the financial statement impact.

Due to these events, a ~~return~~number of ERCOT market participants experienced bankruptcies or defaulted on ~~these project costs.~~

~~The $250~~payments to ERCOT, resulting in approximately a $3.0 billion payment shortfall in collections, which is allocated to the remaining ERCOT market participants. As of September 30, 2021, Generation has recorded its estimated portion of this obligation of approximately $17 million on a discounted basis, which is to be paid over a term of ~~project costs funded~~83 years. ERCOT rules historically have limited recovery of default from market participants to $2.5 million per month market-wide. In February 2021, the PUCT gave ERCOT discretion to disregard those rules, but ERCOT has declined to exercise that discretion thus far. On March 8, 2021, a third party filed a notice of appeal in the Court of Appeals for the Third District of Texas challenging the validity of the PUCT's order to ERCOT in February 2021. Generation intervened in that appeal and filed its initial brief on July 7, 2021. On May 7, 2021, Generation filed a declaratory action and request for judicial review of the PUCT's order in the District Court of Travis County, Texas. Generation subsequently requested that the District Court of Travis County, Texas stay its proceeding pending action by the District of Columbia will come from two sources. Project costs of $187.5 million will be funded through a charge assessed on Pepco by the District of Columbia; Pepco will recover this charge from customers through a volumetric distribution rider. The remaining costs up to $62.5 million are to be funded by the existing capital projects program of the District Department of Transportation (DDOT). Ownership and responsibility for the operation and maintenance of all the assets funded by the District of Columbia will be transferred to Pepco for a nominal amount upon completion. Pepco will not recover or earn a return on the cost of the assets transferred to it by the District of Columbia.

In accordance with the Infrastructure Improvement Financing Act, Pepco filed an application for approval of the first two-year portion of the DC PLUG initiative (the First Biennial Plan) on July 3, 2017. After the initial application, Pepco will be required to make two updated applications, one every two years until the project is completed. Pepco anticipates that the DCPSC will issue an order approving the First Biennial Plan in early November 2017. Upon the issuance of a DCPSC order approving the First Biennial Plan, Pepco will become obligated to pay $187.5 million to the District of Columbia over the six year project term, at which time it will record an obligation and offsetting regulatory asset.

~~New Jersey Regulatory Matters~~

~~New Jersey Consolidated Tax Adjustment (Exelon, PHI and ACE).~~ The Consolidated Tax Adjustment (CTA) is a New Jersey ratemaking policy that requires utilities that are part of a consolidated tax group to share with customers the tax benefits that came from losses at unregulated affiliates through a reduction in rate base. In 2013, the NJBPU opened a generic proceeding to review the policy. In 2014, the NJBPU issued a decision which retained the CTA, but in a highly modified format that significantly reduced the impact of the CTA to ACE. On September 18, 2017, the Appellate Division of the Superior Court of ~~New Jersey reversed~~Appeals in the ~~NJBPU’s decision in adopting~~third party proceeding. Exelon and Generation cannot predict the ~~revised CTA policy and held that NJBPU’s actions related to~~outcome of these proceedings or the CTA constituted a rulemaking that should have been undertaken pursuant to the requirements of the Administrative Procedures Act. The Court did not address the merits of the CTA methodology itself. No party filed an appeal of the Court’s decision, and the NJBPU is expected to conduct further proceedings. If the NJBPU were to apply the CTA in its unmodified form, it could have a material prospective impact to ACE through a reduction in rate base in future rate cases.

~~2017 Electric Distribution Rates (Exelon, PHI and ACE).~~ On March 30, 2017, ACE filed an application with the NJBPU to increase its annual electric distribution rates by $70 million (before New Jersey sales and use tax), which was updated to $73 million on July 14, 2017, reflecting a requested ROE of 10.1%. The application also requests approval of a rate surcharge mechanism called the “System Renewal Recovery Charge,” which would permit more timely recovery of certain costs associated with reliability and system renewal-related capital investments.

On September 8, 2017, ACE entered into a settlement agreement with the NJBPU staff, the New Jersey Division of Rate Counsel and Wal-Mart Stores, Inc. in its electric distribution rate proceeding, which provides for an increase

financial statement impact.

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(Dollars in millions, except per share data, unless otherwise noted)

Note 3 — Regulatory Matters

Additionally, several legislative proposals were introduced in ~~ACE annual electric distribution base rates~~the Texas legislature during February and March 2021 concerning the amount, timing and allocation of ~~$43 million (before New Jersey sales~~recovery of the $3.0 billion shortfall, as well as recovery of other costs associated with the PUCT's directive to set prices at $9,000 per MWh. Two of these proposals were enacted into law in June 2021 and ~~use tax) reflecting~~establish financing mechanisms that ERCOT and certain market participants can utilize to fund amounts owed to ERCOT. Generation participated in proceedings before the PUCT addressing the proposed allocation of the $2.1 billion in securitized funds for reliability and ancillary service charges over $9,000/MWh. In September 2021, Generation entered into a ~~ROE of 9.6%. In addition, pursuant~~settlement agreement and stipulation to resolve the allocation issues. The PUCT approved the settlement agreement ~~ACE agreed~~and stipulation on October 13, 2021.

In addition, other legislative proposals were introduced in the Texas legislature during February and March 2021 addressing cold-weather preparation for power plants and natural gas production and transportation infrastructure and the market structure for reliability services. The Texas legislature addressed these proposals by enacting a bill with a broad set of market reforms that, among other things, directed the PUCT to ~~withdraw~~establish weatherization standards for electric generators within six months of enactment and gave the PUCT authority to impose administrative penalties if the new proposed standards, once adopted, are not met. On October 21, 2021, the PUCT adopted rule change requiring generators by December 1, 2021 to complete a number of specified winter readiness preparations and to submit to ERCOT a report describing and certifying the completion of those preparations. The PUCT described these requirements as the first phase of its ~~request for approval~~actions with respect to winter preparedness, to be followed by a second phase consisting of a ~~System Renewal Recovery Charge without prejudice~~year-round set of weather preparedness standards to ~~its right~~be informed by a weather study that is being conducted by ERCOT.

The legislation also directs the PUCT to ~~refile.~~evaluate whether additional ancillary services are needed for reliability in the ERCOT power region to provide adequate incentives for dispatchable generation. Exelon and others have submitted various proposals to the PUCT with respect to a range of potential market reforms, including the implementation of additional ancillary service products as well as changes to the high system-wide offer cap and operating reserve demand curve, which remain pending. On September ~~22, 2017,~~23, 2021, the ~~NJBPU~~PUCT solicited comments regarding whether it should set ERCOT’s high system-wide offer cap at $4,500/MWh if the PUCT takes action to amend its rules with respect to that cap. Exelon and others submitted comments to the PUCT, which remain pending. The PUCT is expected to address potential changes to ERCOT’s market rules later in 2021.

In February 2021, more than 70 local distribution companies (LDCs) and natural gas pipelines in multiple states throughout the mid-continent region, where Generation serves natural gas customers, issued operational flow orders (OFOs), curtailments or other limitations on natural gas transportation or use to manage the operational integrity of the applicable LDC or pipeline system. When in effect, gas transportation or use above these limitations is subject to significant penalties according to the applicable LDCs’ and natural gas pipelines’ tariffs. Gas transportation and supply in many states became restricted due to wells freezing and pipeline compression disruption, while demand was increasing due to the extreme cold temperatures, resulting in extremely high natural gas prices. Due to the extraordinary circumstances, many LDCs and natural gas pipelines have either voluntarily waived or have sought applicable regulatory approvals to waive the tariff penalties associated with the extreme weather event. During March 2021, three natural gas pipelines filed individual petitions with FERC requesting approval to waive OFO penalties. Generation also filed motions in March 2021 to intervene and filed comments in support of these FERC waiver requests. On March 25, 2021, FERC issued an order on one of the petitions approving a pipeline’s request for a limited waiver of penalties for February 15, 2021. On April 23, 2021, Generation and several other entities filed a request at FERC for rehearing of this order which was denied on May 24, 2021. Generation and the other entities filed an appeal of the rehearing of the order with the U.S. Court of Appeals for the D.C. Circuit on July 21, 2021. Additionally, Generation and the other entities filed a complaint requesting that FERC expand the order to include additional days of the weather event in February, from February 16 through February 19, 2021. On October 21, 2021, FERC denied the complaint finding that a pipeline has the discretion whether to waive penalties under its tariff. Generation is evaluating whether to seek rehearing and appeal of the FERC order. During April 2021, FERC issued orders on the remaining petitions approving the ~~settlement agreement,~~requests to waive the penalties. During May 2021, an LDC filed a motion with the ~~new rates effective on~~Kansas Corporation Commission (KCC) requesting the KCC to grant a waiver from the tariff and allow the LDC to reduce the amounts assessed by permitting the removal of a multiplier from the penalty calculation. On October ~~1, 2017.~~

~~2016 Electric Distribution Rates (Exelon, PHI and ACE).~~ ~~On August 24, 2016, the NJBPU issued an order approving~~8, 2021, a ~~stipulation of~~ settlement among ACE, the New Jersey Division of Rate Counsel, NJBPU Staff and Unimin Corporation, which, among other things, provided that a determination on ACE's grid resiliency program, PowerAhead, would be separated into a phase II of the rate proceeding and decided at a later date. PowerAhead includes capital investments to enhance the resiliency of the system through improvements focused on improving the distribution system's ability to withstand major storm events. A stipulation of settlement with respect to the PowerAhead program (the PowerAhead Stipulation) was approved by the NJBPU on May 31, 2017. As adopted, the PowerAhead program includes an approved investment level of $79 million to be recovered through the cost recovery mechanism described in the PowerAhead Stipulation. The NJBPU order adopting the PowerAhead Stipulation was effective on June 10, 2017.

~~Update and Reconciliation of Certain Under-Recovered Balances (Exelon, PHI and ACE).~~ On February 1, 2017, ACE submitted its 2017 annual petition with the NJBPU seeking to reconcile and update (i) charges related to the recovery of above-market costs associated with ACE’s long-term power purchase contracts with the non-utility generators and (ii) costs related to surcharges for the New Jersey Societal Benefit Program (a statewide public interest program that is intended to benefit low income customers and address other public policy goals) and ACE’s uncollectible accounts. As filed, the net impact of adjusting the charges as proposed would have been an overall annual rate decrease of approximately $29 million (revised to approximately $32 million in April 2017, based upon an update for actuals through March 2017), including New Jersey sales and use tax. On May 31, 2017, the NJBPU approved a stipulation of settlement entered into by the parties providing for an overall annual rate decrease of approximately $32 million, effective June 1, 2017. The rate decrease was placed into effect provisionally, subject to a review by NJBPU and the Division of Rate Counsel of the final underlying costs for reasonableness and prudence. This rate decrease will have no effect on ACE’s operating income, since these revenues provide for recovery of deferred costs under an approved deferral mechanism. The matter is pending at the NJBPU.

~~New York Regulatory Matters~~

~~New York Clean Energy Standard (Exelon and Generation).~~ On August 1, 2016, the New York Public Service Commission (NYPSC) issued an order establishing the New York CES, a component of which is the Tier 3 ZEC program targeted at preserving the environmental attributes of zero-emissions nuclear-powered generating facilities that meet the criteria demonstrating public necessity as determined by the NYPSC. The New York State Energy Research and Development Authority (NYSERDA) will centrally procure the ZECs from eligible plants through a 12-year contract, to be administered in six two-year tranches, extending from April 1, 2017 through March 31, 2029. ZEC payments will be made to the eligible resources based upon the number of MWh produced, subject to specified caps and minimum performance requirements. The price to be paid for the ZECs under each tranche will be administratively determined using a formula based on the social cost of carbon as determined in 2016 by the federal government, subject to pricing adjustments designed to lower the ZEC price based on increase in underlying energy and capacity prices. The ZEC price for the first tranche has been set at $17.48 per MWh of production. Following the first tranche, the price will be updated bi-annually. Each Load Serving Entity (LSE) shall be required to purchase an amount of ZECs equivalent to its load ratio share of the total electric energy in the New York Control Area. Cost recovery from ratepayers shall be incorporated into the commodity charges on customer bills.

The NYPSC initially identified three plants eligible for the ZEC program: the FitzPatrick, Ginna, and Nine Mile Point nuclear facilities. As issued, the order also provided that the duration of the program beyond the first tranche was conditional upon a buyer purchasing the FitzPatrick facility and taking title prior to September 1, 2018. On November 18, 2016, the required contracts with NYSERDA were executed for Ginna and Nine Mile Point, in addition to Entergy’s execution of the required contract for the FitzPatrick facility. On March 31, 2017, Generation closed on the acquisition of FitzPatrick. Generation is currently recognizing revenue for the sale of New York ZECs in the month following generation when the ZECs are transferred to NYSERDA. For the three and nine months ended September 30, 2017, Generation has recognized $118 million and $191 million of ZEC revenue.

~~Several parties~~ filed with the ~~NYPSC requests for rehearing or reconsideration~~KCC that, if approved, would resolve this matter. Exelon and Generation cannot predict the outcome of the ~~New York CES. Generation~~pending FERC complaint proceeding, the KCC proceeding, or the determinations made by the LDCs and CENG also filed a request for clarification, or in the alternative limited rehearing, that the condition limiting the duration of the program beyond the first tranche be limited to the eligibility of the FitzPatrick plant only and have no

natural gas pipelines.

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Note 3 — Regulatory Matters

~~bearing on Ginna or Nine Mile Point’s eligibility~~Illinois Regulatory Matters

Clean Energy Law. See Clean Energy Law above for ~~the full 12-year duration. On December 15, 2016, the NYPSC approved Generation’s and CENG's petition~~additional information related to clarify this condition and denied all petitions for rehearing of the New York CES. Parties had until mid-April to appeal to New York State court the denials of the requests for rehearing. A Petition seeking to invalidate the ZEC program was filed in New York State court by certain environmental groups and other parties on November 30, 2016, and amended on January 13, 2017, arguing that the NYPSC did not have authority to establish the program and that it violated certain technical provisions of the State Administrative Procedures Act (SAPA) when adopting the ZEC program. On February 15, 2017, Generation and CENG filed a motion to dismiss the state court action. The NYPSC also filed a motion to dismiss the state court action. On March 24, 2017, the plaintiffs filed a memorandum of law opposing the motions to dismiss, and Generation and CENG filed a reply brief on April 28, 2017. Oral argument was held on June 19, 2017. The motions to dismiss are pending.

On October 19, 2016, a coalition of fossil generation companies filed a complaint in federal district court against the NYPSC alleging that the ZEC program violates certain provisions of the U.S. Constitution; specifically that the ZEC program interferes with FERC’s jurisdiction over wholesale rates and that it discriminates against out of state competitors. On December 9, 2016, Generation and CENG filed a motion to intervene in the case and to dismiss the lawsuit. The State also filed a motion to dismiss. Oral argument was held on March 29, 2017. On July 25, 2017, the court granted both motions to dismiss. On August 24, 2017, plaintiffs appealed the decision to the Second Circuit. ~~Plaintiffs-Appellants’ initial brief was filed on October 13, 2017. The state’s and Exelon’s briefs are due on November 17, 2017. Reply briefs are due on December 1, 2017.~~

~~Other legal challenges remain possible, the outcomes of which remain uncertain.~~Generation. See Note 7 -– Early ~~Nuclear~~ Plant Retirements for additional information ~~relative to Ginna and Nine Mile Point. See Note 4 - Mergers, Acquisitions and Dispositions~~on Generation’s Illinois nuclear plants.

New Jersey Regulatory Matters

New Jersey Clean Energy Legislation. On May 23, 2018, New Jersey enacted legislation that established a ZEC program that provides compensation for ~~additional information on Generation's acquisition of FitzPatrick.~~

~~Ginna Nuclear Power Plant Reliability Support Services Agreement (Exelon and Generation).~~ In November 2014, in response to a petition filed by Ginna Nuclear Power Plant (Ginna) regarding the possible retirement of Ginna, the NYPSC directed Ginna and Rochester Gas & Electric Company (RG&E) to negotiate a Reliability Support Services Agreement (RSSA) to support the continued operation of Ginna to maintain the reliability of the RG&E transmission grid for a specified period of time. During 2015 and 2016, Ginna and RG&E made filings with the NYPSC and FERC for their approval of the proposed RSSA. Although the RSSA was still subject to regulatory approvals, on April 1, 2015, Ginna began delivering the power and capacity from the Ginna plant into the ISO-NY consistent with the technical provisions of the RSSA.

~~On March 22, 2016, Ginna submitted a compliance filing with FERC with revisions~~nuclear plants that demonstrate to the ~~RSSA requested by FERC.~~NJBPU that they meet certain requirements, including that they make a significant contribution to air quality in the state and that their revenues are insufficient to cover their costs and risks. Under the legislation, the NJBPU will issue ZECs to qualifying nuclear power plants and the electric distribution utilities in New Jersey, including ACE, will be required to purchase those ZECs. On April ~~8, 2016, FERC accepted~~18, 2019, the ~~compliance filing~~NJBPU approved the award of ZECs to Salem 1 and ~~on April 20, 2016, the NYPSC accepted the revised RSSA with a term expiring on March 31, 2017. In April 2016,~~Salem 2. Upon approval, Generation began recognizing revenue based on the final approved pricing contained in the RSSA and also recognized a one-time revenue adjustment of approximately $101 million representing the net cumulative previously unrecognized amount of revenue retroactive from the April 1, 2015 effective date through March 31, 2016. A 49.99% portion of the one-time adjustment was removed from Generation’s results of operations as a result of the noncontrolling interests in CENG.

The RSSA required Ginna to continue operating through the RSSA term. On September 30, 2016, Ginna filed the required notice with the NYPSC of its intent to continue operating beyond the March 31, 2017 expiry of the RSSA, conditioned upon successful execution of an agreement between Ginna and NYSERDA for the sale of New Jersey ZECs ~~under~~in the month they are generated. On March 19, 2021, a three-judge panel of the Superior Court of New Jersey Appellate Division unanimously affirmed the NJBPU’s April 2019 order awarding ZECs for the first eligibility period. On April 8, 2021, New Jersey Rate Counsel filed a notice asking the New ~~York CES. As stated previously, on November 18, 2016~~Jersey Supreme Court to hear the ~~required contract with NYSERDA was executed by Generation and CENG for Ginna. Upon the expiry~~appeal of the ~~RSSA~~Superior Court’s order. On July 9, 2021, the New Jersey Supreme Court declined to hear the appeal. On October 1, 2020, PSEG and Generation filed applications seeking ZECs for the second eligibility period (June 2022 through May 2025). On April 27, 2021, the NJBPU approved the award of ZECs to Salem 1 and Salem 2 for the second eligibility period. On May 11, 2021, the New Jersey Rate Counsel appealed the April 27, 2021 decision to the Superior Court of New Jersey Appellate Division. Briefing on ~~March 31, 2017, Ginna was required to make refund payments of $20 million to RG&E related to capital expenditures. Ginna paid RG&E~~ the $20 million in June 2017. Additionally, the provisions of the RSSA provided for a one-time payment of $12 million to be paid from RG&E to Ginna at the end of the contract. This $12 million was recognized in revenue as of March 31, 2017. RG&E paid the $12 million to Ginna in May 2017. Subject to prevailing over any administrative or legal challenges, itappeal is expected to conclude in the fourth quarter of 2021 or first quarter of 2022. Exelon and Generation cannot predict the outcome of this proceeding.

New ~~York CES will allow Ginna to continue to operate through the end~~England Regulatory Matters

Mystic Units 8 and 9 and Everett Marine Terminal Cost of Service Agreement. On March 29, 2018, Generation notified grid operator ISO-NE of its ~~current operating license in 2029. See Note 7-Early Nuclear Plant Retirements for further information regarding the impacts of a decision~~plans to early retire ~~one or more nuclear plants.~~Mystic Units 8 and 9 absent regulatory reforms on June 1, 2022. On May 16, 2018, Generation made a filing with FERC to establish cost-of-service compensation and terms and conditions of service for Mystic Units 8 & 9 for the period between June 1, 2022 - May 31, 2024. On December 20, 2018, FERC issued an order accepting the cost of service compensation, reflecting a number of adjustments to the annual fixed revenue requirement and allowing for recovery of a substantial portion of the costs associated with the adjacent Everett Marine Terminal acquired by Generation in October 2018. Those adjustments were reflected in a compliance filing made on March 1, 2019. In the December 20, 2018 order, FERC also directed a paper hearing on ROE using a new methodology. On January 22, 2019, Exelon and several other parties filed requests for rehearing of certain findings in the order. On July 15, 2021, FERC issued an order establishing the ROE to be used in the cost of service agreement for Mystic 8 and 9 at 9.33%. On August 16, 2021, Exelon and several other parties filed requests for rehearing of certain aspects of the July 15, 2021 order. These requests were denied by operation of law; however, FERC indicated it would address the issues raised in the request in a future order.

On July 17, 2020, FERC issued three orders, which together affirmed the recovery of key elements of Mystic's cost of service compensation, including recovery of costs associated with the operation of the Everett Marine Terminal. FERC directed a downward adjustment to the rate base for Mystic Units 8 and 9, the effect of which will be partially offset by elimination of a crediting mechanism for third party gas sales during the term of the cost of service agreement. In addition, several parties filed protests to a compliance filing by Generation on September 15, 2020, taking issue with how gross plant in-service was calculated, and Generation filed an answer to the protests on October 21, 2020. On December 21, 2020, FERC issued an order on rehearing of the three July 17, 2020 orders, clarifying several cost of service provisions. Several parties appealed the December 21, 2020 order to the U.S. Court of Appeals for the D.C. Circuit and that appeal was consolidated with appeals of orders issued December 20, 2018 and July 17, 2020 in the Mystic proceeding. Briefs in support of their petitions for review were filed by Exelon and several other parties on September 7, 2021. Briefing is expected to conclude in February 2022.

On February 25, 2021, Mystic made its filing to comply with the December 21, 2020 order. On April 26, 2021, FERC rejected Mystic’s language and directed another compliance filing relating to the claw back provision language, which only applies if Mystic 8 and 9 were to continue operation after the conclusion of the cost-of-service period. FERC’s April 26, 2021 order also accepted in part and rejected in part Mystic’s September 15, 2020 compliance filing. It directed a further compliance filing in 60 days consistent with the information provided

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(Dollars in millions, except per share data, unless otherwise noted)

Note 3 — Regulatory Matters

in Mystic’s October 21, 2020 answer to protests, which Mystic filed on June 2, 2021 and FERC accepted on July 29, 2021. On August 16, 2021, Mystic made a compliance filing, reflecting changes to the cost of service agreement to comply with the July 15, 2021 order on ROE.

On August 25, 2020, a group of New England generators filed a complaint against Generation seeking to extend the scope of the claw back provision in the cost-of-service agreement, whereby Generation would refund certain amounts recovered during the term of the cost of service if it returns to market afterwards. On April 15, 2021 FERC dismissed the complaint.

On February 16, 2021, Generation filed an unopposed motion to voluntarily dismiss an appeal filed with the U.S. Court of Appeals for the D.C. Circuit stemming from a June 2020 complaint filed with FERC against ISO-NE over failures to follow its tariff in evaluating Mystic for transmission security for the 2024 to 2025 Capacity Commitment Period, which was granted on February 18, 2021.

See Note 7 — Early Plant Retirements for additional information on the impacts of Generation’s August 2020 decision to retire Mystic Units 8 and 9 upon expiration of the cost of service agreement.

Federal Regulatory Matters

~~Transmission Formula Rate (Exelon, ComEd, BGE, Pepco, DPL and ACE).~~ ~~The following total increases/(decreases) were included in ComEd’s, BGE’s, Pepco's, DPL's and ACE's 2017 annual electric transmission formula rate filings:~~

2017
Annual Transmission Filings^(a)
ComEd BGE Pepco DPL ACE
Initial revenue requirement
increase
$ 44
$ 31
$ 5
$ 6
$ 20
Annual reconciliation (decrease) increase (33 ) 3
15
8
22
Dedicated facilities decrease^(b)
—
(8 ) —
—
—
Total revenue requirement increase $ 11
$ 26
$ 20
$ 14
$ 42

Allowed return on rate base^(c)
8.43 % 7.47 % 7.92 % 7.16 % 8.02 %
Allowed ROE^(d)
11.50 % 10.50 % 10.50 % 10.50 % 10.50 %

~~_________~~


~~(a)~~	~~All rates are effective June 2017, subject to review by the FERC and other parties, which is due by fourth quarter 2017.~~


~~(b)~~	~~BGE's transmission revenues include a FERC approved dedicated facilities charge to recover the costs of providing transmission service to specifically designated load by BGE.~~


~~(c)~~	~~Represents the weighted average debt and equity return on transmission rate bases.~~

~~(d)~~

As part of the FERC-approved settlement of ComEd’s 2007 transmission rate case, the rate of return on common equity is 11.50% and the common equity component of the ratio used to calculate the weighted average debt and equity return for the transmission formula rate is currently capped at 55%. As part of the FERC-approved settlement of the ROE complaint against BGE, Pepco, DPL and ACE, the rate of return on common equity is 10.50%, inclusive of a 50 basis point incentive adder for being a member of a regional transmission organization.

~~For additional information regarding transmission formula rate filings see Note 3 — Regulatory Matters of the Exelon 2016 Form 10-K.~~

~~Transmission Formula Rate (Exelon and PECO).~~ On May 1, 2017, PECO filed a request with FERC seeking approval to update its transmission rates and change the manner in which PECO’s transmission rate is determined from a fixed rate to a formula rate. The formula rate would be updated annually to ensure that under this rate customers pay the actual costs of providing transmission services. The formula rate filing includes a requested increase of $22 million to PECO’s annual transmission revenues and a requested rate of return on common equity of 11%, inclusive of a 50 basis point adder for being a member of a regional transmission organization. PECO requested that the new transmission rate be effective as of July 2017. On June 27, 2017, FERC issued an Order accepting the filing and suspending the proposed rates until December 1, 2017, subject to refund, and set the matter for hearing and settlement judge procedures. PECO cannot predict the final outcome of the settlement or hearing proceedings, or the transmission formula FERC may approve.

~~PJM Transmission Rate Design and Operating Agreements (Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE).~~ PJM Transmission Rate Design specifies the rates for transmission service charged to customers within PJM. Currently, ComEd, PECO, BGE, Pepco, DPL and ACE incur costs based on the existing rate design, which charges customers based on the cost of the existing transmission facilities within their load zone and the cost of new transmission facilities based on those who benefit from those facilities. In April 2007, FERC issued an order concluding that PJM’s current rate design for existing facilities is just and reasonable and should not be changed. In the same order, FERC held that the costs of new facilities 500 kV and above should be socialized across the entire PJM footprint and that the costs of new facilities less than 500 kV should be allocated to the customers of the new facilities who caused the need for those facilities. A number of parties appealed to the U.S. Court of Appeals for the Seventh Circuit for review of the decision.

In August 2009, the court issued its decision affirming the FERC’s order with regard to the existing facilities, but remanded to FERC the issue of the cost allocation associated with the new facilities 500 kV and above (Cost Allocation Issue) for further consideration by the FERC. On remand, FERC reaffirmed its earlier decision to socialize the costs of new facilities 500 kV and above. A number of parties filed appeals of these orders. In June 2014, the court again remanded the Cost Allocation Issue to FERC. On December 18, 2014, FERC issued an order setting an evidentiary hearing and settlement proceeding regarding the Cost Allocation Issue. ~~On June 15, 2016, a number of parties, including~~

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~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

Exelon and the Utility Registrants, filed a proposed Settlement with FERC. If the Settlement is approved, 50% of the costs of the 500 kV and above facilities approved by the PJM Board on or before February 1, 2013 will be socialized across PJM and 50% will be allocated according to a formula that calculates the flows on the transmission facilities. Each state that is a party in this proceeding either signed, or did not oppose, the settlement. The Settlement is opposed by a number of merchant transmission owners and New York load-serving entities. The Settlement includes provisions for monthly credits or charges that are expected to be mostly refunded or recovered through customer rates over a 10-year period based on negotiated numbers for charges prior to January 1, 2016.

Exelon expects that the Settlement will not have a material impact on the results of operations, cash flows and financial position of Generation, ComEd, PECO, BGE, Pepco, DPL or ACE. The Settlement is subject to approval by ~~FERC.~~

~~DOE Notice of Proposed Rulemaking (Exelon and Generation).~~ On August 23, 2017, the DOE released its report on the reliability of the electric grid. One aspect of the wide-ranging report is the DOE’s recognition that the electricity markets do not currently value the resiliency provided by baseload generation, such as nuclear plants. On September, 28, 2017, the DOE issued a Notice of Proposed Rulemaking (NOPR) that would entitle certain eligible resilient generating units (i.e., those located in organized markets, with a 90-day supply of fuel on site, not already subject to state cost of service regulation and satisfying certain other requirements) to recover fully allocated costs and earn a fair return on equity on their investment. The DOE issued the NOPR under an infrequently-used section of the DOE Organization Act under which the FERC has exclusive jurisdiction to consider and take any final action related to NOPRs proposed by the DOE. The DOE NOPR recommended that the FERC take comments for 45 days after publication in the Federal Register and issue a final order 60 days after such publication. On October 2, 2017, the FERC issued a notice inviting comments regarding the DOE NOPR within 21 days and established a new docket wherein the FERC will consider the matter. On October 23, 2017, Exelon filed comments with the FERC, supporting the goals of the NOPR and urging the agency to take swift action to protect customers from power supply interruptions and ensure resiliency in a way that appropriately balances the value and cost to customers. Exelon cannot predict the final outcome of the proceeding or its potential impact, if any, on Exelon or Generation.

~~Complaints at FERC Seeking to Mitigate Illinois and New York Programs Providing ZECs (Exelon and Generation).~~ NYISO MOPR Proceedings. PJM and NYISO capacity markets include a ~~Minimum Offer Price Rule (MOPR) that is intended to preclude buyers from exercising buyer market power.~~MOPR. If a resource is subjected to a MOPR, its offer is adjusted to effectively remove the revenues it receives through a ~~federal,~~ state ~~or other~~ government-provided financial support program - resulting in a higher offer that may not clear the capacity market. Prior to December 19, 2019, the MOPR in PJM applied only to certain new gas-fired resources. Currently, the ~~MOPRs~~MOPR in NYISO applies only to certain resources in downstate New York.

For Generation’s nuclear facilities in PJM and NYISO ~~apply only to certain new resources. Exelon has generally opposed policies~~ that require subsidies or give preferential treatment to generation providers or technologies that do not provide superior reliability or environmental benefits, or that would threaten the reliability and value of the integrated electricity grid. Thus, Exelon has supported a MOPR as a means of minimizing the detrimental impact certain subsidized resources could have on capacity markets (such as the New Jersey (LCAPP) and Maryland (CfD) programs). However, in Exelon’s view, MOPRs should not be applied to resources that receiveare currently receiving state-supported compensation for ~~providing superior reliability or environmental benefits.~~

On January 9, 2017, the Electric Power Supply Association (EPSA) filed two requests with FERC: one seeking to amend a prior complaint against PJM and another seeking expedited action on a pending NYISO compliance filing in an existing proceeding. Both filings allege that the relevant MOPR should be expanded to also apply to existing resources receiving ZEC compensation under the New York CES and Illinois ZES programs. The EPSA parties have filed motions to expedite both proceedings. Exelon has filed protests at FERC in response to each filing, arguing generally that ZEC payments provide compensation for an environmental attribute that is distinct from the energy and capacity sold in the FERC-jurisdictional markets, and therefore, are no different than other renewable support programs like the PTC and RPS that have generally not been subject to a MOPR. However, if successful, for Generation's facilities in NYISO and PJM expected to receive ZEC compensation (Quad Cities, Ginna, Nine Mile Point and FitzPatrick),carbon-free attributes, an expanded MOPR ~~could~~would require exclusion of ~~ZEC~~such compensation when bidding into future capacity auctions, ~~such that these facilities would have~~resulting in an increased risk of these facilities not ~~clearing in those auctions and thus no longer~~ receiving capacity revenues ~~during~~in future auctions.

On December 19, 2019, FERC required PJM to broadly apply the ~~respective~~MOPR to all new and existing resources including nuclear, renewables, demand response, energy efficiency, storage, and all resources owned by vertically-integrated utilities. This greatly expanded the breadth and scope of PJM’s MOPR, which became effective as of PJM’s capacity auction for the 2022-23 planning year. While FERC included some limited exemptions, no exemptions were available to state-supported nuclear resources.

FERC provided no new mechanism for accommodating state-supported resources other than the existing FRR mechanism (under which an entire utility zone would be removed from PJM’s capacity auction along with sufficient resources to support the load in such zone). In response to FERC’s order, PJM submitted a compliance filing on March 18, 2020 wherein PJM proposed tariff language interpreting and implementing FERC's directives, and proposed a schedule for resuming capacity auctions that is contingent on the timing of FERC's action on the compliance filing.

On April 16, 2020, FERC issued an order largely denying most requests for rehearing of FERC's December 2019 order but granting a few clarifications that required an additional PJM compliance filing which PJM submitted on June 1, 2020.

A number of parties, including Exelon, have filed petitions for review of FERC's orders in this proceeding, which remain pending before the Court of Appeals for the District of Columbia Circuit.

As a result, the MOPR applied in the capacity auction for the 2022-23 planning year to Generation's owned or jointly owned nuclear plants in those states receiving a benefit under the Illinois ZES and the New Jersey ZEC program. The MOPR prevented Quad Cities from clearing in that capacity auction.

At the direction of the PJM Board of Managers, PJM and its stakeholders developed further MOPR reforms to ensure that the capacity market rules respect and accommodate state resource preferences such as the ZEC programs. ~~Any such mitigation~~PJM filed related tariff revisions at FERC on July 30, 2021 and, on September 29, 2021, PJM's proposed MOPR reforms became effective by operation of ~~these generating resources could have a material effect on Exelon’s and Generation’s future cash flows and results of operations. On August 30, 2017, EPSA filed motions to lodge~~law. Under the district court decisions dismissing the complaints and urging FERC to act expeditiously on its requests to expand the MOPR. On September 14, 2017, Exelon filed a response in each docket noting that it does not oppose the motions to lodge but arguing that the requests to expedite a decision on the requests to expandnew tariff provisions, the MOPR ~~have~~will no ~~merit. The timing~~longer apply to any of ~~FERC’s decision with respect to both proceedings is currently unknown and the outcome~~Generation’s owned or jointly owned nuclear plants. A request for rehearing of ~~these matters is currently uncertain.~~

FERC’s

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— ~~(Continued)~~

(Dollars in millions, except per share data, unless otherwise noted)

Note 3 — Regulatory Matters

notice establishing the effective date for PJM’s proposed market reforms was filed on October 5, 2021 and remains pending.

On February 20, 2020, FERC issued an order rejecting requests to expand NYISO’s version of the MOPR (referred to as buyer-side mitigation rules) beyond its current limited applicability to certain resources in downstate. However, on October 14, 2020, two natural gas-fired generators in New York filed a complaint at FERC seeking to expand the MOPR in NYISO to apply to all resources, new and existing, across the entire NYISO market. Exelon is strenuously opposing expansion of FERC’s MOPR policies in the NYISO market. While it is too early in the proceeding to predict its outcome and there are significant differences between the NYISO and PJM markets that would justify a different result, if FERC applies the MOPR in NYISO broadly as requested in the complaint, Generation’s facilities in NYISO that are receiving ZEC compensation may be at increased risk of not clearing the capacity auction.

If Generation’s state-supported nuclear plants in PJM or NYISO are subjected to the MOPR or equivalent without compensation under an FRR or similar program, it could have a material adverse impact on Exelon's and Generation's financial statements, which Exelon and Generation cannot reasonably estimate at this time.

Operating License Renewals ~~(Exelon and Generation).~~

Conowingo Hydroelectric Project. On August 29, 2012, Generation submitted ~~a hydroelectric license~~an application to FERC for a ~~46-year~~new license for the Conowingo Hydroelectric Project (Conowingo). In connection with Generation’s efforts to obtain a water quality certification pursuant to Section 401 of the Clean Water Act ~~with Maryland Department of the Environment (MDE)~~(401 Certification) from MDE for Conowingo, Generation ~~continues to work~~had been working with MDE and other stakeholders to resolve water quality licensing issues, including: (1) water quality, (2) fish habitat, and (3) sediment. ~~In addition, Generation continues to work with MDE and other Federal and Maryland state agencies to conduct and fund an additional sediment and nutrient monitoring study.~~

On April ~~21, 2016, Exelon~~27, 2018, MDE issued its 401 Certification for Conowingo. On October 29, 2019, Generation and ~~Interior executed~~MDE filed with FERC a Joint Offer of Settlement ~~Agreement resolving~~(Offer of Settlement) that would resolve all ~~fish passage~~outstanding issues ~~between~~relating to the ~~parties. The financial impact~~401 Certification. Pursuant to the Offer of Settlement, the ~~Settlement Agreement is estimated~~parties submitted Proposed License Articles to FERC to be ~~$3 million~~incorporated by FERC into the new license in accordance with FERC’s discretionary authority under the Federal Power Act.

On March 19, 2021, FERC issued a new 50-year license for Conowingo, effective March 1, 2021. FERC adopted the Proposed License Articles into the new license only making modifications it deemed necessary to ~~$7 million per year, on average, over~~allow FERC to enforce the ~~46-year life~~Proposed License Articles. Consistent with the Offer of Settlement, FERC found that MDE waived its 401 Certification. On April 19, 2021, a few environmental groups filed with FERC a petition for rehearing requesting that FERC reconsider the issuance of the new Conowingo license, ~~including both capital~~which was denied by operation of law on May 20, 2021. On June 17, 2021, the petitioners appealed FERC’s ruling to the United States Court of Appeals. On July 15, 2021, FERC issued an order addressing the arguments raised on rehearing, affirming the determinations of its March 19, 2021 order. Generation cannot predict the outcome of this proceeding.

4. Revenue from Contracts with Customers (All Registrants)

The Registrants recognize revenue from contracts with customers to depict the transfer of goods or services to customers at an amount that the entities expect to be entitled to in exchange for those goods or services. Generation’s primary sources of revenue include competitive sales of power, natural gas, and ~~operating costs.~~other energy-related products and services. The ~~actual timing~~Utility Registrants’ primary sources of revenue include regulated electric and ~~amount of these costs are not currently fixed~~gas tariff sales, distribution, and may vary significantly from year to year throughout the life of the new license. Resolution of the remaining issues relating to Conowingo involving various stakeholders may have a material effect on Exelon’s and Generation’s results of operations and financial position through an increase in capital expenditures and operating costs. As of September 30, 2017, $30 million of direct costs associated with Conowingo licensing efforts have been capitalized. transmission services.

See Note ~~3 - Regulatory Matters~~4 — Revenue from Contracts with Customers of the Exelon ~~2016~~2020 Form 10-K for additional information regarding the primary sources of revenue for the Registrants.

Contract Balances (All Registrants)

Contract Assets

Generation records contract assets for the revenue recognized on ~~Generation's operating license renewal efforts.~~

~~Regulatory Assets~~the construction and ~~Liabilities (Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE)~~

~~Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE each prepare their consolidated financial statements in accordance with the authoritative guidance for accounting for certain types~~installation of regulation. Under this guidance, regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent the excess recovery of costs or accrued credits that have been deferred because it is probable such amounts will be returned to customers through future regulated rates or represent billings in advance of expenditures for approved regulatory programs.

~~As a result of applying the acquisition method of accounting and pushing it down to the consolidated financial statements of PHI, certain regulatory~~energy efficiency assets and ~~liabilities were established at Exelon~~new power generating facilities before Generation has an unconditional right to bill for and PHI to offset the impacts of fair valuing the acquired assets and liabilities assumed which are subject to regulatory recovery. In total, Exelon and PHI recorded a net $2.4 billion regulatory asset reflecting adjustments recorded as a result of the acquisition method of accounting. See Note 4 — Mergers, Acquisitions and Dispositions for additional information.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— ~~(Continued)~~

(Dollars in millions, except per share data, unless otherwise noted)

Note 4 — Revenue from Contracts with Customers

receive the consideration from the customer. These contract assets are subsequently reclassified to receivables when the right to payment becomes unconditional. Generation records contract assets and contract receivables in Other current assets and Customer accounts receivable, net, respectively, in Exelon’s and Generation’s Consolidated Balance Sheets.

The following ~~tables provide information about~~table provides a rollforward of the ~~regulatory~~contract assets reflected in Exelon's and Generation's Consolidated Balance Sheets for the three and nine months ended September 30, 2021 and 2020. The Utility Registrants do not have any contract assets.



	Exelon		Generation
Balance as of December 31, 2020	$	144	$	144
Amounts reclassified to receivables	(16)		(16)
Revenues recognized	13		13
Amounts previously held-for-sale	12		12
Balance as of March 31, 2021	153		153
Amounts reclassified to receivables	(12)		(12)
Revenues recognized	9		9
Balance as of June 30, 2021	150		150
Amounts reclassified to receivables	(15)		(15)
Revenues recognized	14		14

Balance as of September 30, 2021	$	149	$	149


	Exelon		Generation
Balance as of December 31, 2019	$	174	$	174
Amounts reclassified to receivables	(19)		(19)
Revenues recognized	17		17

Balance as of March 31, 2020	172		172
Amounts reclassified to receivables	(26)		(26)
Revenues recognized	13		13
Balance as of June 30, 2020	159		159
Amounts reclassified to receivables	(18)		(18)
Revenues recognized	19		19
Balance as of September 30, 2020	$	160	$	160

Contract Liabilities

The Registrants record contract liabilities when consideration is received or due prior to the satisfaction of ~~Exelon, ComEd, PECO, BGE,~~the performance obligations. The Registrants record contract liabilities in Other current liabilities and Other noncurrent liabilities in the Registrants' Consolidated Balance Sheets.

For Generation, these contract liabilities primarily relate to upfront consideration received or due for equipment service plans and the Illinois ZEC program that introduces a cap on the total consideration to be received by Generation.

For PHI, Pepco, DPL, and ACE these contract liabilities primarily relate to upfront consideration received in the third quarter of 2020 for a collaborative arrangement with an unrelated owner and manager of communication infrastructure. The revenue attributable to this arrangement will be recognized as operating revenue over the 35 years under the collaborative arrangement.

The following table provides a rollforward of the contract liabilities reflected in Exelon's, Generation's, PHI's, Pepco's, DPL's, and ACE's Consolidated Balance Sheets for the three and nine months ended September 30, 2021 and 2020. As of September 30, ~~2017~~2021 and December 31, ~~2016. For additional information on the specific regulatory assets~~2020, ComEd's, PECO's, and BGE's contract liabilities ~~refer to Note 3 — Regulatory Matters of the Exelon 2016 Form 10-K.~~were immaterial.

Successor
September 30, 2017 Exelon ComEd PECO BGE PHI Pepco DPL ACE
Regulatory assets
Pension and other postretirement benefits^(a)
$ 4,020
$ —
$ —
$ —
$ —
$ —
$ —
$ —
Deferred income taxes^(b)
2,423
347
1,678
100
298
195
45
58
AMI programs 660
159
40
219
242
163
79
—
Under-recovered distribution service costs^(c)
256
256
—
—
—
—
—
—
Energy efficiency costs 78
78
—
—
—
—
—
—
Debt costs 120
38
1
12
75
16
8
5
Fair value of long-term debt 773
—
—
—
632
—
—
—
Fair value of PHI's unamortized energy contracts 830
—
—
—
830
—
—
—
Severance 2
—
—
2
—
—
—
—
Asset retirement obligations 108
73
22
13
—
—
—
—
MGP remediation costs 300
277
23
—
—
—
—
—
Under-recovered uncollectible accounts 70
60
—
—
10
—
—
10
Renewable energy 277
277
—
—
—
—
—
—
Energy and transmission programs ^{(d)(e)(f)(g)(h)(i)}
65
3
—
26
36
6
9
21
Deferred storm costs 31
—
—
—
31
9
5
17
Electric generation-related regulatory asset 3
—
—
3
—
—
—
—
Energy efficiency and demand response programs 599
—
1
284
314
233
81
—
Merger integration costs^(j)(k)(l)(m)
47
—
—
7
40
20
11
9
Under-recovered revenue decoupling⁽ⁿ⁾
72
—
—
34
38
33
5
—
COPCO acquisition adjustment 6
—
—
—
6
—
6
—
Workers compensation and long-term disability cost 33
—
—
—
33
33
—
—
Vacation accrual 38
—
14
—
24
—
14
10
Securitized stranded costs 93
—
—
—
93
—
—
93
CAP arrearage 9
—
9
—
—
—
—
—
Removal costs
518
—
—
—
518
144
98
277
Other 71
6
21
5
40
28
8
4
Total regulatory assets 11,502
1,574
1,809
705
3,260
880
369
504
Less: current portion 1,264
187
36
208
568
181
69
87
Total noncurrent regulatory assets $ 10,238
$ 1,387
$ 1,773
$ 497
$ 2,692
$ 699
$ 300
$ 417

Successor
September 30, 2017 Exelon ComEd PECO BGE PHI Pepco DPL ACE
Regulatory liabilities
Other postretirement benefits $ 41
$ —
$ —
$ —
$ —
$ —
$ —
$ —
Nuclear decommissioning 2,971
2,438
533
—
—
—
—
—
Removal costs 1,588
1,337
—
119
132
22
110
—
Deferred rent 37
—
—
—
37
—
—
—
Energy efficiency and demand response programs 62
33
29
—
—
—
—
—
DLC program costs 8
—
8
—
—
—
—
—
Electric distribution tax repairs 50
—
50
—
—
—
—
—
Gas distribution tax repairs 14
—
14
—
—
—
—
—
Energy and transmission programs ^{(d)(e)(f)(g)(h)(i)}
139
54
68
—
17
3
9
5
Renewable portfolio standards costs 46
46
—
—
—
—
—
—
Zero emission credit costs 71
71
—
—
—
—
—
—
Other 75
5
17
28
25
1
9
13
Total regulatory liabilities 5,102
3,984
719
147
211
26
128
18
Less: current portion 553
249
159
63
65
5
42
18
Total noncurrent regulatory liabilities $ 4,549
$ 3,735
$ 560
$ 84
$ 146
$ 21
$ 86
$ —

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— ~~(Continued)~~

(Dollars in millions, except per share data, unless otherwise noted)

Note 4 — Revenue from Contracts with Customers



	Exelon		Generation		PHI		Pepco		DPL		ACE
Balance as of December 31, 2020	$	151	$	84	$	118	$	94	$	12	$	12
Consideration received or due	20		31		—		—		—		—
Revenues recognized	(27)		(64)		(2)		(2)		—		—
Amounts previously held-for-sale	3		3		—		—		—		—
Balance as of March 31, 2021	147		54		116		92		12		12
Consideration received or due	17		39		—		—		—		—
Revenues recognized	(32)		(68)		(3)		(1)		(1)		(1)

Balance as of June 30, 2021	132		25		113		91		11		11
Consideration received or due	31		93		—		—		—		—
Revenues recognized	(26)		(65)		(2)		(2)		—		—
Balance as of September 30, 2021	$	137	$	53	$	111	$	89	$	11	$	11


	Exelon		Generation		PHI		Pepco		DPL		ACE
Balance as of December 31, 2019	$	33	$	71	$	—	$	—	$	—	$	—
Consideration received or due	20		55		—		—		—		—
Revenues recognized	(24)		(70)		—		—		—		—
Balance as of March 31, 2020	29		56		—		—		—		—
Consideration received or due	13		34		—		—		—		—
Revenues recognized	(22)		(63)		—		—		—		—
Balance as of June 30, 2020	20		27		—		—		—		—
Consideration received or due	154		94		124		98		13		13
Revenues recognized	(25)		(65)		(2)		(2)		—		—
Balance as of September 30, 2020	$	149	$	56	$	122	$	96	$	13	$	13

The following table reflects revenues recognized in the three and nine months ended September 30, 2021 and 2020, which were included in contract liabilities at December 31, 2020 and 2019, respectively:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Exelon	$	4	$	2	$	38	$	25
Generation	2		2		81		63
PHI	2		—		7		—
Pepco	2		—		5		—
DPL	—		—		1		—
ACE	—		—		1		—

Transaction Price Allocated to Remaining Performance Obligations (All Registrants)

The following table shows the amounts of future revenues expected to be recorded in each year for performance obligations that are unsatisfied or partially unsatisfied as of September 30, 2021. This disclosure only includes contracts for which the total consideration is fixed and determinable at contract inception. The average contract term varies by customer type and commodity but ranges from one month to several years.

This disclosure excludes Generation's power and gas sales contracts as they contain variable volumes and/or variable pricing. This disclosure also excludes the Utility Registrants' gas and electric tariff sales contracts and transmission revenue contracts as they generally have an original expected duration of one year or less and, therefore, do not contain any future, unsatisfied performance obligations to be included in this disclosure.

Successor
December 31, 2016 Exelon ComEd PECO BGE PHI Pepco DPL ACE
Regulatory assets
Pension and other postretirement benefits ^(a)
$ 4,162
$ —
$ —
$ —
$ —
$ —
$ —
$ —
Deferred income taxes ^(b)
2,016
75
1,583
98
260
171
38
51
AMI programs 701
164
49
230
258
174
84
—
Under-recovered distribution service costs ^(c)
188
188
—
—
—
—
—
—
Debt costs 124
42
1
7
81
17
9
6
Fair value of long-term debt 812
—
—
—
671
—
—
—
Fair value of PHI's unamortized energy contracts 1,085
—
—
—
1,085
—
—
—
Severance 5
—
—
5
—
—
—
—
Asset retirement obligations 111
76
23
12
—
—
—
—
MGP remediation costs 305
278
26
1
—
—
—
—
Under-recovered uncollectible accounts 56
56
—
—
—
—
—
—
Renewable energy 260
258
—
—
2
—
—
2
Energy and transmission programs ^{(d)(e)(f)(g)(h)(i)}
89
23
—
38
28
6
5
17
Deferred storm costs 36
—
—
1
35
12
5
18
Electric generation-related regulatory asset 10
—
—
10
—
—
—
—
Rate stabilization deferral 7
—
—
7
—
—
—
—
Energy efficiency and demand response programs 621
—
1
285
335
250
85
—
Merger integration costs^(j)(k)(l)(m)
25
—
—
10
15
11
4
—
Under-recovered revenue decoupling⁽ⁿ⁾
27
—
—
3
24
21
3
—
COPCO acquisition adjustment 8
—
—
—
8
—
8
—
Workers compensation and long-term disability costs 34
—
—
—
34
34
—
—
Vacation accrual 31
—
7
—
24
—
14
10
Securitized stranded costs 138
—
—
—
138
—
—
138
CAP arrearage 11
—
11
—
—
—
—
—
Removal costs 477
—
—
—
477
134
88
255
Other 49
7
9
5
29
22
5
4
Total regulatory assets 11,388
1,167
1,710
712
3,504
852
348
501
Less: current portion 1,342
190
29
208
653
162
59
96
Total noncurrent regulatory assets $ 10,046
$ 977
$ 1,681
$ 504
$ 2,851
$ 690
$ 289
$ 405

Successor
December 31, 2016 Exelon ComEd PECO BGE PHI Pepco DPL ACE
Regulatory liabilities
Other postretirement benefits $ 47
$ —
$ —
$ —
$ —
$ —
$ —
$ —
Nuclear decommissioning 2,607
2,169
438
—
—
—
—
—
Removal costs 1,601
1,324
—
141
136
18
118
—
Deferred rent 39
—
—
—
39
—
—
—
Energy efficiency and demand response programs 185
141
41
—
3
3
—
—
DLC program costs 8
—
8
—
—
—
—
—
Electric distribution tax repairs 76
—
76
—
—
—
—
—
Gas distribution tax repairs 20
—
20
—
—
—
—
—
Energy and transmission programs ^{(d)(e)(f)(g)(h)(i)}
134
60
56
—
18
8
5
5
Other 72
4
5
19
41
2
17
20
Total regulatory liabilities 4,789
3,698
644
160
237
31
140
25
Less: current portion 602
329
127
50
79
11
43
25
Total noncurrent regulatory liabilities $ 4,187
$ 3,369
$ 517
$ 110
$ 158
$ 20
$ 97
$ —

~~_________~~

~~(a)~~

As of September 30, 2017 and December 31, 2016, the pension and other postretirement benefits regulatory asset at Exelon includes regulatory assets of $969 million and $995 million, respectively, as a result of the PHI Merger related to unrecognized costs that are probable of regulatory recovery. The regulatory assets are amortized over periods from 3 to 15 years, depending on the underlying component. Pepco, DPL and ACE are currently recovering these costs through base rates. Pepco, DPL and ACE are not earning a return on the recovery of these costs in base rates.

~~(b)~~

As of September 30, 2017, includes transmission-related income tax regulatory assets that require FERC approval separate from the transmission formula rate of $73 million, $42 million, $34 million, $23 million and $21 million for ComEd, BGE, Pepco, DPL and ACE, respectively. As of December 31, 2016, includes transmission-related regulatory assets that require FERC approval separate from the transmission formula rate of $22 million, $38 million, $31 million, $20 million and $19 million for ComEd, BGE, Pepco, DPL and ACE, respectively. On December 13, 2016, BGE filed with FERC to begin recovering these existing and any similar future regulatory assets through its transmission formula rate. On May 9, 2017, FERC accepted BGE’s filing

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— ~~(Continued)~~

(Dollars in millions, except per share data, unless otherwise noted)

Note 4 — Revenue from Contracts with Customers


	2021		2022		2023		2024		2025 and thereafter		Total
Exelon	$	82	$	125	$	50	$	35	$	184	$	476
Generation	168		281		92		41		97		679
PHI	2		8		8		6		87		111
Pepco	2		6		6		5		70		89
DPL	—		1		1		—		9		11
ACE	—		1		1		1		8		11

Revenue Disaggregation (All Registrants)

The Registrants disaggregate revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and ~~made effective BGE’s proposed modifications~~uncertainty of revenue and cash flows are affected by economic factors. See Note 5 — Segment Information for the presentation of the Registrant's revenue disaggregation.

5. Segment Information (All Registrants)

Operating segments for each of the Registrants are determined based on information used by the CODM in deciding how to ~~its transmission formula rate, subject~~evaluate performance and allocate resources at each of the Registrants.

Exelon has 11 reportable segments, which include Generation's 5 reportable segments consisting of the Mid-Atlantic, Midwest, New York, ERCOT, and all other power regions referred to ~~refund~~collectively as “Other Power Regions” and ~~further Commission order.~~ ComEd, PECO, BGE, and PHI's 3 reportable segments consisting of Pepco, DPL, and ACE. ComEd, PECO, BGE, Pepco, DPL, and ACE ~~are expected to make similar filings with FERC~~each represent a single reportable segment, and ~~other parties in subsequent periods.~~

~~(c)~~

As of September 30, 2017, ComEd’s regulatory asset of $256 million was comprised of $200 million for the 2015 - 2017 annual reconciliations and $56 million related to significant one-time events including $11 million of deferred storm costs, $7 million of Constellation and PHI merger and integration related costs, $6 million of emerald ash borer costs, and $32 million of smart meter related costs. As of December 31, 2016, ComEd’s regulatory asset of $188 million was comprised of $134 million for the 2015 and 2016 annual reconciliations and $54 million related to significant one-time events, including $20 million of deferred storm costs and $11 million of Constellation and PHI merger and integration related costs, and $23 million of smart meter related costs. See Note 4— Mergers, Acquisitions and Dispositions of theas such, no separate segment information is provided for these Registrants. Exelon, ~~2016 Form 10-K for further information.~~

~~(d)~~

As of September 30, 2017, ComEd’s regulatory liability of $54 million included $22 million related to over-recovered energy costs and $32 million associated with revenues received for renewable energy requirements. As of December 31, 2016, ComEd’s regulatory asset of $23 million included $15 million associated with transmission costs recoverable through its FERC approved formula rate and $8 million of Constellation merger and integration costs to be recovered upon FERC approval. As of December 31, 2016, ComEd’s regulatory liability of $60 million included $30 million related to over-recovered energy costs and $30 million associated with revenues received for renewable energy requirements.

~~(e)~~

As of September 30, 2017, PECO's regulatory liability of $68 million included $34 million related to over-recovered costs under the DSP program, $21 million related to the over-recovered natural gas costs under the PGC and $13 million related to over-recovered non-bypassable transmission service charges. As of December 31, 2016, PECO's regulatory liability of $56 million included $34 million related to over-recovered costs under the DSP program, $10 million related to over-recovered non-bypassable transmission service charges, $8 million related to the over-recovered natural gas costs under the PGC and $4 million related to the over-recovered electric transmission costs.

~~(f)~~

As of September 30, 2017, BGE's regulatory asset of $26 million included $5 million related to under-recovered electric energy costs, $14 million related to under-recovered natural gas costs, $3 million of costs associated with transmission costs recoverable through its FERC approved formula rate and $4 million of abandonment costs to be recovered upon FERC approval. As of December 31, 2016, BGE’s regulatory asset of $38 million included $4 million of costs associated with transmission costs recoverable through its FERC approved formula rate, $28 million related to under-recovered electric energy costs, $3 million of abandonment costs to be recovered upon FERC approval, and $3 million of under-recovered natural gas costs.

~~(g)~~

As of September 30, 2017, Pepco's regulatory asset of $6 million included $3 million of transmission costs recoverable through its FERC approved formula rate and $3 million of under-recovered electric energy costs. As of September 30, 2017, Pepco's regulatory liability of $3 million related to over-recovered electric energy costs. As of December 31, 2016, Pepco's regulatory asset of $6 million related to under-recovered electric energy costs. As of December 31, 2016, Pepco's regulatory liability of $8 million included $5 million of over-recovered transmission costs and $3 million of over-recovered electric energy costs.

~~(h)~~

As of September 30, 2017, DPL's regulatory asset of $9 million included $4 million of transmission costs recoverable through its FERC approved formula rate and $5 million related to under-recovered electric energy costs. As of September 30, 2017, DPL's regulatory liability of $9 million related to over-recovered electric energy costs. As of December 31, 2016, DPL's regulatory asset of $5 million included $1 million of transmission costs recoverable through its FERC approved formula rate and $4 million of under-recovered electric energy costs. As of December 31, 2016, DPL's regulatory liability of $5 million included $2 million of over-recovered electric energy costs and $3 million of over-recovered transmission costs.

~~(i)~~

As of September 30, 2017, ACE's regulatory asset of $21 million included $11 million of transmission costs recoverable through its FERC approved formula rate and $10 million of under-recovered electric energy costs. As of September 30, 2017, ACE's regulatory liability of $5 million related to over-recovered electric energy costs. As of December 31, 2016, ACE's regulatory asset of $17 million included $6 million of transmission costs recoverable through its FERC approved formula rate and $11 million of under-recovered electric energy costs. As of December 31, 2016, ACE's regulatory liability of $5 million included $4 million of over-recovered transmission costs and $1 million of over-recovered electric energy costs.


~~(j)~~	As of September 30, 2017 and December 31, 2016, BGE's regulatory asset of $7 million and $10 million, respectively, included $5 million and $6 million, respectively, of previously incurred PHI acquisition costs as authorized by the June 2016 rate case order.

~~(k)~~

As of September 30, 2017, Pepco’s regulatory asset of $20 million represents previously incurred PHI acquisition costs, including $11 million authorized for recovery in Maryland and $9 million expected to be recovered in the District of Columbia service territory. As of December 31, 2016, Pepco's regulatory asset of $11 million represents previously incurred PHI acquisition costs authorized for recovery in Maryland.

~~(l)~~

As of September 30, 2017, DPL’s regulatory asset of $11 million represents previously incurred PHI acquisition costs, including $4 million authorized for recovery in Maryland, $5 million authorized for recovery in Delaware electric rates, and $2 million expected to be recovered in electric and gas rates in the Delaware service territory. As of December 31, 2016, DPL's regulatory asset of $4 million represents previously incurred PHI acquisition costs expected to be recovered in the Maryland service territory.


~~(m)~~	~~As of September 30, 2017, ACE’s regulatory asset of $9 million represents previously incurred PHI acquisition costs expected to be recovered in the New Jersey service territory.~~

~~(n)~~

Represents the electric and natural gas distribution costs recoverable from customers under BGE’s decoupling mechanism. As of September 30, 2017, BGE had a regulatory asset of $24 million related to under-recovered electric revenue decoupling and $10 million related to under-recovered natural gas revenue decoupling. As of December 31, 2016, BGE had a regulatory asset of $2 million related to under-recovered natural gas revenue decoupling and $1 million related to under-recovered electric revenue decoupling.

~~Capitalized Ratemaking Amounts Not Recognized (Exelon,~~ ComEd, PECO, BGE, ~~PHI,~~ Pepco, DPL, and ~~ACE)~~ACE's CODMs evaluate the performance of and allocate resources to ComEd, PECO, BGE, Pepco, DPL, and ACE based on net income.

The ~~following table illustrates our authorized amounts capitalized~~basis for ~~ratemaking purposes related~~Generation's reportable segments is the integrated management of its electricity business that is located in different geographic regions, and largely representative of the footprints of ISO/RTO and/or NERC regions, which utilize multiple supply sources to ~~earnings on shareholders’ investment that~~provide electricity through various distribution channels (wholesale and retail). Generation's hedging strategies and risk metrics are ~~not recognized for financial reporting purposes on our Consolidated Balance Sheets. These amounts will be recognized~~also aligned to these same geographic regions. Descriptions of each of Generation’s 5 reportable segments are as ~~revenues in our Consolidated Statements of Operations and Comprehensive Income~~follows:

•Mid-Atlantic represents operations in the ~~periods they are billable to our customers.~~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 CAISO.

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

Exelon
ComEd^(a)
PECO
BGE^(b)
PHI
Pepco^(c)

DPL^(c)
ACE
September 30, 2017 $ 71
$ 7
$ —
$ 54
$ 10
$ 6
$ 4
$ —

Exelon
ComEd^(a)
PECO
BGE^(b)
PHI
Pepco^(c)

DPL^(c)
ACE
December 31, 2016 $ 72
$ 5
$ —
$ 57
$ 10
$ 6
$ 4
$ —

~~_________~~


~~(a)~~	~~Reflects ComEd's unrecognized equity returns earned for ratemaking purposes on its under-recovered distribution services costs 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.

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— ~~(Continued)~~

(Dollars in millions, except per share data, unless otherwise noted)

Note 5 — Segment Information

~~Purchase~~The CODMs for Exelon and Generation evaluate the performance of ~~Receivables Programs (Exelon,~~Generation’s electric business activities and allocate resources based on Revenues Net of Purchased Power and Fuel Expense (RNF). Generation believes that RNF is a useful measurement of operational performance. RNF 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. Generation’s operating revenues include all sales to third parties and affiliated sales to the Utility Registrants. Purchased power costs include all costs associated with the procurement and supply of electricity including capacity, energy, and ancillary services. Fuel expense includes the fuel costs for Generation’s owned generation and fuel costs associated with tolling agreements. The results of Generation's other business activities are not regularly reviewed by the CODM and are therefore not classified as operating segments or included in the regional reportable segment amounts. These activities include natural gas, as well as other miscellaneous business activities that are not significant to Generation's overall operating revenues or results of operations. Further, Generation’s unrealized mark-to-market gains and losses on economic hedging activities and its amortization of certain intangible assets and liabilities relating to commodity contracts recorded at fair value from mergers and acquisitions are also excluded from the regional reportable segment amounts. Exelon and Generation do not use a measure of total assets in making decisions regarding allocating resources to or assessing the performance of these reportable segments.

An analysis and reconciliation of the Registrants’ reportable segment information to the respective information in the consolidated financial statements for the three and nine months ended September 30, 2021 and 2020 is as follows:

Three Months Ended September 30, 2021 and 2020



	Generation		ComEd		PECO		BGE		PHI		Other(a)		Intersegment Eliminations		Exelon
Operating revenues(b):
2021
Competitive businesses electric revenues	$	4,330	$	—	$	—	$	—	$	—	$	—	$	(319)	$	4,011
Competitive businesses natural gas revenues	575		—		—		—		—		—		—		575
Competitive businesses other revenues	(499)		—		—		—		—		—		(3)		(502)
Rate-regulated electric revenues	—		1,789		762		677		1,444		—		(15)		4,657
Rate-regulated natural gas revenues	—		—		56		93		23		—		(3)		169
Shared service and other revenues	—		—		—		—		3		534		(537)		—
Total operating revenues	$	4,406	$	1,789	$	818	$	770	$	1,470	$	534	$	(877)	$	8,910
2020
Competitive businesses electric revenues	$	4,201	$	—	$	—	$	—	$	—	$	—	$	(326)	$	3,875
Competitive businesses natural gas revenues	323		—		—		—		—		—		—		323
Competitive businesses other revenues	135		—		—		—		—		—		(3)		132
Rate-regulated electric revenues	—		1,643		759		646		1,339		—		(22)		4,365
Rate-regulated natural gas revenues	—		—		54		85		23		—		(3)		159
Shared service and other revenues	—		—		—		—		6		484		(491)		(1)

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in millions, except per share data, unless otherwise noted)

Note 5 — Segment Information


Total operating revenues	$	4,659	$	1,643	$	813	$	731	$	1,368	$	484	$	(845)	$	8,853


	Generation		ComEd		PECO		BGE		PHI		Other(a)		Intersegment Eliminations		Exelon
Intersegment revenues(c):
2021	$	324	$	9	$	2	$	7	$	3	$	531	$	(876)	$	—
2020	331		15		3		6		6		485		(845)		1
Depreciation and amortization:
2021	$	866	$	304	$	86	$	142	$	210	$	16	$	—	$	1,624
2020	558		294		85		133		200		19		—		1,289
Operating expenses:
2021	$	3,465	$	1,428	$	677	$	709	$	1,155	$	541	$	(858)	$	7,117
2020	4,727		1,302		658		642		1,102		489		(833)		8,087
Interest expense, net:
2021	$	77	$	98	$	40	$	36	$	67	$	79	$	—	$	397
2020	80		95		39		34		67		89		—		404
Income (loss) before income taxes:
2021	$	814	$	276	$	108	$	32	$	264	$	(88)	$	—	$	1,406
2020	219		256		122		61		215		(87)		—		786
Income Taxes:
2021	$	177	$	56	$	(3)	$	(4)	$	(2)	$	(50)	$	—	$	174
2020	100		60		(16)		8		(1)		65		—		216
Net income (loss):
2021	$	633	$	220	$	111	$	36	$	266	$	(37)	$	—	$	1,229
2020	117		196		138		53		216		(151)		—		569
Capital Expenditures:
2021	$	367	$	561	$	301	$	287	$	410	$	4	$	—	$	1,930
2020	282		554		312		290		386		9		—		1,833

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

(b)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 18 — Supplemental Financial Information for additional information on total utility taxes.

(c)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. See Note 19— Related Party Transactions for additional information on intersegment revenues.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in millions, except per share data, unless otherwise noted)

Note 5 — Segment Information

PHI:



	Pepco		DPL		ACE		Other(a)		Intersegment Eliminations		PHI
Operating revenues(b):
2021
Rate-regulated electric revenues	$	660	$	337	$	451	$	—	$	(4)	$	1,444
Rate-regulated natural gas revenues	—		23		—		—		—		23
Shared service and other revenues	—		—		—		92		(89)		3
Total operating revenues	$	660	$	360	$	451	$	92	$	(93)	$	1,470
2020
Rate-regulated electric revenues	$	611	$	314	$	420	$	—	$	(6)	$	1,339
Rate-regulated natural gas revenues	—		23		—		—		—		23
Shared service and other revenues	—		—		—		91		(85)		6
Total operating revenues	$	611	$	337	$	420	$	91	$	(91)	$	1,368
Intersegment revenues(c):
2021	$	2	$	2	$	1	$	91	$	(93)	$	3
2020	3		3		1		90		(91)		6
Depreciation and amortization:
2021	$	104	$	53	$	46	$	7	$	—	$	210
2020	96		48		48		8		—		200
Operating expenses:
2021	$	501	$	295	$	359	$	93	$	(93)	$	1,155
2020	465		296		338		94		(91)		1,102
Interest expense, net:
2021	$	35	$	15	$	14	$	3	$	—	$	67
2020	35		15		15		2		—		67
Income (loss) before income taxes:
2021	$	136	$	53	$	79	$	(4)	$	—	$	264
2020	121		28		68		(2)		—		215
Income Taxes:
2021	$	6	$	3	$	(11)	$	—	$	—	$	(2)
2020	3		1		(7)		2		—		(1)
Net income (loss):
2021	$	130	$	50	$	90	$	(4)	$	—	$	266
2020	118		27		75		(4)		—		216
Capital Expenditures:
2021	$	202	$	109	$	97	$	2	$	—	$	410
2020	188		94		103		1		—		386

__________

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

(c)Includes intersegment revenues with ComEd, BGE, and PECO, which are eliminated at Exelon.

The following tables disaggregate the Registrants' revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. For Generation, the disaggregation of revenues reflects Generation’s two primary products of power sales and natural gas sales, with further disaggregation of power sales provided by geographic region. For the Utility Registrants, the disaggregation of revenues reflects the two primary utility services of rate-regulated

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in millions, except per share data, unless otherwise noted)

Note 5 — Segment Information

electric sales and rate-regulated natural gas sales (where applicable), with further disaggregation of these tariff sales provided by major customer groups. Exelon’s disaggregated revenues are consistent with Generation and the Utility Registrants, but exclude any intercompany revenues.

Competitive Business Revenues (Generation):


	Three Months Ended September 30, 2021
	Revenues from external customers(a)						Intersegment Revenues		Total Revenues
	Contracts with customers		Other(b)		Total
Mid-Atlantic	$	1,145	$	123	$	1,268	$	4	$	1,272
Midwest	1,084		(99)		985		—		985
New York	445		10		455		—		455
ERCOT	191		165		356		2		358
Other Power Regions	948		318		1,266		(6)		1,260
Total Competitive Businesses Electric Revenues	3,813		517		4,330		—		4,330
Competitive Businesses Natural Gas Revenues	266		309		575		—		575
Competitive Businesses Other Revenues(c)	95		(594)		(499)		—		(499)
Total Generation Consolidated Operating Revenues	$	4,174	$	232	$	4,406	$	—	$	4,406


	Three Months Ended September 30, 2020
	Revenues from external customers(a)						Intersegment revenues		Total Revenues
	Contracts with customers		Other(b)		Total
Mid-Atlantic	$	1,327	$	(20)	$	1,307	$	6	$	1,313
Midwest	974		68		1,042		1		1,043
New York	401		5		406		—		406
ERCOT	249		74		323		7		330
Other Power Regions	937		186		1,123		(14)		1,109
Total Competitive Businesses Electric Revenues	3,888		313		4,201		—		4,201
Competitive Businesses Natural Gas Revenues	169		154		323		—		323
Competitive Businesses Other Revenues(c)	85		50		135		—		135
Total Generation Consolidated Operating Revenues	$	4,142	$	517	$	4,659	$	—	$	4,659

__________

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

(b)Includes revenues from derivatives and leases.

(c)Other represents activities not allocated to a region. See text above for a description of included activities. Includes unrealized mark-to-market losses of $635 million and gains of $37 million in 2021 and 2020, respectively, and elimination of intersegment revenues.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in millions, except per share data, unless otherwise noted)

Note 5 — Segment Information

Revenues net of purchased power and fuel expense (Generation):


	Three Months Ended September 30, 2021						Three Months Ended September 30, 2020
	RNF from external customers(a)		Intersegment RNF		Total RNF		RNF from external customers(a)		Intersegment RNF		Total RNF
Mid-Atlantic	$	567	$	3	$	570	$	586	$	5	$	591
Midwest	655		—		655		748		2		750
New York	343		3		346		281		4		285
ERCOT	181		(2)		179		141		6		147
Other Power Regions	233		(22)		211		253		(28)		225
Total RNF for Reportable Segments	1,979		(18)		1,961		2,009		(11)		1,998
Other(b)	881		18		899		336		11		347
Total Generation RNF	$	2,860	$	—	$	2,860	$	2,345	$	—	$	2,345

__________

(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 $754 million and gains of $255 million in 2021 and 2020, respectively;

•accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 7 — Early Plant Retirements of $42 million and $24 million in 2021 and 2020 respectively; and

•the elimination of intersegment RNF.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in millions, except per share data, unless otherwise noted)

Note 5 — Segment Information

Electric and Gas Revenue by Customer Class (Utility Registrants):


	Three Months Ended September 30, 2021
Revenues from contracts with customers	ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Rate-regulated electric revenues
Residential	$	978	$	509	$	383	$	782	$	309	$	198	$	275
Small commercial & industrial	433		113		73		150		36		53		61
Large commercial & industrial	148		67		128		320		244		27		49
Public authorities & electric railroads	11		7		7		15		8		4		3
Other(a)	245		61		104		172		53		56		63
Total rate-regulated electric revenues(b)	$	1,815	$	757	$	695	$	1,439	$	650	$	338	$	451
Rate-regulated natural gas revenues
Residential	$	—	$	36	$	57	$	10	$	—	$	10	$	—
Small commercial & industrial	—		13		10		5		—		5		—
Large commercial & industrial	—		—		22		2		—		2		—
Transportation	—		5		—		3		—		3		—
Other(c)	—		2		6		3		—		3		—
Total rate-regulated natural gas revenues(d)	$	—	$	56	$	95	$	23	$	—	$	23	$	—
Total rate-regulated revenues from contracts with customers	$	1,815	$	813	$	790	$	1,462	$	650	$	361	$	451

Other revenues
Revenues from alternative revenue programs	$	(32)	$	3	$	(24)	$	6	$	9	$	(2)	$	—
Other rate-regulated electric revenues(e)	6		2		3		2		1		1		—
Other rate-regulated natural gas revenues(e)	—		—		1		—		—		—		—

Total other revenues	$	(26)	$	5	$	(20)	$	8	$	10	$	(1)	$	—
Total rate-regulated revenues for reportable segments	$	1,789	$	818	$	770	$	1,470	$	660	$	360	$	451

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in millions, except per share data, unless otherwise noted)

Note 5 — Segment Information


	Three Months Ended September 30, 2020
Revenues from contracts with customers	ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Rate-regulated electric revenues
Residential	$	920	$	518	$	389	$	763	$	307	$	193	$	263
Small commercial & industrial	379		104		65		134		36		45		53
Large commercial & industrial	135		66		113		262		195		21		46
Public authorities & electric railroads	10		7		7		14		8		3		3
Other(a)	234		58		78		141		47		44		50
Total rate-regulated electric revenues(b)	$	1,678	$	753	$	652	$	1,314	$	593	$	306	$	415
Rate-regulated natural gas revenues
Residential	$	—	$	32	$	55	$	11	$	—	$	11	$	—
Small commercial & industrial	—		16		9		6		—		6		—
Large commercial & industrial	—		—		21		1		—		1		—
Transportation	—		6		—		3		—		3		—
Other(c)	—		1		3		2		—		2		—
Total rate-regulated natural gas revenues(d)	$	—	$	55	$	88	$	23	$	—	$	23	$	—
Total rate-regulated revenues from contracts with customers	$	1,678	$	808	$	740	$	1,337	$	593	$	329	$	415

Other revenues
Revenues from alternative revenue programs	$	(38)	$	5	$	(9)	$	31	$	18	$	8	$	5
Other rate-regulated electric revenues(e)	3		—		—		—		—		—		—
Other rate-regulated natural gas revenues(e)	—		—		—		—		—		—		—

Total other revenues	$	(35)	$	5	$	(9)	$	31	$	18	$	8	$	5
Total rate-regulated revenues for reportable segments	$	1,643	$	813	$	731	$	1,368	$	611	$	337	$	420

__________

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

(b)Includes operating revenues from affiliates in 2021 and 2020 respectively of:

•$9 million, $15 million at ComEd

•$2 million, $3 million at PECO

•$4 million, $3 million at BGE

•$3 million, $6 million at PHI

•$2 million, $3 million at Pepco

•$2 million, $3 million at DPL

•$1 million, $1 million at ACE

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

(d)Includes operating revenues from affiliates in 2021 and 2020 respectively of:

•less than $1 million at PECO both 2021 and 2020

•$3 million, $3 million at BGE

(e)Includes late payment charge revenues.

Nine Months Ended September 30, 2021 and 2020


	Generation		ComEd		PECO		BGE		PHI		Other(a)		Intersegment Eliminations		Exelon
Operating revenues(b):
2021
Competitive businesses electric revenues	$	12,264	$	—	$	—	$	—	$	—	$	—	$	(860)	$	11,404

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in millions, except per share data, unless otherwise noted)

Note 5 — Segment Information


	Generation		ComEd		PECO		BGE		PHI		Other(a)		Intersegment Eliminations		Exelon
Competitive businesses natural gas revenues	2,408		—		—		—		—		—		—		2,408
Competitive businesses other revenues	(555)		—		—		—		—		—		(9)		(564)
Rate-regulated electric revenues	—		4,840		2,033		1,866		3,726		—		(33)		12,432
Rate-regulated natural gas revenues	—		—		366		560		118		—		(9)		1,035
Shared service and other revenues	—		—		—		—		10		1,549		(1,559)		—
Total operating revenues	$	14,117	$	4,840	$	2,399	$	2,426	$	3,854	$	1,549	$	(2,470)	$	26,715
2020
Competitive businesses electric revenues	$	11,367	$	—	$	—	$	—	$	—	$	—	$	(920)	$	10,447
Competitive businesses natural gas revenues	1,348		—		—		—		—		—		(3)		1,345
Competitive businesses other revenues	557		—		—		—		—		—		(5)		552
Rate-regulated electric revenues	—		4,499		1,948		1,763		3,425		—		(50)		11,585
Rate-regulated natural gas revenues	—		—		358		521		116		—		(5)		990
Shared service and other revenues	—		—		—		—		13		1,440		(1,447)		6
Total operating revenues	$	13,272	$	4,499	$	2,306	$	2,284	$	3,554	$	1,440	$	(2,430)	$	24,925

Intersegment revenues(c):
2021	$	872	$	19	$	6	$	20	$	10	$	1,542	$	(2,469)	$	—
2020	932		31		7		16		13		1,435		(2,430)		4
Depreciation and amortization:
2021	$	2,735	$	893	$	259	$	434	$	614	$	52	$	1	$	4,988
2020	1,161		841		259		405		585		61		—		3,312
Operating expenses:
2021	$	14,605	$	3,833	$	1,908	$	2,080	$	3,167	$	1,572	$	(2,407)	$	24,758
2020	12,674		3,798		1,900		1,903		3,057		1,452		(2,397)		22,387
Interest expense, net:
2021	$	225	$	292	$	119	$	103	$	201	$	241	$	(1)	$	1,180
2020	277		287		108		99		201		269		—		1,241

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in millions, except per share data, unless otherwise noted)

Note 5 — Segment Information


	Generation		ComEd		PECO		BGE		PHI		Other(a)		Intersegment Eliminations		Exelon
Income (loss) before income taxes:
2021	$	(8)	$	750	$	392	$	266	$	538	$	(264)	$	1	$	1,675
2020	532		446		310		299		340		(262)		—		1,665
Income Taxes:
2021	$	108	$	141	$	9	$	(24)	$	3	$	(8)	$	—	$	229
2020	41		142		(7)		26		(77)		16		—		141
Net income (loss):
2021	$	(122)	$	609	$	383	$	290	$	535	$	(255)	$	1	$	1,441
2020	485		304		317		273		418		(278)		—		1,519
Capital Expenditures:
2021	$	1,086	$	1,723	$	878	$	907	$	1,299	$	77	$	—	$	5,970
2020	1,212		1,583		824		838		1,072		77		—		5,606
Total assets:
September 30, 2021	$	48,010	$	36,002	$	13,733	$	12,197	$	24,502	$	8,387	$	(10,210)	$	132,621
December 31, 2020	48,094		34,466		12,531		11,650		23,736		9,005		(10,165)		129,317

__________

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

(c)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. See Note 19 — Related Party Transactions for additional information on intersegment revenues.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in millions, except per share data, unless otherwise noted)

Note 5 — Segment Information

PHI:


	Pepco		DPL		ACE		Other(a)		Intersegment Eliminations		PHI
Operating revenues(b):
2021
Rate-regulated electric revenues	$	1,736	$	922	$	1,080	$	—	$	(12)	$	3,726
Rate-regulated natural gas revenues	—		118		—		—		—		118
Shared service and other revenues	—		—		—		281		(271)		10
Total operating revenues	$	1,736	$	1,040	$	1,080	$	281	$	(283)	$	3,854
2020
Rate-regulated electric revenues	$	1,650	$	838	$	952	$	—	$	(15)	$	3,425
Rate-regulated natural gas revenues	—		116		—		—		—		116
Shared service and other revenues	—		—		—		279		(266)		13
Total operating revenues	$	1,650	$	954	$	952	$	279	$	(281)	$	3,554
Intersegment revenues(c):
2021	$	4	$	6	$	2	$	281	$	(283)	$	10
2020	6		7		3		278		(281)		13
Depreciation and amortization:
2021	$	302	$	157	$	133	$	22	$	—	$	614
2020	282		143		134		26		—		585
Operating expenses:
2021	$	1,396	$	858	$	911	$	285	$	(283)	$	3,167
2020	1,364		843		847		284		(281)		3,057
Interest expense, net:
2021	$	104	$	47	$	43	$	7	$	—	$	201
2020	103		47		45		6		—		201
Income (loss) before income taxes:
2021	$	273	$	144	$	129	$	(8)	$	—	$	538
2020	211		71		67		(9)		—		340
Income Taxes:
2021	$	9	$	9	$	(12)	$	(3)	$	—	$	3
2020	(16)		(20)		(39)		(2)		—		(77)
Net income (loss):
2021	$	264	$	135	$	141	$	(5)	$	—	$	535
2020	227		91		106		(6)		—		418
Capital Expenditures:
2021	$	641	$	320	$	336	$	2	$	—	$	1,299
2020	512		278		281		1		—		1,072
Total assets:
September 30, 2021	$	9,748	$	5,295	$	4,532	$	4,977	$	(50)	$	24,502
December 31, 2020	9,264		5,140		4,286		5,079		(33)		23,736

__________

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

(c)Includes intersegment revenues with ComEd, BGE, and PECO, which are eliminated at Exelon.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in millions, except per share data, unless otherwise noted)

Note 5 — Segment Information

Competitive Business Revenues (Generation):



	Nine Months Ended September 30, 2021
	Revenues from external customers(a)						Intersegment Revenues		Total Revenues
	Contracts with customers		Other(b)		Total
Mid-Atlantic	$	3,377	$	134	$	3,511	$	16	$	3,527
Midwest	3,067		(123)		2,944		1		2,945
New York	1,204		(30)		1,174		(1)		1,173
ERCOT	724		155		879		11		890
Other Power Regions	3,043		713		3,756		(27)		3,729
Total Competitive Businesses Electric Revenues	11,415		849		12,264		—		12,264
Competitive Businesses Natural Gas Revenues	1,384		1,024		2,408		—		2,408
Competitive Businesses Other Revenues(c)	291		(846)		(555)		—		(555)
Total Generation Consolidated Operating Revenues	$	13,090	$	1,027	$	14,117	$	—	$	14,117



	Nine Months Ended September 30, 2020
	Revenues from external customers(a)						Intersegment revenues		Total Revenues
	Contracts with customers		Other(b)		Total
Mid-Atlantic	$	3,692	$	(152)	$	3,540	$	21	$	3,561
Midwest	2,773		240		3,013		(6)		3,007
New York	1,074		(12)		1,062		(1)		1,061
ERCOT	579		155		734		20		754
Other Power Regions	2,718		300		3,018		(34)		2,984
Total Competitive Businesses Electric Revenues	10,836		531		11,367		—		11,367
Competitive Businesses Natural Gas Revenues	881		467		1,348		—		1,348
Competitive Businesses Other Revenues(c)	268		289		557		—		557
Total Generation Consolidated Operating Revenues	$	11,985	$	1,287	$	13,272	$	—	$	13,272

__________

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

(b)Includes revenues from derivatives and leases.

(c)Other represents activities not allocated to a region. See text above for a description of included activities. Includes unrealized mark-to-market losses of $958 million and gains of $238 million in 2021 and 2020, respectively, and elimination of intersegment revenues.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in millions, except per share data, unless otherwise noted)

Note 5 — Segment Information

Revenues net of purchased power and fuel expense (Generation):



	Nine Months Ended September 30, 2021						Nine Months Ended September 30, 2020
	RNF from external customers(a)		Intersegment RNF		Total RNF		RNF from external customers(a)		Intersegment RNF		Total RNF
Mid-Atlantic	$	1,698	$	14	$	1,712	$	1,660	$	23	$	1,683
Midwest	2,014		1		2,015		2,180		(2)		2,178
New York	873		7		880		714		11		725
ERCOT	(775)		(147)		(922)		311		14		325
Other Power Regions	641		(77)		564		608		(70)		538
Total RNF for Reportable Segments	4,451		(202)		4,249		5,473		(24)		5,449
Other(b)	1,563		202		1,765		838		24		862
Total Generation RNF	$	6,014	$	—	$	6,014	$	6,311	$	—	$	6,311

__________

(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. Primarily includes:

•unrealized mark-to-market gains of $1,242 million and gains of $472 million in 2021 and 2020, respectively;

•accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 7 — Early Plant Retirements of $148 million and $24 million in 2021 and 2020 respectively; and

• the elimination of intersegment RNF.

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in millions, except per share data, unless otherwise noted)

Note 5 — Segment Information

Electric and Gas Revenue by Customer Class (Utility Registrants):



	Nine Months Ended September 30, 2021
Revenues from contracts with customers	ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Rate-regulated electric revenues
Residential	$	2,479	$	1,325	$	1,044	$	1,924	$	785	$	535	$	604
Small commercial & industrial	1,176		312		202		392		101		145		146
Large commercial & industrial	420		183		342		825		616		70		139
Public authorities & electric railroads	33		24		20		45		24		11		10
Other(a)	676		167		269		453		154		143		158
Total rate-regulated electric revenues(b)	$	4,784	$	2,011	$	1,877	$	3,639	$	1,680	$	904	$	1,057
Rate-regulated natural gas revenues
Residential	$	—	$	251	$	354	$	67	$	—	$	67	$	—
Small commercial & industrial	—		94		59		29		—		29		—
Large commercial & industrial	—		—		103		5		—		5		—
Transportation	—		17		—		11		—		11		—
Other(c)	—		4		41		6		—		6		—
Total rate-regulated natural gas revenues(d)	$	—	$	366	$	557	$	118	$	—	$	118	$	—
Total rate-regulated revenues from contracts with customers	$	4,784	$	2,377	$	2,434	$	3,757	$	1,680	$	1,022	$	1,057

Other revenues
Revenues from alternative revenue programs	$	32	$	20	$	(17)	$	94	$	54	$	17	$	23
Other rate-regulated electric revenues(e)	24		2		7		3		2		1		—
Other rate-regulated natural gas revenues(e)	—		—		2		—		—		—		—

Total other revenues	$	56	$	22	$	(8)	$	97	$	56	$	18	$	23
Total rate-regulated revenues for reportable segments	$	4,840	$	2,399	$	2,426	$	3,854	$	1,736	$	1,040	$	1,080

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in millions, except per share data, unless otherwise noted)

Note 5 — Segment Information



	Nine Months Ended September 30, 2020
Revenues from contracts with customers	ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Rate-regulated electric revenues
Residential	$	2,389	$	1,277	$	1,034	$	1,825	$	779	$	501	$	545
Small commercial & industrial	1,067		291		183		355		101		127		127
Large commercial & industrial	388		174		311		755		558		66		131
Public authorities & electric railroads	33		21		20		45		25		10		10
Other(a)	663		171		233		471		166		148		159
Total rate-regulated electric revenues(b)	$	4,540	$	1,934	$	1,781	$	3,451	$	1,629	$	852	$	972
Rate-regulated natural gas revenues
Residential	$	—	$	252	$	342	$	68	$	—	$	68	$	—
Small commercial & industrial	—		86		55		30		—		30		—
Large commercial & industrial	—		—		96		3		—		3		—
Transportation	—		18		—		10		—		10		—
Other(c)	—		3		16		5		—		5		—
Total rate-regulated natural gas revenues(d)	$	—	$	359	$	509	$	116	$	—	$	116	$	—
Total rate-regulated revenues from contracts with customers	$	4,540	$	2,293	$	2,290	$	3,567	$	1,629	$	968	$	972

Other revenues
Revenues from alternative revenue programs	$	(51)	$	10	$	(10)	$	(15)	$	20	$	(15)	$	(20)
Other rate-regulated electric revenues(e)	10		3		3		2		1		1		—
Other rate-regulated natural gas revenues(e)	—		—		1		—		—		—		—

Total other revenues	$	(41)	$	13	$	(6)	$	(13)	$	21	$	(14)	$	(20)
Total rate-regulated revenues for reportable segments	$	4,499	$	2,306	$	2,284	$	3,554	$	1,650	$	954	$	952

__________

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

(b)Includes operating revenues from affiliates in 2021 and 2020 respectively of:

•$19 million, $31 million at ComEd

•$5 million, $6 million at PECO

•$10 million, $9 million at BGE

•$10 million, $13 million at PHI

•$4 million, $6 million at Pepco

•$6 million, $7 million at DPL

•$2 million, $3 million at ACE

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

(d)Includes operating revenues from affiliates in 2021 and 2020 respectively of:

•$1 million, $1 million at PECO

•$10 million, $7 million at BGE

(e)Includes late payment charge revenues.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in millions, except per share data, unless otherwise noted)

Note 6 — Accounts Receivable

6. Accounts Receivable (All Registrants)

Allowance for Credit Losses on Accounts Receivable (All Registrants)

The following tables present the rollforward of Allowance for Credit Losses on Customer Accounts Receivable.


	Three Months Ended September 30, 2021
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance as of June 30, 2021	$	395	$	75	$	89	$	111	$	27	$	93	$	38	$	19	$	36
Plus: Current period provision for expected credit losses(a)	47		10		11		1		7		18		5		3		10
Less: Write-offs, net of recoveries(b)	33		1		12		11		3		6		2		4		—

Balance as of September 30, 2021	$	409	$	84	$	88	$	101	$	31	$	105	$	41	$	18	$	46

	Three Months Ended September 30, 2020
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance as of June 30, 2020	$	261	$	33	$	72	$	71	$	23	$	62	$	24	$	18	$	20
Plus: Current period provision for expected credit losses(c)	114		1		37		27		14		35		11		7		17
Less: Write-offs, net of recoveries(b)	17		1		4		2		2		8		—		3		5

Balance as of September 30, 2020	$	358	$	33	$	105	$	96	$	35	$	89	$	35	$	22	$	32

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in millions, except per share data, unless otherwise noted)

Note 6 — Accounts Receivable


















	Nine Months Ended September 30, 2021
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance as of December 31, 2020	$	366	$	32	$	97	$	116	$	35	$	86	$	32	$	22	$	32
Plus: Current period provision for expected credit losses(d)	122		57		23		7		2		33		15		4		14
Less: Write-offs, net of recoveries(b)	79		5		32		22		6		14		6		8		—

Balance as of September 30, 2021	$	409	$	84	$	88	$	101	$	31	$	105	$	41	$	18	$	46

	Nine Months Ended September 30, 2020
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance as of December 31, 2019	$	243	$	80	$	59	$	55	$	12	$	37	$	13	$	11	$	13
Plus: Current period provision for expected credit losses(c)	222		13		62		56		28		63		24		14		25
Less: Write-offs, net of recoveries(b)	51		4		16		15		5		11		2		3		6
Less: Sale of customer accounts receivable(e)	56		56		—		—		—		—		—		—		—
Balance as of September 30, 2020	$	358	$	33	$	105	$	96	$	35	$	89	$	35	$	22	$	32

__________

(a)For ACE, the increase is primarily a result of increased aging of receivables and a slight decrease in the expected recovery rate.

(b)Recoveries were not material to the Registrants.

(c)For the Utility Registrants, the increase is primarily as a result of increased aging of receivables, the temporary suspension of customer disconnections for non-payment, temporary cessation of new late payment fees, and reconnections of service to customers previously disconnected due to COVID-19.

(d)For Generation, primarily relates to the impacts of the February 2021 extreme cold weather event. See Note 3 — Regulatory Matters for additional information. For PHI, Pepco, ~~DPL and ACE)~~

~~ComEd, PECO, BGE, Pepco, DPL~~ and ACE, the increase is primarily a result of increased aging of receivables and a slight decrease in the expected recovery rate.

(e)See below for additional information on the sale of customer accounts receivable at Generation in the second quarter of 2020.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in millions, except per share data, unless otherwise noted)

Note 6 — Accounts Receivable

The following tables present the rollforward of Allowance for Credit Losses on Other Accounts Receivable.


	Three Months Ended September 30, 2021
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance as of June 30, 2021	$	72	$	1	$	18	$	7	$	8	$	38	$	16	$	9	$	13
Plus: Current period provision for expected credit losses	9		3		2		1		1		2		1		(1)		2
Less: Write-offs, net of recoveries(a)	4		—		1		1		1		—		—		—		—
Balance as of September 30, 2021	$	77	$	4	$	19	$	7	$	8	$	40	$	17	$	8	$	15

	Three Months Ended September 30, 2020
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance as of June 30, 2020	$	61	$	—	$	22	$	7	$	6	$	26	$	11	$	7	$	8
Plus: Current period provision for expected credit losses	15		—		5		1		3		6		2		1		3
Less: Write-offs, net of recoveries(a)	1		—		—		1		—		—		—		—		—
Balance as of September 30, 2020	$	75	$	—	$	27	$	7	$	9	$	32	$	13	$	8	$	11

	Nine Months Ended September 30, 2021
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance as of December 31, 2020	$	71	$	—	$	21	$	8	$	9	$	33	$	13	$	9	$	11
Plus: Current period provision for expected credit losses	15		4		—		2		2		7		4		(1)		4
Less: Write-offs, net of recoveries(a)	9		—		2		3		3		—		—		—		—
Balance as of September 30, 2021	$	77	$	4	$	19	$	7	$	8	$	40	$	17	$	8	$	15

	Nine Months Ended September 30, 2020
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance as of December 31, 2019	$	48	$	—	$	20	$	7	$	5	$	16	$	7	$	4	$	5
Plus: Current period provision for expected credit losses	36		—		9		3		7		17		6		4		7
Less: Write-offs, net of recoveries(a)	9		—		2		3		3		1		—		—		1
Balance as of September 30, 2020	$	75	$	—	$	27	$	7	$	9	$	32	$	13	$	8	$	11

__________

(a)Recoveries were not material to the Registrants.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in millions, except per share data, unless otherwise noted)

Note 6 — Accounts Receivable

Unbilled Customer Revenue (All Registrants)

The following table provides additional information about unbilled customer revenues recorded in the Registrants' Consolidated Balance Sheets as of September 30, 2021 and December 31, 2020.


	Unbilled customer revenues(a)
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
September 30, 2021	$	941	$	359	$	224	$	113	$	98	$	147	$	70	$	34	$	43
December 31, 2020	998		258		218		147		197		178		87		62		29

__________

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

Sales of Customer Accounts Receivable (Exelon and Generation)

On April 8, 2020, NER, a bankruptcy remote, special purpose entity, which is wholly-owned by Generation, entered into a revolving accounts receivable financing arrangement with a number of financial institutions and a commercial paper conduit (the Purchasers) to sell certain customer accounts receivable (the Facility). The Facility had a maximum funding limit of $750 million and was scheduled to expire on April 7, 2021, unless renewed by the mutual consent of the parties in accordance with its terms. The Facility was renewed on March 29, 2021. The Facility term was extended through March 29, 2024, unless further renewed by the mutual consent of the parties, and the maximum funding limit was increased to $900 million.Under the Facility, NER may sell eligible short-term customer accounts receivable to the Purchasers in exchange for cash and subordinated interest. The transfers are reported as sales of receivables in Exelon’s and Generation’s consolidated financial statements. The subordinated interest in collections upon the receivables sold to the Purchasers is referred to as the DPP, which is reflected in Other current assets in Exelon’s and Generation’s Consolidated Balance Sheets.

The Facility requires the balance of eligible receivables to be maintained at or above the balance of cash proceeds received from the Purchasers. To the extent the eligible receivables decrease below such balance, Generation is required to repay cash to the Purchasers. When eligible receivables exceed cash proceeds, Generation has the ability to increase the cash received up to the maximum funding limit. These cash inflows and outflows impact the DPP.

On April 8, 2020, Generation derecognized and transferred approximately $1.2 billion of receivables at fair value to the Purchasers in exchange for approximately $500 million in cash purchase price and $650 million of DPP.

During the first quarter of 2021, Generation received additional cash of $250 million from the Purchasers for the remaining available funding in the Facility.

Additionally, during the first quarter of 2021, Generation received cash of approximately $150 million from the Purchasers in connection with the increased funding limit at the time of the Facility renewal.

During the second quarter of 2021, Generation returned cash of $50 million to the Purchasers due to the eligible receivables decreasing temporarily. Subsequently, in the second quarter, Generation received cash of $50 million from the Purchasers as a result of an increase in the eligible receivable balance. The $50 million cash outflow and inflow is included in the Collection of DPP line within Cash flows from investing activities in Exelon’s and Generation’s Consolidated Statements of Cash Flows.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in millions, except per share data, unless otherwise noted)

Note 6 — Accounts Receivable

The following table summarizes the impact of the sale of certain receivables:


	September 30, 2021		December 31, 2020
Derecognized receivables transferred at fair value	$	1,401	$	1,139
Cash proceeds received	900		500
DPP	501		639


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Loss on sale of receivables(a)	$	1	$	8	$	26	$	23

__________

(a)Reflected in Operating and maintenance expense in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.


	Nine Months Ended September 30,
	2021		2020
Proceeds from new transfers(a)	$	4,440	$	1,889
Cash collections received on DPP and reinvested in the Facility(b)	2,652		2,518
Cash collections reinvested in the Facility	7,092		4,407

__________

(a)Customer accounts receivable sold into the Facility were $7,373 million and $4,515 million for the nine months ended September 30, 2021 and September 30, 2020, respectively.

(b)Does not include the $400 million in cash proceeds received from the Purchasers in the first quarter of 2021.

Generation’s risk of loss following the transfer of accounts receivable is limited to the DPP outstanding. Payment of DPP is not subject to significant risks other than delinquencies and credit losses on accounts receivable transferred, which have historically been and are expected to be immaterial. Generation continues to service the receivables sold in exchange for a servicing fee. Generation did not record a servicing asset or liability as the servicing fees were immaterial.

Generation recognizes the cash proceeds received upon sale in Net cash provided by operating activities in the Consolidated Statements of Cash Flows. The collection and reinvestment of DPP is recognized in Net cash provided by investing activities in the Consolidated Statements of Cash Flows.

See Note 14 — Fair Value of Financial Assets and Liabilities and Note 17 — Variable Interest Entities for additional information.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in millions, except per share data, unless otherwise noted)

Note 6 — Accounts Receivable

Other Purchases and Sales of Customer and Other Accounts Receivables (All Registrants)

Generation is required, under supplier tariffs in ISO-NE, MISO, NYISO, and PJM, to sell customer and other receivables to utility companies, which include the Utility Registrants. The Utility Registrants are required, under separate legislation and regulations in Illinois, Pennsylvania, Maryland, District of Columbia, Delaware, and New Jersey, to purchase certain receivables from alternative retail electric and, as applicable, natural gas suppliers that participate in the utilities' consolidated billing. ComEd, BGE, Pepco and DPL purchase receivables at a discount to recover primarily uncollectible accounts expense from the suppliers. PECO is required to purchase receivables at face value and is permitted to recover uncollectible accounts expense, including those from Third Party Suppliers, from customers through distribution rates. ACE purchases receivables at face value. ACE recovers all uncollectible accounts expense, including those from Third Party Suppliers, through the Societal Benefits Charge (SBC) rider, which includes uncollectible accounts expense as a component. The SBC is filed annually with the NJBPU. Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE do not record unbilled commodity receivables under the POR programs. Purchased billed receivables are classified in Other accounts receivable, net on Exelon’s, ComEd’s, PECO’s, BGE’s, PHI's, Pepco's, DPL's and ACE's Consolidated Balance Sheets. The following tables ~~provide information about~~present the total receivables purchased ~~receivables of those companies as of September 30, 2017~~ and ~~December 31, 2016.~~sold.


	Nine Months Ended September 30, 2021
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Total receivables purchased	$	2,945	$	—	$	810	$	795	$	531	$	826	$	504	$	166	$	156
Total receivables sold	100		117		—		—		—		—		—		—		—

Related party transactions:
Receivables purchased from Generation	—		—		—		—		17		—		—		—		—
Receivables sold to the Utility Registrants	—		17		—		—		—		—		—		—		—

Successor
As of September 30, 2017 Exelon ComEd PECO BGE PHI Pepco DPL ACE
Purchased receivables $ 312
$ 89
$ 68
$ 55
$ 100
$ 66
$ 10
$ 24
Allowance for uncollectible accounts^(a)
(33 ) (13 ) (5 ) (4 ) (11 ) (6 ) (1 ) (4 )
Purchased receivables, net $ 279
$ 76
$ 63
$ 51
$ 89
$ 60
$ 9
$ 20



	Nine Months Ended September 30, 2020
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Total receivables purchased	$	2,698	$	—	$	865	$	786	$	508	$	787	$	484	$	160	$	143
Total receivables sold	542		790		—		—		—		—		—		—		—

Related party transactions:
Receivables purchased from Generation	—		—		34		67		75		72		51		13		8
Receivables sold to the Utility Registrants	—		248		—		—		—		—		—		—		—

Successor
As of December 31, 2016 Exelon ComEd PECO BGE PHI Pepco DPL ACE
Purchased receivables $ 313
$ 87
$ 72
$ 59
$ 95
$ 63
$ 10
$ 22
Allowance for uncollectible accounts^(a)
(37 ) (14 ) (6 ) (4 ) (13 ) (7 ) (2 ) (4 )
Purchased receivables, net $ 276
$ 73
$ 66
$ 55
$ 82
$ 56
$ 8
$ 18

~~_________~~


~~(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.

~~6. Impairment of Long-Lived Assets (Exelon and Generation)~~

~~Long-Lived Assets (Exelon and Generation)~~

Generation evaluates long-lived assets for recoverability whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. EGTP’s operating cash flows have been negatively impacted by certain market conditions and the seasonality of its cash flows. On May 2, 2017, EGTP entered into a consent agreement with its lenders to initiate an orderly sales process to sell the assets of its wholly owned subsidiaries, the proceeds from which will first be used to pay the administrative costs of the sale, the normal and ordinary costs of operating the plants and repayment of the secured debt of EGTP. As a result, as of June 30, 2017, and September 30, 2017, certain of EGTP’s assets and liabilities were classified as held for sale at their respective fair values less costs to sell and included in the other current assets and other current liabilities balances on Exelon’s and Generation’s Consolidated Balance Sheets. As of June 30, 2017, the fair value analysis was based on an income approach using significant unobservable inputs (Level 3) including revenue and generation forecasts, projected capital and maintenance expenditures and discount rates. As a result of this analysis, in the second quarter 2017, Exelon and Generation recorded a pre-tax impairment charge of $418 million within Operating and maintenance expense on their Consolidated Statements of Operations and Comprehensive Income. In the third quarter 2017, Exelon and Generation recorded an additional pre-tax impairment charge of $40 million within Operating and maintenance expense on their Consolidated Statements of Operations and Comprehensive Income to reflect an indicated decline in fair value based on new information obtained in the quarter through the orderly sales process. See Note 4 - Mergers, Acquisitions and Dispositions and Note 11 - Debt and Credit Agreements, for further information.

During the first quarter of 2016, significant changes in Generation’s intended use of the Upstream oil and gas assets, developments with nonrecourse debt held by its upstream subsidiary CEU Holdings, LLC (as described in Note

~~Table of Contents~~

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

14 - Debt and Credit Agreements of the Exelon 2016 Form 10-K) and continued declines in both production volumes and commodity prices suggested that the carrying value may be impaired. Generation concluded that the estimated undiscounted future cash flows and fair value of its Upstream properties were less than their carrying values. As a result, a pre-tax impairment charge of $119 million was recorded in March 2016 within Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. On June 16, 2016, Generation initiated the sales process of its Upstream business by executing a forbearance agreement with the lenders of the nonrecourse debt. An additional pre-tax impairment charge of $15 million was recorded in September 2016 within Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income due to further declines in fair value. In December 2016, Generation sold substantially all of the Upstream Assets. See Note 4 - Mergers, Acquisitions and Dispositions of the Exelon 2016 Form 10-K for further information.

In the second quarter of 2016, updates to the Company's long-term view of energy and capacity prices suggested that the carrying value of a group of merchant wind assets, located in West Texas, may be impaired. Upon review, the estimated undiscounted future cash flows and fair value of the group were less than their carrying value. The fair value analysis was based on the income approach using significant unobservable inputs (Level 3) including revenue and generation forecasts, projected capital and maintenance expenditures and discount rates. As a result of the fair value analysis, long-lived assets held and used with a carrying amount of approximately $60 million were written down to their fair value of $24 million and a pre-tax impairment charge of $36 million was recorded during the second quarter in Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

Also in the second quarter of 2016, updates to the Company's long-term view, as described above, in conjunction with the previous decision to early retire the Clinton and Quad Cities nuclear facilities in Illinois suggested that the carrying value of our Midwest asset group may be impaired. Generation completed a comprehensive review of the estimated undiscounted future cash flows of the Midwest asset group and no impairment charge was required.

~~Like-Kind Exchange Transaction (Exelon)~~

In June 2000, UII, LLC (formerly Unicom Investments, Inc.) (UII), a wholly owned subsidiary of Exelon Corporation, entered into transactions pursuant to which UII invested in coal-fired generating station leases (Headleases) with the Municipal Electric Authority of Georgia (MEAG). The generating stations were leased back to MEAG as part of the transactions (Leases).

On March 31, 2016, UII and MEAG finalized an agreement to terminate the MEAG Headleases, the MEAG Leases, and other related agreements prior to their expiration dates. As a result of the lease termination, UII received an early termination payment of $360 million from MEAG and wrote-off the $356 million net investment in the MEAG Headleases and the Leases. The transaction resulted in a pre-tax gain of $4 million which is reflected in Operating and maintenance expense in Exelon's Consolidated Statements of Operations and Comprehensive Income. See Note 12—Income Taxes for additional information.

7. Early ~~Nuclear~~ Plant Retirements (Exelon and Generation)

Exelon and Generation ~~continue to~~continuously evaluate factors that affect the current and expected economic value of ~~each of~~ Generation’s ~~nuclear plants. Factors that will continue to affect the economic value of Generation’s nuclear~~ plants, ~~include,~~including, but ~~are~~ not limited to: market power prices, results of capacity auctions, potential legislative and regulatory solutions to ensure ~~nuclear~~ plants are fairly compensated for benefits they provide through their carbon-free emissions, reliability, or fuel security, and the impact of potential rules from the EPA requiring reduction of carbon and other emissions and the efforts of states to implement those final rules. The precise timing of an early retirement date for any ~~nuclear~~ plant, and the resulting financial statement impacts, may be affected by ~~a number of~~many factors, including the status of potential regulatory or legislative solutions, results of any transmission system reliability study assessments, the nature of any co-owner requirements and stipulations, and ~~decommissioning trust~~NDT fund requirements for nuclear plants, among other factors. However, the earliest retirement date for any plant would usually be the first year in which the unit does not have capacity or other obligations, and where applicable, ~~and~~ just prior to its next scheduled nuclear refueling outage.

~~In 2015 and 2016,~~Nuclear Generation identified the Clinton, Quad Cities, Ginna, Nine Mile Point, and Three Mile Island (TMI) nuclear plants as having the greatest risk of early retirement based on economic valuation and other factors. PSEG has also recently made public similar financial challenges facing its New Jersey nuclear plants including Salem,

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— ~~(Continued)~~

(Dollars in millions, except per share data, unless otherwise noted)

Note 7 — Early Plant Retirements

On August 27, 2020, Generation announced that it intended to permanently cease generation operations at Byron in September 2021 and at Dresden in November 2021. Neither of ~~which Generation owns a 42.59% ownership interest. As previously disclosed, Exelon and Generation have committed to cease operation of the Oyster Creek~~these nuclear ~~plant by the end of 2019.~~

~~The TMI nuclear plant did not clear~~plants cleared in ~~the May 2017 PJM~~PJM’s capacity auction for the ~~2020-2021~~2022-2023 planning year held in May 2021. Generation’s Braidwood and LaSalle nuclear plants in Illinois did clear in the capacity auction, but were also showing increased signs of economic distress.

On September 15, 2021, the Illinois Public Act 102-0662 was signed into law by the Governor of Illinois (“Clean Energy Law”). The Clean Energy Law is designed to achieve 100% carbon-free power by 2045 to enable the state’s transition to a clean energy economy. Among other things, the Clean Energy Law authorizes the IPA to procure up to 54.5 million CMCs from qualifying nuclear plants for a five-year period beginning on June 1, 2022 through May 31, 2027. CMCs are credits for the carbon-free attributes of eligible nuclear power plants in PJM. The Byron, Dresden, and Braidwood nuclear plants located in Illinois will ~~not receive capacity revenue for that period,~~be eligible to participate in the ~~third consecutive year that TMI failed to clear the PJM base residual capacity auction. The plant is currently~~CMC procurement process and, if awarded contracts, would be committed to operate through May ~~2019.~~

~~Based~~31, 2027. See Note 3 — Regulatory Matters for additional information. Following enactment of the legislation, Generation announced on these capacity auction results, prolonged periods of low wholesale power prices, and the absence of federal or state policies that place a value on nuclear energy for its ability to produce electricity without air pollution, Exelon announced that Generation will permanently cease generation operations at TMI on or about September 30, 2019. The current NRC license for TMI expires in 2034. Generation is proceeding with the market and regulatory notifications that must be made to shut down the plant, including filing of a deactivation notice with PJM on May 30, 2017 and notification to the NRC on June 20, 2017. PJM has subsequently notified Generation15, 2021, that it has ~~not identified any reliability issues~~reversed its previous decision to retire Byron and ~~has approved~~Dresden given the ~~deactivation of TMI as proposed.~~opportunity for additional revenue under the Clean Energy Law. In addition, Generation no longer considers the Braidwood or LaSalle nuclear plants to be at risk for premature retirement.

~~In 2017, as~~As a result of the ~~plant retirement~~ decision ~~of TMI,~~to early retire Byron and Dresden, Exelon and Generation recognized certain one-time charges in ~~Operating~~the third and ~~maintenance expense~~fourth quarters of ~~$76 million~~2020 related to materials and supplies inventory reserve adjustments, employee-related costs including severance benefit costs, and construction work-in-progress ~~(CWIP)~~ impairments, among other items. In addition, ~~to these one-time charges,~~ there ~~will be~~were ongoing annual ~~incremental non-cash charges to earnings~~financial impacts stemming from shortening the expected economic useful ~~life~~lives of ~~TMI~~these nuclear plants primarily related to accelerated depreciation of plant assets (including any ARC), accelerated amortization of nuclear fuel, and ~~additional~~changes in ARO accretion expense associated with the changes in decommissioning timing and cost ~~assumptions. During~~assumptions to reflect an earlier retirement date.

In the ~~three~~third quarter of 2021, Exelon and ~~nine months ended~~Generation reversed $81 million of severance benefit costs and $13 million of other one-time charges initially recorded in Operating and maintenance expense in the third and fourth quarters of 2020 associated with the early retirements. In addition, Generation updated the expected economic useful life for both facilities to 2044 and 2046 for Byron Units 1 and 2, respectively, and to 2029 and 2031 for Dresden Units 2 and 3, respectively, the end of the respective NRC operating license for each unit. Depreciation was therefore adjusted beginning September ~~30, 2017, both Exelon’s and Generation’s results include an incremental $112 million and $149 million, respectively, of pre-tax expense for~~15, 2021, to reflect these ~~items. Please refer to~~extended useful life estimates. See Note 13 8 — Nuclear Decommissioning for additional detail on changes to the nuclear decommissioning ARO balances resulting from the ~~early retirement~~initial decision and subsequent reversal of ~~TMI.~~

Income statement expense (pre-tax) Q3 2017 YTD 2017
Depreciation and amortization
Accelerated depreciation^(a)
$ 106
$ 141
Accelerated nuclear fuel amortization 6
8
Total $ 112
$ 149

~~_________~~


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

~~Based on insufficient capacity auction results and~~ the ~~lack of progress on Illinois energy legislation, on June 2, 2016, Generation announced a~~ decision to ~~shut down~~early retire Byron and Dresden.

The total impact for the ~~Clinton~~three and ~~Quad Cities nuclear plants on June 1, 2017~~nine months ended September 30, 2021 and June 1, 2018, respectively. With the passage of the Illinois ZES on December 7, 2016, and subject to prevailing over any related administrative or legal challenges, Generation reversed this decision and revised the expected economic useful lives for both facilities; 2027 for Clinton and 2032 for Quad Cities. Refer to Note 5 - Regulatory Matters for additional discussion on the Illinois ZES.

2020 in Exelon's and Generation's ~~2016 results included a net incremental $714 million~~Consolidated Statements of ~~total pre-tax expense associated with~~Operations and Comprehensive Income resulting from the initial decision and subsequent reversal of the decision to early ~~retirement decision for Clinton~~retire Byron and ~~Quad Cities, as~~Dresden is summarized in the table below.


Income statement expense (pre-tax)	Three Months Ended September 30, 2021		Nine Months Ended September 30, 2021		Three and Nine Months Ended September 30, 2020
Depreciation and amortization
Accelerated depreciation(a)	$	574	$	1,805	$	254
Accelerated nuclear fuel amortization	42		148		14
Operating and maintenance
One-time charges	(94)		(94)		220
Other charges	4		8		34
Contractual offset(b)	(60)		(451)		(129)
Total	$	466	$	1,416	$	393

Income statement expense (pre-tax) Q2 2016 Q3 2016 Q4 2016 YTD 2016
Depreciation and amortization
Accelerated depreciation^(a)
$ 115
$ 344
$ 253
$ 712
Accelerated Nuclear Fuel amortization 9
28
23
60
Operating and maintenance
One time charges^(b)
141
5
(120 ) 26
ARO accretion, net of contractual offset^(c)
—
2
—
2
Contractual offset for ARC depreciation^(c)
(14 ) (41 ) (31 ) (86 )
Total $ 251
$ 338
$ 125
$ 714
_________

(a)Includes the accelerated depreciation of plant assets including any ARC.

(b)Reflects contractual offset for ARO accretion and ARC depreciation and excludes any changes in earnings in the NDT funds. Decommissioning-related impacts were not offset for the Byron units starting in the second quarter of 2021 due to the inability to recognize a regulatory asset at ComEd. With Generation’s September 15, 2021 reversal of the previous decision to retire Byron, Generation resumed contractual offset for Byron as of that date. Based on the regulatory agreement with the ICC, decommissioning-related activities are offset in Exelon's and Generation's Consolidated

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— ~~(Continued)~~

(Dollars in millions, except per share data, unless otherwise noted)

Note 7 — Early Plant Retirements

~~_________~~


~~(a)~~	~~Reflects incremental accelerated depreciation of plant assets, including any ARC, for the period June 2, 2016, through December 6, 2016.~~


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

~~(c)~~

For Quad Cities based on the regulatory agreement with the Illinois Commerce Commission, decommissioning-related activities are offset within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. The offset results in an equal adjustment to the noncurrent payables to ComEd at Generation and an adjustment to the regulatory liabilities at ComEd. Likewise, ComEd has recorded an equal noncurrent affiliate receivable from Generation and corresponding regulatory liability.

~~In New York,~~Statements of Operations and Comprehensive Income as long as the ~~Ginna, Nine Mile Point,~~net cumulative decommissioning-related activities result in a regulatory liability at ComEd. The offset resulted in an equal adjustment to the noncurrent payables to ComEd at Generation and ~~Generation’s recently acquired FitzPatrick nuclear plant also faced significant economic challenges and risk of retirement before~~an adjustment to the end of each unit’s respective operating license period (2029 for Ginna and Nine Mile Point Unit 1, 2046 for Nine Mile Point Unit 2, and 2034 for FitzPatrick). On August 1, 2016, the NYPSC issued an order adopting the New York CES that, subject to prevailing over any administrative or legal challenges, would allow Ginna, Nine Mile Point, and FitzPatrick to continue to operateregulatory liabilities at least through the life of the program (March 31, 2029). The assumed useful life for depreciation purposes for each facility is through the end of their current operating licenses. Ginna most recently operated under an RSSA which expired March 31, 2017 and has filed the required notice with the NYPSC of its intent to continue operating beyond the expiry of the RSSA. Refer toComEd. See Note ~~4 - Mergers, Acquisitions and Dispositions~~8 — Nuclear Decommissioning for additional ~~information on Generation’s acquisition of FitzPatrick and Note 5 - Regulatory Matters~~information.

Generation remains committed to continued operations for ~~additional discussion on the Ginna RSSA and the New York CES.~~

~~Assuming the successful implementation of~~its other nuclear plants receiving state-supported payments under the Illinois ZES (Clinton and Quad Cities), New Jersey ZEC program (Salem), and the New York CES (FitzPatrick, Ginna, and Nine Mile Point) assuming the continued effectiveness of these programs, Generation and CENG, through its ownership of Ginna and Nine Mile Point, no longer consider Clinton, Quad Cities, Ginna or Nine Mile Point to be at heightened risk for early retirement. However, tosuch programs. To the extent ~~either the Illinois ZES or the New York CES~~such programs do not operate as expected over their full terms, each of these plants ~~(and now including the newly acquired FitzPatrick) could again~~would be at heightened risk for early retirement, which could have a material impact on Exelon’s and Generation’s future financial statements. See Note 3 — Regulatory Matters for additional information on the New Jersey ZEC program and Note 3 — Regulatory Matters of the 2020 Form 10-K for additional information on the Illinois ZES and New York CES.

Exelon continues to work with stakeholders on state policy solutions to support continued operation of our nuclear fleet, while also advocating for broader market reforms at the regional and federal level. The absence of such solutions or reforms could have a material unfavorable impact on Exelon's and Generation's future results of ~~operations, cash flows and financial position.~~operations.

~~8. Intangible Assets (Exelon and PHI)~~Other Generation

In March 2018, Generation notified ISO-NE of its plans to early retire, among other assets, the Mystic Generating Station's units 8 and 9 (Mystic 8 and 9) absent regulatory reforms to properly value reliability and regional fuel security. Thereafter, ISO-NE identified Mystic 8 and 9 as being needed to ensure fuel security for the region and entered into a cost of service agreement with these two units for the period between June 1, 2022 - May 31, 2024. The agreement was approved by FERC in December 2018.

On June 10, 2020, Generation filed a complaint with FERC against ISO-NE stating that ISO-NE failed to follow its tariff with respect to its evaluation of Mystic 8 and 9 for transmission security for the 2024 to 2025 Capacity Commitment Period and that the modifications that ISO-NE made to its unfiled planning procedures to avoid retaining Mystic 8 and 9 should have been filed with FERC for approval. On August 17, 2020, FERC issued an order denying the complaint. As a result, on August 20, 2020, Exelon determined that Generation will permanently cease generation operations at Mystic 8 and 9 at the expiration of the cost of service commitment in May 2024. See Note 3 — Regulatory Matters for additional discussion of Mystic’s cost of service agreement.

As a result of the decision to early retire Mystic 8 and 9, Exelon and Generation recognized $43 million in the third quarter of ~~2015, PHI entered into a sponsorship agreement with~~2020 of one-time charges related to an expected long-term contract termination and materials and supplies reserve adjustments, among other items. In addition, there are financial impacts stemming from shortening the ~~District~~expected economic useful life of ~~Columbia~~Mystic 8 and 9 primarily related to accelerated depreciation of plant assets. Exelon and Generation recorded an immaterial amount of incremental Depreciation and amortization expense for ~~future sponsorship rights associated with public property within~~ the ~~District of Columbia and paid the District of Columbia $25 million. The specific sponsorship rights were to be determined over time through future negotiations. As of~~three months ended September 30, ~~2017, PHI~~2021 and $41 million for the nine months ended September 30, 2021. Exelon and Generation recorded incremental Depreciation and amortization expense of $6 million for the three and nine months ended September 30, 2020.

8. Nuclear Decommissioning (Exelon and Generation)

Nuclear Decommissioning Asset Retirement Obligations

Generation has ~~recorded~~a legal obligation to decommission its nuclear power plants following the ~~sponsorship agreement as~~expiration of their operating licenses. To estimate its decommissioning obligation related to its nuclear generating stations for financial accounting and reporting purposes, Generation uses a ~~finite-lived intangible asset with~~probability-weighted, discounted cash flow model which, on a $25 million carrying amount. Because no specific sponsorship agreements have yet been entered into with the District of Columbia, amortization of the finite-lived intangible asset has yet to commence. In the third quarter of 2017, PHI continued discussions with the District of Columbia regarding the natureunit-by-unit basis, considers multiple outcome scenarios that include significant estimates and ~~timing of available sponsorship opportunities,~~assumptions, and are based on ~~these ongoing discussions, will continue to evaluate any potential impact on the valuation of the sponsorship intangible asset.~~

~~9. Fair Value of Financial Assets~~decommissioning cost studies, cost escalation rates, probabilistic cash flow models, and ~~Liabilities (All Registrants)~~

~~Fair Value of Financial Liabilities Recorded at the Carrying Amount~~

The following tables present the carrying amounts and fair values of the Registrants’ short-term liabilities, long-term debt, SNF obligation, and trust preferred securities (long-term debt to financing trusts or junior subordinated debentures) as of September 30, 2017 and December 31, 2016:

~~Exelon~~discount rates. Generation updates its ARO annually, unless circumstances warrant more frequent

September 30, 2017

Carrying
Amount
Fair Value
Level 1 Level 2 Level 3 Total
Short-term liabilities $ 710
$ —
$ 710
$ —
$ 710
Long-term debt (including amounts due within one year)^(a)
34,865
—
34,686
1,949
36,635
Long-term debt to financing trusts^(b)
389
—
—
423
423
SNF obligation 1,142
—
857
—
857

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— ~~(Continued)~~

(Dollars in millions, except per share data, unless otherwise noted)

Note 8 — Nuclear Decommissioning

updates, based on its review of updated cost studies and its annual evaluation of cost escalation factors and probabilities assigned to various scenarios.

The financial statement impact for changes in the ARO, on an individual unit basis, due to the changes in and timing of estimated cash flows generally result in a corresponding change in the unit’s ARC in Property, plant, and equipment in Exelon’s and Generation’s Consolidated Balance Sheets. If the ARO decreases for a Non-Regulatory Agreement unit without any remaining ARC, the corresponding change is recorded as decrease in Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

The following table provides a rollforward of the nuclear decommissioning ARO reflected in Exelon’s and Generation’s Consolidated Balance Sheets from December 31, 2020 to September 30, 2021:


Nuclear decommissioning ARO at December 31, 2020(a)	$	11,922
Accretion expense	375
Net increase due to changes in, and timing of, estimated future cash flows	256
Costs incurred related to decommissioning plants	(57)
Nuclear decommissioning ARO at September 30, 2021(a)	$	12,496

_________

(a)Includes $74 million and $80 million as the current portion of the ARO at September 30, 2021 and December 31, 2020, which is included in Other current liabilities in Exelon’s and Generation’s Consolidated Balance Sheets.

During the nine months ended September 30, 2021, the net $256 million increase in the ARO for the changes in the amounts and timing of estimated decommissioning cash flows was driven by multiple adjustments. These adjustments primarily include:

•An increase of approximately $510 million for updated cost escalation rates, primarily for labor and energy, and a decrease in discount rates.

•A net decrease of approximately $170 million was driven by updates to Byron and Dresden reflecting changes in assumed retirement dates and assumed methods of decommissioning as a result of the reversal of the decision to early retire the plants. See Note 7 — Early Plant Retirements for additional information.

•A net decrease of approximately $110 million due to lower estimated costs to decommission Byron, Braidwood, Dresden, LaSalle, and Zion nuclear units resulting from the completion of updated cost studies.

The 2021 ARO updates resulted in a decrease of $51 million in Operating and maintenance expense for the three and nine months ended September 30, 2021 in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.

NDT Funds

Exelon and Generation had NDT funds totaling $15,602 million and $14,599 million at September 30, 2021 and December 31, 2020, respectively. The NDT funds also include $198 million and $134 million for the current portion of the NDT funds at September 30, 2021 and December 31, 2020, respectively, which are included in Other current assets in Exelon's and Generation's Consolidated Balance Sheets. See Note 18 — Supplemental Financial Information for additional information on activities of the NDT funds.

Accounting Implications of the Regulatory Agreements with ComEd and PECO

Based on the regulatory agreements with the ICC and PAPUC that dictate Generation’s obligations related to the shortfall or excess of NDT funds necessary for decommissioning the former ComEd units on a unit-by-unit basis and the former PECO units in total, decommissioning-related activities net of applicable taxes, including realized and unrealized gains and losses on the NDT funds, depreciation of the ARC, and accretion of the decommissioning obligation, are generally offset in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income and are recorded by Generation and the corresponding regulated utility as a component of the intercompany and regulatory balances in the balance sheet. For the purposes of making

December 31, 2016

Carrying
Amount
Fair Value
Level 1 Level 2 Level 3 Total
Short-term liabilities $ 1,267
$ —
$ 1,267
$ —
$ 1,267
Long-term debt (including amounts due within one year)^(a)
34,005
1,113
31,741
1,959
34,813
Long-term debt to financing trusts^(b)
641
—
—
667
667
SNF obligation 1,024
—
732
—
732

~~Generation~~

September 30, 2017

Carrying
Amount
Fair Value
Level 1 Level 2 Level 3 Total
Short-term liabilities $ 92
$ —
$ 92
$ —
$ 92
Long-term debt (including amounts due within one year)^(a)
9,528
—
7,915
1,652
9,567
SNF obligation 1,142
—
857
—
857

December 31, 2016

Carrying
Amount
Fair Value
Level 1 Level 2 Level 3 Total
Short-term liabilities $ 699
$ —
$ 699
$ —
$ 699
Long-term debt (including amounts due within one year)^(a)
9,241
—
7,482
1,670
9,152
SNF obligation 1,024
—
732
—
732

~~ComEd~~

September 30, 2017

Carrying
Amount
Fair Value
Level 1 Level 2 Level 3 Total
Long-term debt (including amounts due within one year)^(a)
$ 7,600
$ —
$ 8,353
$ —
$ 8,353
Long-term debt to financing trusts^(b)
205
—
—
226
226

December 31, 2016

Carrying
Amount
Fair Value
Level 1 Level 2 Level 3 Total
Long-term debt (including amounts due within one year)^(a)
$ 7,033
$ —
$ 7,585
$ —
$ 7,585
Long-term debt to financing trusts^(b)
205
—
—
215
215

~~PECO~~

September 30, 2017

Carrying
Amount
Fair Value
Level 1 Level 2 Level 3 Total
Long-term debt (including amounts due within one year)^(a)
$ 2,902
$ —
$ 3,181
$ —
$ 3,181
Long-term debt to financing trusts 184
—
—
197
197

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— ~~(Continued)~~

(Dollars in millions, except per share data, unless otherwise noted)

Note 8 — Nuclear Decommissioning

this determination, the decommissioning obligation referred to is different from the calculation used in the NRC minimum funding obligation filings based on NRC guidelines.

For the former ComEd units, given no further recovery from ComEd customers is permitted and Generation retains an obligation to ultimately return any unused NDTs to ComEd customers (on a unit-by-unit basis), to the extent the related NDT investment balances are expected to exceed the total estimated decommissioning obligation for each unit, decommissioning-related activities are offset in the Consolidated Statements of Operations and Comprehensive Income which results with Generation recognizing an intercompany payable to ComEd while ComEd records an intercompany receivable from Generation with a corresponding regulatory liability. However, given the asymmetric settlement provision that does not allow for continued recovery from ComEd customers in the event of a shortfall, recognition of a regulatory asset at ComEd is not permissible and accounting for decommissioning-related activities at Generation for that unit would not be offset, and the impact to Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income could be material during such periods. During the second and third quarter of 2021, a pre-tax charge of $53 million and $140 million, respectively, was recorded in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income for decommissioning-related activities that were not offset for the Byron units due to contractual offset being temporarily suspended. With Generation’s September 15, 2021 reversal of the previous decision to retire Byron and the corresponding adjustment to the ARO for Byron discussed previously, Generation resumed contractual offset for Byron as of that date.

As of September 30, 2021, decommissioning-related activities for all of the former ComEd units, except for Zion, are currently offset in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

The decommissioning-related activities related to the Non-Regulatory Agreement Units are reflected in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

See Note 10 — Asset Retirement Obligations of the Exelon 2020 Form 10-K for additional information.

NRC Minimum Funding Requirements

NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts to decommission the facility at the end of its life.

Generation filed its biennial decommissioning funding status report with the NRC on February 24, 2021 for all units, including its shutdown units, except for Zion Station which is included in a separate report to the NRC submitted by ZionSolutions, LLC. The status report demonstrated adequate decommissioning funding assurance as of December 31, 2020 for all units except for Byron Units 1 and 2. Generation filed an updated decommissioning funding status report for Byron Units 1 and 2 and Dresden Units 2 and 3 on September 28, 2021 based on their current license expiration dates consistent with Generation’s announcements regarding the continued operations of these units. This report demonstrated adequate decommissioning funding assurance as of December 31, 2020 for Byron Units 1 and 2 and Dresden Units 2 and 3.

Generation will file its next decommissioning funding status report with the NRC by March 31, 2022. This report will reflect the status of decommissioning funding assurance as of December 31, 2021 for shutdown units.

9. Asset Impairments (Exelon and Generation)

The Registrants evaluate the carrying value of long-lived assets or asset groups for recoverability whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators of impairment may include a deteriorating business climate, including, but not limited to, declines in energy prices, condition of the asset, specific regulatory disallowance, or plans to dispose of a long-lived asset significantly before the end of its useful life. The Registrants determine if long-lived assets or asset groups are impaired by comparing the undiscounted expected future cash flows to the carrying value. When the undiscounted cash flow analysis indicates a long-lived asset or asset group is not recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. The fair value analysis is primarily based on the income approach using significant unobservable inputs (Level 3) including revenue and generation forecasts, projected capital and maintenance expenditures, and discount rates. A variation in the assumptions used could lead to a different conclusion

December 31, 2016

Carrying
Amount
Fair Value
Level 1 Level 2 Level 3 Total
Long-term debt (including amounts due within one year)^(a)
$ 2,580
$ —
$ 2,794
$ —
$ 2,794
Long-term debt to financing trusts 184
—
—
192
192

~~BGE~~

September 30, 2017

Carrying
Amount
Fair Value
Level 1 Level 2 Level 3 Total
Long-term debt (including amounts due within one year)^(a)
$ 2,577
$ —
$ 2,817
$ —
$ 2,817

December 31, 2016

Carrying
Amount
Fair Value
Level 1 Level 2 Level 3 Total
Short-term liabilities $ 45
$ —
$ 45
$ —
$ 45
Long-term debt (including amounts due within one year)^(a)
2,322
—
2,467
—
2,467
Long-term debt to financing trusts^(b)
252
—
—
260
260

~~PHI (Successor)~~

September 30, 2017
Carrying Amount Fair Value
Level 1 Level 2 Level 3 Total
Short-term liabilities $ 118
$ —
$ 118
$ —
$ 118
Long-term debt (including amounts due within one year)^(a)
5,930
—
5,729
297
6,026

December 31, 2016
Carrying Amount Fair Value
Level 1 Level 2 Level 3 Total
Short-term liabilities $ 522
$ —
$ 522
$ —
$ 522
Long-term debt (including amounts due within one year)^(a)
5,898
—
5,520
289
5,809

~~Pepco~~

September 30, 2017
Carrying Amount Fair Value
Level 1 Level 2 Level 3 Total
Long-term debt (including amounts due within one year)^(a)
$ 2,546
$ —
$ 3,087
$ 9
$ 3,096

December 31, 2016
Carrying Amount Fair Value
Level 1 Level 2 Level 3 Total
Short-term liabilities $ 23
$ —
$ 23
$ —
$ 23
Long-term debt (including amounts due within one year)^(a)
2,349
—
2,788
8
2,796

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— ~~(Continued)~~

(Dollars in millions, except per share data, unless otherwise noted)

~~DPL~~

Note 9 — Asset Impairments

September 30, 2017
Carrying Amount Fair Value
Level 1 Level 2 Level 3 Total
Short-term liabilities $ 54
$ —
$ 54
$ —
$ 54
Long-term debt (including amounts due within one year)^(a)
1,326
—
1,407
—
1,407

December 31, 2016
Carrying Amount Fair Value
Level 1 Level 2 Level 3 Total
Long-term debt (including amounts due within one year)^(a)
$ 1,340
$ —
$ 1,383
$ —
$ 1,383

~~ACE~~

September 30, 2017
Carrying Amount Fair Value
Level 1 Level 2 Level 3 Total
Short-term liabilities $ 65
$ —
$ 65
$ —
$ 65
Long-term debt (including amounts due within one year)^(a)
1,130
—
969
288
1,257

December 31, 2016
Carrying Amount Fair Value
Level 1 Level 2 Level 3 Total
Long-term debt (including amounts due within one year)^(a)
$ 1,155
$ —
$ 1,007
$ 280
$ 1,287

~~_________~~

~~(a)~~

~~Includes unamortized debt issuance costs which are not fair valued of $196 million, $51 million, $53 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 September 30, 2017. Includes unamortized debt issuance costs which are not fair valued of $200 million, $64 million, $46 million, $15 million, $15 million, $2 million, $30 million, $11 million, and $6 million for Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, as of December 31, 2016.


~~(b)~~	Includes unamortized debt issuance costs which are not fair valued of $1 million and $1 million for Exelon and ComEd, respectively, as of September 30, 2017. Includes unamortized debt issuance costs which are not fair valued of $7 million, $1 million, and $6 million for Exelon, ComEd and BGE, respectively, as of December 31, 2016.

~~Short-Term Liabilities.~~ ~~The short-term liabilities included~~regarding the recoverability of an asset or asset group and, thus, could potentially result in ~~the tables above are comprised of dividends payable (included in other current liabilities) (Level 1) and short-term borrowings (Level 2). The Registrants’ carrying amounts~~material future impairments of the ~~short-term liabilities are representative~~Registrant's long-lived assets.

New England Asset Group

In the third quarter of ~~fair value because~~2020, in conjunction with the retirement announcement of Mystic Units 8 and 9, Generation completed a comprehensive review of the ~~short-term nature of these instruments.~~

~~Long-Term Debt.~~ The fair value amounts of Exelon’s taxable debt securities (Level 2) and private placement taxable debt securities (Level 3) are determined by a valuation model that is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. In order to incorporate the credit risk of the Registrants into the discount rates, Exelon obtains pricing (i.e., U.S. Treasury rate plus credit spread) based on trades of existing Exelon debt securities as well as debt securities of other issuers in the utility sector with similar credit ratings in both the primary and secondary market, across the Registrants’ debt maturity spectrum. The credit spreads of various tenors obtained from this information are added to the appropriate benchmark U.S. Treasury rates in order to determine the current market yields for the various tenors. The yields are then converted into discount rates of various tenors that are used for discounting the respectiveestimated undiscounted future cash flows of the ~~same tenor for each bond or note. Due to low trading volume of private placement debt, qualitative factors such as market conditions, low volume of investors~~New England asset group and ~~investor demand, this debt is classified as Level 3. The~~concluded that the estimated undiscounted future cash flows and fair value of the New England asset group were less than their carrying values. As a result, a pre-tax impairment charge of $500 million was recorded in the third quarter of 2020 in Operating and maintenance expense in Exelon's ~~equity units (Level 1) are valued based on publicly traded securities issued by Exelon.~~and Generation's Consolidated Statements of Operations and Comprehensive Income. See Note 7 — Early Plant Retirements for additional information.

~~The~~In the second quarter of 2021, an overall decline in the asset group's portfolio value suggested that the carrying value of the New England asset group may be impaired. Generation completed a comprehensive review of the estimated undiscounted future cash flows of the New England asset group and concluded that the carrying value was not recoverable and that its fair value was less than its carrying value. As a result, a pre-tax impairment charge of Generation’s and Pepco's non-government-backed fixed rate nonrecourse debt (Level 3) is based on market and quoted prices for its own and other nonrecourse debt with similar risk profiles. Given the low trading volume$350 million was recorded in the ~~nonrecourse debt market,~~second quarter of 2021 in Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

Contracted Wind Project

In the ~~price quotes used to determine~~third quarter of 2021, significant long-term operational issues anticipated for a specific wind turbine technology suggested that the carrying value of a contracted wind asset, located in Maryland and part of the EGRP joint venture, may be impaired. Generation completed a comprehensive review of the estimated undiscounted future cash flows and concluded that the carrying value of this contracted wind project was not recoverable and that its fair value ~~will reflect certain qualitative factors, such as market conditions, investor demand, new developments that might significantly impact~~was less than its carrying value. As a result, in the ~~project~~

third quarter of 2021, a pre-tax impairment charge of $45 million was recorded in Operating and maintenance expense, $21 million of which was offset in Net income attributable to noncontrolling interests in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

~~100~~

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— ~~(Continued)~~

(Dollars in millions, except per share data, unless otherwise noted)

Note 10 — Income Taxes

~~cash flows or off-taker credit, and other circumstances related~~10. Income Taxes (All Registrants)

Rate Reconciliation

The effective income tax rate from continuing operations varies from the U.S. federal statutory rate principally due to the ~~project (e.g., political and regulatory environment). The fair value of Generation’s government-backed fixed rate project financing debt (Level 3)~~following:


	Three Months Ended September 30, 2021

	Exelon(a)	Generation(a)	ComEd(a)	PECO(a)(b)	BGE(a)(b)	PHI(a)	Pepco(a)	DPL(a)	ACE(a)(b)
U.S. Federal statutory rate	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	6.0	4.4	8.0	(4.1)	(13.0)	5.0	3.4	6.4	7.0
Qualified NDT fund income	0.5	0.9	—	—	—	—	—	—	—

Amortization of investment tax credit, including deferred taxes on basis difference	(0.4)	(0.7)	(0.1)	—	(0.1)	(0.1)	—	(0.2)	(0.2)
Plant basis differences	(1.7)	—	(0.8)	(16.2)	(1.4)	(1.3)	(2.0)	(0.6)	(0.6)
Production tax credits and other credits	(1.0)	(1.4)	(0.5)	—	(0.9)	(0.5)	(0.5)	(0.4)	(0.5)
Noncontrolling interests	(0.4)	(0.6)	—	—	—	—	—	—	—
Excess deferred tax amortization	(6.8)	—	(7.6)	(3.4)	(17.3)	(24.9)	(17.6)	(19.9)	(41.4)

Other(c)	(4.8)	(1.9)	0.3	(0.1)	(0.8)	—	0.1	(0.6)	0.8
Effective income tax rate	12.4%	21.7%	20.3%	(2.8)%	(12.5)%	(0.8)%	4.4%	5.7%	(13.9)%


	Three Months Ended September 30, 2020
	Exelon(a)	Generation(a)	ComEd(a)	PECO(a)(d)	BGE(a)(d)	PHI(a)(d)	Pepco(a)(d)	DPL(a)(d)	ACE(a)(d)
U.S. Federal statutory rate	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	12.3	(10.3)	8.1	(6.2)	5.1	5.5	4.6	6.6	6.9
Qualified NDT fund income	13.2	47.4	—	—	—	—	—	—	—

Amortization of investment tax credit, including deferred taxes on basis difference	(1.4)	(4.5)	(0.2)	—	(0.1)	(0.2)	(0.1)	(0.2)	(0.3)
Plant basis differences	(4.3)	—	(0.6)	(23.3)	(1.2)	(1.5)	(2.1)	(0.4)	(1.3)
Production tax credits and other credits	(3.0)	(9.2)	(0.4)	—	(0.8)	(0.5)	(0.5)	(0.5)	(0.4)
Noncontrolling interests	0.8	2.9	—	—	—	—	—	—	—
Excess deferred tax amortization	(10.1)	—	(5.6)	(3.8)	(10.6)	(24.9)	(20.0)	(23.6)	(36.8)
Tax Settlements	(0.2)	(0.7)	—	—	—	—	—	—	—
Other	(0.8)	(0.9)	1.1	(0.8)	(0.3)	0.1	(0.4)	0.7	0.6
Effective income tax rate	27.5%	45.7%	23.4%	(13.1)%	13.1%	(0.5)%	2.5%	3.6%	(10.3)%

__________

(a)Positive percentages represent income tax expense. Negative percentages represent income tax benefit.

(b)For PECO, the income tax benefit is largely based on a discounted cash flow methodology that is similar to the taxable debt securities methodology described above. Due to the lack of market trading data on similar debt, the discount rates are derived based on the original loan interest rate spread to the applicable Treasury rate as well as a current market curve derived from government-backed securities. Variable rate financing debt resets on a monthly or quarterly basis and the carrying value approximates fair value (Level 2). When trading data is available on variable rate financing debt, the fair value is based on market and quoted prices for its own and other nonrecourse debt with similar risk profiles (Level 2). Generation, Pepco, DPL and ACE also have tax-exempt debt (Level 2). Due to low trading volume in this market, qualitative factors, such as market conditions, investor demand, and circumstances related to the issuer (e.g., conduit issuer political and regulatory environment), may be incorporated into the credit spreads that are used to obtain the fair value as described above. Variable rate tax-exempt debt (Level 2) resets on a regular basis and the carrying value approximates fair value.

~~SNF Obligation~~. The carrying amount of Generation’s SNF obligation (Level 2) is derived from a contract with the DOE to provide for disposal of SNF from Generation’s nuclear generating stations. When determining the fair value of the obligation, the future carrying amount of the SNF obligation is calculated by compounding the current book value of the SNF obligation at the 13-week Treasury rate. The compounded obligation amount is discounted back to present value using Generation’s discount rate, which is calculated using the same methodology as described above for the taxable debt securities, and an estimated maturity date of 2030. The carrying amount also includes $112 million as of September 30, 2017 for the one-time fee obligation associated with closing of the FitzPatrick acquisition on March 31, 2017. The fair value was determined using a similar methodology, however the New York Power Authority's (NYPA) discount rate is used in place of Generation's given the contractual right to reimbursement from NYPA for the obligation; see Note 4 - Mergers, Acquisitions and Dispositions for additional information on Generation's acquisition of FitzPatrick.

~~Long-Term Debt to Financing Trusts~~. Exelon’s long-term debt to financing trusts is valued based on publicly traded securities issued by the financing trusts. Due to low trading volume of these securities, qualitative factors, such as market conditions, investor demand, and circumstances related to each issue, this debt is classified as Level 3.

~~Recurring Fair Value Measurements~~

Exelon records the fair value of assets and liabilities in accordance with the hierarchy established by the authoritative guidance for fair value measurements. The hierarchy prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:

~~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~~primarily due to ~~little or no market activity for the asset or liability.~~

Transfers in and out of levels are recognized as of the end of the reporting period when the transfer occurred. Given derivatives categorized within Level 1 are valued using exchange-based quoted prices within observable periods, transfers between Level 2 and Level 1 were not material. Additionally, there were no material transfers between Level 1 and Level 2 during the nine months ended September 30, 2017 for cash equivalents, nuclear decommissioning trust fund investments, pledged assets for Zion Station decommissioning, Rabbi trust investments, and deferred compensation obligations.plant basis differences attributable to tax repair deductions. For derivative contracts, transfers into Level 2 from Level 3 generally occur when the contract tenor becomes more observable and due to changes in market liquidity or assumptions for certain commodity contracts.

BGE,

~~101~~

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— ~~(Continued)~~

(Dollars in millions, except per share data, unless otherwise noted)

Note 10 — Income Taxes

~~Generation~~the income tax benefit is primarily due to the Maryland multi-year plan which resulted in the acceleration of certain income tax benefits. For ACE, the income tax benefit is primarily due to a distribution rate case settlement which allows ACE to retain certain tax benefits.

(c)For Exelon, "Other" is primarily driven by the reversal of the consolidating income tax adjustment recorded at Exelon Corporate in the first quarter of 2021 that was required pursuant to GAAP interim reporting guidance.

(d)At PECO, the lower effective tax rate is primarily related to an increase in plant basis differences attributable to storm tax repair deductions. At BGE, PHI, Pepco, DPL and ~~Exelon~~

~~In accordance with~~ACE, the ~~applicable guidance on fair value measurement, certain investments that are measured at fair value using the NAV per share~~lower effective tax rate is primarily attributable to accelerated amortization of transmission related deferred income tax regulatory liabilities as a ~~practical expedient are no longer classified within the fair value hierarchy and are included under "Not subject to leveling" in the table below.~~result of regulatory settlements.

The following tables present assets and liabilities measured and recorded at fair value on Exelon's and Generation’s Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of September 30, 2017 and December 31, 2016:


	Nine Months Ended September 30, 2021
	Exelon(a)	Generation(b)	ComEd(a)	PECO(a)(c)	BGE(a)(c)	PHI(a)	Pepco(a)	DPL(a)	ACE(a)(c)
U.S. Federal statutory rate	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	3.0	90.2	7.6	(2.6)	(10.8)	4.6	2.5	6.5	7.3
Qualified NDT fund income	9.4	(1,932.6)	—	—	—	—	—	—	—

Amortization of investment tax credit, including deferred taxes on basis difference	(0.8)	130.6	(0.1)	—	(0.1)	(0.1)	—	(0.2)	(0.2)
Plant basis differences	(3.9)	—	(0.7)	(12.6)	(1.5)	(1.3)	(1.9)	(0.7)	(0.6)
Production tax credits and other credits	(2.6)	425.1	(0.5)	—	(0.9)	(0.5)	(0.5)	(0.4)	(0.5)
Noncontrolling interests	(0.7)	145.2	—	—	—	—	—	—	—
Excess deferred tax amortization	(13.9)	—	(7.2)	(3.3)	(16.0)	(22.8)	(17.4)	(19.7)	(36.3)

Other(d)	2.2	(229.5)	(1.3)	(0.2)	(0.7)	(0.3)	(0.4)	(0.2)	—
Effective income tax rate	13.7%	(1,350.0)%	18.8%	2.3%	(9.0)%	0.6%	3.3%	6.3%	(9.3)%

Generation Exelon
As of September 30, 2017 Level 1 Level 2 Level 3 Not subject to leveling Total Level 1 Level 2 Level 3 Not subject to leveling Total
Assets
Cash equivalents^(a)
$ 80
$ —
$ —
$ —
$ 80
$ 944
$ —
$ —
$ —
$ 944
NDT fund investments

Cash equivalents^(b)
149
86
—
—
235
149
86
—
—
235
Equities 3,935
840
—

2,088
6,863
3,935
840
—

2,088
6,863
Fixed income
Corporate debt —
1,651
255
—
1,906
—
1,651
255
—
1,906
U.S. Treasury and agencies 1,951
28
—
—
1,979
1,951
28
—
—
1,979
Foreign governments —
70
—
—
70
—
70
—
—
70
State and municipal debt —
246
—
—
246
—
246
—
—
246
Other^(c)
—
46
—
509
555
—
46
—
509
555
Fixed income subtotal 1,951

2,041

255
509

4,756

1,951

2,041

255
509

4,756
Middle market lending —
—
416
87
503
—
—
416
87
503
Private equity —
—
—
212
212
—
—
—
212
212
Real estate —
—
—
449
449
—
—
—
449
449
NDT fund investments subtotal^(d)
6,035

2,967

671
3,345

13,018

6,035

2,967

671
3,345

13,018
Pledged assets for Zion Station decommissioning
Cash equivalents 15
—
—
—
15
15
—
—
—
15

~~102~~

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— ~~(Continued)~~

(Dollars in millions, except per share data, unless otherwise noted)

Note 10 — Income Taxes


	Nine Months Ended September 30, 2020
	Exelon(a)	Generation(a)	ComEd(a)(e)	PECO(a)(e)	BGE(a)(e)	PHI(a)(e)	Pepco(a)(e)	DPL(a)(e)	ACE(a)(e)
U.S. Federal statutory rate	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	9.3	—	12.7	(3.4)	5.5	5.0	4.2	6.5	6.8
Qualified NDT fund income	3.2	10.0	—	—	—	—	—	—	—
Deferred Prosecution Agreement payments	2.5	—	9.4	—	—	—	—	—	—
Amortization of investment tax credit, including deferred taxes on basis difference	(1.2)	(3.2)	(0.3)	—	(0.1)	(0.2)	(0.1)	(0.3)	(0.5)
Plant basis differences	(4.0)	—	(0.9)	(15.9)	(1.8)	(2.2)	(2.4)	(0.5)	(3.7)
Production tax credits and other credits	(2.6)	(7.0)	(0.4)	—	(0.4)	(0.3)	(0.3)	(0.2)	(0.4)
Noncontrolling interests	1.0	3.1	—	—	—	—	—	—	—
Excess deferred tax amortization	(15.8)	—	(11.8)	(3.5)	(15.0)	(45.3)	(29.2)	(53.6)	(81.4)
Tax Settlements(f)	(5.0)	(15.7)	—	—	—	—	—	—	—
Other	0.1	(0.5)	2.1	(0.5)	(0.5)	(0.6)	(0.8)	(1.1)	—
Effective income tax rate	8.5%	7.7%	31.8%	(2.3)%	8.7%	(22.6)%	(7.6)%	(28.2)%	(58.2)%

__________

(a)Positive percentages represent income tax expense. Negative percentages represent income tax benefit.

(b)Generation recognized a loss before income taxes for the nine months ended September 30, 2021. As a result, a negative percentage represents an income tax expense for the period presented.

(c)For PECO, the lower effective tax rate is primarily related to an increase in plant basis differences attributable to tax repair deductions. For BGE, the income tax benefit is primarily due to the Maryland multi-year plan which resulted in the acceleration of certain income tax benefits. For ACE, the income tax benefit is primarily due to a distribution rate case settlement which allows ACE to retain certain tax benefits.

(d)For Exelon, "Other" is primarily driven by the consolidating income tax adjustment recorded at Exelon Corporate in the first quarter of 2021 that was required pursuant to GAAP interim reporting guidance. This incremental expense will reverse by year-end and will not have an impact on annual results.

(e)For ComEd, the higher effective tax rate is primarily related to the nondeductible Deferred Prosecution Agreement payments. For PECO, the income tax benefit is primarily related to an increase in plant basis differences attributable to storm tax repairs deductions. For BGE, PHI, Pepco, DPL, and ACE, the income tax benefit is primarily attributable to accelerated amortization of transmission related deferred income tax regulatory liabilities as a result of regulatory settlements.

(f)Exelon's and Generation’s unrecognized federal and state tax benefits decreased in the first quarter of 2020 by approximately $411 million due to the settlement of a federal refund claim with IRS Appeals. The recognition of these tax benefits resulted in an increase to Exelon's and Generation’s net income of $76 million and $73 million, respectively, in the first quarter of 2020, reflecting a decrease to Exelon's and Generation's income tax expense of $67 million.

Unrecognized Tax Benefits

100

Generation Exelon
As of September 30, 2017 Level 1 Level 2 Level 3 Not subject to leveling Total Level 1 Level 2 Level 3 Not subject to leveling Total
Middle market lending —
—
17
25
42
—
—
17
25
42
Pledged assets for Zion Station
decommissioning subtotal^(e)
15

—

17
25

57

15

—

17
25

57
Rabbi trust investments

Cash equivalents 5
—
—
—
5
77
—
—
—
77
Mutual funds 22
—
—
—
22
56
—
—
—
56
Fixed income —
—
—
—
—
—
13
—
—
13
Life insurance contracts —
21
—
—
21
—
68
21
—
89
Rabbi trust investments subtotal 27

21

—
—

48

133

81

21
—

235
Commodity derivative assets
Economic hedges 487
2,076
1,628
—
4,191
487
2,076
1,628
—
4,191
Proprietary trading 2
41
42
—
85
2
41
42
—
85
Effect of netting and allocation of collateral^{(f) (g)}
(501 ) (1,828 ) (837 ) —
(3,166 ) (501 ) (1,828 ) (837 ) —
(3,166 )
Commodity derivative assets subtotal (12 )
289

833
—

1,110

(12 )
289

833
—

1,110
Interest rate and foreign currency derivative assets
Derivatives designated as hedging instruments —
—
—
—
—
—
10
—
—
10
Economic hedges 3
13
—
—
16
3
13
—
—
16
Effect of netting and allocation of collateral (3 ) (8 ) —
—
(11 ) (3 ) (8 ) —
—
(11 )
Interest rate and foreign currency derivative assets subtotal —

5

—
—

5

—

15

—
—

15
Other investments —
—
43
—
43
—
—
43
—
43
Total assets 6,145

3,282

1,564

3,370

14,361

7,115

3,352

1,585

3,370

15,422
Liabilities
Commodity derivative liabilities
Economic hedges (559 ) (2,062 ) (1,189 ) —
(3,810 ) (559 ) (2,062 ) (1,466 ) —
(4,087 )
Proprietary trading (3 ) (43 ) (27 ) —
(73 ) (3 ) (43 ) (27 ) —
(73 )
Effect of netting and allocation of collateral^{(f) (g)}
560
2,043
978
—
3,581
560
2,043
978
—
3,581
Commodity derivative liabilities subtotal (2 ) (62 ) (238 ) —
(302 ) (2 ) (62 ) (515 ) —
(579 )
Interest rate and foreign currency derivative liabilities
Economic hedges (2 ) (17 ) —
—
(19 ) (2 ) (17 ) —
—
(19 )
Effect of netting and allocation of collateral 2
8
—
—
10
2
8
—
—
10
Interest rate and foreign currency derivative liabilities subtotal —

(9 )
—
—

(9 )
—

(9 )
—
—

(9 )
Deferred compensation obligation —
(35 ) —
—
(35 ) —
(137 ) —
—
(137 )
Total liabilities (2 )
(106 )
(238 ) —

(346 )
(2 )
(208 )
(515 ) —

(725 )
Total net assets $ 6,143

$ 3,176

$ 1,326
$ 3,370

$ 14,015

$ 7,113

$ 3,144

$ 1,070
$ 3,370

$ 14,697

~~103~~

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— ~~(Continued)~~

(Dollars in millions, except per share data, unless otherwise noted)

Note 10 — Income Taxes

PHI and ACE have the following unrecognized tax benefits as of September 30, 2021 and December 31, 2020. Exelon's, Generation's, ComEd's, PECO's, BGE's, Pepco's, and DPL's amounts are not material.


	PHI		ACE
September 30, 2021	$	56	$	16
December 31, 2020	52		15

Reasonably possible the total amount of unrecognized tax benefits could significantly increase or decrease within 12 months after the reporting date

As of September 30, 2021, ACE has approximately $14 million of unrecognized state tax benefits that could significantly decrease within the 12 months after the reporting date based on the outcome of pending court cases involving other taxpayers. The unrecognized tax benefit, if recognized, may be included in future base rates and that portion would have no impact to the effective tax rate.

Other Income Tax Matters

CENG Put Option (Exelon and Generation)

On August 6, 2021, Generation and EDF entered into a settlement agreement pursuant to which Generation purchased EDF’s equity interest in CENG. Exelon and Generation recorded deferred tax liabilities of $290 million and $288 million, respectively, against Common Stock in Exelon’s Consolidated Balance Sheet and Membership Interest in Generation’s Consolidated Balance Sheet. The deferred tax liabilities represent the tax effect on the difference between the net purchase price and EDF’s noncontrolling interest as of August 6, 2021. The deferred tax liabilities will reverse during the remaining operating lives and during decommissioning of the CENG nuclear plants. See Note 2 – Mergers, Acquisitions, and Dispositions for additional information.

Long-Term Marginal State Income Tax Rate (All Registrants)

In the third quarter of 2021 and 2020, Exelon updated its marginal state income tax rates for changes in state apportionment. The changes in marginal rates in the third quarter of 2021 resulted in an increase of $27 million to the deferred income tax liability at Exelon, and a corresponding adjustment to income tax expense, net of federal taxes. The changes in marginal rates in the third quarter of 2020 resulted in an increase of $66 million and a decrease of $26 million to the deferred income tax liability at Exelon and Generation, respectively. Exelon and Generation recorded a corresponding adjustment to income tax expense, net of federal taxes.

Allocation of Tax Benefits (All Registrants)

Generation and the Utility Registrants are all party to an agreement with Exelon and other subsidiaries of Exelon that provides for the allocation of consolidated tax liabilities and benefits (Tax Sharing Agreement). The Tax Sharing Agreement provides that each party is allocated an amount of tax similar to that which would be owed had the party been separately subject to tax. In addition, any net benefit attributable to Exelon is reallocated to the other Registrants. That allocation is treated as a contribution to the capital of the party receiving the benefit.

The following table presents the allocation of federal tax benefits from Exelon under the Tax Sharing Agreement.


	Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
September 30, 2021	$	64	$	1	$	19	$	—	$	17	$	16	$	—	$	—
September 30, 2020	64		14		17		—		17		8		6		1

11. Retirement Benefits (All Registrants)

Defined Benefit Pension and OPEB

During the first quarter of 2021, Exelon received an updated valuation of its pension and OPEB to reflect actual census data as of January 1, 2021. This valuation resulted in an increase to the pension obligations of $33 million and a decrease to the OPEB obligations of $9 million. Additionally, accumulated other comprehensive loss

101

Generation Exelon
As of December 31, 2016 Level 1 Level 2 Level 3 Not subject to leveling Total Level 1
Level 2
Level 3 Not subject to leveling
Total
Assets
Cash equivalents^(a)
$ 39
$ —
$ —
$ —
$ 39
$ 373
$ —
$ —
$ —
$ 373
NDT fund investments

Cash equivalents^(b)
110
19
—
—
129
110
19
—
—
129
Equities 3,551

452

—

2,011

6,014

3,551

452

—

2,011

6,014
Fixed income
Corporate debt —
1,554
250
—
1,804
—
1,554
250
—
1,804
U.S. Treasury and agencies 1,291
29
—
—
1,320
1,291
29
—
—
1,320
Foreign governments —
37
—
—
37
—
37
—
—
37
State and municipal debt —
264
—
—
264
—
264
—
—
264
Other^(c)
—
59
—
493
552
—
59
—
493
552
Fixed income subtotal 1,291

1,943

250
493

3,977

1,291

1,943

250
493

3,977
Middle market lending —
—
427
71
498
—
—
427
71
498
Private equity —
—
—
148
148
—
—
—
148
148
Real estate —
—
—
326
326
—
—
—
326
326
NDT fund investments subtotal^(d)
4,952

2,414

677
3,049

11,092

4,952

2,414

677
3,049
11,092
Pledged assets for Zion Station decommissioning
Cash equivalents 11
—
—
—
11
11
—
—
—
11
Equities —
2
—
—
2
—
2
—
—
2
Fixed Income - U.S. Treasury and agencies 16
1
—
—
17
16
1
—
—
17
Middle market lending —
—
19
64
83
—
—
19
64
83
Pledged assets for Zion Station decommissioning subtotal^(e)
27

3

19
64

113

27

3

19
64

113
Rabbi trust investments
Cash equivalents 2
—
—
—
2
74
—
—
—
74
Mutual funds 19
—
—
—
19
50
—
—
—
50
Fixed income —
—
—
—
—
—
16
—
—
16
Life insurance contracts —
18
—
—
18
—
64
20
—
84
Rabbi trust investments subtotal 21

18

—
—

39

124

80

20
—

224
Commodity derivative assets
Economic hedges 1,356
2,505
1,229
—
5,090
1,358
2,505
1,229
—
5,092
Proprietary trading 3
50
23
—
76
3
50
23
—
76
Effect of netting and allocation of collateral^{(f) (g)}
(1,162 ) (2,142 ) (481 ) —
(3,785 ) (1,164 ) (2,142 ) (481 ) —
(3,787 )
Commodity derivative assets subtotal 197

413

771
—

1,381

197

413

771
—

1,381
Interest rate and foreign currency derivative assets

Derivatives designated as hedging instruments —
—
—
—
—
—
16
—
—
16
Economic hedges —
28
—
—
28
—
28
—
—
28
Proprietary trading 3
2
—
—
5
3
2
—
—
5
Effect of netting and allocation of collateral (2 ) (19 ) —
—
(21 ) (2 ) (19 ) —
—
(21 )
Interest rate and foreign currency derivative assets subtotal 1

11

—
—

12

1

27

—
—

28
Other investments —
—
42
—
42
—
—
42
—
42
Total assets 5,237

2,859

1,509
3,113

12,718

5,674

2,937

1,529
3,113

13,253

~~104~~

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— ~~(Continued)~~

(Dollars in millions, except per share data, unless otherwise noted)

Note 11 — Retirement Benefits

increased by $1 million (after-tax) and regulatory assets and liabilities increased by $21 million and $1 million, respectively.

The majority of the 2021 pension benefit cost for the Exelon-sponsored plans is calculated using an expected long-term rate of return on plan assets of 7.00% and a discount rate of 2.58%. The majority of the 2021 OPEB cost is calculated using an expected long-term rate of return on plan assets of 6.46% for funded plans and a discount rate of 2.51%.

A portion of the net periodic benefit cost for all plans is capitalized in the Consolidated Balance Sheets. The following table presents the components of Exelon's net periodic benefit costs, prior to capitalization, for the three and nine months ended September 30, 2021 and 2020.



	Pension Benefits				OPEB
	Three Months Ended September 30,				Three Months Ended September 30,
	2021		2020		2021		2020
Components of net periodic benefit cost:
Service cost	$	110	$	97	$	20	$	22
Interest cost	161		190		29		37
Expected return on assets	(335)		(317)		(40)		(41)
Amortization of:
Prior service cost (credit)	1		1		(8)		(30)
Actuarial loss	150		128		9		12
Settlement charges	12		8		—		—

Net periodic benefit cost	$	99	$	107	$	10	$	—



	Pension Benefits				OPEB
	Nine Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Components of net periodic benefit cost:
Service cost	$	330	$	290	$	60	$	67
Interest cost	481		569		86		114
Expected return on assets	(1,003)		(953)		(119)		(122)
Amortization of:
Prior service cost (credit)	3		3		(25)		(92)
Actuarial loss	449		384		27		36
Curtailment benefits	—		—		(1)		—
Settlement charges	16		14		—		—

Net periodic benefit cost	$	276	$	307	$	28	$	3

102

Generation Exelon
As of December 31, 2016 Level 1 Level 2 Level 3 Not subject to leveling Total Level 1
Level 2
Level 3 Not subject to leveling
Total
Liabilities

Commodity derivative liabilities
Economic hedges (1,267 ) (2,378 ) (794 ) —
(4,439 ) (1,267 ) (2,378 ) (1,052 ) —
(4,697 )
Proprietary trading (3 ) (50 ) (26 ) —
(79 ) (3 ) (50 ) (26 ) —
(79 )
Effect of netting and allocation of collateral^{(f) (g)}
1,233
2,339
542
—
4,114
1,233
2,339
542
—
4,114
Commodity derivative liabilities subtotal (37 )
(89 )
(278 ) —

(404 )
(37 )
(89 )
(536 ) —

(662 )
Interest rate and foreign currency derivative liabilities
Derivatives designated as hedging instruments —
(10 ) —
—
(10 ) —
(10 ) —
—
(10 )
Economic hedges —
(21 ) —
—
(21 ) —
(21 ) —
—
(21 )
Proprietary trading (4 ) —
—
—
(4 ) (4 ) —
—
—
(4 )
Effect of netting and allocation of collateral 4
19
—
—
23
4
19
—
—
23
Interest rate and foreign currency derivative liabilities subtotal —

(12 )
—
—

(12 )
—

(12 )
—
—

(12 )
Deferred compensation obligation —
(34 ) —
—
(34 ) —
(136 ) —
—
(136 )
Total liabilities (37 )
(135 )
(278 ) —

(450 )
(37 )
(237 )
(536 ) —

(810 )
Total net assets $ 5,200

$ 2,724

$ 1,231
$ 3,113

$ 12,268

$ 5,637

$ 2,700

$ 993
$ 3,113

$ 12,443

~~_________~~

~~(a)~~

Generation excludes cash of $282 million and $252 million at September 30, 2017 and December 31, 2016 and restricted cash of $184 million and $157 million at September 30, 2017 and December 31, 2016. Exelon excludes cash of $382 million and $360 million at September 30, 2017 and December 31, 2016 and restricted cash of $219 million and $180 million at September 30, 2017 and December 31, 2016 and includes long-term restricted cash of $22 million and $25 million at September 30, 2017 and December 31, 2016, which is reported in other deferred debits on the balance sheet.


~~(b)~~	Includes $75 million and $29 million of cash received from outstanding repurchase agreements at September 30, 2017 and December 31, 2016, respectively, and is offset by an obligation to repay upon settlement of the agreement as discussed in (d) below.

~~(c)~~

Includes derivative instruments of less than $1 million and $(2) million, which have a total notional amount of $885 million and $933 million at September 30, 2017 and December 31, 2016, 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 $52 million and $31 million at September 30, 2017 and December 31, 2016, 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 less than $1 million at September 30, 2017 and December 31, 2016. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases.

~~(f)~~

Collateral posted/(received) from counterparties totaled $59 million, $215 million and $141 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of September 30, 2017. Collateral posted/(received) from counterparties, net of collateral paid to counterparties, totaled $71 million, $197 million and $61 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2016.


~~(g)~~	Of the collateral posted/(received), $27 million represents variation margin on the exchanges as of September 30, 2017. Of the collateral posted/(received), $(158) million represents variation margin on the exchanges as of December 31, 2016.

~~105~~

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— ~~(Continued)~~

(Dollars in millions, except per share data, unless otherwise noted)

Note 11 — Retirement Benefits

~~ComEd, PECO and BGE~~

The ~~following tables present assets~~amounts below represent the Registrants' allocated pension and ~~liabilities measured~~OPEB costs. For Exelon, the service cost component is included in Operating and ~~recorded at fair value on ComEd's, PECO's~~maintenance expense and ~~BGE's Consolidated Balance Sheets on a recurring basis~~Property, plant, and equipment, net while the non-service cost components are included in Other, net and Regulatory assets. For Generation and the Utility Registrants, the service cost and non-service cost components are included in Operating and maintenance expense and Property, plant, and equipment, net in their ~~level within the fair value hierarchy as of September 30, 2017 and December 31, 2016:~~consolidated financial statements.


	Three Months Ended September 30,				Nine Months Ended September 30,
Pension and OPEB Costs	2021		2020		2021		2020
Exelon	$	109	$	107	$	304	$	310
Generation	36		30		92		89
ComEd	32		29		97		85
PECO	2		1		5		4
BGE	16		16		47		47
PHI	12		17		36		52
Pepco	2		4		5		11
DPL	1		2		2		6
ACE	3		3		8		10

ComEd PECO BGE
As of September 30, 2017 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets
Cash equivalents^(a)
$ 273
$ —
$ —
$ 273
$ 314
$ —
$ —
$ 314
$ 18
$ —
$ —
$ 18
Rabbi trust investments

Mutual funds —
—
—
—
7
—
—
7
5
—
—
5
Life insurance contracts —
—
—
—
—
10
—
10
—
—
—
—
Rabbi trust investments subtotal —

—

—

—

7

10

—

17

5

—

—

5
Total assets 273

—

—

273

321

10

—

331

23

—

—

23
Liabilities

Deferred compensation obligation —
(7 ) —
(7 ) —
(10 ) —
(10 ) —
(4 ) —
(4 )
Mark-to-market derivative liabilities^(b)
—
—
(277 ) (277 ) —
—
—
—
—
—
—
—
Total liabilities —
(7 ) (277 ) (284 ) —
(10 ) —
(10 ) —
(4 ) —
(4 )
Total net assets (liabilities) $ 273
$ (7 ) $ (277 ) $ (11 ) $ 321
$ —
$ —
$ 321
$ 23
$ (4 ) $ —
$ 19

ComEd PECO BGE
As of December 31, 2016 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets
Cash equivalents^(a)
$ 20
$ —
$ —
$ 20
$ 45
$ —
$ —
$ 45
$ 36
$ —
$ —
$ 36
Rabbi trust investments

Mutual funds —
—
—
—
7
—
—
7
4
—
—
4
Life insurance contracts —
—
—
—
—
10
—
10
—
—
—
—
Rabbi trust investments subtotal —

—

—

—

7

10

—

17

4

—

—

4
Total assets 20

—

—

20

52

10

—

62

40

—

—

40
Liabilities

Deferred compensation obligation —
(8 ) —
(8 ) —
(11 ) —
(11 ) —
(4 ) —
(4 )
Mark-to-market derivative liabilities^(b)
—
—
(258 ) (258 ) —
—
—
—
—
—
—
—
Total liabilities —
(8 ) (258 ) (266 ) —
(11 ) —
(11 ) —
(4 ) —
(4 )
Total net assets (liabilities) $ 20
$ (8 ) $ (258 ) $ (246 ) $ 52
$ (1 ) $ —
$ 51
$ 40
$ (4 ) $ —
$ 36

~~_________~~

~~(a)~~

ComEd excludes cash of $36 million at September 30, 2017 and December 31, 2016 and restricted cash of $2 million at December 31, 2016. PECO excludes cash of $20 million and $22 million at September 30, 2017 and December 31, 2016. BGE excludes cash of $11 million and $13 million at September 30, 2017 and December 31, 2016 and restricted cash of $1 million at September 30, 2017 and includes long-term restricted cash of $2 million at December 31, 2016, which is reported in other deferred debits on the balance sheet.


~~(b)~~	The Level 3 balance consists of the current and noncurrent liability of $20 million and $257 million, respectively, at September 30, 2017, and $19 million and $239 million, respectively, at December 31, 2016, related to floating-to-fixed energy swap contracts with unaffiliated suppliers.

~~106~~

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~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

~~PHI, Pepco, DPL and ACE~~Defined Contribution Savings Plans

The ~~following tables present assets~~Registrants participate in various 401(k) defined contribution savings plans that are sponsored by Exelon. The plans are qualified under applicable sections of the IRC and ~~liabilities measured and recorded at fair value on PHI's, Pepco's, DPL's and ACE's Consolidated Balance Sheets on~~allow employees to contribute a ~~recurring basis and~~portion of their ~~level within~~pre-tax and/or after-tax income in accordance with specified guidelines. All Registrants match a percentage of the ~~fair value hierarchy as of September 30, 2017 and December 31, 2016:~~

Successor
As of September 30, 2017 As of December 31, 2016
PHI Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets
Cash equivalents^(a)
$ 184
$ —
$ —
$ 184
$ 217
$ —
$ —
$ 217
Mark-to-market derivative assets^(b)
—
—
—
—
2
—
—
2
Effect of netting and allocation of collateral —
—
—
—
(2 ) —
—
(2 )
Mark-to-market derivative assets subtotal —
—
—
—
—
—
—
—
Rabbi trust investments

Cash equivalents 72
—
—
72
73
—
—
73
Fixed income —
13
—
13
—
16
—
16
Life insurance contracts —
23
21
44
—
22
20
42
Rabbi trust investments subtotal 72

36

21

129

73

38

20

131
Total assets 256

36

21

313
290

38

20

348
Liabilities

Deferred compensation obligation —
(24 ) —
(24 ) —
(28 ) —
(28 )
Total liabilities —

(24 )
—

(24 )
—

(28 )
—

(28 )
Total net assets $ 256

$ 12

$ 21

$ 289
$ 290

$ 10

$ 20

$ 320

Pepco DPL ACE
As of September 30, 2017 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets

Cash equivalents^(a)
$ 144
$ —
$ —
$ 144
$ —
$ —
$ —
$ —
$ 31
$ —
$ —
$ 31
Rabbi trust investments

Cash equivalents 43
—
—
43
—
—
—
—
—
—
—
—
Fixed income —
13
—
13
—
—
—
—
—
—
—
—
Life insurance contracts —
23
21
44
—
—
—
—
—
—
—
—
Rabbi trust investments subtotal 43

36

21

100

—

—

—

—

—

—

—

—
Total assets 187

36

21

244

—

—

—

—

31

—

—

31
Liabilities

Deferred compensation obligation —
(4 ) —
(4 ) —
(1 ) —
(1 ) —
—
—
—
Total liabilities —

(4 )
—

(4 )
—

(1 )
—

(1 )
—

—

—

—
Total net assets (liabilities) $ 187
$ 32
$ 21
$ 240
$ —
$ (1 ) $ —
$ (1 ) $ 31
$ —
$ —
$ 31

~~107~~

~~Table of Contents~~

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

Pepco DPL ACE
As of December 31, 2016 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets

Cash equivalents^(a)
$ 33
$ —
$ —
$ 33
$ 42
$ —
$ —
$ 42
$ 130
$ —
$ —
$ 130
Mark-to-market derivative assets^(b)
—
—
—
—
2
—
—
2
—
—
—
—
Effect of netting and allocation of collateral —
—
—
—
(2 ) —
—
(2 ) —
—
—
—
Mark-to-market derivative assets subtotal —
—
—
—
—
—
—
—
—
—
—
—
Rabbi trust investments
Cash equivalents 43
—
—
43
—
—
—
—
—
—
—
—
Fixed income —
16
—
16
—
—
—
—
—
—
—
—
Life insurance contracts —
22
19
41
—
—
—
—
—
—
—
—
Rabbi trust investments subtotal 43

38

19

100

—

—

—

—

—

—

—

—
Total assets 76

38

19

133

42

—

—

42

130

—

—

130
Liabilities
Deferred compensation obligation —
(5 ) —
(5 ) —
(1 ) —
(1 ) —
—
—
—
Total liabilities —
(5 ) —
(5 ) —
(1 ) —
(1 ) —
—
—
—
Total net assets (liabilities) $ 76
$ 33
$ 19

$ 128
$ 42
$ (1 ) $ —
$ 41
$ 130
$ —
$ —
$ 130

~~_________~~

~~(a)~~

PHI excludes cash of $18 million and $19 million at September 30, 2017 and December 31, 2016 and includes long-term restricted cash of $22 million and $23 million at September 30, 2017 and December 31, 2016 which is reported in other deferred debits on the balance sheet. Pepco excludes cash of $7 million and $9 million at September 30, 2017 and December 31, 2016. DPL excludes cash of $3 million and $4 million at September 30, 2017 and December 31, 2016. ACE excludes cash of $5 million and $3 million at September 30, 2017 and December 31, 2016 and includes long-term restricted cash of $22 million and $23 million at September 30, 2017 and December 31, 2016 which is reported in other deferred debits on the balance sheet.


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

employee contributions up to certain limits. The following ~~tables present~~table presents the ~~fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during~~matching contributions to the savings plans for the three and nine months ended September 30, ~~2017~~2021 and ~~2016:~~2020, respectively.


	Three Months Ended September 30,				Nine Months Ended September 30,
Savings Plans Matching Contributions	2021		2020		2021		2020
Exelon	$	38	$	37	$	107	$	104
Generation	14		14		40		41
ComEd	9		9		27		25
PECO	2		3		8		8
BGE	4		4		8		8
PHI	5		3		12		9
Pepco	1		1		3		3
DPL	1		1		3		2
ACE	1		—		2		1

Successor
Generation ComEd PHI Exelon
Three Months Ended September 30, 2017
NDT Fund
Investments

Pledged Assets
for Zion Station
Decommissioning

Mark-to-Market
Derivatives

Other
Investments
Total Generation
Mark-to-Market
Derivatives
Life Insurance Contracts Eliminated in Consolidation Total
Balance as of June 30, 2017 $ 683
$ 21
$ 589
$ 41
$ 1,334
$ (256 ) $ 20
$ —
$ 1,098
Total realized / unrealized gains (losses)

Included in net income —
—
(82 )
^(a)
1
(81 ) —
1
—
(80 )
Included in payable for Zion Station decommissioning —
(4 ) —
—
(4 ) —
—
—
(4 )
Included in regulatory assets —
—
—
—
—
(21 )
^(b)
—
—
(21 )
Change in collateral —
—
11
—
11
—
—
—
11
Purchases, sales, issuances and settlements

Purchases 19
—
57
1
77
—
—
—
77
Settlements (31 ) —
10
^(c)
—
(21 ) —
—
—
(21 )
Transfers out of Level 3 —
—
10
—
10
—
—
—
10
Balance at September 30, 2017 $ 671
$ 17
$ 595
$ 43
$ 1,326
$ (277 ) $ 21
$ —
$ 1,070
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2017 $ —
$ —
$ 24
$ 1
$ 25
$ —
$ 1
$ —
$ 26

~~108~~

~~Table of Contents~~

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

Successor
Generation ComEd PHI Exelon
Nine Months Ended September 30, 2017
NDT Fund
Investments

Pledged Assets
for Zion Station
Decommissioning

Mark-to-Market
Derivatives

Other
Investments
Total Generation
Mark-to-Market
Derivatives
Life Insurance Contracts Eliminated in Consolidation �� Total
Balance as of December 31, 2016 $ 677
$ 19
$ 493
$ 42
$ 1,231
$ (258 ) $ 20
$ —
$ 993
Total realized / unrealized gains (losses)

Included in net income 4
—
(110 )
^(a)
2
(104 ) —
2
—
(102 )
Included in noncurrent payables to affiliates 13
—
—
—
13
—
—
(13 ) —
Included in payable for Zion Station decommissioning —
(3 ) —
—
(3 ) —
—
—
(3 )
Included in regulatory assets —
—
—
—
—
(19 )
^(b)
—
13
(6 )
Change in collateral —
—
81
—
81
—
—
—
81
Purchases, sales, issuances and settlements

Purchases 54
1
146
4
205
—
—
—
205
Sales —
—
(15 ) —
(15 ) —
—
—
(15 )
Issuances —
—
—
—
—
—
(1 ) —
(1 )
Settlements (77 ) —
(8 )
^(c)
—
(85 ) —
—
—
(85 )
Transfers into Level 3 —
—
(9 ) —
(9 ) —
—
—
(9 )
Transfers out of Level 3 —
—
17
(5 ) 12
—
—
—
12
Balance as of September 30, 2017 $ 671
$ 17

$ 595
$ 43
$ 1,326
$ (277 ) $ 21
$ —
$ 1,070
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2017 $ 2
$ —
$ 161
$ 2
$ 165
$ —
$ 2
$ —
$ 167

~~_________~~


~~(a)~~	~~Includes a reduction for the reclassification of $96 million and $279 million of realized gains due to the settlement of derivative contracts for the three and nine months ended September 30, 2017.~~

~~(b)~~

Includes $24 million of decreases in fair value and an increase for realized losses due to settlements of $3 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended September 30, 2017. Includes $32 million of decreases in fair value and an increase for realized losses due to settlements of $13 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the nine months ended September 30, 2017.


~~(c)~~	~~Exelon includes the settlement value for any open contracts that were net settled prior to their scheduled maturity within this line item.~~

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~~(Dollars in millions, except per share data, unless otherwise noted)~~

Successor
Generation ComEd PHI Exelon
Three Months Ended September 30, 2016
NDT Fund
Investments

Pledged Assets
for Zion Station
Decommissioning

Mark-to-Market
Derivatives

Other
Investments
Total Generation
Mark-to-Market
Derivatives
Life Insurance Contracts Eliminated in Consolidation Total
Balance as of June 30, 2016 $ 715
$ 25
$ 609
$ 37
$ 1,386
$ (221 ) $ 20
$ —
$ 1,185
Total realized / unrealized gains (losses)

Included in net income (4 ) —
95
^(a)
1
92
—
1
—
93
Included in noncurrent payables to affiliates 6
—
—
—
6
—
—
(6 ) —
Included in payable for Zion Station decommissioning —
(1 ) —
—
(1 ) —
—
—
(1 )
Included in regulatory assets —
—
—
—
—
(23 )
^(b)
—
6
(17 )
Change in collateral —
—
31
—
31
—
—
—
31
Purchases, sales, issuances and settlements

Purchases 4
—
207
^(c)
3
214
—
—
—
214
Sales —
(5 ) (2 ) —
(7 ) —
—
—
(7 )
Issuances —
—
—
—
—
—
—
—
—
Settlements (28 ) —
—
—
(28 ) —
—
—
(28 )
Transfers into Level 3 —
—
(1 ) 1
—
—
—
—
—
Transfers out of Level 3 —
—
(4 ) —
(4 ) —
—
—
(4 )
Balance as of September 30, 2016 $ 693

$ 19

$ 935

$ 42

$ 1,689

$ (244 )
$ 21
$ —

$ 1,466
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2016 $ 3
$ —
$ 285
$ —
$ 288
$ —
$ —
$ —
$ 288

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~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

Successor
Generation ComEd
PHI^(d)
Exelon
Nine Months Ended September 30, 2016
NDT Fund
Investments

Pledged Assets
for Zion Station
Decommissioning

Mark-to-Market
Derivatives

Other
Investments
Total Generation
Mark-to-Market
Derivatives
Life Insurance Contracts Eliminated in Consolidation Total
Balance as of December 31, 2015 $ 670
$ 22
$ 1,051
$ 33
$ 1,776
$ (247 ) $ —
$ —
$ 1,529
Included due to merger —
—
—
—
—
—
20
—
20
Total realized / unrealized gains (losses)

Included in net income 2
—
(339 )
^(a)
1
(336 ) —
2
—
(334 )
Included in noncurrent payables to affiliates 18
—
—
—
18
—
—
(18 ) —
Included in payable for Zion Station decommissioning —
1
—
—
1
—
—
—
1
Included in regulatory assets —
—
—
—
—
3
^(b)
—
18
21
Change in collateral —
—
(51 ) —
(51 ) —
—
—
(51 )
Purchases, sales, issuances and settlements

Purchases 123
1
289
^(c)
7
420
—
—
—
420
Sales (1 ) (5 ) (5 ) —
(11 ) —
—
—
(11 )
Issuances —
—
—
—
—
—
(1 ) —
(1 )
Settlements (119 ) —
—
—
(119 ) —
—
—
(119 )
Transfers into Level 3 —
—
1
1
2
—
—
—
2
Transfers out of Level 3 —
—
(11 ) —
(11 ) —
—
—
(11 )
Balance as of September 30, 2016 $ 693
$ 19
$ 935
$ 42
$ 1,689

$ (244 ) $ 21
$ —
$ 1,466
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2016 $ 7
$ —
$ 240
$ —
$ 247
$ —
$ 1
$ —
$ 248

~~_________~~


~~(a)~~	Includes a reduction for the reclassification of $190 million and $579 million of realized gains due to the settlement of derivative contracts recorded in results of operations for the three and nine months ended September 30, 2016.

~~(b)~~

Includes $25 million of decreases in fair value and an increase for realized losses due to settlements of $2 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended September 30, 2016. Includes $10 million of decreases in fair value and an increase for realized losses due to settlements of $13 million for the nine months ended September 30, 2016.


~~(c)~~	~~Includes $168 million of fair value from contracts acquired as a result of portfolio acquisitions.~~


~~(d)~~	Successor period represents activity from March 24, 2016 through September 30, 2016. See tables below for PHI's predecessor periods, as well as activity for Pepco for the three and nine months ended September 30, 2017 and 2016.

Predecessor
January 1, 2016 to March 23, 2016
PHI Preferred Stock Life Insurance Contracts
Beginning Balance $ 18
$ 19
Total realized / unrealized gains (losses)
Included in net income (18 ) 1
Ending Balance
$ —
$ 20
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities for the period $ —
$ 1

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~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

Life Insurance Contracts
Three Months Ended
September 30, Nine Months Ended
September 30,
Pepco 2017 2016 2017 2016
Beginning balance $ 20
$ 20
$ 20
$ 19
Total realized / unrealized gains (losses)
Included in net income 1
1
2
3
Purchases, sales, issuances and settlements
Issuances —
—
(1 ) (1 )
Ending balance $ 21

$ 21
$ 21

$ 21
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities for the period $ 1
$ —
$ 2
$ 2

The following tables present the income statement classification of the total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis during the three and nine months ended September 30, 2017 and 2016:

Successor
Generation PHI Exelon
Operating
Revenues Purchased
Power and
Fuel
Other, net^(a)

Other, net^(a)
Operating
Revenues Purchased
Power and
Fuel
Other, net^(a)
Total gains (losses) included in net income for the three months ended September 30, 2017 $ (3 ) $ (69 ) $ 1
$ 1
$ (3 ) $ (69 ) $ 2
Total gains (losses) included in net income for the nine months ended September 30, 2017 34
(152 ) 6
2
34
(152 ) 8
Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended September 30, 2017 47
(23 ) 1
1
47
(23 ) 2
Change in the unrealized gains (losses) relating to assets and liabilities held for the nine months ended September 30, 2017 222
(61 ) 4
2
222
(61 ) 6

Successor
Generation PHI Exelon

Operating
Revenues

Purchased
Power and
Fuel

Other, net^(a)

Other, net^(a)

Operating
Revenues

Purchased
Power and
Fuel

Other, net^(a)
Total gains (losses) included in net income for the three months ended September 30, 2016 $ 180
$ (85 ) $ (4 ) $ 1
$ 180
$ (85 ) $ (3 )
Total gains (losses) included in net income for the nine months ended September 30, 2016 (232 ) (107 ) 2
2
(232 ) (107 ) 4
Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended September 30, 2016 323
(38 ) 3
—
323
(38 ) 3
Change in the unrealized gains (losses) relating to assets and liabilities held for the nine months ended September 30, 2016 303
(63 ) 7
1
303
(63 ) 8

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~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

Predecessor
PHI Pepco
January 1, 2016 to March 23, 2016 Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016

Other, net^(a)

Other, net^(a)

Total gains (losses) included in net income $ (17 ) $ 1
$ 1
$ 2
$ 3
Change in the unrealized gains (losses) relating to assets and liabilities held 1
1
—
2
2

~~_________~~


~~(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.

~~Valuation Techniques Used to Determine Fair Value~~

~~The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the tables above.~~

~~Cash Equivalents (Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE).~~ The Registrants’ cash equivalents include investments with original maturities of three months or less when purchased. The cash equivalents shown in the fair value tables are comprised of investments in mutual and money market funds. The fair values of the shares of these funds are based on observable market prices and, therefore, have been categorized in Level 1 in the fair value hierarchy.

~~Preferred Stock Derivative (PHI).~~ In connection with entering into the PHI Merger Agreement, PHI entered into a Subscription Agreement with Exelon dated April 29, 2014, pursuant to which PHI issued to Exelon shares of Preferred stock. The Preferred stock contained embedded features requiring separate accounting consideration to reflect the potential value to PHI that any issued and outstanding Preferred stock could be called and redeemed at a nominal par value upon a termination of the merger agreement under certain circumstances due to the failure to obtain required regulatory approvals. The embedded call and redemption features on the shares of the Preferred stock in the event of such a termination were separately accounted for as derivatives. These Preferred stock derivatives were valued quarterly using quantitative and qualitative factors, including management’s assessment of the likelihood of a Regulatory Termination and therefore, were categorized in Level 3 in the fair value hierarchy. As a result of the PHI Merger, the PHI Preferred stock derivative was reduced to zero as of March 23, 2016. The write-off was charged to Other, net on the PHI Consolidated Statement of Operations and Comprehensive Income.

~~Nuclear Decommissioning Trust Fund Investments and Pledged Assets for Zion Station Decommissioning (Exelon and Generation).~~ The trust fund investments have been established to satisfy Generation’s and CENG's nuclear decommissioning obligations as required by the NRC. The NDT funds hold debt and equity securities directly and indirectly through commingled funds and mutual funds, which are included in Equities and Fixed Income. Generation’s and CENG's NDT fund investments policies outline investment guidelines for the trusts and limit the trust funds’ exposures to investments in highly illiquid markets and other alternative investments. Investments with maturities of three months or less when purchased, including certain short-term fixed income securities are considered cash equivalents and included in the recurring fair value measurements hierarchy as Level 1 or Level 2.

With respect to individually held equity securities, the trustees obtain prices from pricing services, whose prices are generally obtained from direct feeds from market exchanges, which Generation is able to independently corroborate. The fair values of equity securities held directly by the trust funds which are based on quoted prices in active markets are categorized in Level 1. Certain equity securities have been categorized as Level 2 because they are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities. Equity securities held individually are primarily traded on the New York Stock Exchange and NASDAQ-Global Select Market, which contain only actively traded securities due to the volume trading requirements imposed by these exchanges.

For fixed income securities, multiple prices from pricing services are obtained whenever possible, which enables cross-provider validations in addition to checks for unusual daily movements. A primary price source is identified based on asset type, class or issue for each security. With respect to individually held fixed income securities, the trustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the portfolio managers challenge an assigned price and the trustees determine that another

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~~(Dollars in millions, except per share data, unless otherwise noted)~~

price source is considered to be preferable. Generation has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, Generation selectively corroborates the fair values of securities by comparison to other market-based price sources. U.S. Treasury securities are categorized as Level 1 because they trade in a highly liquid and transparent market. The fair values of fixed income securities, excluding U.S. Treasury securities, are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities, adjusted for observable differences and are categorized in Level 2. The fair values of private placement fixed income securities, which are included in Corporate debt, are determined using a third party valuation that contains significant unobservable inputs and are categorized in Level 3.

Equity and fixed income commingled funds and mutual funds are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives such as holding short-term fixed income securities or tracking the performance of certain equity indices by purchasing equity securities to replicate the capitalization and characteristics of the indices. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized as Level 1. For commingled funds and mutual funds, which are not publicly quoted, the funds are valued using NAV as a practical expedient for fair value, which is primarily derived from the quoted prices in active markets on the underlying securities, and are not classified within the fair value hierarchy. These investments typically can be redeemed monthly with 30 or less days of notice and without further restrictions.

Derivative instruments consisting primarily of futures and interest rate swaps to manage risk are recorded at fair value. Over the counter derivatives are valued daily based on quoted prices in active markets and trade in open markets, and have been categorized as Level 1. Derivative instruments other than over the counter derivatives are valued based on external price data of comparable securities and have been categorized as Level 2.

Middle market lending are investments in loans or managed funds which lend to private companies. Generation elected the fair value option for its investments in certain limited partnerships that invest in middle market lending managed funds. The fair value of these loans is determined using a combination of valuation models including cost models, market models and income models. Investments in loans are categorized as Level 3 because the fair value of these securities is based largely on inputs that are unobservable and utilize complex valuation models. Managed funds are valued using NAV or its equivalent as a practical expedient, and therefore, are not classified within the fair value hierarchy. Investments in middle market lending typically cannot be redeemed until maturity of the term loan.

Private equity and real estate investments include those in limited partnerships that invest in operating companies and real estate holding companies that are not publicly traded on a stock exchange, such as, leveraged buyouts, growth capital, venture capital, distressed investments, investments in natural resources, and direct investments in pools of real estate properties. The fair value of private equity and real estate investments is determined using NAV or its equivalent as a practical expedient, and therefore, are not classified within the fair value hierarchy. These investments typically cannot be redeemed and are generally liquidated over a period of 8 to 10 years from the initial investment date. Private equity and real estate valuations are reported by the fund manager and are based on the valuation of the underlying investments, which include inputs such as cost, operating results, discounted future cash flows, market based comparable data, and independent appraisals from sources with professional qualifications. These valuation inputs are unobservable.

~~As of September 30, 2017, Generation has outstanding commitments to invest in fixed income, middle market lending, private equity and real estate investments of approximately $75 million~~, ~~$285 million,$240 million, and$95 million, respectively. These commitments will be funded by Generation’s existing nuclear decommissioning trust funds.~~

~~Concentrations of Credit Risk~~. Generation evaluated its NDT portfolios for the existence of significant concentrations of credit risk as of September 30, 2017. Types of concentrations that were evaluated include, but are not limited to, investment concentrations in a single entity, type of industry, foreign country, and individual fund. As of September 30, 2017, there were no significant concentrations (generally defined as greater than 10 percent) of risk in Generation's NDT assets.

~~See Note 13 — Nuclear Decommissioning for further discussion on the NDT fund investments.~~

~~Rabbi Trust Investments (Exelon, Generation, PECO, BGE, PHI, Pepco, DPL and ACE).~~ The Rabbi trusts were established to hold assets related to deferred compensation plans existing for certain active and retired members of Exelon’s executive management and directors. The Rabbi trusts assets are included in investments in the Registrants’ Consolidated Balance Sheets and consist primarily of money market funds, mutual funds, fixed income securities and

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~~(Dollars in millions, except per share data, unless otherwise noted)~~

life insurance policies. The mutual funds are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives, which are consistent with Exelon’s overall investment strategy. Money market funds and mutual funds are publicly quoted and have been categorized as Level 1 given the clear observability of the prices. The fair values of fixed income securities are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities, adjusted for observable differences and are categorized in Level 2. The life insurance policies are valued using the cash surrender value of the policies, net of loans against those policies, which is provided by a third-party. Certain life insurance policies, which consist primarily of mutual funds that are priced based on observable market data, have been categorized as Level 2 because the life insurance policies can be liquidated at the reporting date for the value of the underlying assets. Life insurance policies that are valued using unobservable inputs have been categorized as Level 3.

~~Mark-to-Market Derivatives (Exelon, Generation, ComEd, PHI and DPL)~~.Derivative contracts are traded in both exchange-based and non-exchange-based markets. Exchange-based derivatives that are valued using unadjusted quoted prices in active markets are categorized in Level 1 in the fair value hierarchy. Certain derivatives’ pricing is verified using indicative price quotations available through brokers or over-the-counter, on-line exchanges and are categorized in Level 2. These price quotations reflect the average of the bid-ask, mid-point prices and are obtained from sources that the Registrants believe provide the most liquid market for the commodity. The price quotations are reviewed and corroborated to ensure the prices are observable and representative of an orderly transaction between market participants. This includes consideration of actual transaction volumes, market delivery points, bid-ask spreads and contract duration. The remainder of derivative contracts are valued using the Black model, an industry standard option valuation model. The Black model takes into account inputs such as contract terms, including maturity, and market parameters, including assumptions of the future prices of energy, interest rates, volatility, credit worthiness and credit spread. For derivatives that trade in liquid markets, such as generic forwards, swaps and options, model inputs are generally observable. Such instruments are categorized in Level 2. The Registrants’ derivatives are predominantly at liquid trading points. For derivatives that trade in less liquid markets with limited pricing information model inputs generally would include both observable and unobservable inputs. These valuations may include an estimated basis adjustment from an illiquid trading point to a liquid trading point for which active price quotations are available. Such instruments are categorized in Level 3.

Exelon may utilize fixed-to-floating interest rate swaps, which are typically designated as fair value hedges, as a means to achieve its targeted level of variable-rate debt as a percent of total debt. In addition, the Registrants may utilize interest rate derivatives to lock in interest rate levels in anticipation of future financings. These interest rate derivatives are typically designated as cash flow hedges. Exelon determines the current fair value by calculating the net present value of expected payments and receipts under the swap agreement, based on and discounted by the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk and other market parameters. As these inputs are based on observable data and valuations of similar instruments, the interest rate swaps are categorized in Level 2 in the fair value hierarchy. See Note 10 - Derivative Financial Instruments for further discussion on mark-to-market derivatives.

~~Deferred Compensation Obligations (Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE).~~ The Registrants’ deferred compensation plans allow participants to defer certain cash compensation into a notional investment account. The Registrants include such plans in other current and noncurrent liabilities in their Consolidated Balance Sheets. The value of the Registrants’ deferred compensation obligations is based on the market value of the participants’ notional investment accounts. The underlying notional investments are comprised primarily of equities, mutual funds, commingled funds, and fixed income securities which are based on directly and indirectly observable market prices. Since the deferred compensation obligations themselves are not exchanged in an active market, they are categorized as Level 2 in the fair value hierarchy.

The value of certain employment agreement obligations (which are included with the Deferred Compensation Obligation in the tables above) are based on a known and certain stream of payments to be made over time and are categorized as Level 2 within the fair value hierarchy.

~~Additional Information Regarding Level 3 Fair Value Measurements (Exelon, Generation, ComEd, PHI, Pepco, DPL and ACE)~~

~~Mark-to-Market Derivatives (Exelon, Generation and ComEd).~~ For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations whose contract tenure extends into unobservable periods. In instances where observable data is unavailable, consideration is given to the

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~~(Dollars in millions, except per share data, unless otherwise noted)~~

assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility and contract duration. Such instruments are categorized in Level 3 as the model inputs generally are not observable. Exelon’s RMC approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of risk exposures. The RMC is chaired by the chief executive officer and includes the chief risk officer, chief strategy officer, chief executive officer of Exelon Utilities, chief commercial officer, chief financial officer and chief executive officer of Constellation. The RMC reports to the Finance and Risk Committee of the Exelon Board of Directors on the scope of the risk management activities. Forward price curves for the power market utilized by the front office to manage the portfolio, are reviewed and verified by the middle office, and used for financial reporting by the back office. The Registrants consider credit and nonperformance risk in the valuation of derivative contracts categorized in Level 2 and 3, including both historical and current market data in its assessment of credit and nonperformance risk by counterparty. Due to master netting agreements and collateral posting requirements, the impacts of credit and nonperformance risk were not material to the financial statements.

Disclosed below is detail surrounding the Registrants’ significant Level 3 valuations. The calculated fair value includes marketability discounts for margining provisions and other attributes. Generation’s Level 3 balance generally consists of forward sales and purchases of power and natural gas and certain transmission congestion contracts. Generation utilizes various inputs and factors including market data and assumptions that market participants would use in pricing assets or liabilities as well as assumptions about the risks inherent in the inputs to the valuation technique. The inputs and factors include forward commodity prices, commodity price volatility, contractual volumes, delivery location, interest rates, credit quality of counterparties and credit enhancements.

For commodity derivatives, the primary input to the valuation models is the forward commodity price curve for each instrument. Forward commodity price curves are derived by risk management for liquid locations and by the traders and portfolio managers for illiquid locations. All locations are reviewed and verified by risk management considering published exchange transaction prices, executed bilateral transactions, broker quotes, and other observable or public data sources. The relevant forward commodity curve used to value each of the derivatives depends on a number of factors, including commodity type, delivery location, and delivery period. Price volatility varies by commodity and location. When appropriate, Generation discounts future cash flows using risk free interest rates with adjustments to reflect the credit quality of each counterparty for assets and Generation’s own credit quality for liabilities. The level of observability of a forward commodity price varies generally due to the delivery location and delivery period. Certain delivery locations including PJM West Hub (for power) and Henry Hub (for natural gas) are more liquid and prices are observable for up to three years in the future. The observability period of volatility is generally shorter than the underlying power curve used in option valuations. The forward curve for a less liquid location is estimated by using the forward curve from the liquid location and applying a spread to represent the cost to transport the commodity to the delivery location. This spread does not typically represent a majority of the instrument’s market price. As a result, the change in fair value is closely tied to liquid market movements and not a change in the applied spread. The change in fair value associated with a change in the spread is generally immaterial. An average spread calculated across all Level 3 power and gas delivery locations is approximately $2.93 and $0.41 for power and natural gas, respectively. Many of the commodity derivatives are short-term in nature and thus a majority of the fair value may be based on observable inputs even though the contract as a whole must be classified as Level 3.

On December 17, 2010, ComEd entered into several 20-year floating to fixed energy swap contracts with unaffiliated suppliers for the procurement of long-term renewable energy and associated RECs. See Note 10 —Derivative Financial Instruments for more information. The fair value of these swaps has been designated as a Level 3 valuation due to the long tenure of the positions and internal modeling assumptions. The modeling assumptions include using natural gas heat rates to project long term forward power curves adjusted by a renewable factor that incorporates time of day and seasonality factors to reflect accurate renewable energy pricing. In addition, marketability reserves are applied to the positions based on the tenor and supplier risk.

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~~(Dollars in millions, except per share data, unless otherwise noted)~~

~~The table below discloses the significant inputs to the forward curve used to value these positions.~~

Type of trade Fair Value at September 30, 2017
Valuation
Technique

Unobservable
Input
Range
Mark-to-market derivatives — Economic Hedges (Exelon and Generation)^(a)(b)
$ 439
Discounted
Cash Flow Forward power
price $7 - $124

Forward gas
price $1.84 - $9.43

Option Model Volatility
percentage 9% - 114%

Mark-to-market derivatives — Proprietary trading (Exelon and Generation)^(a)(b)
$ 15
Discounted
Cash Flow Forward power
price $12 - $69

Mark-to-market derivatives (Exelon and ComEd) $ (277 ) Discounted
Cash Flow
Forward heat
rate^(c)
9x - 10x
Marketability
reserve 3% - 8%
Renewable
factor 88% - 125%

~~_________~~


~~(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 $141 million as of September 30, 2017.~~


~~(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.

Type of trade Fair Value at December 31, 2016
Valuation
Technique

Unobservable
Input
Range
Mark-to-market derivatives — Economic Hedges (Exelon and Generation)^(a)(b)
$ 435
Discounted
Cash Flow Forward power price $11 - $130

Forward gas price $1.72 - $9.20

Option Model Volatility percentage 8% - 173%

Mark-to-market derivatives — Proprietary trading (Exelon and Generation)^(a)(b)
$ (3 ) Discounted
Cash Flow Forward power price $19 - $79

Mark-to-market derivatives (Exelon and ComEd) $ (258 ) Discounted Cash Flow
Forward heat
rate^(c)
8x - 9x
Marketability reserve 3% - 8%
Renewable factor 89% - 121%

~~_________~~


~~(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 $61 million as of December 31, 2016.~~


~~(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.

The inputs listed above would have a direct impact on the fair values of the above instruments if they were adjusted. The significant unobservable inputs used in the fair value measurement of Generation’s commodity derivatives are forward commodity prices and for options is price volatility. Increases (decreases) in the forward commodity price in isolation would result in significantly higher (lower) fair values for long positions (contracts that give Generation the obligation or option to purchase a commodity), with offsetting impacts to short positions (contracts that give Generation the obligation or right to sell a commodity). Increases (decreases) in volatility would increase (decrease) the value for the holder of the option (writer of the option). Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of volatility of prices. An increase to the reserves listed above would decrease

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~~(Dollars in millions, except per share data, unless otherwise noted)~~

the fair value of the positions. An increase to the heat rate or renewable factors would increase the fair value accordingly. Generally, interrelationships exist between market prices of natural gas and power. As such, an increase in natural gas pricing would potentially have a similar impact on forward power markets.

~~Nuclear Decommissioning Trust Fund Investments and Pledged Assets for Zion StationDecommissioning (Exelon and Generation).~~ For middle market lending and certain corporate debt securities investments, the fair value is determined using a combination of valuation models including cost models, market models and income models. The valuation estimates are based on discounting the forecasted cash flows, market-based comparable data, credit and liquidity factors, as well as other factors that may impact value. Significant judgment is required in the application of discounts or premiums applied for factors such as size, marketability, credit risk and relative performance.

Because Generation relies on third-party fund managers to develop the quantitative unobservable inputs without adjustment for the valuations of its Level 3 investments, quantitative information about significant unobservable inputs used in valuing these investments is not reasonably available to Generation. This includes information regarding the sensitivity of the fair values to changes in the unobservable inputs. Generation gains an understanding of the fund managers’ inputs and assumptions used in preparing the valuations. Generation performed procedures to assess the reasonableness of the valuations.

~~Rabbi Trust Investments - Life insurance contracts (Exelon, PHI, Pepco, DPL and ACE).~~ ~~For~~life insurance policies categorized as Level 3, the fair value is determined based on the cash surrender value of the policy, which contains unobservable inputs and assumptions. Because Exelon relies on its third-party insurance provider to develop the inputs without adjustment for the valuations of its Level 3 investments, quantitative information about significant unobservable inputs used in valuing these investments is not reasonably available to Exelon. Exelon gains an understanding of the types of inputs and assumptions used in preparing the valuations and performs procedures to assess the reasonableness of the valuations.

~~10.~~12. Derivative Financial Instruments (All Registrants)

The Registrants use derivative instruments to manage commodity price risk, ~~foreign currency exchange~~interest rate risk, and ~~interest rate~~foreign exchange risk related to ongoing business operations.

Authoritative guidance requires that derivative instruments be recognized as either assets or liabilities at fair value, with changes in fair value of the derivative recognized in earnings immediately. Other accounting treatments are available through special election and designation, provided they meet specific, restrictive criteria both at the time of designation and on an ongoing basis. These alternative permissible accounting treatments include NPNS, cash flow hedges, and fair value hedges. All derivative economic hedges related to commodities, referred to as economic hedges, are recorded at fair value through earnings at Generation and are offset by a corresponding regulatory asset or liability at ComEd. For all NPNS derivative instruments, accounts receivable or accounts payable are recorded when derivatives settle and revenue or expense is recognized in earnings as the underlying physical commodity is sold or consumed.

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(Dollars in millions, except per share data, unless otherwise noted)

Note 12 — Derivative Financial Instruments

Authoritative guidance about offsetting assets and liabilities requires the fair value of derivative instruments to be shown in the Combined Notes to Consolidated Financial Statements on a gross basis, even when the derivative instruments are subject to legally enforceable master netting agreements and qualify for net presentation in the Consolidated Balance Sheets. A master netting agreement is an agreement between two counterparties that may have derivative and non-derivative contracts with each other providing for the net settlement of all referenced contracts via one payment stream, which takes place as the contracts deliver, when collateral is requested or in the event of default. In the tables below, which present fair value balances, Generation’s energy-related economic hedges and proprietary trading derivatives are shown gross. The impact of the netting of fair value balances with the same counterparty that are subject to legally enforceable master netting agreements, as well as netting of cash collateral, including margin on exchange positions, is aggregated in the collateral and netting columns.

Generation’s and ComEd’s use of cash collateral is generally unrestricted unless Generation or ComEd are downgraded below investment grade. Cash collateral held by PECO, BGE, Pepco, DPL, and ACE must be deposited in an unaffiliated major U.S. commercial bank or foreign bank with a U.S. branch office that meet certain qualifications.

Commodity Price Risk (All Registrants)

To the extent the amount of energy Generation produces differs from the amount of energy it has contracted to sell, Exelon and Generation are exposed to market fluctuations in the prices of electricity, fossil fuels, and other commodities. Each of the Registrants employ established policies and procedures to manage their risks associated with market fluctuations in commodity prices by entering into physical and financial derivative contracts, including swaps, futures, forwards, options, and short-term and long-term commitments to purchase and sell energy and ~~energy-related~~commodity products. The Registrants believe these instruments, which are either determined to be non-derivative or classified as ~~either~~ economic hedges, ~~or non-derivatives,~~ mitigate exposure to fluctuations in commodity prices.

~~Derivative accounting guidance requires that derivative instruments be recognized as either assets or liabilities at fair value, with changes in fair value of~~Generation. To the ~~derivative recognized in earnings each period. Other accounting treatments are available through special election and designation, provided they meet specific, restrictive criteria both at~~extent the time of designation and on an ongoing basis. These alternative permissible accounting treatments include normal purchase normal sale (NPNS), cash flow hedge, and fair value hedge. For Generation, all derivative economic hedges related to commodities are recorded at fair value through earnings for the consolidated company, referred to as economic hedges in the following tables. The Registrants have applied the NPNS scope exception to certain derivative contracts for the forward sale of generation, power procurement agreements, and natural gas supply agreements. Generation has also entered into bilateral long-term contractual obligations for salesamount of energy to load-serving entities, including electric utilities, municipalities, electric cooperatives, and retail load aggregators, as well as contractual obligations to deliver energy to market participants who primarily focus onGeneration produces differs from the ~~resale~~amount of energy ~~products for delivery. These non-derivative contracts are accounted for primarily under the accrual method of accounting. Additionally,~~it has contracted to sell, Exelon and Generation is exposed to certain market risks through its proprietary trading activities. The proprietary trading activities are a complement to Generation’s energy marketing portfolio but represent a small portion of Generation’s overall energy marketing activities.

~~Economic Hedging.~~ ~~The Registrants~~ are exposed to ~~commodity price risk primarily relating to changes~~market fluctuations in the ~~market price~~prices of electricity, fossil fuels, and other ~~commodities associated with price movements resulting from changes~~

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~~(Dollars in millions, except per share data, unless otherwise noted)~~

~~in supply and demand, fuel costs, market liquidity, weather conditions, governmental regulatory and environmental policies, and other factors.~~commodities. Within Exelon, Generation has the most exposure to commodity price risk. As such, Generation uses a variety of derivative and non-derivative instruments to manage the commodity price risk of its electric generation facilities, including power and gas sales, fuel and ~~energy~~power purchases, natural gas transportation and pipeline capacity agreements, and other energy-related products marketed and purchased. ~~In order to~~To manage these risks, Generation may enter into fixed-price derivative or non-derivative contracts to hedge the variability in future cash flows from ~~forecasted~~expected sales of ~~energy~~power and gas and purchases of ~~fuel~~power and ~~energy.~~fuel. The objectives for ~~entering into~~executing such hedges include fixing the price for a portion of anticipated future electricity sales at a level that provides an acceptable return on electric generation operations, fixing the price of a portion of anticipated fuel purchases for the operation of power plants, and fixing the price for a portion of anticipated energy purchases to supply load-serving customers. The portion of forecasted transactions hedged may vary based upon management’s policies and hedging objectives, the market, weather conditions, operational and other factors.return. Generation is also exposed to differences between the locational settlement prices of certain economic hedges and the hedged generating units. This price difference is actively managed through other instruments which include derivative congestion products, whose changes in fair value are recognized in earnings each period, and auction revenue rights, which are accounted for on an accrual basis.

Additionally, Generation is exposed to certain market risks through its proprietary trading activities. The proprietary trading activities are a complement to Generation’s energy marketing portfolio but represent a small portion of Generation’s overall energy marketing activities and are subject to limits established by Exelon’s RMC.

Utility Registrants. The Utility Registrants procure electric and natural gas supply through a competitive procurement process approved by each of the respective state utility commissions. The Utility Registrants’ hedging programs are intended to reduce exposure to energy and natural gas price volatility and have no direct earnings impact as the costs are fully recovered from customers through regulatory-approved recovery

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(Dollars in millions, except per share data, unless otherwise noted)

Note 12 — Derivative Financial Instruments

mechanisms. The following table provides a summary of the Utility Registrants’ primary derivative hedging instruments, listed by commodity and accounting treatment.


Registrant	Commodity	Accounting Treatment	Hedging Instrument
ComEd	Electricity	NPNS	Fixed price contracts based on all requirements in the IPA procurement plans.
	Electricity	Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability(a)	20-year floating-to-fixed energy swap contracts beginning June 2012 based on the renewable energy resource procurement requirements in the Illinois Settlement Legislation of approximately 1.3 million MWhs per year.
PECO	Electricity	NPNS	Fixed price contracts for default supply requirements through full requirements contracts.
	Gas	NPNS	Fixed price contracts to cover about 10% of planned natural gas purchases in support of projected firm sales.
BGE	Electricity	NPNS	Fixed price contracts for all SOS requirements through full requirements contracts.
	Gas	NPNS	Fixed price contracts for between 10-20% of forecasted system supply requirements for flowing (i.e., non-storage) gas for the November through March period.
Pepco	Electricity	NPNS	Fixed price contracts for all SOS requirements through full requirements contracts.
DPL	Electricity	NPNS	Fixed price contracts for all SOS requirements through full requirements contracts.
	Gas	NPNS	Fixed and Index priced contracts through full requirements contracts.
		Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability(b)	Exchange traded future contracts for up to 50% of estimated monthly purchase requirements each month, including purchases for storage injections.
ACE	Electricity	NPNS	Fixed price contracts for all BGS requirements through full requirements contracts.

__________

(a)See Note 3 — Regulatory Matters of the 2020 Form 10-K for additional information.

(b)The fair value of the DPL economic hedge is not material as of September 30, 2021 and December 31, 2020 and is not presented in the fair value tables below.

The following tables provide a summary of the derivative fair value balances recorded by Exelon, Generation, and ComEd as of September 30, 2021 and December 31, 2020:


	Exelon		Generation										ComEd
September 30, 2021	Total Derivatives		Economic Hedges		Proprietary Trading		Collateral(a)(b)		Netting(a)		Subtotal		Economic Hedges
Mark-to-market derivative assets (current assets)	$	1,505	$	19,631	$	63	$	(790)	$	(17,399)	$	1,505	$	—
Mark-to-market derivative assets (noncurrent assets)	661		3,612		5		(201)		(2,755)		661		—
Total mark-to-market derivative assets	2,166		23,243		68		(991)		(20,154)		2,166		—
Mark-to-market derivative liabilities (current liabilities)	(1,710)		(18,490)		(55)		(559)		17,399		(1,705)		(5)
Mark-to-market derivative liabilities (noncurrent liabilities)	(720)		(3,168)		(3)		(95)		2,755		(511)		(209)
Total mark-to-market derivative liabilities	(2,430)		(21,658)		(58)		(654)		20,154		(2,216)		(214)
Total mark-to-market derivative net (liabilities) assets	$	(264)	$	1,585	$	10	$	(1,645)	$	—	$	(50)	$	(214)

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(Dollars in millions, except per share data, unless otherwise noted)

Note 12 — Derivative Financial Instruments


	Exelon		Generation										ComEd
December 31, 2020	Total Derivatives		Economic Hedges		Proprietary Trading		Collateral(a)(b)		Netting(a)		Subtotal		Economic Hedges
Mark-to-market derivative assets (current assets)	$	639	$	2,757	$	40	$	103	$	(2,261)	$	639	$	—
Mark-to-market derivative assets (noncurrent assets)	554		1,501		4		64		(1,015)		554		—
Total mark-to-market derivative assets	1,193		4,258		44		167		(3,276)		1,193		—
Mark-to-market derivative liabilities (current liabilities)	(293)		(2,629)		(23)		131		2,261		(260)		(33)
Mark-to-market derivative liabilities (noncurrent liabilities)	(472)		(1,335)		(2)		118		1,015		(204)		(268)
Total mark-to-market derivative liabilities	(765)		(3,964)		(25)		249		3,276		(464)		(301)
Total mark-to-market derivative net assets (liabilities)	$	428	$	294	$	19	$	416	$	—	$	729	$	(301)

_________

(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. As of September 30, 2021, $1 million of cash collateral posted with external counterparties and an additional $71 million of cash collateral posted with affiliates, including $50 million with ComEd, and as of December 31, 2020, $15 million of cash collateral held with external counterparties, was not offset against derivative positions because such collateral was not associated with any energy-related derivatives, was associated with accrual positions, or had no positions to offset as of the balance sheet date.

(b)Includes $2,084 million held and $209 million posted of variation margin with the exchanges as of September 30, 2021 and December 31, 2020 respectively.

Economic Hedges (Commodity Price Risk)

Generation. For the three and nine months ended September 30, 2021 and 2020, Exelon and Generation recognized the following net pre-tax commodity mark-to-market gains (losses) which are also located in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows.


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Income Statement Location	(Loss) Gain				(Loss) Gain
Operating revenues	$	(637)	$	39	$	(961)	$	238
Purchased power and fuel	1,392		209		2,209		224
Total Exelon and Generation	$	755	$	248	$	1,248	$	462

In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on Generation’s owned and contracted generation positions that have not been hedged. Generation hedges commodity price risk on a ratable basis over three-year periods. As of September 30, ~~2017,~~2021, the percentage of expected generation hedged is 98%-101%, 79%-82%, and 45%-48% for 2017, 2018, and 2019, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted generating facilities based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products, and options. Equivalent sales represent all hedging products, which include economic hedges and certain non-derivative contracts including Generation’s sales to ComEd, PECO, BGE, Pepco, DPL, and ACE to serve their retail load.

~~On December 17, 2010, ComEd entered into several 20-year floating-to-fixed energy swap contracts with unaffiliated suppliers~~ for the ~~procurement of long-term renewable energy~~Mid-Atlantic, Midwest, New York, and associated RECs. Delivery under the contracts began in June 2012. These contracts are designed to lock in a portion of the long-term commodity price risk resulting from the renewable energy resource procurement requirements in the Illinois Settlement Legislation. ComEd has not elected hedge accounting for these derivative financial instruments. ComEd records the fair value of the swap contracts on its balance sheet. Because ComEd receives full cost recovery for energy procurement and related costs from retail customers, the change in fair value each periodERCOT reportable segments is ~~recorded by ComEd as a regulatory asset or liability. See Note 3 — Regulatory Matters of the Exelon 2016 Form 10-K for additional information.~~

PECO has contracts to procure electric supply that were executed through the competitive procurement process outlined in its PAPUC-approved DSP Programs, which are further discussed in Note 5 — Regulatory Matters. Based on Pennsylvania legislation and the DSP Programs permitting PECO to recover its electric supply procurement costs from retail customers with no mark-up, PECO’s price risk related to electric supply procurement is limited. PECO locked in fixed prices for a significant portion of its commodity price risk through full requirements contracts. PECO has certain full requirements contracts that are considered derivatives and qualify96%-99% for the ~~NPNS scope exception under current derivative authoritative guidance.~~remainder of 2021.

PECO’s natural gas procurement policy is designed to achieve a reasonable balance of long-term and short-term gas purchases under different pricing approaches in order to achieve system supply reliability at the least cost. PECO’s reliability strategy is two-fold. First, PECO must assure that there is sufficient transportation capacity to satisfy delivery requirements. Second, PECO must ensure that a firm source of supply exists to utilize the capacity resources. All of PECO’s natural gas supply and asset management agreements that are derivatives either qualify for the NPNS scope exception and have been designated as such, or have no mark-to-market balances because the derivatives are index priced. Additionally, in accordance with the 2016 PAPUC PGC settlement and to reduce the exposure of PECO and its customers to natural gas price volatility, PECO has continued its program to purchase natural gas for both winter and summer supplies using a layered approach of locking-in prices ahead of each season with long-term gas purchase agreements (those with primary terms of at least twelve months). Under the terms of the 2016 PGC settlement, PECO is required to lock in (i.e., economically hedge) the price of a minimum volume of its long-term gas commodity purchases. PECO’s gas-hedging program is designed to cover about 20% of planned natural gas purchases in support of projected firm sales. The hedging program for natural gas procurement has no direct impact on PECO’s financial position or results of operations as natural gas costs are fully recovered from customers under the PGC.Proprietary Trading (Commodity Price Risk)

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~~(Dollars in millions, except per share data, unless otherwise noted)~~

BGE has contracts to procure SOS electric supply that are executed through a competitive procurement process approved by the MDPSC. The SOS rates charged recover BGE's wholesale power supply costs and include an administrative fee. BGE’s price risk related to electric supply procurement is limited. BGE locks in fixed prices for all of its SOS requirements through full requirements contracts. Certain of BGE’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other BGE full requirements contracts are not derivatives.

BGE provides natural gas to its customers under a MBR mechanism approved by the MDPSC. Under this mechanism, BGE’s actual cost of gas is compared to a market index (a measure of the market price of gas in a given period). The difference between BGE’s actual cost and the market index is shared equally between shareholders and customers. BGE must also secure fixed price contracts for at least 10%, but not more than 20%, of forecasted system supply requirements for flowing (i.e., non-storage) gas for the November through March period. These fixed-price contracts are not subject to sharing under the MBR mechanism. BGE also ensures it has sufficient pipeline transportation capacity to meet customer requirements. All of BGE’s natural gas supply and asset management agreements qualify for the NPNS scope exception and result in physical delivery.

Pepco has contracts to procure SOS electric supply that are executed through a competitive procurement process approved by the MDPSC and DCPSC. The SOS rates charged recover Pepco's wholesale power supply costs and include an administrative fee. The administrative fee includes an incremental cost component and a shareholder return component for residential and commercial rate classes. Pepco’s price risk related to electric supply procurement is limited. Pepco locks in fixed prices for all of its SOS requirements through full requirements contracts. Certain of Pepco’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other Pepco full requirements contracts are not derivatives.

DPL has contracts to procure SOS electric supply that are executed through a competitive procurement process approved by the MDPSC and the DPSC. The SOS rates charged recover DPL's wholesale power supply costs. In Delaware, DPL is also entitled to recover a Reasonable Allowance for Retail Margin (RARM). The RARM includes a fixed annual margin of approximately $2.75 million, plus an incremental cost component and a cash working capital allowance. In Maryland, DPL charges an administrative fee intended to allow it to recover its administrative costs. DPL locks in fixed prices for all of its SOS requirements through full requirements contracts. DPL’s price risk related to electric supply procurement is limited. Certain of DPL’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other DPL full requirements contracts are not derivatives.

DPL provides natural gas to its customers under an Annual GCR mechanism approved by the DPSC. Under this mechanism, DPL’s Annual GCR Filing establishes a future GCR for firm bundled sales customers by using a forecast of demand and commodity costs. The actual costs are trued up versus the forecast on a monthly basis and any shortfall or excess is carried forward as a recovery balance in the next GCR filing. The demand portion of the GCR is based upon DPL’s firm transportation and storage contracts. DPL has firm deliverability of swing and seasonal storage; a liquefied natural gas facility and firm transportation capacity to meet customer demand and provide a reserve margin. The commodity portion of the GCR includes a commission approved hedging program which is intended to reduce gas commodity price volatility while limiting the firm natural gas customers’ exposure to adverse changes in the market price of natural gas. The hedge program requires that DPL hedge, on a non-discretionary basis, an amount equal to fifty percent (50%) of estimated purchase requirements for each month, including estimated monthly purchases for storage injections. The fifty percent (50%) hedge monthly target is achieved by hedging 1/12th of the 50% target each month beginning 12-months prior to the month in which the physical gas is to be purchased. Currently, DPL uses only exchange traded futures for its gas hedging program, which are considered derivatives, however, it retains the capability to employ other physical and financial hedges if needed. DPL has not elected hedge accounting for these derivative financial instruments. Because of the DPSC-approved fuel adjustment clause for DPL's derivatives, the change in fair value of the derivatives each period, in addition to all premiums paid and other transaction costs incurred as part of the Gas Hedging Program, are fully recoverable and are recorded by DPL as regulatory assets or liabilities. DPL’s physical gas purchases are currently all daily, monthly or intra-month transactions. From time to time, DPL will enter into seasonal purchase or sale arrangements, however, there are none currently in the portfolio. Certain of DPL's full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other DPL full requirements contracts are not derivatives.

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~~(Dollars in millions, except per share data, unless otherwise noted)~~

any profit or incur any loss on the supply component of the BGS it supplies to customers. ACE’s price risk related to electric supply procurement is limited. ACE locks in fixed prices for all of its BGS requirements through full requirements contracts. Certain of ACE’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other ACE full requirements contracts are not derivatives.

~~Proprietary Trading.~~Generation also ~~enters into certain energy-related~~executes commodity derivatives for proprietary trading purposes. Proprietary trading includes all contracts ~~entered into~~executed with the intent of benefiting from shifts or changes in market prices as opposed to those ~~entered into~~executed with the intent of hedging or managing risk. Proprietary trading activities are subject to limits established by Exelon’s RMC. The proprietary trading activities, which included settled physical sales volumes of 2,601 GWhs and 6,763 GWhs for the three and nine months ended September 30, 2017, respectively, and 1,506 GWhs and 4,015 GWhs and for the three and nine months September 30, 2016, respectively, are a complement to Generation’s energy marketing portfolio but represent a small portion of Generation’s revenue from energy marketing activities. ComEd, PECO, BGE, PHI, Pepco, DPL and ACE do not enter into derivatives for proprietary trading purposes.

~~Interest Rate and Foreign Exchange Risk (All Registrants)~~

The Registrants use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. The Registrants utilize fixed-to-floating interest rate swaps, which are typically designated as fair value hedges, as a means to manage their interest rate exposure. In addition, the Registrants may utilize interest rate derivatives to lock in rate levels in anticipation of future financings, which are typically designated as cash flow hedges. These strategies are employed to manage interest rate risks. At September 30, 2017, Exelon had $800 million of notional amounts of fixed-to-floating hedges outstanding, and Exelon and Generation had $491 million of notional amounts of floating-to-fixed hedges outstanding. To manage foreign exchange rate exposure associated with international energy purchases in currencies other than U.S. dollars, Generation utilizes foreign currency derivatives, which are typically designated as economic hedges. Below is a summary of the interest rate and foreign exchange hedge balances as of September 30, 2017:

Generation Exelon Corporate Exelon
Description
Derivatives
Designated
as Hedging
Instruments

Economic
Hedges

Proprietary
Trading(a)

Collateral
and
Netting(b)
Subtotal
Derivatives
Designated
as Hedging
Instruments
Total
Mark-to-market derivative assets (current assets) $ —
$ 15
$ —
$ (10 ) $ 5
$ —
$ 5
Mark-to-market derivative assets (noncurrent assets) —
1
—
(1 ) —
10
10
Total mark-to-market derivative assets —
16
—
(11 ) 5
10
15
Mark-to-market derivative liabilities (current liabilities) —
(17 ) —
9
(8 ) —
(8 )
Mark-to-market derivative liabilities (noncurrent liabilities) —
(2 ) —
1
(1 ) —
(1 )
Total mark-to-market derivative liabilities —
(19 ) —
10
(9 ) —
(9 )
Total mark-to-market derivative net assets (liabilities) $ —
$ (3 ) $ —
$ (1 ) $ (4 ) $ 10
$ 6

~~__________~~

~~(a)~~

Generation enters into interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions. The characterization of the interest rate derivative contracts between the proprietary trading activity in the above table is driven by the corresponding characterization of the underlying commodity position that gives rise to the interest rate exposure. Generation does not utilize proprietary trading interest rate derivatives with the objective of benefiting from shifts or changes in market interest rates.

~~(b)~~

Exelon and Generation net all available amounts allowed under the derivative accounting 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. These are not reflected in the table above.

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~~(Dollars in millions, except per share data, unless otherwise noted)~~

~~The following table provides a summary of the interest rate and foreign exchange hedge balances recorded by the Registrants as of December 31, 2016:~~

Generation Exelon Corporate Exelon
Description
Derivatives
Designated
as Hedging
Instruments

Economic
Hedges

Proprietary
Trading^(a)

Collateral
and
Netting^(b)
Subtotal
Derivatives
Designated
as Hedging
Instruments
Total
Mark-to-market derivative assets (current assets) $ —
$ 17
$ 4
$ (13 ) $ 8
$ —
$ 8
Mark-to-market derivative assets (noncurrent assets) —
11
1
(8 ) 4
16
20
Total mark-to-market derivative assets —
28
5
(21 ) 12
16
28
Mark-to-market derivative liabilities (current liabilities) (7 ) (13 ) (2 ) 14
(8 ) —
(8 )
Mark-to-market derivative liabilities (noncurrent liabilities) (3 ) (8 ) (2 ) 9
(4 ) —
(4 )
Total mark-to-market derivative liabilities (10 ) (21 ) (4 ) 23
(12 ) —
(12 )
Total mark-to-market derivative net assets (liabilities) $ (10 ) $ 7
$ 1
$ 2
$ —
$ 16
$ 16

~~__________~~

~~(a)~~

~~(b)~~

~~Fair Value Hedges~~. For derivative instruments that are designated and qualify as fair value hedges, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item attributable to the hedged risk are recognized in current earnings. Exelon includes the gain or loss on the hedged items and the offsetting loss or gain on the related interest rate swaps in interest expense as follows:

Three Months Ended September 30,

Income Statement
Location
2017 2016 2017 2016

Gain (loss) on Swaps Gain (loss) on Borrowings
Exelon Interest expense $ (2 ) $ (8 ) $ 6
$ 14


Nine Months Ended September 30,

Income Statement
Location
2017 2016 2017 2016

Gain (loss) on Swaps Gain (loss) on Borrowings
Exelon Interest expense $ (6 ) $ 15
$ 17
$ (3 )

At September 30, 2017, Exelon had total outstanding fixed-to-floating fair value hedges related to interest rate swaps of $800 million, with a derivative asset of $10 million. At December 31, 2016, Exelon had total outstanding fixed-to-floating fair value hedges related to interest rate swaps of $800 million, with a derivative asset of $16 million. During the three and nine months ended September 30, 2017 and 2016, the impact on the results of operations as a result of ineffectiveness from fair value hedges was a $4 million gain, a $11 million gain, a $6 million gain, and a $12 million gain, respectively.

~~Cash Flow Hedges~~. During the first and second quarter of 2016, Exelon entered into $600 million and $100 million of floating-to-fixed forward starting interest rate swaps, respectively, to manage a portion of the interest rate exposure associated with an anticipated debt issuance. The swaps were designated as cash flow hedges. Exelon terminated the swaps during the second quarter of 2016 upon issuance of the debt. Exelon recognized a loss of $3 million related to the swaps and $3 million of AOCI will be amortized into Other, net in Exelon's Consolidated Statement

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~~(Dollars in millions, except per share data, unless otherwise noted)~~

~~of Operations and Comprehensive Income over the term of the debt. See Note 11— Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.~~

During the first quarter of 2016, Exelon entered into a $100 million floating-to-fixed forward starting interest rate swaps to manage a portion of the interest rate exposure associated with an anticipated debt issuance. The swap was designated as a cash flow hedge. Exelon terminated the swap during the first quarter of 2016 upon issuance of the debt. Exelon did not recognize a gain or loss as a result of the termination of the swap and an immaterial amount of AOCI will be amortized into Other, net in Exelon's Consolidated Statement of Operations and Comprehensive Income over the term of the debt.

During the first quarter of 2014, EGR, a subsidiary of Generation, entered into floating-to-fixed interest rate swaps to manage a portion of its interest rate exposure in connection with its long-term borrowings. The swaps were de-designated as cash flow hedges and, during the second quarter of 2017, upon termination of the debt, Generation terminated the swaps. The total notional amount of the swaps was $164 million. No gain or loss was recognized as a result of the termination of the swaps. See Note 11 — Debt and Credit Agreements for additional information.

During the three and nine months ended September 30, 2017 and 2016, the impact on the results of operations as a result of ineffectiveness from cash flow hedges in continuing designated hedge relationships was immaterial.

~~Economic Hedges~~. During the third quarter of 2014, EGTP, a subsidiary of Generation, entered into a floating-to-fixed interest rate swap to manage a portion of its interest rate exposure in connection with the long-term borrowing. See Note 14 —Debt and Credit Agreements of the Exelon 2016 Form 10-K for additional information regarding the financing. The swaps have a notional amount of $491 million as of September 30, 2017 and expire in 2019. The swap was designated as a cash flow hedge in the fourth quarter of 2014. During the first quarter of 2017, the swap was de-designated. At September 30, 2017, the subsidiary had a $6 million derivative liability related to the swap. During the three and nine months ended September 30, 2017, a gain of $2 million and a loss of $2 million related to the swap, respectively, were recorded to Interest expense.

During the third quarter of 2011, Sacramento PV Energy, a subsidiary of Generation entered into floating-to-fixed interest rate swaps to manage a portion of its interest rate exposure in connection with the long-term borrowings. See Note 14 — Debt and Credit Agreements of the Exelon 2016 Form 10-K for additional information regarding the financing. During the first quarter of 2016, upon the termination of debt, Generation terminated the swaps. The total notional amount of the swaps was $25 million. No gain or loss was recognized as a result of the termination of the swaps.

During the third quarter of 2012, Constellation Solar Horizons, a subsidiary of Generation, entered into a floating-to-fixed interest rate swap to manage a portion of its interest rate exposure in connection with the long-term borrowings. See Note 14 — Debt and Credit Agreements of the Exelon 2016 Form 10-K for additional information regarding the financing. During the first quarter of 2016, upon the termination of debt, Generation terminated the swap. The total notional amount of the swap was $24 million. No gain or loss was recognized as a result of the termination of the swap.

At September 30, 2017, Generation had immaterial notional amounts of interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions and $111 million in notional amounts of foreign currency exchange rate swaps that are marked-to-market to manage the exposure associated with international purchases of commodities in currencies other than U.S. dollars.

~~Fair Value Measurement and Accounting for the Offsetting of Amounts Related to Certain Contracts (Exelon, Generation, ComEd, PECO, BGE, PHI and DPL)~~

Fair value accounting guidance and disclosures about offsetting assets and liabilities requires the fair value of derivative instruments to be shown in the Notes to the Consolidated Financial Statements on a gross basis, even when the derivative instruments are subject to legally enforceable master netting agreements and qualify for net presentation in the Consolidated Balance Sheet. A master netting agreement is an agreement between two counterparties that may have derivative and non-derivative contracts with each other providing for the net settlement of all referencing contracts via one payment stream, which takes place as the contracts deliver, when collateral is requested or in the event of default. Generation’s use of cash collateral is generally unrestricted, unless Generation is downgraded below investment grade (i.e., to BB+ or Ba1). In the table below, Generation’s energy related economic hedges and proprietary trading derivatives are shown gross. The impact of the netting of fair value balances with the same counterparty that are subject to legally enforceable master netting agreements, as well as netting of cash collateral, including margin on exchange positions, is aggregated in the collateral and netting column. As of September 30, 2017 and December 31, 2016, $3

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~~(Dollars in millions, except per share data, unless otherwise noted)~~

million and $8 million of cash collateral held, respectively, was not offset against derivative positions because such collateral was not associated with any energy-related derivatives, were associated with accrual positions, or as of the balance sheet date there were no positions to offset. Excluded from the tables below are economic hedges that qualify for the NPNS scope exception and other non-derivative contracts that are accounted for under the accrual method of accounting.

~~ComEd’s use of cash collateral is generally unrestricted unless ComEd is downgraded below investment grade (i.e., to BB+ or Ba1).~~

~~Cash collateral held by PECO and BGE must be deposited in a non affiliate major U.S. commercial bank or foreign bank with a U.S. branch office that meet certain qualifications.~~

In the table below, DPL's economic hedges are shown gross. The impact of the netting of fair value balances with the same counterparty that are subject to legally enforceable master netting agreements, as well as netting of cash collateral, including margin on exchange positions, is aggregated in the collateral and netting column.

~~The following table provides a summary of the derivative fair value balances recorded by the Registrants as of September 30, 2017:~~

Successor
Generation ComEd DPL PHI Exelon
Derivatives
Economic
Hedges

Proprietary
Trading

Collateral
and
Netting^{(a) (e)}

Subtotal^(b)

Economic
Hedges^(c)

Economic
Hedges^(d)

Collateral
and
Netting^(a)
Subtotal Subtotal
Total
Derivatives
Mark-to-market derivative assets (current assets) $ 2,608
$ 55
$ (1,969 ) $ 694
$ —
$ —
$ —
$ —
$ —
$ 694
Mark-to-market derivative assets (noncurrent assets) 1,583
30
(1,197 ) 416
—
—
—
—
—
416
Total mark-to-market derivative assets 4,191

85
(3,166 ) 1,110
—
—
—
—

—
1,110
Mark-to-market derivative liabilities (current liabilities) (2,334 ) (46 ) 2,230
(150 ) (20 ) —
—
—
—
(170 )
Mark-to-market derivative liabilities (noncurrent liabilities) (1,476 ) (27 ) 1,351
(152 ) (257 ) —
—
—
—
(409 )
Total mark-to-market derivative liabilities (3,810 ) (73 ) 3,581
(302 ) (277 ) —
—
—

—
(579 )
Total mark-to-market derivative net assets (liabilities) $ 381
$ 12
$ 415
$ 808
$ (277 ) $ —
$ —
$ —

$ —
$ 531

~~_________~~

~~(a)~~

Exelon, Generation, PHI and DPL net all available amounts allowed under the derivative accounting 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 $123 million and $61 million, respectively, and current and noncurrent liabilities are shown net of collateral of $138 million and $93 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $415 million at September 30, 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), $27 million represents variation margin on the exchanges.~~

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~~(Dollars in millions, except per share data, unless otherwise noted)~~

~~The following table provides a summary of the derivative fair value balances recorded by the Registrants as of December 31, 2016:~~

Successor
Generation ComEd DPL PHI Exelon
Description
Economic
Hedges

Proprietary
Trading

Collateral
and
Netting^{(a) (e)}

Subtotal^(b)

Economic
Hedges^(c)

Economic
Hedges^(d)

Collateral and
Netting^(a)
Subtotal Subtotal Total
Derivatives
Mark-to-market derivative assets (current assets) $ 3,623
$ 55
$ (2,769 ) $ 909
$ —
$ 2
$ (2 ) $ —
$ —
$ 909
Mark-to-market derivative assets (noncurrent assets) 1,467
21
(1,016 ) 472
—
—
—
—
—
472
Total mark-to-market derivative assets 5,090
76
(3,785 ) 1,381
—
2
(2 ) —
—
1,381
Mark-to-market derivative liabilities (current liabilities) (3,165 ) (54 ) 2,964
(255 ) (19 ) —
—
—
—
(274 )
Mark-to-market derivative liabilities (noncurrent liabilities) (1,274 ) (25 ) 1,150
(149 ) (239 ) —
—
—
—
(388 )
Total mark-to-market derivative liabilities (4,439 ) (79 ) 4,114
(404 ) (258 ) —
—
—
—
(662 )
Total mark-to-market derivative net assets (liabilities) $ 651
$ (3 ) $ 329
$ 977
$ (258 ) $ 2
$ (2 ) $ —
$ —
$ 719

~~_________~~

~~(a)~~

Exelon, Generation, PHI and DPL net all available amounts allowed under the derivative accounting 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 $100 million and $72 million, respectively, and current and noncurrent liabilities are shown net of collateral of $95 million and $62 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $329 million at December 31, 2016.


~~(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), $(158) million represents variation margin on the exchanges.~~

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~~(Dollars in millions, except per share data, unless otherwise noted)~~

~~Cash Flow Hedges (Exelon and Generation).~~ The tables below provide the activity of OCI related to cash flow hedges for the nine months ended September 30, 2017 and 2016, containing information about the changes in the fair value of cash flow hedges and the reclassification from Accumulated OCI into results of operations. The amounts reclassified from OCI, when combined with the impacts of the hedged transactions, result in the ultimate recognition of net revenues or expenses at the contractual price.

Total Cash Flow Hedge OCI Activity, Net of Income Tax
Generation Exelon
Three Months Ended September 30, 2017
Income Statement
Location
Total Cash
Flow Hedges
Total Cash
Flow Hedges

Accumulated OCI derivative loss at June 30, 2017 $ (14 ) $ (12 )
Effective portion of changes in fair value 1
1

Reclassifications from AOCI to net income Interest Expense (1 )
^(a)
(1 )
^(a)
Accumulated OCI derivative loss at September 30, 2017 $ (14 ) $ (12 )

Total Cash Flow Hedge OCI Activity, Net of Income Tax
Generation Exelon
Nine Months Ended September 30, 2017
Income Statement
Location
Total Cash
Flow Hedges Total Cash
Flow Hedges
Accumulated OCI derivative loss at December 31, 2016 $ (19 ) $ (17 )
Effective portion of changes in fair value 2

2

Reclassifications from AOCI to net income Interest Expense 3
^(b)
3
^(b)
Accumulated OCI derivative loss at September 30, 2017 $ (14 ) $ (12 )

Total Cash Flow Hedge OCI Activity, Net of Income Tax
Generation Exelon
Three Months Ended September 30, 2016
Income Statement
Location
Total Cash
Flow Hedges
Total Cash
Flow Hedges

Accumulated OCI derivative loss at June 30, 2016 $ (25 ) $ (26 )
Effective portion of changes in fair value 1

3

Accumulated OCI derivative loss at September 30, 2016 $ (24 ) $ (23 )

Total Cash Flow Hedge OCI Activity, Net of Income Tax
Generation Exelon
Nine Months Ended September 30, 2016
Income Statement
Location
Total Cash
Flow Hedges
Total Cash
Flow Hedges

Accumulated OCI derivative loss at December 31, 2015 $ (21 ) $ (19 )
Effective portion of changes in fair value —

(1 )
Reclassifications from AOCI to net income Interest Expense (3 )
^(c)
(3 )
^(c)
Accumulated OCI derivative loss at September 30, 2016 $ (24 ) $ (23 )

~~_________~~


~~(a)~~	~~Amount is net of related income tax benefit of $1 million for the three months ended September 30, 2017.~~


~~(b)~~	~~Amount is net of related income tax expense of $2 million for the nine months ended September 30, 2017.~~


~~(c)~~	~~Amount is net of related income tax expense of $2 million for the nine months ended September 30, 2016.~~

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~~(Dollars in millions, except per share data, unless otherwise noted)~~

~~Economic Hedges (Exelon and Generation).~~ These instruments represent hedges that economically mitigate exposure to fluctuations in commodity prices and include financial options, futures, swaps, physical forward sales and purchases, but for which the fair value or cash flow hedge elections were not made. Additionally, Generation enters into interest rate derivative contracts and foreign exchange currency swaps ("treasury") to manage the exposure related to the interest rate component of commodity positions and international purchases of commodities in currencies other than U.S. Dollars. For the three and nine months ended September 30, 2017 and 2016, the following net pre-tax mark-to-market gains (losses) of certain purchase and sale contracts were reported in Operating revenues or Purchased power and fuel expense, or Interest expense at Exelon and Generation in the Consolidated Statements of Operations and Comprehensive Income and are included in “Net fair value changes related to derivatives” in Exelon’s and Generation’s Consolidated Statements of Cash Flows. In the tables below, “Change in fair value” represents the change in fair value of the derivative contracts held at the reporting date. The “Reclassification to realized” generally represents the recognized change in fair value that was reclassified from unrealized to realized when the transaction to which the derivative relates occurs.

Generation Exelon
Three Months Ended September 30, 2017
Operating
Revenues

Purchased
Power
and Fuel
Total Total
Change in fair value of commodity positions $ 132
$ 45
$ 177
$ 177
Reclassification to realized at settlement of commodity positions (77 ) (24 ) (101 ) (101 )
Net commodity mark-to-market gains (losses) 55
21
76
76
Change in fair value of treasury positions (3 ) —
(3 ) (3 )
Reclassification to realized at settlement of treasury positions —
—
—
—
Net treasury mark-to-market gains (losses) (3 ) —
(3 ) (3 )
Net mark-to-market gains (losses) $ 52
$ 21
$ 73
$ 73

Generation Exelon
Nine Months Ended September 30, 2017
Operating
Revenues

Purchased
Power
and Fuel
Total Total
Change in fair value of commodity positions $ 123
$ (153 ) $ (30 ) $ (30 )
Reclassification to realized of commodity positions (164 ) 39
(125 ) (125 )
Net commodity mark-to-market gains (losses) (41 ) (114 ) (155 ) (155 )
Change in fair value of treasury positions (4 ) —
(4 ) (4 )
Reclassification to realized of treasury positions (2 ) —
(2 ) (2 )
Net treasury mark-to-market gains (losses) (6 ) —
(6 ) (6 )
Net mark-to-market gains (losses) $ (47 ) $ (114 ) $ (161 ) $ (161 )

Generation Exelon
Three Months Ended September 30, 2016
Operating
Revenues

Purchased
Power
and Fuel
Total Total
Change in fair value of commodity positions $ 280
$ (73 ) $ 207
$ 207
Reclassification to realized at settlement of commodity positions (92 ) (26 ) (118 ) (118 )
Net commodity mark-to-market gains (losses) 188
(99 ) 89
89
Change in fair value of treasury positions 1
—
1
1
Reclassification to realized at settlement of treasury positions (2 ) —
(2 ) (2 )
Net treasury mark-to-market gains (losses) (1 ) —
(1 ) (1 )
Net mark-to-market gains (losses) $ 187
$ (99 ) $ 88
$ 88

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~~(Dollars in millions, except per share data, unless otherwise noted)~~

Generation Exelon
Nine Months Ended September 30, 2016
Operating
Revenues

Purchased
Power
and Fuel
Total Total
Change in fair value of commodity positions $ 127
$ 36
$ 163
$ 163
Reclassification to realized of commodity positions (484 ) 217
(267 ) (267 )
Net commodity mark-to-market gains (losses) (357 ) 253
(104 ) (104 )
Change in fair value of treasury positions (3 ) —
(3 ) (3 )
Reclassification to realized of treasury positions (6 ) —
(6 ) (6 )
Net treasury mark-to-market gains (losses) (9 ) —
(9 ) (9 )
Net mark-to-market gains (losses) $ (366 ) $ 253
$ (113 ) $ (113 )

~~Proprietary Trading Activities (Exelon and Generation).~~ For the three and nine months ended September 30, 2017 and 2016, Exelon and Generation recognized the following net unrealized mark-to-market gains (losses), net realized mark-to-market gains (losses) and total net mark-to-market gains (losses) before income taxes relating to mark-to-market activity on commodity derivative instruments entered into for proprietary trading purposes and interest rate and foreign exchange derivative contracts to hedge risk associated with the interest rate and foreign exchange components of underlying commodity positions. Gains and losses associated with proprietary trading are reported as ~~operating~~Operating revenues in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income and are included in ~~“Net~~the Net fair value changes related to ~~derivatives”~~derivatives line in ~~Exelon’s and Generation’s~~the Consolidated Statements of Cash Flows. InFor the ~~tables below, “Change~~three and nine months ended September 30, 2021 and 2020,

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in ~~fair value” represents~~millions, except per share data, unless otherwise noted)

Note 12 — Derivative Financial Instruments

net pre-tax commodity mark-to-market gains and losses for Exelon and Generation were not material. The Utility Registrants do not execute derivatives for proprietary trading purposes.

Interest Rate and Foreign Exchange Risk (Exelon and Generation)

Generation utilizes interest rate swaps to manage its interest rate exposure and foreign currency derivatives to manage foreign exchange rate exposure associated with international commodity purchases in currencies other than U.S. dollars, both of which are treated as economic hedges. The notional amounts were $567 million and $665 million for Exelon and Generation as of September 30, 2021 and December 31, 2020, respectively.

The mark-to-market derivative assets and liabilities as of September 30, 2021 and December 31, 2020 and the ~~change in fair value of~~mark-to-market gains and losses for the derivative contracts held at the reporting date. The “Reclassification to realized” represents the recognized change in fair value that was reclassified to realized due to settlement of the derivative during the period.

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Change in fair value of commodity positions $ 11
$ 4
$ 17
$ 18
Reclassification to realized of commodity positions (6 ) (6 ) (13 ) (17 )
Net commodity mark-to-market gains (losses) 5
(2 ) 4
1
Change in fair value of treasury positions (1 ) —
(2 ) (2 )
Reclassification to realized of treasury positions 1
1
1
2
Net treasury mark-to-market gains (losses) —
1
(1 ) —
Total net mark-to-market gains (losses) $ 5
$ (1 ) $ 3
$ 1
three and nine months ended September 30, 2021 and 2020 were not material for Exelon and Generation.

Credit Risk (All Registrants)

The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties ~~that enter into~~on executed derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date.

Generation. For ~~energy-related derivative instruments,~~commodity derivatives, Generation enters into enabling agreements that allow for payment netting with its counterparties, which reduces Generation’s exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. Typically, each enabling agreement is for a specific commodity and so, with respect to each individual counterparty, netting is limited to transactions involving that specific commodity product, except where master netting agreements exist with a counterparty that allow for cross product netting. In addition to payment netting language in the enabling agreement, Generation’s credit department establishes credit limits, margining thresholds, and collateral requirements for each counterparty, which are defined in the derivative contracts. Counterparty credit limits are based on an internal credit review process that considers a variety of factors, including the results of a scoring model, leverage, liquidity, profitability, credit ratings by credit rating agencies, and risk management capabilities. To the extent that a counterparty’s margining thresholds are exceeded, the counterparty is required to post collateral with Generation as specified in each enabling agreement. Generation’s credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— ~~(Continued)~~

(Dollars in millions, except per share data, unless otherwise noted)

Note 12 — Derivative Financial Instruments

The following tables provide information on Generation’s credit exposure for all derivative instruments, NPNS, and ~~applicable~~ payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of September 30, ~~2017.~~2021. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties. The ~~figures~~amounts in the tables below exclude credit risk exposure from individual retail counterparties, ~~Nuclear~~nuclear fuel procurement contracts, and exposure through RTOs, ISOs, NYMEX, ICE, NASDAQ, NGX, and Nodal commodity exchanges. ~~Additionally, the figures in the tables below exclude exposures with affiliates, including net receivables with ComEd, PECO, BGE, Pepco, DPL and ACE of $18 million, $22 million~~, ~~$22 million, $34 million, $12 million, and $7 million as of September 30, 2017, respectively.~~


Rating as of September 30, 2017	Total Exposure Before Credit Collateral		Credit Collateral^(a)		Net Exposure		Number of Counterparties Greater than 10% of Net Exposure	Net Exposure of Counterparties Greater than 10% of Net Exposure
Rating as of September 30, 2021										Rating as of September 30, 2021	Total Exposure Before Credit Collateral		Credit Collateral(a)		Net Exposure		Number of Counterparties Greater than 10% of Net Exposure	Net Exposure of Counterparties Greater than 10% of Net Exposure
Investment grade	$	828	$	9	$	819	1	$	278	Investment grade	$	701	$	254	$	447	—	$	—
Non-investment grade	44		4		40					Non-investment grade	23		2		21		—	—
No external ratings										No external ratings
Internally rated — investment grade	316		—		316					Internally rated — investment grade	110		1		109		—	—
Internally rated — non-investment grade	100		18		82					Internally rated — non-investment grade	309		48		261		—	—
Total	$	1,288	$	31	$	1,257	1	$	278	Total	$	1,143	$	305	$	838	—	$	—

Net Credit Exposure by Type of Counterparty As of
September 30, 2017
Financial institutions $ 48
Investor-owned utilities, marketers, power producers 538
Energy cooperatives and municipalities 525
Other 146
Total $ 1,257

~~_________~~


~~(a)~~Net Credit Exposure by Type of Counterparty	As of September 30, ~~2017, credit collateral held from counterparties where Generation had credit exposure included $19 million of cash~~2021
Financial institutions	$	53
Investor-owned utilities, marketers, power producers	652
Energy cooperatives and ~~$12 million of letters of credit. The credit collateral does not include non-liquid collateral.~~municipalities	62
Other	71
Total	$	838

~~ComEd’s power procurement~~_________

(a)As of September 30, 2021, credit collateral held from counterparties where Generation had credit exposure included $188 million of cash and $117 million of letters of credit. The credit collateral does not include non-liquid collateral.

Utility Registrants. The Utility Registrants have contracts to procure electric and natural gas supply that provide suppliers with a certain amount of unsecured credit. The credit position is based on daily, updated forward market prices compared to the benchmark prices. The benchmark prices are the forward prices of energy projected through the contract term and are set at the point of supplier bid submittals. If the ~~forward market price of energy~~exposure on the supply contract exceeds the ~~benchmark price on a given day,~~amount of unsecured credit, the suppliers ~~are~~may be required to post ~~collateral for the secured~~collateral. The net credit ~~portion after adjusting for any unpaid deliveries and unsecured credit allowed under the contract. The unsecured credit used~~exposure is mitigated primarily by the ~~suppliers represents ComEd’s net credit exposure.~~ability to recover procurement costs through customer rates. As of September 30, ~~2017, ComEd’s net credit exposure to suppliers was less than $1 million.~~

~~ComEd is permitted to recover its costs of procuring energy through~~2021, the Illinois Settlement Legislation. ComEd’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 3 — Regulatory Matters of the Exelon 2016 Form 10-K for additional information.

PECO’s supplier master agreements that govern the terms of its electric supply procurement contracts, which define a supplier’s performance assurance requirements, allow a supplier to meet its credit requirements with a certain amount of ~~unsecured credit. The amount of unsecured credit is determined based on the supplier’s lowest credit rating from the major credit rating agencies~~cash collateral held with external counterparties by ComEd, BGE, and ~~the supplier’s tangible net worth. The credit position is based on the initial market price,~~DPL was $56 million, $21 million, and $25 million, respectively, which is ~~the forward price of energy on the day a transaction is executed, compared to the current forward price curve~~recorded in Other Current Liabilities in ComEd’s, BGE’s, and DPL’s Consolidated Balance Sheets. The amounts for energy. To the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to post collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. The unsecured credit used by the suppliers represents PECO’s net credit exposure. AsPECO, Pepco, and ACE as of September 30, ~~2017, PECO had no material net credit exposure to suppliers.~~

~~PECO is permitted to recover its costs~~2021 and for the Utility Registrants as of procuring electric supply through its PAPUC-approved DSP Program. PECO’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 5 — Regulatory MattersDecember 31, 2020 are not material. The amount for ~~additional information.~~

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~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

PECO’s natural gas procurement plan is reviewed and approved annually on a prospective basis by the PAPUC. PECO’s counterparty credit risk under its natural gas supply and asset management agreements is mitigated by its ability to recover its natural gas costs through the PGC, which allows PECO to adjust rates quarterly to reflect realized natural gas prices. PECO does not obtain collateral from suppliers under its natural gas supply and asset management agreements. AsComEd as of September 30, ~~2017, PECO had no material credit exposure under its natural gas supply and asset management agreements with investment grade suppliers.~~

BGE is permitted to recover its costs of procuring energy through the MDPSC-approved procurement tariffs. BGE’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 3 — Regulatory Matters of the Exelon 2016 Form 10-K for additional information.

BGE’s full requirement wholesale electric power agreements that govern the terms of its electric supply procurement contracts, which define a supplier’s performance assurance requirements, allow a supplier, or its guarantor, to meet its credit requirements with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s lowest credit rating2021 does not include cash collateral held from ~~the major credit rating agencies and the supplier’s tangible net worth, subject to an unsecured credit cap. The credit position is based on the initial market price,~~Generation, which is disclosed in the ~~forward price of energy on the day a transaction is executed, compared~~notes to the current forward price curve for energy. To the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to post collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. The unsecured credit used by the suppliers represents BGE’s net credit exposure. The seller’s credit exposure is calculated each business day. As of September 30, 2017, BGE had no net credit exposure to suppliers.

BGE’s regulated gas business is exposed to market-price risk. This market-price risk is mitigated by BGE’s recovery of its costs to procure natural gas through a gas cost adjustment clause approved by the MDPSC. BGE does make off-system sales after BGE has satisfied its customers’ demands, which are not covered by the gas cost adjustment clause. At September 30, 2017, BGE had credit exposure of less than $1 million related to off-system sales which is mitigated by parental guarantees, letters of credit or right to offset clauses within other contracts with those third-party suppliers.

Pepco’s, DPL's and ACE's power procurement contracts provide suppliers with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s lowest credit rating from the major credit rating agencies and the supplier’s tangible net worth. The credit position is based on the initial market price, which is the forward price of energy on the day a transaction is executed, compared to the current forward price curve for energy. To the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to post collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. The unsecured credit used by the suppliers represents Pepco’s, DPL's and ACE's net credit exposure. As of September 30, 2017, Pepco’s, DPL's and ACE's net credit exposures to suppliers were immaterial.

Pepco is permitted to recover its costs of procuring energy through the MDPSC-approved and DCPSC-approved procurement tariffs. DPL is permitted to recover its costs of procuring energy through the MDPSC-approved and DPSC-approved procurement tariffs. ACE is permitted to recover its costs of procuring energy through the NJBPU-approved procurement tariffs. Pepco’s, DPL's and ACE's counterparty credit risks are mitigated by their ability to recover realized energy costs through customer rates. See Note 3 — Regulatory Matters of the Exelon 2016 Form 10-K for additional information.

DPL’s natural gas procurement plan is reviewed and approved annually on a prospective basis by the DPSC. DPL’s counterparty credit risk under its natural gas supply and asset management agreements is mitigated by its ability to recover its natural gas costs through the GCR, which allows DPL to adjust rates annually to reflect realized natural gas prices. To the extent that thederivative fair value of the transactions in a net loss position exceeds the unsecured credit threshold, then collateral is required to be posted in an amount equal to the amount by which the unsecured credit threshold is exceeded. Exchange-traded contracts are required to be fully collateralized without regard to the credit rating of the holder. As of September 30, 2017, DPL had no credit exposure under its natural gas supply and asset management agreements with investment grade suppliers.balances tables above.

~~Collateral and Contingent-Related~~Credit-Risk-Related Contingent Features (All Registrants)

Generation. As part of the normal course of business, Generation routinely enters into ~~physical~~physically or financially settled contracts for the purchase and sale of electric capacity, ~~energy,~~electricity, fuels, emissions allowances, and other energy-related products. Certain of Generation’s derivative instruments contain provisions that require Generation to post collateral. Generation

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~~(Dollars in millions, except per share data, unless otherwise noted)~~

also enters into commodity transactions on exchanges ~~(i.e., NYMEX, ICE). The~~where the exchanges act as the counterparty to each trade. Transactions on the exchanges must adhere to comprehensive collateral and margining requirements. This collateral may be posted in the form of cash or credit support with thresholds contingent upon Generation’s credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. These credit-risk-related contingent features stipulate that if Generation were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. This incremental collateral requirement allows for the offsetting of derivative instruments that are assets with the same counterparty, where

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Note 12 — Derivative Financial Instruments

the contractual right of offset exists under applicable master netting agreements. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. In this case, Generation believes an amount of several months of future payments (i.e., capacity payments) rather than a calculation of fair value is the best estimate for the contingent collateral obligation, which has been factored into the disclosure below.

The aggregate fair value of all derivative instruments with ~~credit-risk-related~~credit-risk related contingent features in a liability position that are not fully collateralized (excluding transactions on the exchanges that are fully collateralized) is detailed in the table below:


Credit-Risk Related Contingent Features	September 30, 2021		December 31, 2020
Gross fair value of derivative contracts containing this feature(a)	$	(5,289)	$	(834)
Offsetting fair value of in-the-money contracts under master netting arrangements(b)	2,735		537
Net fair value of derivative contracts containing this feature(c)	$	(2,554)	$	(297)

Credit-Risk Related Contingent Feature September 30, 2017 December 31, 2016
Gross fair value of derivative contracts containing this feature^(a)
$ (916 ) $ (960 )
Offsetting fair value of in-the-money contracts under master netting arrangements^(b)
638
627
Net fair value of derivative contracts containing this feature^(c)
$ (278 ) $ (333 )
_________

~~_________~~

(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.


~~(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)~~	(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.

Generation ~~had~~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.

As of September 30, 2021 and December 31, 2020, Exelon and Generation posted or held the following amounts of cash collateral ~~posted of $460 million~~ and letters of credit ~~posted of $255 million and cash collateral held of $49 million and letters of credit held of $29 million as of September 30, 2017 for~~on derivative contracts with external counterparties, with derivative positions. Generation had cash collateral posted of $347 million and letters of credit posted of $284 million and cash collateral held of $24 million and letters of credit held of $28 million at December 31, 2016 for external counterparties with derivative positions. In the event of a credit downgrade below investment grade (i.e., to BB+ by S&P or Ba1 by Moody’s), Generation would have been required to post additional collateral of $1.8 billion and $1.9 billion as of September 30, 2017 and December 31, 2016, respectively. These amounts represent the potential additional collateral required after giving consideration to offsetting derivative and non-derivative positions under master netting agreements.

Generation’s and Exelon’s interest rate swaps contain provisions that, in the event of a merger, if Generation’s debt ratings were to materially weaken, it would be in violation of these provisions, resulting in the ability of the counterparty to terminate the agreement prior to maturity. Collateralization would not be required under any circumstance. Termination of the agreement could result in a settlement payment by Exelon or the counterparty on any interest rate swap in a net liability position. The settlement amount would be equal to the fair value of the swap on the termination date. As of September 30, 2017, Generation's swaps were in a liability position with a fair value of $4 million and Exelon's swaps were in an asset position, with a fair value of $6 million.

~~See Note 26 — Segment Information of the Exelon 2016 Form 10-K for further information regarding the letters of credit supporting the cash collateral.~~


	September 30, 2021		December 31, 2020
Cash collateral posted	$	299	$	511
Letters of credit posted	477		226
Cash collateral held	1,872		110
Letters of credit held	130		40
Additional collateral required in the event of a credit downgrade below investment grade	3,001		1,432

Generation entered into supply forward contracts with certain utilities, including PECO and BGE, with one-sided collateral postings only from Generation. If market prices fall below the benchmark price levels in these contracts, the utilities are not required to post collateral. However, when market prices rise above the benchmark price levels, counterparty suppliers, including Generation, are required to post collateral once certain unsecured credit limits are exceeded. ~~Under the terms of ComEd’s standard block energy~~

Utility Registrants

The Utility Registrants’ electric supply procurement contracts collateral postings are one-sided from suppliers, including Generation, should exposures between market prices and benchmark prices exceed established unsecured credit limits outlined in the contracts. As of September 30, 2017, ComEd held approximately $10 million in

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~~(Dollars in millions, except per share data, unless otherwise noted)~~

collateral from suppliers in association with energy procurement contracts. Under the terms of ComEd's annual renewable energy contracts, collateral postings are required to cover a fixed value for RECs only. In addition, under the terms of ComEd’s long-term renewable energy contracts, collateral postings are required from suppliers for both RECs and energy. The REC portion is a fixed value and the energy portion is one-sided from suppliers should the forward market prices exceed contract prices. As of September 30, 2017, ComEd held approximately $21 million in the form of cash and letters of credit as margin for both the annual and long-term REC obligations. If ComEd lost its investment grade credit rating as of September 30, 2017, itdo not contain provisions that would ~~have been required~~require them to post ~~approximately $3 million of collateral to its counterparties. See Note 3 — Regulatory Matters of the Exelon 2016 Form 10-K for additional information.~~collateral.

PECO’s, BGE’s, and DPL’s natural gas procurement contracts contain provisions that could require PECO, BGE, and DPL to post ~~collateral. This~~ collateral ~~may be posted~~ in the form of cash or credit support, which vary by contract and counterparty, with thresholds contingent upon PECO’s, BGE's, and DPL’s credit ~~rating from the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty.~~rating. As of September 30, ~~2017,~~2021, PECO, ~~was~~BGE, and DPL were not required to post collateral for any of these agreements. If PECO, BGE, or DPL lost ~~its~~their investment grade credit rating as of September 30, ~~2017, PECO~~2021, they could have been required to post ~~approximately $20 million of~~incremental collateral to ~~its counterparties.~~their counterparties of $23 million, $46 million, and $11 million, respectively.

~~PECO’s supplier master agreements that govern the terms~~

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Table of ~~its DSP Program contracts do not contain provisions that would require PECO to post collateral.~~Contents

~~BGE’s full requirements wholesale power agreements that govern the terms of its electric supply procurement contracts do not contain provisions that would require BGE to post collateral.~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

~~BGE’s natural gas procurement contracts contain provisions that could require BGE to post collateral. This collateral may be posted~~(Dollars in ~~the form of cash or credit support with thresholds contingent upon BGE’s credit rating from the major credit rating agencies. The collateral~~millions, except per share data, unless otherwise noted)

Note 13 — Debt and credit support requirements vary by contract and by counterparty. As of September 30, 2017, BGE was not required to post collateral for any of these agreements. If BGE lost its investment grade credit rating as of September 30, 2017, BGE could have been required to post approximately $28 million of collateral to its counterparties.Credit Agreements

~~Pepco’s full requirements wholesale power agreements that govern the terms of its electric supply procurement contracts do not contain provisions that would require Pepco to post collateral.~~

~~DPL’s full requirements wholesale power agreements that govern the terms of its electric supply procurement contracts do not contain provisions that would require DPL to post collateral.~~

DPL's natural gas procurement contracts contain provisions that could require DPL to post collateral. To the extent that the fair value of the natural gas derivative transaction in a net loss position exceeds the unsecured credit threshold, then collateral is required to be posted in an amount equal to the amount by which the unsecured credit threshold is exceeded. The DPL obligations are standalone, without the guaranty of PHI. If DPL lost its investment grade credit rating as of September 30, 2017, DPL could have been required to post an additional amount of approximately $9 million of collateral to its natural gas counterparties.

~~ACE’s full requirements wholesale power agreements that govern the terms of its electric supply procurement contracts do not contain provisions that would require ACE to post collateral.~~

~~11.~~13. Debt and Credit Agreements (All Registrants)

~~Short-Term Borrowings~~Nuclear Decommissioning Asset Retirement Obligations

~~Exelon, Pepco, DPL~~Generation has a legal obligation to decommission its nuclear power plants following the expiration of their operating licenses. To estimate its decommissioning obligation related to its nuclear generating stations for financial accounting and ~~ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper~~reporting purposes, Generation uses a probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios that include significant estimates and ~~short-term notes. ComEd~~assumptions, and ~~BGE meet their short-term liquidity requirements primarily through the issuance of commercial paper.~~are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models, and discount rates. Generation ~~and PECO meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the Exelon intercompany money pool. PHI meets~~updates its ~~short-term liquidity requirement primarily through the issuance of short-term notes and the Exelon intercompany money pool.~~

ARO annually, unless circumstances warrant more frequent

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(Dollars in millions, except per share data, unless otherwise noted)

Note 8 — Nuclear Decommissioning

~~Commercial Paper~~updates, based on its review of updated cost studies and its annual evaluation of cost escalation factors and probabilities assigned to various scenarios.

The ~~Registrants had~~financial statement impact for changes in the ARO, on an individual unit basis, due to the changes in and timing of estimated cash flows generally result in a corresponding change in the unit’s ARC in Property, plant, and equipment in Exelon’s and Generation’s Consolidated Balance Sheets. If the ARO decreases for a Non-Regulatory Agreement unit without any remaining ARC, the corresponding change is recorded as decrease in Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

The following ~~amounts~~table provides a rollforward of ~~commercial paper borrowings outstanding as of~~the nuclear decommissioning ARO reflected in Exelon’s and Generation’s Consolidated Balance Sheets from December 31, 2020 to September 30, ~~2017~~2021:


Nuclear decommissioning ARO at December 31, 2020(a)	$	11,922
Accretion expense	375
Net increase due to changes in, and timing of, estimated future cash flows	256
Costs incurred related to decommissioning plants	(57)
Nuclear decommissioning ARO at September 30, 2021(a)	$	12,496

_________

(a)Includes $74 million and $80 million as the current portion of the ARO at September 30, 2021 and December 31, ~~2016:~~2020, which is included in Other current liabilities in Exelon’s and Generation’s Consolidated Balance Sheets.

Commercial Paper Borrowings September 30, 2017 December 31, 2016
Exelon $ 118
$ 688
Generation —
620
BGE —
45
PHI 118
23
Pepco —
23
DPL 54
—
ACE 65
—
•An increase of approximately $510 million for updated cost escalation rates, primarily for labor and energy, and a decrease in discount rates.

~~Short-Term Loan Agreements~~

~~On January 13, 2016, PHI entered into~~•A net decrease of approximately $170 million was driven by updates to Byron and Dresden reflecting changes in assumed retirement dates and assumed methods of decommissioning as a ~~$500 million term loan agreement, which was amended on March 28, 2016. The net proceeds~~result of the ~~loan were used~~reversal of the decision to ~~repay PHI's outstanding commercial paper,~~early retire the plants. See Note 7 — Early Plant Retirements for additional information.

The 2021 ARO updates resulted in a decrease of $51 million in Operating and maintenance expense for ~~general corporate purposes. Pursuant~~the three and nine months ended September 30, 2021 in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.

NDT Funds

Accounting Implications of the Regulatory Agreements with ComEd and PECO

Based on the regulatory agreements with the ICC and PAPUC that dictate Generation’s obligations related to the ~~loan agreement, as amended, loans made thereunder bear interest at~~shortfall or excess of NDT funds necessary for decommissioning the former ComEd units on a variable rate equal to LIBOR plus 1%, and all indebtedness thereunder is unsecured. On March 23, 2017, the aggregate principal amount of all loans, together with any accrued but unpaid interest due under the loan agreement was fully repaidunit-by-unit basis and the ~~loan terminated. On March 23, 2017, Exelon Corporate entered into a similar type term loan for $500 million which expires~~former PECO units in total, decommissioning-related activities net of applicable taxes, including realized and unrealized gains and losses on ~~March 22, 2018. Pursuant to~~ the ~~loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 1%~~NDT funds, depreciation of the ARC, and ~~all indebtedness thereunder is unsecured. The loan agreement is reflected~~accretion of the decommissioning obligation, are generally offset in Exelon’s and Generation’s Consolidated ~~Balance Sheet within Short-Term borrowings.~~

~~Credit Agreements~~

~~On January 9, 2017, the credit agreement for Generation's $75 million bilateral credit facility was amended~~Statements of Operations and ~~restated to increase the facility size to $100 million~~Comprehensive Income and ~~extend the maturity to January 2019. This facility will solely be used~~are recorded by Generation ~~to issue letters of credit.~~

~~On May 26, 2016, Exelon Corporate, Generation, ComEd, PECO~~ and ~~BGE entered into amendments to each of their respective syndicated revolving credit facilities, which extended~~ the ~~maturity of each~~corresponding regulated utility as a component of the ~~facilities to May 26, 2021. Exelon Corporate also increased~~intercompany and regulatory balances in the ~~size~~balance sheet. For the purposes of its facility from $500 million to $600 million. On May 26, 2016, PHI, Pepco, DPL and ACE entered into an amendment to their Second Amended and Restated Credit Agreement dated as of August 1, 2011, which (i) extended the maturity date of the facility to May 26, 2021, (ii) removed PHI as a borrower under the facility, (iii) decreased the size of the facility from $1.5 billion to $900 million and (iv) converted its financial covenant from a debt to capitalization leverage ratio to an interest coverage ratio. On May 26, 2017, each of the Registrants' respective syndicated revolving credit facilities had their maturity dates extended to May 26, 2022.

making

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(Dollars in millions, except per share data, unless otherwise noted)

Note 8 — Nuclear Decommissioning

~~Long-Term Debt~~this determination, the decommissioning obligation referred to is different from the calculation used in the NRC minimum funding obligation filings based on NRC guidelines.

~~Issuance~~For the former ComEd units, given no further recovery from ComEd customers is permitted and Generation retains an obligation to ultimately return any unused NDTs to ComEd customers (on a unit-by-unit basis), to the extent the related NDT investment balances are expected to exceed the total estimated decommissioning obligation for each unit, decommissioning-related activities are offset in the Consolidated Statements of ~~Long-Term Debt~~

Operations and Comprehensive Income which results with Generation recognizing an intercompany payable to ComEd while ComEd records an intercompany receivable from Generation with a corresponding regulatory liability. However, given the asymmetric settlement provision that does not allow for continued recovery from ComEd customers in the event of a shortfall, recognition of a regulatory asset at ComEd is not permissible and accounting for decommissioning-related activities at Generation for that unit would not be offset, and the impact to Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income could be material during such periods. During the ~~nine months ended~~second and third quarter of 2021, a pre-tax charge of $53 million and $140 million, respectively, was recorded in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income for decommissioning-related activities that were not offset for the Byron units due to contractual offset being temporarily suspended. With Generation’s September ~~30, 2017,~~15, 2021 reversal of the ~~following long-term debt was issued:~~previous decision to retire Byron and the corresponding adjustment to the ARO for Byron discussed previously, Generation resumed contractual offset for Byron as of that date.

Company Type Interest Rate Maturity Amount Use of Proceeds
Exelon
Junior Subordinated Notes^(a)
3.50 % June 1, 2022 $ 1,150
Refinance Exelon's Junior Subordinated Notes issued in June 2014.
Generation Albany Green Energy Project Financing LIBOR + 1.25%
November 17, 2017 $ 14
Albany Green Energy biomass generation development.
Generation Energy Efficiency Project Financing 3.90 % February 1, 2018 $ 17
Funding to install energy conservation measures for the Naval Station Great Lakes project.
Generation Energy Efficiency Project Financing 2.61 % September 30, 2018 $ 10
Funding to install energy conservation measures for the Pensacola project.
Generation Energy Efficiency Project Financing 3.53 % April 1, 2019 $ 8
Funding to install energy conservation measures for the State Department project.
Generation Energy Efficiency Project Financing 3.72 % May 1, 2018 $ 4
Funding to install energy conservation measures for the Smithsonian Zoo project.
Generation Senior Notes 2.95 % January 15, 2020 $ 250
Repay outstanding commercial paper obligations and for general corporate purposes.
Generation Senior Notes 3.40 % March 15, 2022 $ 500
Repay outstanding commercial paper obligations and for general corporate purposes.
Generation ExGen Texas Power Nonrecourse Debt LIBOR + 4.75%
September 18, 2021 $ 6
Funding for general corporate purposes.
ComEd First Mortgage Bonds, Series 122 2.95 % August 15, 2027 $ 350
Refinance maturing first mortgage bonds, to repay a portion of ComEd’s outstanding commercial paper obligations and for general corporate purposes.
ComEd First Mortgage Bonds, Series 123 3.75 % August 15, 2047 $ 650
Refinance maturing first mortgage bonds, to repay a portion of ComEd’s outstanding commercial paper obligations and for general corporate purposes.
PECO First and Refunding Mortgage Bonds 3.70 % September 15, 2047 $ 325
General corporate purposes.
BGE Notes 3.75 % August 15, 2047 $ 300
Redeem $250 million in principal amount of the 6.20% Deferrable Interest Subordinated Debentures due October 15, 2043 issued by BGE's affiliate BGE Capital Trust II, repay commercial paper obligations and for general corporate purposes.
Pepco Energy Efficiency Project Financing 3.30 % December 15, 2017 $ 2
Funding to install energy conservation measures for the DOE Germantown project.
Pepco First Mortgage Bonds 4.15 % March 15, 2043 $ 200
Funding to repay outstanding commercial paper and for general corporate purposes.

~~_________~~


~~(a)~~	~~See the Junior Subordinated Notes discussion below for further information.~~

~~EGTP Nonrecourse Debt~~

In September 2014, EGTP, an indirect subsidiary of Exelon and Generation, issued $675 million aggregate principal amount of a nonrecourse senior secured term loan. The net proceeds were distributed to Generation for general business purposes. The loan is scheduled to mature on September 18, 2021. The term loan bears interest at a variable rate equal to LIBOR plus 4.75%, subject to a 1% LIBOR floor with interest payable quarterly. As of September 30, 2021, decommissioning-related activities for all of the former ComEd units, except for Zion, are currently offset in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

The decommissioning-related activities related to the Non-Regulatory Agreement Units are reflected in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

See Note 10 — Asset Retirement Obligations of the Exelon 2020 Form 10-K for additional information.

NRC Minimum Funding Requirements

9. Asset Impairments (Exelon and Generation)

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Note 9 — Asset Impairments

~~2017, $660~~regarding the recoverability of an asset or asset group and, thus, could potentially result in material future impairments of the Registrant's long-lived assets.

New England Asset Group

In the third quarter of 2020, in conjunction with the retirement announcement of Mystic Units 8 and 9, Generation completed a comprehensive review of the estimated undiscounted future cash flows of the New England asset group and concluded that the estimated undiscounted future cash flows and fair value of the New England asset group were less than their carrying values. As a result, a pre-tax impairment charge of $500 million was outstanding. As part of the agreement, a revolving credit facility was established for the amount of $20 million available through, and scheduled to mature on September 18, 2019. In addition to the financing, EGTP entered into various interest rate swaps with an initial notional amount of approximately $505 million at an interest rate of 2.34% to hedge a portion of the interest rate exposure in connection with this financing, as required by the debt covenants. See Note 10 — Derivative Financial Instruments for additional information regarding interest rate swaps.

~~On May 2, 2017, EGTP entered into a consent agreement with its lenders, which resulted~~recorded in the ~~outstanding debt balance being classified as Long-term debt due within one year on~~third quarter of 2020 in Operating and maintenance expense in Exelon's and Generation's Consolidated ~~Balance Sheets.~~Statements of Operations and Comprehensive Income. See Note ~~4 - Mergers, Acquisitions and Dispositions and Note 6 - Impairment of Long-Lived Assets~~7 — Early Plant Retirements for ~~more~~additional information.

~~Junior Subordinated Notes~~

In ~~June 2014, Exelon issued $1.15 billion~~the second quarter of ~~junior subordinated notes~~2021, an overall decline in the form of 23 million equity units at a stated amount of $50.00 per unit. Each equity unit represented an undivided beneficial ownership interest in Exelon’s $1.15 billion of 2.50% junior subordinated notes due in 2024 (“2024 notes”) and a forward equity purchase contract. As contemplated inasset group's portfolio value suggested that the ~~June 2014 equity unit structure, in April 2017, Exelon completed the remarketing~~carrying value of the ~~2024 notes into $1.15 billion of 3.497% junior subordinated notes due in 2022 (“Remarketing”). Exelon conducted the Remarketing on behalf~~New England asset group may be impaired. Generation completed a comprehensive review of the ~~holders of equity units and did not directly receive any proceeds therefrom. Instead, the former holders~~estimated undiscounted future cash flows of the ~~2024 notes used debt remarketing proceeds towards settling~~New England asset group and concluded that the ~~forward equity purchase contract with Exelon on June 1, 2017. Exelon issued approximately 33~~carrying value was not recoverable and that its fair value was less than its carrying value. As a result, a pre-tax impairment charge of $350 million shares of common stock from treasury stock and received $1.15 billion upon settlement of the forward equity purchase contract. When reissuing treasury stock Exelon uses the average price paid to repurchase shares to calculate a gain or loss on issuance and records gains or losses directly to retained earnings. A loss on reissuance of treasury shares of $1.05 billion was recorded ~~to retained earnings as of September 30, 2017. See Note 17 - Earnings Per Share and Equity for further information on the issuance of common stock.~~

~~Albany Green Energy Project~~

During the third quarter of 2017, upon completion of AGE, Generation retired $228 million of its LIBOR + 1.25% outstanding debt balance, which included $6 million of accumulated interest. Pursuant to the financing terms entered into by AGE in the second quarter of ~~2015,~~2021 in Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

Contracted Wind Project

In the ~~entire financing balance plus accumulated interest was due upon substantial completion, but no later than November 17, 2017. See Note 3 - Variable Interest Entities~~third quarter of 2021, significant long-term operational issues anticipated for ~~more details regarding AGE.~~

~~BGE Redemption~~a specific wind turbine technology suggested that the carrying value of ~~Trust Preferred Securities~~

~~On August 28, 2017, BGE redeemed all~~a contracted wind asset, located in Maryland and part of the ~~outstanding shares of BGE Capital Trust II 6.20% Preferred Securities (“Securities”), pursuant to the optional redemption provisions~~EGRP joint venture, may be impaired. Generation completed a comprehensive review of the ~~Indenture under~~estimated undiscounted future cash flows and concluded that the carrying value of this contracted wind project was not recoverable and that its fair value was less than its carrying value. As a result, in the third quarter of 2021, a pre-tax impairment charge of $45 million was recorded in Operating and maintenance expense, $21 million of which ~~the Securities were issued. The redemption price per share~~ was ~~$25.19, which equaled the stated value per share plus accrued~~offset in Net income attributable to noncontrolling interests in Exelon’s and unpaid dividends to, but excluding, the redemption date. No dividends on the Securities redeemed were accrued on or after the redemption date, nor did any interest accrue on amounts held to pay the redemption price.

Generation’s Consolidated Statements of Operations and Comprehensive Income.

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Note 10 — Income Taxes

~~12.~~10. Income Taxes (All Registrants)

Rate Reconciliation

The effective income tax rate from continuing operations varies from the U.S. ~~Federal~~federal statutory rate principally due to the following:


	Three Months Ended September 30, 2021

	Exelon(a)	Generation(a)	ComEd(a)	PECO(a)(b)	BGE(a)(b)	PHI(a)	Pepco(a)	DPL(a)	ACE(a)(b)
U.S. Federal statutory rate	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	6.0	4.4	8.0	(4.1)	(13.0)	5.0	3.4	6.4	7.0
Qualified NDT fund income	0.5	0.9	—	—	—	—	—	—	—

Amortization of investment tax credit, including deferred taxes on basis difference	(0.4)	(0.7)	(0.1)	—	(0.1)	(0.1)	—	(0.2)	(0.2)
Plant basis differences	(1.7)	—	(0.8)	(16.2)	(1.4)	(1.3)	(2.0)	(0.6)	(0.6)
Production tax credits and other credits	(1.0)	(1.4)	(0.5)	—	(0.9)	(0.5)	(0.5)	(0.4)	(0.5)
Noncontrolling interests	(0.4)	(0.6)	—	—	—	—	—	—	—
Excess deferred tax amortization	(6.8)	—	(7.6)	(3.4)	(17.3)	(24.9)	(17.6)	(19.9)	(41.4)

Other(c)	(4.8)	(1.9)	0.3	(0.1)	(0.8)	—	0.1	(0.6)	0.8
Effective income tax rate	12.4%	21.7%	20.3%	(2.8)%	(12.5)%	(0.8)%	4.4%	5.7%	(13.9)%

Three Months Ended September 30, 2017
Successor
Exelon
Generation
ComEd
PECO
BGE PHI Pepco DPL ACE
U.S. Federal statutory rate 35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit 2.2 5.6 6.6 (0.1) 5.3 5.1 2.2 5.3 5.6
Qualified nuclear decommissioning trust fund income 2.6 5.8 — — — — — — —
Amortization of investment tax credit, including deferred taxes on basis difference
(1.1) (2.2) (0.2) (0.1) (0.1) (0.2) (0.1) (0.2) (0.4)
Plant basis differences (2.6) — (0.3) (14.6) (0.8) (4.9) (6.7) (1.9) (3.4)
Production tax credits and other credits (2.2) (4.8) — — — — — — —
Noncontrolling interests 0.5 1.0 — — — — — — —
FitzPatrick bargain purchase gain (0.2) (0.4) — — — — — — —
Other (0.1) 0.3 (0.2) (0.2) (0.2) 0.2 — (0.2) 0.1
Effective income tax rate 34.1% 40.3% 40.9% 20.0% 39.2% 35.2% 30.4% 38.0% 36.9%


	Three Months Ended September 30, 2020
	Exelon(a)	Generation(a)	ComEd(a)	PECO(a)(d)	BGE(a)(d)	PHI(a)(d)	Pepco(a)(d)	DPL(a)(d)	ACE(a)(d)
U.S. Federal statutory rate	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	12.3	(10.3)	8.1	(6.2)	5.1	5.5	4.6	6.6	6.9
Qualified NDT fund income	13.2	47.4	—	—	—	—	—	—	—

Amortization of investment tax credit, including deferred taxes on basis difference	(1.4)	(4.5)	(0.2)	—	(0.1)	(0.2)	(0.1)	(0.2)	(0.3)
Plant basis differences	(4.3)	—	(0.6)	(23.3)	(1.2)	(1.5)	(2.1)	(0.4)	(1.3)
Production tax credits and other credits	(3.0)	(9.2)	(0.4)	—	(0.8)	(0.5)	(0.5)	(0.5)	(0.4)
Noncontrolling interests	0.8	2.9	—	—	—	—	—	—	—
Excess deferred tax amortization	(10.1)	—	(5.6)	(3.8)	(10.6)	(24.9)	(20.0)	(23.6)	(36.8)
Tax Settlements	(0.2)	(0.7)	—	—	—	—	—	—	—
Other	(0.8)	(0.9)	1.1	(0.8)	(0.3)	0.1	(0.4)	0.7	0.6
Effective income tax rate	27.5%	45.7%	23.4%	(13.1)%	13.1%	(0.5)%	2.5%	3.6%	(10.3)%

__________

(a)Positive percentages represent income tax expense. Negative percentages represent income tax benefit.

(b)For PECO, the income tax benefit is primarily due to plant basis differences attributable to tax repair deductions. For BGE,

Three Months Ended September 30, 2016
Successor
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
U.S. Federal statutory rate 35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit 3.8 2.6 7.3 2.4 5.2 5.6 5.6 5.2 6.1
Qualified nuclear decommissioning trust fund income 4.0 7.8 — — — — — — —
Amortization of investment tax credit, including deferred taxes on basis difference (0.9) (1.6) (0.6) (0.1) (0.2) (0.1) — (0.2) (0.1)
Plant basis differences (3.0) — (1.9) (6.7) (0.5) (5.0) (6.7) (1.3) (4.6)
Production tax credits and other credits (2.9) (5.7) (0.1) — — — — — —
Noncontrolling interest 0.2 0.5 — — — — — — —
Statute of limitations expiration

(0.1) 0.3 — — — — — — —
Penalties 4.3 — 27.2 — — — — — —
Merger expenses

(0.6) — — — — (5.7) (2.3) (8.6) (2.9)
Other (0.8) (0.5) 0.1 0.1 (0.4) (0.7) (0.9) 0.1 (0.6)
Effective income tax rate 39.0% 38.4% 67.0% 30.7% 39.1% 29.1% 30.7% 30.2% 32.9%

~~136~~

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— ~~(Continued)~~

(Dollars in millions, except per share data, unless otherwise noted)

Note 10 — Income Taxes

the income tax benefit is primarily due to the Maryland multi-year plan which resulted in the acceleration of certain income tax benefits. For ACE, the income tax benefit is primarily due to a distribution rate case settlement which allows ACE to retain certain tax benefits.

(d)At PECO, the lower effective tax rate is primarily related to an increase in plant basis differences attributable to storm tax repair deductions. At BGE, PHI, Pepco, DPL and ACE, the lower effective tax rate is primarily attributable to accelerated amortization of transmission related deferred income tax regulatory liabilities as a result of regulatory settlements.


	Nine Months Ended September 30, 2021
	Exelon(a)	Generation(b)	ComEd(a)	PECO(a)(c)	BGE(a)(c)	PHI(a)	Pepco(a)	DPL(a)	ACE(a)(c)
U.S. Federal statutory rate	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	3.0	90.2	7.6	(2.6)	(10.8)	4.6	2.5	6.5	7.3
Qualified NDT fund income	9.4	(1,932.6)	—	—	—	—	—	—	—

Amortization of investment tax credit, including deferred taxes on basis difference	(0.8)	130.6	(0.1)	—	(0.1)	(0.1)	—	(0.2)	(0.2)
Plant basis differences	(3.9)	—	(0.7)	(12.6)	(1.5)	(1.3)	(1.9)	(0.7)	(0.6)
Production tax credits and other credits	(2.6)	425.1	(0.5)	—	(0.9)	(0.5)	(0.5)	(0.4)	(0.5)
Noncontrolling interests	(0.7)	145.2	—	—	—	—	—	—	—
Excess deferred tax amortization	(13.9)	—	(7.2)	(3.3)	(16.0)	(22.8)	(17.4)	(19.7)	(36.3)

Other(d)	2.2	(229.5)	(1.3)	(0.2)	(0.7)	(0.3)	(0.4)	(0.2)	—
Effective income tax rate	13.7%	(1,350.0)%	18.8%	2.3%	(9.0)%	0.6%	3.3%	6.3%	(9.3)%

Nine Months Ended September 30, 2017
Successor
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
U.S. Federal statutory rate 35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit 0.7 2.1 5.9 (0.1) 5.2 4.9 3.0 5.1 5.6
Qualified nuclear decommissioning trust fund income 4.0 14.0 — — — — — — —
Amortization of investment tax credit, including deferred taxes on basis difference (0.9) (2.7) (0.2) (0.1) (0.1) (0.2) (0.1) (0.2) (0.4)
Plant basis differences (3.4) — (0.3) (14.4) (0.8) (4.6) (6.3) (1.8) (3.4)
Production tax credits and other credits (1.8) (6.2) — — — — — — —
Noncontrolling interests 0.2 0.7 — — — — — — —
Merger expenses (5.4) (2.5) — — — (11.8) (8.0) (10.0) (23.0)
FitzPatrick bargain purchase gain (3.2) (11.2) — — — — — — —
Like-kind exchange^(a)
(1.7) — 1.7 — — — — — —
Other — (0.4) 0.2 — 0.2 — (0.3) 0.6 (0.3)
Effective income tax rate 23.5% 28.8% 42.3% 20.4% 39.5% 23.3% 23.3% 28.7% 13.5%

~~137~~

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— ~~(Continued)~~

(Dollars in millions, except per share data, unless otherwise noted)

Successor Predecessor
Nine Months Ended September 30, 2016 March 24, 2016 to September 30, 2016 January 1, 2016 to March 23, 2016
Exelon Generation ComEd PECO BGE Pepco
DPL^(b)

ACE^(b)

PHI^(b)
PHI
U.S. Federal statutory rate 35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0% 35.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit^(c)
2.5 2.6 5.4 1.3 4.8 23.0 310.5 5.5 4.4 11.9
Qualified nuclear decommissioning trust fund income 4.8 8.8 — — — — — — — —
Amortization of investment tax credit, including deferred taxes on basis difference (1.3) (2.0) (0.3) (0.1) (0.2) (0.2) (17.9) 0.5 0.5 (0.9)
Plant basis differences (4.5) — (0.6) (8.8) (3.3) (29.0) (98.6) 7.8 17.5 (13.5)
Production tax credits and other credits (4.1) (7.6) — — — — — — — —
Noncontrolling interest 0.5 0.9 — — — — — — — —
Statute of limitations expiration
(0.5) (1.7) — — — — — — — —
Penalties 2.3 — 5.6 — — — — — — —
Merger expenses
6.2 — — — — 36.7 635.9 (35.4) (49.8) 11.1
Other (1.8) (2.1) — (1.5) — (2.5) 35.1 0.4 1.4 3.6
Effective income tax rate 39.1% 33.9% 45.1% 25.9% 36.3% 63.0% 900.0%
13.8%
9.0% 47.2%

~~_________~~


~~(a)~~	~~See Like-Kind Exchange within the Other Income Tax Matters section below for further details.~~


~~(b)~~	DPL and ACE recognized a loss before income taxes for the nine months ended September 30, 2016, and PHI recognized a loss before income taxes for the period of March 24, 2016, through September 30, 2016. As a result, positive percentages represent an income tax benefit for the periods presented.


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

~~Accounting for Uncertainty in~~Note 10 — Income Taxes

~~The Registrants~~


	Nine Months Ended September 30, 2020
	Exelon(a)	Generation(a)	ComEd(a)(e)	PECO(a)(e)	BGE(a)(e)	PHI(a)(e)	Pepco(a)(e)	DPL(a)(e)	ACE(a)(e)
U.S. Federal statutory rate	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	9.3	—	12.7	(3.4)	5.5	5.0	4.2	6.5	6.8
Qualified NDT fund income	3.2	10.0	—	—	—	—	—	—	—
Deferred Prosecution Agreement payments	2.5	—	9.4	—	—	—	—	—	—
Amortization of investment tax credit, including deferred taxes on basis difference	(1.2)	(3.2)	(0.3)	—	(0.1)	(0.2)	(0.1)	(0.3)	(0.5)
Plant basis differences	(4.0)	—	(0.9)	(15.9)	(1.8)	(2.2)	(2.4)	(0.5)	(3.7)
Production tax credits and other credits	(2.6)	(7.0)	(0.4)	—	(0.4)	(0.3)	(0.3)	(0.2)	(0.4)
Noncontrolling interests	1.0	3.1	—	—	—	—	—	—	—
Excess deferred tax amortization	(15.8)	—	(11.8)	(3.5)	(15.0)	(45.3)	(29.2)	(53.6)	(81.4)
Tax Settlements(f)	(5.0)	(15.7)	—	—	—	—	—	—	—
Other	0.1	(0.5)	2.1	(0.5)	(0.5)	(0.6)	(0.8)	(1.1)	—
Effective income tax rate	8.5%	7.7%	31.8%	(2.3)%	8.7%	(22.6)%	(7.6)%	(28.2)%	(58.2)%

__________

(a)Positive percentages represent income tax expense. Negative percentages represent income tax benefit.

(b)Generation recognized a loss before income taxes for the nine months ended September 30, 2021. As a result, a negative percentage represents an income tax expense for the period presented.

(e)For ComEd, the ~~following~~higher effective tax rate is primarily related to the nondeductible Deferred Prosecution Agreement payments. For PECO, the income tax benefit is primarily related to an increase in plant basis differences attributable to storm tax repairs deductions. For BGE, PHI, Pepco, DPL, and ACE, the income tax benefit is primarily attributable to accelerated amortization of transmission related deferred income tax regulatory liabilities as a result of regulatory settlements.

(f)Exelon's and Generation’s unrecognized federal and state tax benefits asdecreased in the first quarter of ~~September 30, 2017~~2020 by approximately $411 million due to the settlement of a federal refund claim with IRS Appeals. The recognition of these tax benefits resulted in an increase to Exelon's and ~~December 31, 2016:~~Generation’s net income of $76 million and $73 million, respectively, in the first quarter of 2020, reflecting a decrease to Exelon's and Generation's income tax expense of $67 million.

Unrecognized Tax Benefits

100

Successor
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
September 30, 2017 $ 738
$ 468
$ 2
$ —
$ 120
$ 120
$ 59
$ 21
$ 8

Successor
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
December 31, 2016 $ 916
$ 490
$ (12 ) $ —
$ 120
$ 172
$ 80
$ 37
$ 22

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— ~~(Continued)~~

(Dollars in millions, except per share data, unless otherwise noted)

Note 10 — Income Taxes

first quarter 2017, as a part of its examination of Exelon’s return, the IRS National Office issued guidance concurring with Exelon’s position that the merger commitments were deductible. As a result, Exelon, Generation, PHI ~~Pepco, DPL,~~ and ACE ~~decreased their liability for~~have the following unrecognized tax benefits ~~by $146 million, $19 million, $59 million, $21 million, $16 million, and $22 million, respectively,~~ as of September 30, ~~2017, resulting in a benefit to Income taxes on Exelon’s, Generation’s, PHI’s, Pepco’s, DPL’s~~2021 and ~~ACE’s Consolidated Statements of Operations~~December 31, 2020. Exelon's, Generation's, ComEd's, PECO's, BGE's, Pepco's, and ~~Comprehensive Income and corresponding decreases in their effective tax rates.~~DPL's amounts are not material.

Exelon reduced the liability related to the uncertain tax position associated with the like-kind exchange in the second quarter of 2017. Please see the Other Income Tax Matters section below for additional details related to the like-kind exchange adjustments made in the second quarter of 2017.


	PHI		ACE
September 30, 2021	$	56	$	16
December 31, 2020	52		15

Reasonably possible the total amount of unrecognized tax benefits could significantly increase or decrease within 12 months after the reporting date

~~Like-Kind Exchange~~

As of September 30, ~~2017, Exelon and ComEd have~~2021, ACE has approximately $39 million and $2 million, respectively, of unrecognized federal and state income tax benefits that could significantly decrease within the 12 months after the reporting date due to a final resolution of the like-kind exchange litigation described below. The recognition of these unrecognized tax benefits would decrease Exelon and ComEd's effective tax rate.

~~Settlement of Income Tax Positions~~

~~As of September 30, 2017, Exelon, Generation, BGE, PHI, Pepco, DPL, and ACE have approximately $676 million, $469 million, $120 million, $88 million, $59 million, $21 million, and $8~~$14 million of unrecognized ~~federal and~~ state tax benefits that could significantly decrease within the 12 months after the reporting date ~~as a result of completing audits, potential settlements, and~~based on the ~~outcomes~~outcome of pending court ~~cases. Of the above unrecognized tax benefits, Exelon and Generation have $462 million that, if recognized, would decrease the effective tax rate.~~cases involving other taxpayers. The unrecognized tax ~~benefits related to BGE, DPL, ACE, and a portion of Pepco,~~benefit, if recognized, may be included in future ~~regulated~~ base rates and that portion would have no impact to the effective tax rate.

Other Income Tax Matters

~~Like-Kind Exchange~~CENG Put Option (Exelon and ~~ComEd)~~Generation)

On August 6, 2021, Generation and EDF entered into a settlement agreement pursuant to which Generation purchased EDF’s equity interest in CENG. Exelon ~~through~~and Generation recorded deferred tax liabilities of $290 million and $288 million, respectively, against Common Stock in Exelon’s Consolidated Balance Sheet and Membership Interest in Generation’s Consolidated Balance Sheet. The deferred tax liabilities represent the tax effect on the difference between the net purchase price and EDF’s noncontrolling interest as of August 6, 2021. The deferred tax liabilities will reverse during the remaining operating lives and during decommissioning of the CENG nuclear plants. See Note 2 – Mergers, Acquisitions, and Dispositions for additional information.

Long-Term Marginal State Income Tax Rate (All Registrants)

In the third quarter of 2021 and 2020, Exelon updated its ~~ComEd subsidiary, took a position on its 1999~~marginal state income tax ~~return~~rates for changes in state apportionment. The changes in marginal rates in the third quarter of 2021 resulted in an increase of $27 million to ~~defer approximately $1.2 billion~~the deferred income tax liability at Exelon, and a corresponding adjustment to income tax expense, net of federal taxes. The changes in marginal rates in the third quarter of 2020 resulted in an increase of $66 million and a decrease of $26 million to the deferred income tax liability at Exelon and Generation, respectively. Exelon and Generation recorded a corresponding adjustment to income tax expense, net of federal taxes.

Allocation of Tax Benefits (All Registrants)

Generation and the Utility Registrants are all party to an agreement with Exelon and other subsidiaries of Exelon that provides for the allocation of consolidated tax liabilities and benefits (Tax Sharing Agreement). The Tax Sharing Agreement provides that each party is allocated an amount of tax gain on the sale of ComEd’s fossil generating assets. The gain was deferred by reinvesting a portion of the proceeds from the sale in qualifying replacement property under the like-kind exchange provisions of the IRC. The like-kind exchange replacement property purchased by Exelon included interests in three municipal-owned electric generation facilities which were properly leased back to the municipalities.

The IRS disagreed with this position and asserted that the entire gain of approximately $1.2 billion was taxable in 1999. Exelon was unable to reach agreement with the IRS regarding the dispute over the like-kind exchange position. The IRS asserted that the Exelon purchase and leaseback transaction was substantially similar to ~~a leasing transaction, known as a SILO,~~that which would be owed had the IRS does not respect as the acquisition of an ownership interest in property. A SILO is a “listed transaction” that the IRS has identified as a potentially abusive tax shelter under guidance issued in 2005. Accordingly, the IRS asserted that the sale of the fossil plants followed by the purchase and leaseback of the municipal owned generation facilities did not qualify as a like-kind exchange and the gain on the sale is fullyparty been separately subject to tax. ~~The IRS also asserted a penalty of approximately $90 million for a substantial understatement of tax.~~

~~On September 30, 2013, the IRS issued a notice of deficiency~~In addition, any net benefit attributable to Exelon ~~for~~is reallocated to the ~~like-kind exchange position. Exelon filed~~other Registrants. That allocation is treated as a ~~petition on December 13, 2013~~contribution to ~~initiate litigation in~~ the ~~United States Tax Court (Tax Court) and the trial took place in August of 2015. Exelon was not required to remit any part~~capital of the ~~asserted~~party receiving the benefit.

The following table presents the allocation of federal tax ~~or penalty in order to litigate the issue.~~

~~On September 19, 2016,~~benefits from Exelon under the Tax ~~Court rejected Exelon’s position~~Sharing Agreement.


	Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
September 30, 2021	$	64	$	1	$	19	$	—	$	17	$	16	$	—	$	—
September 30, 2020	64		14		17		—		17		8		6		1

11. Retirement Benefits (All Registrants)

Defined Benefit Pension and OPEB

During the first quarter of 2021, Exelon received an updated valuation of its pension and OPEB to reflect actual census data as of January 1, 2021. This valuation resulted in the case and ruled that Exelon was not entitled to defer gain on the transaction. In addition, contrary to Exelon’s evaluation that the penalty was unwarranted, the Tax Court ruled that Exelon is liable for the penalty and interest due on the asserted penalty. In June of 2017, the IRS finalized its computation of tax, penalties and interest owed by Exelon pursuantan increase to the ~~Tax Court’s decision. In September~~pension obligations of ~~2017, Exelon appealed this decision~~$33 million and a decrease to the ~~U.S. Court~~OPEB obligations of ~~Appeals for the Seventh Circuit.~~

$9 million. Additionally, accumulated other comprehensive loss

~~139~~

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— ~~(Continued)~~

(Dollars in millions, except per share data, unless otherwise noted)

Note 11 — Retirement Benefits

In the first quarter of 2013, Exelon concluded that it was no longer more likely than not that the like-kind exchange position would be sustained and recorded charges to earnings representing the amount of interest expenseincreased by $1 million (after-tax) and ~~incremental state income tax expense that would be payable~~regulatory assets and liabilities increased by $21 million and $1 million, respectively.

A portion of the net periodic benefit cost for all plans is capitalized in the ~~event Exelon is unsuccessful in litigation. Exelon agreed~~Consolidated Balance Sheets. The following table presents the components of Exelon's net periodic benefit costs, prior to ~~hold ComEd harmless from any unfavorable impacts on ComEd’s equity of the after-tax interest and penalty amounts.~~

Prior to the Tax Court’s decision, however, Exelon did not believe it was likely a penalty would be assessed based on applicable case law and the facts of the transaction. As a result, no charge had been recordedcapitalization, for the ~~penalty or for after-tax interest on the penalty. While it has strong arguments on appeal with respect to both the merits~~three and the penalty, Exelon has determined that, pursuant to accounting standards, it is no longer more likely than not to avoid ultimate imposition of the penalty. As a result, in the third quarter of 2016, Exelon and ComEd recorded a charge to earnings of approximately $106 million and $86 million, respectively, of penalty and approximately $94 million and $64 million, respectively, of after-tax interest. Exelon and ComEd recorded the penalty and pre-tax interest due on the asserted penalty to Other, net and Interest expense, net, respectively, on their Consolidated Statements of Operations. Consistent with Exelon’s agreement to continue to hold ComEd harmless from any unfavorable impact on its equity from the like-kind exchange position, ComEd recorded on its Consolidated Balance Sheets as ofnine months ended September 30, ~~2016, an additional $150 million receivable~~2021 and ~~non-cash equity contributions from Exelon.~~2020.

As a result of the IRS’s finalization of its computation in the second quarter 2017, Exelon recorded a benefit to earnings of approximately $26 million, consisting of an income tax benefit of $50 million and a reduction of penalties of $2 million, partially offset by after-tax interest expense of $26 million, while ComEd recorded a charge to earnings of approximately $23 million, consisting of income tax expense of $15 million and after-tax interest expense of $8 million.



	Pension Benefits				OPEB
	Three Months Ended September 30,				Three Months Ended September 30,
	2021		2020		2021		2020
Components of net periodic benefit cost:
Service cost	$	110	$	97	$	20	$	22
Interest cost	161		190		29		37
Expected return on assets	(335)		(317)		(40)		(41)
Amortization of:
Prior service cost (credit)	1		1		(8)		(30)
Actuarial loss	150		128		9		12
Settlement charges	12		8		—		—

Net periodic benefit cost	$	99	$	107	$	10	$	—

In the second quarter of 2017, Exelon amended its agreement with ComEd to also hold ComEd harmless for the unfavorable impacts on its equity from the additional income tax amounts owed by ComEd as a result of the IRS’s finalization of its computation related to the like-kind exchange position. Accordingly, in the second quarter of 2017, ComEd recorded an additional receivable and non-cash equity contribution from Exelon for the total $23 million. As of June 30, 2017, ComEd had a total receivable from Exelon pursuant to the hold harmless agreement of $369 million, which was included in Current Receivables from Affiliates on ComEd’s Consolidated Balance Sheet.

Exelon expects to pay the tax, penalties and interest of approximately $1.3 billion related to the like-kind exchange, including $300 million attributable to ComEd, in the fourth quarter of 2017. While Exelon will receive a tax benefit of approximately $350 million associated with the deduction for the interest, Exelon currently has a net operating loss carryforward and thus does not expect to realize the cash benefit until 2018. After taking into account these interest deduction tax benefits, the total estimated net cash outflow for the like-kind exchange is approximately $950 million, of which approximately $300 million is attributable to ComEd after giving consideration to Exelon’s agreement to hold ComEd harmless from any unfavorable impacts on ComEd’s equity from the like-kind exchange position. Following a final appellate decision, which is expected in 2018, Exelon expects to receive approximately $60 million related to final interest computations.



	Pension Benefits				OPEB
	Nine Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Components of net periodic benefit cost:
Service cost	$	330	$	290	$	60	$	67
Interest cost	481		569		86		114
Expected return on assets	(1,003)		(953)		(119)		(122)
Amortization of:
Prior service cost (credit)	3		3		(25)		(92)
Actuarial loss	449		384		27		36
Curtailment benefits	—		—		(1)		—
Settlement charges	16		14		—		—

Net periodic benefit cost	$	276	$	307	$	28	$	3

Of the above amounts payable, Exelon deposited with the IRS $1.25 billion in October of 2016. Any remaining amounts due to the IRS will be paid by Exelon in the fourth quarter of 2017. Exelon funded the $1.25 billion deposit with a combination of cash on hand and short-term borrowings. The deposit is reflected as a current asset and the related liabilities for the tax, penalty, and interest are included on Exelon’s balance sheet as current obligations. In the third quarter of 2017, the $300 million payable discussed above attributable to ComEd, net of ComEd’s receivable pursuant to the hold harmless agreement, was settled with Exelon. No recovery will be sought from ComEd customers for any interest, penalty, or additional income tax payment amounts resulting from the like-kind exchange tax position.

As previously disclosed, in the first quarter of 2014, Exelon entered into an agreement to terminate its investment in one of the three municipal-owned electric generation properties in exchange for a net early termination amount of $335 million. In the first quarter of 2016, Exelon terminated its interests in the remaining two municipal-owned electric generation properties in exchange for $360 million.

~~Long-Term Marginal State Income Tax Rate (Exelon, Generation, ComEd, PHI and Pepco)~~

Exelon, Generation and PHI periodically review events that may significantly impact how income is apportioned among the states and, therefore, the calculation of their respective deferred state income taxes. Events that may require Exelon, Generation and PHI to update their long-term state tax apportionment include significant changes in tax law

~~140~~

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(Dollars in millions, except per share data, unless otherwise noted)

Note 11 — Retirement Benefits

~~and/or significant operational changes. Exelon's, PHI's~~The amounts below represent the Registrants' allocated pension and ~~Pepco's long-term marginal state income tax rate were revised~~OPEB costs. For Exelon, the service cost component is included in Operating and maintenance expense and Property, plant, and equipment, net while the ~~first quarter of 2017 as a result of a statutory rate change~~non-service cost components are included in ~~Washington, D.C. As a result, Exelon, PHI~~Other, net and Pepco recorded a one-time decrease to Deferred income tax liability of $28 million, $8 million, and $8 million, respectively, on their Consolidated Balance Sheets. Because income taxes are recovered through customer rates, Exelon, PHI and Pepco recorded a corresponding regulatory liability of $8 million, in the Consolidated Balance Sheets. In addition, Exelon recorded a decrease to Income tax expense of $20 million, net of federal taxes, in the Consolidated Statements of Operations and Comprehensive Income for the three months ended March 31, 2017.

~~In the third quarter of 2017, Exelon reviewed and updated its marginal state income tax rates based on 2016 state apportionment rates. In addition, Exelon,~~Regulatory assets. For Generation and ~~ComEd recorded~~ the ~~impacts of Illinois’ statutory rate change, which increased~~Utility Registrants, the ~~total corporate income tax rate from 7.75% to 9.5% effective July 1, 2017. As a result~~service cost and non-service cost components are included in Operating and maintenance expense and Property, plant, and equipment, net in their consolidated financial statements.


	Three Months Ended September 30,				Nine Months Ended September 30,
Pension and OPEB Costs	2021		2020		2021		2020
Exelon	$	109	$	107	$	304	$	310
Generation	36		30		92		89
ComEd	32		29		97		85
PECO	2		1		5		4
BGE	16		16		47		47
PHI	12		17		36		52
Pepco	2		4		5		11
DPL	1		2		2		6
ACE	3		3		8		10

Defined Contribution Savings Plans

The Registrants participate in various 401(k) defined contribution savings plans that are sponsored by Exelon. The plans are qualified under applicable sections of the ~~rate changes,~~IRC and allow employees to contribute a portion of their pre-tax and/or after-tax income in accordance with specified guidelines. All Registrants match a percentage of the ~~third quarter of 2017, Exelon, Generation and ComEd recorded a one-time increase~~employee contributions up to Deferred income taxes of approximately $250 million, $20 million and $270 million, respectively, on their Consolidated Balance Sheets. Because income taxes are recovered through customer rates, each of Exelon and ComEd recorded a corresponding regulatory asset of $272 million. Further, Exelon recorded a decreasecertain limits. The following table presents the matching contributions to ~~Income tax expense of approximately $20 million and Generation recorded an increase to Income tax expense of approximately $20 million (each net of federal taxes) in their Consolidated Statements of Operations and Comprehensive Income~~the savings plans for the three and nine months ended September 30, ~~2017.~~ 2021 and 2020, respectively.


	Three Months Ended September 30,				Nine Months Ended September 30,
Savings Plans Matching Contributions	2021		2020		2021		2020
Exelon	$	38	$	37	$	107	$	104
Generation	14		14		40		41
ComEd	9		9		27		25
PECO	2		3		8		8
BGE	4		4		8		8
PHI	5		3		12		9
Pepco	1		1		3		3
DPL	1		1		3		2
ACE	1		—		2		1

12. Derivative Financial Instruments (All Registrants)

The ~~Illinois statutory~~Registrants use derivative instruments to manage commodity price risk, interest rate ~~increase~~risk, and foreign exchange risk related to ongoing business operations.

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Note 12 — Derivative Financial Instruments

Commodity Price Risk (All Registrants)

Each of the Registrants employ established policies and procedures to manage their risks associated with market fluctuations in commodity prices by entering into physical and financial derivative contracts, including swaps, futures, forwards, options, and short-term and long-term commitments to purchase and sell energy and commodity products. The Registrants believe these instruments, which are either determined to be non-derivative or classified as economic hedges, mitigate exposure to fluctuations in commodity prices.

Generation. To the extent the amount of energy Generation produces differs from the amount of energy it has contracted to sell, Exelon and Generation are exposed to market fluctuations in the prices of electricity, fossil fuels, and other commodities. Within Exelon, Generation has the most exposure to commodity price risk. As such, Generation uses a variety of derivative and non-derivative instruments to manage the commodity price risk of its electric generation facilities, including power and gas sales, fuel and power purchases, natural gas transportation and pipeline capacity agreements, and other energy-related products marketed and purchased. To manage these risks, Generation may enter into fixed-price derivative or non-derivative contracts to hedge the variability in future cash flows from expected sales of power and gas and purchases of power and fuel. The objectives for executing such hedges include fixing the price for a portion of anticipated future electricity sales at a level that provides an acceptable return. Generation is also exposed to differences between the locational settlement prices of certain economic hedges and the hedged generating units. This price difference is actively managed through other instruments which include derivative congestion products, whose changes in fair value are recognized in earnings each period, and auction revenue rights, which are accounted for on an accrual basis.

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Note 12 — Derivative Financial Instruments

mechanisms. The following table provides a summary of the Utility Registrants’ primary derivative hedging instruments, listed by commodity and accounting treatment.


Registrant	Commodity	Accounting Treatment	Hedging Instrument
ComEd	Electricity	NPNS	Fixed price contracts based on all requirements in the IPA procurement plans.
	Electricity	Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability(a)	20-year floating-to-fixed energy swap contracts beginning June 2012 based on the renewable energy resource procurement requirements in the Illinois Settlement Legislation of approximately 1.3 million MWhs per year.
PECO	Electricity	NPNS	Fixed price contracts for default supply requirements through full requirements contracts.
	Gas	NPNS	Fixed price contracts to cover about 10% of planned natural gas purchases in support of projected firm sales.
BGE	Electricity	NPNS	Fixed price contracts for all SOS requirements through full requirements contracts.
	Gas	NPNS	Fixed price contracts for between 10-20% of forecasted system supply requirements for flowing (i.e., non-storage) gas for the November through March period.
Pepco	Electricity	NPNS	Fixed price contracts for all SOS requirements through full requirements contracts.
DPL	Electricity	NPNS	Fixed price contracts for all SOS requirements through full requirements contracts.
	Gas	NPNS	Fixed and Index priced contracts through full requirements contracts.
		Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability(b)	Exchange traded future contracts for up to 50% of estimated monthly purchase requirements each month, including purchases for storage injections.
ACE	Electricity	NPNS	Fixed price contracts for all BGS requirements through full requirements contracts.

__________

(a)See Note 3 — Regulatory Matters of the 2020 Form 10-K for additional information.

(b)The fair value of the DPL economic hedge is not ~~expected~~material as of September 30, 2021 and December 31, 2020 and is not presented in the fair value tables below.

The following tables provide a summary of the derivative fair value balances recorded by Exelon, Generation, and ComEd as of September 30, 2021 and December 31, 2020:


	Exelon		Generation										ComEd
September 30, 2021	Total Derivatives		Economic Hedges		Proprietary Trading		Collateral(a)(b)		Netting(a)		Subtotal		Economic Hedges
Mark-to-market derivative assets (current assets)	$	1,505	$	19,631	$	63	$	(790)	$	(17,399)	$	1,505	$	—
Mark-to-market derivative assets (noncurrent assets)	661		3,612		5		(201)		(2,755)		661		—
Total mark-to-market derivative assets	2,166		23,243		68		(991)		(20,154)		2,166		—
Mark-to-market derivative liabilities (current liabilities)	(1,710)		(18,490)		(55)		(559)		17,399		(1,705)		(5)
Mark-to-market derivative liabilities (noncurrent liabilities)	(720)		(3,168)		(3)		(95)		2,755		(511)		(209)
Total mark-to-market derivative liabilities	(2,430)		(21,658)		(58)		(654)		20,154		(2,216)		(214)
Total mark-to-market derivative net (liabilities) assets	$	(264)	$	1,585	$	10	$	(1,645)	$	—	$	(50)	$	(214)

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Note 12 — Derivative Financial Instruments


	Exelon		Generation										ComEd
December 31, 2020	Total Derivatives		Economic Hedges		Proprietary Trading		Collateral(a)(b)		Netting(a)		Subtotal		Economic Hedges
Mark-to-market derivative assets (current assets)	$	639	$	2,757	$	40	$	103	$	(2,261)	$	639	$	—
Mark-to-market derivative assets (noncurrent assets)	554		1,501		4		64		(1,015)		554		—
Total mark-to-market derivative assets	1,193		4,258		44		167		(3,276)		1,193		—
Mark-to-market derivative liabilities (current liabilities)	(293)		(2,629)		(23)		131		2,261		(260)		(33)
Mark-to-market derivative liabilities (noncurrent liabilities)	(472)		(1,335)		(2)		118		1,015		(204)		(268)
Total mark-to-market derivative liabilities	(765)		(3,964)		(25)		249		3,276		(464)		(301)
Total mark-to-market derivative net assets (liabilities)	$	428	$	294	$	19	$	416	$	—	$	729	$	(301)

_________

(b)Includes $2,084 million held and $209 million posted of variation margin with the exchanges as of September 30, 2021 and December 31, 2020 respectively.

Economic Hedges (Commodity Price Risk)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Income Statement Location	(Loss) Gain				(Loss) Gain
Operating revenues	$	(637)	$	39	$	(961)	$	238
Purchased power and fuel	1,392		209		2,209		224
Total Exelon and Generation	$	755	$	248	$	1,248	$	462

In general, increases and decreases in forward market prices have a ~~material ongoing~~positive and negative impact, respectively, on Generation’s owned and contracted generation positions that have not been hedged. Generation hedges commodity price risk on a ratable basis over three-year periods. As of September 30, 2021, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York, and ERCOT reportable segments is 96%-99% for the remainder of 2021.

Proprietary Trading (Commodity Price Risk)

Generation also executes commodity derivatives for proprietary trading purposes. Proprietary trading includes all contracts executed with the intent of benefiting from shifts or changes in market prices as opposed to those executed with the intent of hedging or managing risk. Gains and losses associated with proprietary trading are reported as Operating revenues in Exelon’s and Generation’s ~~or ComEd’s future results~~Consolidated Statements of ~~operations.~~Operations and Comprehensive Income and are included in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows. For the three and nine months ended September 30, 2021 and 2020,

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Note 12 — Derivative Financial Instruments

net pre-tax commodity mark-to-market gains and losses for Exelon and Generation were not material. The Utility Registrants do not execute derivatives for proprietary trading purposes.

Interest Rate and Foreign Exchange Risk (Exelon and Generation)

The mark-to-market derivative assets and liabilities as of September 30, 2021 and December 31, 2020 and the mark-to-market gains and losses for the three and nine months ended September 30, 2021 and 2020 were not material for Exelon and Generation.

Credit Risk (All Registrants)

The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties on executed derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date.

Generation. For commodity derivatives, Generation enters into enabling agreements that allow for payment netting with its counterparties, which reduces Generation’s exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. Typically, each enabling agreement is for a specific commodity and so, with respect to each individual counterparty, netting is limited to transactions involving that specific commodity product, except where master netting agreements exist with a counterparty that allow for cross product netting. In addition to payment netting language in the enabling agreement, Generation’s credit department establishes credit limits, margining thresholds, and collateral requirements for each counterparty, which are defined in the derivative contracts. Counterparty credit limits are based on an internal credit review process that considers a variety of factors, including the results of a scoring model, leverage, liquidity, profitability, credit ratings by credit rating agencies, and risk management capabilities. To the extent that a counterparty’s margining thresholds are exceeded, the counterparty is required to post collateral with Generation as specified in each enabling agreement. Generation’s credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis.

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Note 12 — Derivative Financial Instruments

The following tables provide information on Generation’s credit exposure for all derivative instruments, NPNS, and payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of September 30, 2021. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties. The amounts in the tables below exclude credit risk exposure from individual retail counterparties, nuclear fuel procurement contracts, and exposure through RTOs, ISOs, NYMEX, ICE, NASDAQ, NGX, and Nodal commodity exchanges.


Rating as of September 30, 2021	Total Exposure Before Credit Collateral		Credit Collateral(a)		Net Exposure		Number of Counterparties Greater than 10% of Net Exposure	Net Exposure of Counterparties Greater than 10% of Net Exposure
Investment grade	$	701	$	254	$	447	—	$	—
Non-investment grade	23		2		21		—	—
No external ratings
Internally rated — investment grade	110		1		109		—	—
Internally rated — non-investment grade	309		48		261		—	—
Total	$	1,143	$	305	$	838	—	$	—


Net Credit Exposure by Type of Counterparty	As of September 30, 2021
Financial institutions	$	53
Investor-owned utilities, marketers, power producers	652
Energy cooperatives and municipalities	62
Other	71
Total	$	838

_________

Utility Registrants. The Utility Registrants have contracts to procure electric and natural gas supply that provide suppliers with a certain amount of unsecured credit. If the exposure on the supply contract exceeds the amount of unsecured credit, the suppliers may be required to post collateral. The net credit exposure is mitigated primarily by the ability to recover procurement costs through customer rates. As of September 30, 2021, the amount of cash collateral held with external counterparties by ComEd, BGE, and DPL was $56 million, $21 million, and $25 million, respectively, which is recorded in Other Current Liabilities in ComEd’s, BGE’s, and DPL’s Consolidated Balance Sheets. The amounts for PECO, Pepco, and ACE as of September 30, 2021 and for the Utility Registrants as of December 31, 2020 are not material. The amount for ComEd as of September 30, 2021 does not include cash collateral held from Generation, which is disclosed in the notes to the derivative fair value balances tables above.

Credit-Risk-Related Contingent Features (All Registrants)

Generation. As part of the normal course of business, Generation routinely enters into physically or financially settled contracts for the purchase and sale of electric capacity, electricity, fuels, emissions allowances, and other energy-related products. Certain of Generation’s derivative instruments contain provisions that require Generation to post collateral. Generation also enters into commodity transactions on exchanges where the exchanges act as the counterparty to each trade. Transactions on the exchanges must adhere to comprehensive collateral and margining requirements. This collateral may be posted in the form of cash or credit support with thresholds contingent upon Generation’s credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. These credit-risk-related contingent features stipulate that if Generation were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. This incremental collateral requirement allows for the offsetting of derivative instruments that are assets with the same counterparty, where

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Note 12 — Derivative Financial Instruments

The aggregate fair value of all derivative instruments with credit-risk related contingent features in a liability position that are not fully collateralized (excluding transactions on the exchanges that are fully collateralized) is detailed in the table below:


Credit-Risk Related Contingent Features	September 30, 2021		December 31, 2020
Gross fair value of derivative contracts containing this feature(a)	$	(5,289)	$	(834)
Offsetting fair value of in-the-money contracts under master netting arrangements(b)	2,735		537
Net fair value of derivative contracts containing this feature(c)	$	(2,554)	$	(297)

_________

(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 Generation could potentially be required to post collateral.

As of September 30, 2021 and December 31, 2020, Exelon and Generation posted or held the following amounts of cash collateral and letters of credit on derivative contracts with external counterparties, after giving consideration to offsetting derivative and non-derivative positions under master netting agreements.


	September 30, 2021		December 31, 2020
Cash collateral posted	$	299	$	511
Letters of credit posted	477		226
Cash collateral held	1,872		110
Letters of credit held	130		40
Additional collateral required in the event of a credit downgrade below investment grade	3,001		1,432

Utility Registrants

The Utility Registrants’ electric supply procurement contracts do not contain provisions that would require them to post collateral.

PECO’s, BGE’s, and DPL’s natural gas procurement contracts contain provisions that could require PECO, BGE, and DPL to post collateral in the form of cash or credit support, which vary by contract and counterparty, with thresholds contingent upon PECO’s, BGE's, and DPL’s credit rating. As of September 30, 2021, PECO, BGE, and DPL were not required to post collateral for any of these agreements. If PECO, BGE, or DPL lost their investment grade credit rating as of September 30, 2021, they could have been required to post incremental collateral to their counterparties of $23 million, $46 million, and $11 million, respectively.

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Note 13 — Debt and Credit Agreements

13. Debt and Credit Agreements (All Registrants)

Nuclear Decommissioning Asset Retirement Obligations

Generation has a legal obligation to decommission its nuclear power plants following the expiration of their operating licenses. To estimate its decommissioning obligation related to its nuclear generating stations for financial accounting and reporting purposes, Generation uses a probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models, and discount rates. Generation updates its ARO annually, unless circumstances warrant more frequent

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(Dollars in millions, except per share data, unless otherwise noted)

Note 8 — Nuclear Decommissioning

updates, based on its review of updated cost studies and its annual evaluation of cost escalation factors and probabilities assigned to various scenarios.

The following table provides a rollforward of the nuclear decommissioning ARO reflected onin Exelon’s and Generation’s Consolidated Balance Sheets from December 31, ~~2016~~2020 to September 30, ~~2017:~~2021:

Nuclear decommissioning ARO at December 31, 2016^(a)
$ 8,734
Acquisition of FitzPatrick 444
Accretion expense 342
Net decrease due to changes in, and timing of, estimated cash flows (148 )
Costs incurred to decommission retired plants (6 )
Nuclear decommissioning ARO at September 30, 2017^(a)
$ 9,366

~~_________~~


Nuclear decommissioning ARO at December 31, 2020(a)	~~Includes $12 million~~$	11,922
Accretion expense	375
Net increase due to changes in, and ~~$10 million for the current portion~~timing of, ~~the~~estimated future cash flows	256
Costs incurred related to decommissioning plants	(57)
Nuclear decommissioning ARO at September 30, ~~2017 and December 31, 2016, respectively, which is included in Other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets.~~2021(a)	$	12,496

_________

During the nine months ended September 30, ~~2017, Generation’s nuclear ARO increased by approximately $632 million. The increase primarily reflects~~2021, the net ~~impacts of the acquisition of FitzPatrick, the announced early retirement of TMI, year-to-date accretion of~~$256 million increase in the ARO ~~liability due to~~for the ~~passage of time and ARO updates completed during 2017 to reflect~~ changes in the amounts and timing of estimated decommissioning cash ~~flows.~~

In the first quarter of 2017, a preliminary estimate of $417 million was recorded for the fair value of FitzPatrick’s ARO. In the third quarter of 2017, an adjustment was recorded to increase the FitzPatrick ARO valuation by $27 million to $444 million to reflect updated cost estimate inputs from a third-party engineering firm. For additional details on the acquisition of FitzPatrick, see Note 4 - Mergers, Acquisitions and Dispositions.

~~The net $148 million decrease due to changes in, and timing of, estimated cash~~ flows was driven by multiple ~~adjustments throughout the period, some with offsetting impacts.~~adjustments. These adjustments primarily include:

•An increase of approximately $510 million for updated cost escalation rates, primarily for labor and energy, and a decrease in discount rates.

NDT Funds

Accounting Implications of the Regulatory Agreements with ComEd and PECO

unit-by-unit basis and the former PECO units in total, decommissioning-related activities net of applicable taxes, including realized and unrealized gains and losses on the NDT funds, depreciation of the ARC, and accretion of the decommissioning obligation, are generally offset in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income and are recorded by Generation and the corresponding regulated utility as a component of the intercompany and regulatory balances in the balance sheet. For the purposes of making

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Note 8 — Nuclear Decommissioning

~~for refinements~~this determination, the decommissioning obligation referred to is different from the calculation used in ~~estimated fleet wide labor costs~~the NRC minimum funding obligation filings based on NRC guidelines.

For the former ComEd units, given no further recovery from ComEd customers is permitted and Generation retains an obligation to ultimately return any unused NDTs to ComEd customers (on a unit-by-unit basis), to the extent the related NDT investment balances are expected to exceed the total estimated decommissioning obligation for each unit, decommissioning-related activities are offset in the Consolidated Statements of Operations and Comprehensive Income which results with Generation recognizing an intercompany payable to ComEd while ComEd records an intercompany receivable from Generation with a corresponding regulatory liability. However, given the asymmetric settlement provision that does not allow for continued recovery from ComEd customers in the event of a shortfall, recognition of a regulatory asset at ComEd is not permissible and accounting for decommissioning-related activities at Generation for that unit would not be ~~incurred~~offset, and the impact to Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income could be material during such periods. During the second and third quarter of 2021, a pre-tax charge of $53 million and $140 million, respectively, was recorded in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income for ~~certain on-site personnel during decommissioning as well as decreases resulting from updates~~decommissioning-related activities that were not offset for the Byron units due to contractual offset being temporarily suspended. With Generation’s September 15, 2021 reversal of the previous decision to retire Byron and the corresponding adjustment to the ~~cost studies~~ARO for Byron discussed previously, Generation resumed contractual offset for Byron as of ~~Clinton and Quad Cities. These decreases were partially offset by a $138 million increase in TMI's ARO liability associated with the May 30, 2017 announcement to early retire the unit on~~that date.

As of September 30, ~~2019. The increase in the ARO liability~~2021, decommissioning-related activities for TMI incorporates the early shutdown date, increases the probabilities of longer term decommissioning scenarios, and reflects an increase in the estimated costs to decommission based on an updated decommissioning cost study. Refer to Note 7 - Early Nuclear Plant Retirements for additional information regarding the announced early retirement of TMI.

~~Nuclear Decommissioning Trust Fund Investments~~

NDT funds have been established for each generation station unit to satisfy Generation’s nuclear decommissioning obligations. Generally, NDT funds established for a particular unit may not be used to fund the decommissioning obligations of any other unit.

The NDT funds associated with Generation’s nuclear units have been funded with amounts collected from the previous owners and their respective utility customers. PECO is authorized to collect funds, in revenues, for decommissioning the former PECO nuclear plants through regulated rates, and these collections are scheduled through the operating livesall of the former ~~PECO plants.~~ ComEd units, except for Zion, are currently offset in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

The amounts collected from PECO customers are remitted to Generation and deposited into the NDT funds for the unit for which funds are collected. Every five years, PECO files a rate adjustment with the PAPUC that reflects PECO’s calculations of the estimated amount needed to decommission each of the former PECO units based on updated fund balances and estimated decommissioning costs. The rate adjustment is used to determine the amount collectible from PECO customers. On March 31, 2017, PECO filed its Nuclear Decommissioning Cost Adjustment (NDCA) with the PAPUC proposing an annual recovery from customers of approximately $4 million. This amount reflects a decrease from the current approved annual collection of approximately $24 million primarily duedecommissioning-related activities related to the ~~removal of the collections for Limerick~~Non-Regulatory Agreement Units 1 and 2 as a result of the NRC approving the extension of the operating licenses for an additional 20 years. On August 8, 2017, the PAPUC approved the filing and the new rates will be effective January 1, 2018. See Note 16 - Asset Retirement Obligations of Exelon's 2016 Form 10-K, for information regarding the amount collected from PECO ratepayers for decommissioning costs.

Exelon and Generation had NDT fund investments totaling $12,966 million and $11,061 million at September 30, 2017 and December 31, 2016, respectively. The increase is primarily driven by improved market performance and the acquisition of FitzPatrick.

~~The following table provides unrealized gains on NDT funds for the three and nine months ended September 30, 2017 and 2016:~~

Exelon and Generation Exelon and Generation
Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Net unrealized gains on decommissioning trust funds — Regulatory Agreement Units^(a)
$ 44
$ 155
$ 253
$ 286
Net unrealized gains on decommissioning trust funds — Non-Regulatory Agreement Units^(b)(c)
111
116
347
216

~~_________~~


~~(a)~~	Net unrealized gains 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 $4 million and $5 million of net unrealized losses related to the Zion Station pledged assets for the three months ended September 30, 2017 and 2016 respectively. Excludes $5 million and $2 million of net unrealized losses related to the Zion Station pledged assets for the nine months ended September 30, 2017 and 2016, respectively. Net unrealized losses related to Zion Station pledged assets are included in Other current liabilities and Payable for Zion Station decommissioning on Exelon’s and Generation’s Consolidated Balance Sheets in 2017 and 2016, respectively.


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

~~Interest and dividends on NDT fund investments~~ are ~~recognized when earned and are included in Other, net~~reflected in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. Interest and dividends earned on the NDT fund investments for the Regulatory Agreement Units are eliminated within Other, net in Exelon’s and Generation’s Consolidated Statement of Operations and Comprehensive Income.

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~~(Dollars in millions, except per share data, unless otherwise noted)~~

Refer to Note 3 — Regulatory Matters and Note 27 — Related Party Transactions of the Exelon 2016 Form 10-K for information regarding regulatory liabilities at ComEd and PECO and intercompany balances between Generation, ComEd and PECO reflecting the obligation to refund to customers any decommissioning-related assets in excess of the related decommissioning obligations.

~~Zion Station Decommissioning~~

On September 1, 2010, Generation completed an Asset Sale Agreement (ASA) with EnergySolutions Inc. and its wholly owned subsidiaries, EnergySolutions, LLC (EnergySolutions) and ZionSolutions, under which ZionSolutions has assumed responsibility for completing certain decommissioning activities at Zion Station, which is located in Zion, Illinois and ceased operation in 1998. See Note 16 10 — Asset Retirement Obligations of the Exelon ~~2016~~2020 Form 10-K for ~~information regarding the specific treatment of assets, including NDT funds, and decommissioning liabilities transferred in the transaction.~~additional information.

ZionSolutions is subject to certain restrictions on its ability to request reimbursements from the Zion Station NDT funds as defined within the ASA. Therefore, the transfer of the Zion Station assets did not qualify for asset sale accounting treatment and, as a result, the related NDT funds were reclassified to Pledged assets for Zion Station decommissioning within Generation’s and Exelon’s Consolidated Balance Sheets and will continue to be measured in the same manner as prior to the completion of the transaction. Additionally, the transferred ARO for decommissioning was replaced with a Payable for Zion Station decommissioning in Generation’s and Exelon’s Consolidated Balance Sheets. Changes in the value of the Zion Station NDT assets, net of applicable taxes, are recorded as a change in the payable to ZionSolutions. At no point will the payable to ZionSolutions exceed the project budget of the costs remaining to decommission Zion Station. Generation has retained its obligation for the SNF. Following ZionSolutions’ completion of its contractual obligations and transfer of the NRC license to Generation, Generation will store the SNF at Zion Station until it is transferred to the DOE for ultimate disposal, and will complete all remaining decommissioning activities associated with the SNF dry storage facility. Generation has a liability of approximately $112 million which is included within the nuclear decommissioning ARO at September 30, 2017. Generation also has retained NDT assets to fund its obligation to maintain the SNF at Zion Station until transfer to the DOE and to complete all remaining decommissioning activities for the SNF storage facility. Any shortage of funds necessary to maintain the SNF and decommission the SNF storage facility is ultimately required to be funded by Generation. Any Zion Station NDT funds remaining after the completion of all decommissioning activities will be returned to ComEd customers in accordance with the applicable orders. The following table provides the pledged assets and payables to ZionSolutions, and withdrawals by ZionSolutions at September 30, 2017 and December 31, 2016:

Exelon and Generation
September 30, 2017 December 31, 2016
Carrying value of Zion Station pledged assets $ 57
$ 113
Payable to Zion Solutions^(a)
53
104
Current portion of payable to Zion Solutions^(b)
53
90
Cumulative withdrawals by Zion Solutions to pay decommissioning costs^(c)
928
878

~~_________~~


~~(a)~~	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.


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


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

NRC Minimum Funding Requirements

Generation filed its biennial decommissioning funding status report with the NRC on ~~March 30, 2017~~February 24, 2021 for all units, including its shutdown units, except for Zion Station which is included in a separate report to the NRC submitted by ZionSolutions, ~~(see Zion Station Decommissioning above).~~LLC. The status report demonstrated adequate decommissioning funding assurance as of December 31, 2020 for all units except for ~~Peach Bottom Unit 1. As a former PECO plant, financial~~Byron Units 1 and 2. Generation filed an updated decommissioning funding status report for Byron Units 1 and 2 and Dresden Units 2 and 3 on September 28, 2021 based on their current license expiration dates consistent with Generation’s announcements regarding the continued operations of these units. This report demonstrated adequate decommissioning funding assurance as of December 31, 2020 for ~~decommissioning Peach Bottom Unit~~Byron Units 1 is provided by the NDT fund in addition to collections from PECO ratepayers. As discussed under Nuclear Decommissioning Trust Fund Investments above, the amount collected from PECO ratepayers has been adjusted in the March 31, 2017 filing to the PAPUC which was approved on August 8, 2017 and ~~will be effective January 1, 2018.~~

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~~(Dollars in millions, except per share data, unless otherwise noted)~~

2 and Dresden Units 2 and 3.

Generation will file its next decommissioning funding status report with the NRC by March 31, ~~2018 for shutdown reactors and reactors within five years of shutdown.~~2022. This report will reflect the status of decommissioning funding assurance as of December 31, ~~2017~~2021 for shutdown units.

9. Asset Impairments (Exelon and ~~will~~Generation)

The Registrants evaluate the carrying value of long-lived assets or asset groups for recoverability whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators of impairment may include ~~the impact~~a deteriorating business climate, including, but not limited to, declines in energy prices, condition of the ~~announced early retirement~~asset, specific regulatory disallowance, or plans to dispose of ~~TMI. A shortfall could necessitate that Exelon post~~ a ~~parental guarantee for Generation’s share~~long-lived asset significantly before the end of its useful life. The Registrants determine if long-lived assets or asset groups are impaired by comparing the ~~funding assurance. However,~~undiscounted expected future cash flows to the carrying value. When the undiscounted cash flow analysis indicates a long-lived asset or asset group is not recoverable, the amount of ~~any required guarantee will ultimately depend~~the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. The fair value analysis is primarily based on the income approach using significant unobservable inputs (Level 3) including revenue and generation forecasts, projected capital and maintenance expenditures, and discount rates. A variation in the assumptions used could lead to a different conclusion

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in millions, except per share data, unless otherwise noted)

Note 9 — Asset Impairments

regarding the recoverability of an asset or asset group and, thus, could potentially result in material future impairments of the Registrant's long-lived assets.

New England Asset Group

In the second quarter of 2021, an overall decline in the asset group's portfolio value suggested that the carrying value of the New England asset group may be impaired. Generation completed a comprehensive review of the estimated undiscounted future cash flows of the New England asset group and concluded that the carrying value was not recoverable and that its fair value was less than its carrying value. As a result, a pre-tax impairment charge of $350 million was recorded in the second quarter of 2021 in Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

Contracted Wind Project

In the third quarter of 2021, significant long-term operational issues anticipated for a specific wind turbine technology suggested that the carrying value of a contracted wind asset, located in Maryland and part of the EGRP joint venture, may be impaired. Generation completed a comprehensive review of the estimated undiscounted future cash flows and concluded that the carrying value of this contracted wind project was not recoverable and that its fair value was less than its carrying value. As a result, in the third quarter of 2021, a pre-tax impairment charge of $45 million was recorded in Operating and maintenance expense, $21 million of which was offset in Net income attributable to noncontrolling interests in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in millions, except per share data, unless otherwise noted)

Note 10 — Income Taxes

10. Income Taxes (All Registrants)

Rate Reconciliation

The effective income tax rate from continuing operations varies from the U.S. federal statutory rate principally due to the following:


	Three Months Ended September 30, 2021

	Exelon(a)	Generation(a)	ComEd(a)	PECO(a)(b)	BGE(a)(b)	PHI(a)	Pepco(a)	DPL(a)	ACE(a)(b)
U.S. Federal statutory rate	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	6.0	4.4	8.0	(4.1)	(13.0)	5.0	3.4	6.4	7.0
Qualified NDT fund income	0.5	0.9	—	—	—	—	—	—	—

Amortization of investment tax credit, including deferred taxes on basis difference	(0.4)	(0.7)	(0.1)	—	(0.1)	(0.1)	—	(0.2)	(0.2)
Plant basis differences	(1.7)	—	(0.8)	(16.2)	(1.4)	(1.3)	(2.0)	(0.6)	(0.6)
Production tax credits and other credits	(1.0)	(1.4)	(0.5)	—	(0.9)	(0.5)	(0.5)	(0.4)	(0.5)
Noncontrolling interests	(0.4)	(0.6)	—	—	—	—	—	—	—
Excess deferred tax amortization	(6.8)	—	(7.6)	(3.4)	(17.3)	(24.9)	(17.6)	(19.9)	(41.4)

Other(c)	(4.8)	(1.9)	0.3	(0.1)	(0.8)	—	0.1	(0.6)	0.8
Effective income tax rate	12.4%	21.7%	20.3%	(2.8)%	(12.5)%	(0.8)%	4.4%	5.7%	(13.9)%


	Three Months Ended September 30, 2020
	Exelon(a)	Generation(a)	ComEd(a)	PECO(a)(d)	BGE(a)(d)	PHI(a)(d)	Pepco(a)(d)	DPL(a)(d)	ACE(a)(d)
U.S. Federal statutory rate	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	12.3	(10.3)	8.1	(6.2)	5.1	5.5	4.6	6.6	6.9
Qualified NDT fund income	13.2	47.4	—	—	—	—	—	—	—

Amortization of investment tax credit, including deferred taxes on basis difference	(1.4)	(4.5)	(0.2)	—	(0.1)	(0.2)	(0.1)	(0.2)	(0.3)
Plant basis differences	(4.3)	—	(0.6)	(23.3)	(1.2)	(1.5)	(2.1)	(0.4)	(1.3)
Production tax credits and other credits	(3.0)	(9.2)	(0.4)	—	(0.8)	(0.5)	(0.5)	(0.5)	(0.4)
Noncontrolling interests	0.8	2.9	—	—	—	—	—	—	—
Excess deferred tax amortization	(10.1)	—	(5.6)	(3.8)	(10.6)	(24.9)	(20.0)	(23.6)	(36.8)
Tax Settlements	(0.2)	(0.7)	—	—	—	—	—	—	—
Other	(0.8)	(0.9)	1.1	(0.8)	(0.3)	0.1	(0.4)	0.7	0.6
Effective income tax rate	27.5%	45.7%	23.4%	(13.1)%	13.1%	(0.5)%	2.5%	3.6%	(10.3)%

__________

(a)Positive percentages represent income tax expense. Negative percentages represent income tax benefit.

(b)For PECO, the income tax benefit is primarily due to plant basis differences attributable to tax repair deductions. For BGE,

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(Dollars in millions, except per share data, unless otherwise noted)

Note 10 — Income Taxes


	Nine Months Ended September 30, 2021
	Exelon(a)	Generation(b)	ComEd(a)	PECO(a)(c)	BGE(a)(c)	PHI(a)	Pepco(a)	DPL(a)	ACE(a)(c)
U.S. Federal statutory rate	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	3.0	90.2	7.6	(2.6)	(10.8)	4.6	2.5	6.5	7.3
Qualified NDT fund income	9.4	(1,932.6)	—	—	—	—	—	—	—

Amortization of investment tax credit, including deferred taxes on basis difference	(0.8)	130.6	(0.1)	—	(0.1)	(0.1)	—	(0.2)	(0.2)
Plant basis differences	(3.9)	—	(0.7)	(12.6)	(1.5)	(1.3)	(1.9)	(0.7)	(0.6)
Production tax credits and other credits	(2.6)	425.1	(0.5)	—	(0.9)	(0.5)	(0.5)	(0.4)	(0.5)
Noncontrolling interests	(0.7)	145.2	—	—	—	—	—	—	—
Excess deferred tax amortization	(13.9)	—	(7.2)	(3.3)	(16.0)	(22.8)	(17.4)	(19.7)	(36.3)

Other(d)	2.2	(229.5)	(1.3)	(0.2)	(0.7)	(0.3)	(0.4)	(0.2)	—
Effective income tax rate	13.7%	(1,350.0)%	18.8%	2.3%	(9.0)%	0.6%	3.3%	6.3%	(9.3)%

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in millions, except per share data, unless otherwise noted)

Note 10 — Income Taxes


	Nine Months Ended September 30, 2020
	Exelon(a)	Generation(a)	ComEd(a)(e)	PECO(a)(e)	BGE(a)(e)	PHI(a)(e)	Pepco(a)(e)	DPL(a)(e)	ACE(a)(e)
U.S. Federal statutory rate	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	9.3	—	12.7	(3.4)	5.5	5.0	4.2	6.5	6.8
Qualified NDT fund income	3.2	10.0	—	—	—	—	—	—	—
Deferred Prosecution Agreement payments	2.5	—	9.4	—	—	—	—	—	—
Amortization of investment tax credit, including deferred taxes on basis difference	(1.2)	(3.2)	(0.3)	—	(0.1)	(0.2)	(0.1)	(0.3)	(0.5)
Plant basis differences	(4.0)	—	(0.9)	(15.9)	(1.8)	(2.2)	(2.4)	(0.5)	(3.7)
Production tax credits and other credits	(2.6)	(7.0)	(0.4)	—	(0.4)	(0.3)	(0.3)	(0.2)	(0.4)
Noncontrolling interests	1.0	3.1	—	—	—	—	—	—	—
Excess deferred tax amortization	(15.8)	—	(11.8)	(3.5)	(15.0)	(45.3)	(29.2)	(53.6)	(81.4)
Tax Settlements(f)	(5.0)	(15.7)	—	—	—	—	—	—	—
Other	0.1	(0.5)	2.1	(0.5)	(0.5)	(0.6)	(0.8)	(1.1)	—
Effective income tax rate	8.5%	7.7%	31.8%	(2.3)%	8.7%	(22.6)%	(7.6)%	(28.2)%	(58.2)%

__________

(a)Positive percentages represent income tax expense. Negative percentages represent income tax benefit.

(b)Generation recognized a loss before income taxes for the nine months ended September 30, 2021. As a result, a negative percentage represents an income tax expense for the period presented.

Unrecognized Tax Benefits

100

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(Dollars in millions, except per share data, unless otherwise noted)

Note 10 — Income Taxes

PHI and ACE have the following unrecognized tax benefits as of September 30, 2021 and December 31, 2020. Exelon's, Generation's, ComEd's, PECO's, BGE's, Pepco's, and DPL's amounts are not material.


	PHI		ACE
September 30, 2021	$	56	$	16
December 31, 2020	52		15

Reasonably possible the total amount of unrecognized tax benefits could significantly increase or decrease within 12 months after the reporting date

Other Income Tax Matters

CENG Put Option (Exelon and Generation)

On August 6, 2021, Generation and EDF entered into a settlement agreement pursuant to which Generation purchased EDF’s equity interest in CENG. Exelon and Generation recorded deferred tax liabilities of $290 million and $288 million, respectively, against Common Stock in Exelon’s Consolidated Balance Sheet and Membership Interest in Generation’s Consolidated Balance Sheet. The deferred tax liabilities represent the tax effect on the difference between the net purchase price and EDF’s noncontrolling interest as of August 6, 2021. The deferred tax liabilities will reverse during the remaining operating lives and during decommissioning ~~approach adopted~~of the CENG nuclear plants. See Note 2 – Mergers, Acquisitions, and Dispositions for additional information.

Long-Term Marginal State Income Tax Rate (All Registrants)

In the third quarter of 2021 and 2020, Exelon updated its marginal state income tax rates for changes in state apportionment. The changes in marginal rates in the third quarter of 2021 resulted in an increase of $27 million to the deferred income tax liability at ~~TMI,~~Exelon, and a corresponding adjustment to income tax expense, net of federal taxes. The changes in marginal rates in the ~~associated level~~third quarter of ~~costs,~~2020 resulted in an increase of $66 million and a decrease of $26 million to the deferred income tax liability at Exelon and Generation, respectively. Exelon and Generation recorded a corresponding adjustment to income tax expense, net of federal taxes.

Allocation of Tax Benefits (All Registrants)

Generation and the ~~decommissioning trust fund investment performance going forward.~~Utility Registrants are all party to an agreement with Exelon and other subsidiaries of Exelon that provides for the allocation of consolidated tax liabilities and benefits (Tax Sharing Agreement). The Tax Sharing Agreement provides that each party is allocated an amount of tax similar to that which would be owed had the party been separately subject to tax. In addition, any net benefit attributable to Exelon is reallocated to the other Registrants. That allocation is treated as a contribution to the capital of the party receiving the benefit.

The following table presents the allocation of federal tax benefits from Exelon under the Tax Sharing Agreement.

~~14.~~


	Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
September 30, 2021	$	64	$	1	$	19	$	—	$	17	$	16	$	—	$	—
September 30, 2020	64		14		17		—		17		8		6		1

11. Retirement Benefits (All Registrants)

~~Exelon sponsors defined benefit pension plans~~Defined Benefit Pension and other postretirement benefit plans for essentially all employees. Effective March 23, 2016, Exelon became the sponsor of all of PHI's defined benefit pension and other postretirement benefit plans, and assumed PHI's benefit plan obligations and related assets. As a result, PHI's benefit plan net obligation and related regulatory assets were transferred to Exelon.OPEB

During the first quarter of 2017, in connection with the acquisition of Fitzpatrick, Exelon established a new qualified pension plan and a new OPEB plan, and recorded a provisional obligation for Fitzpatrick employees based on information available at the merger date of $38 million and $11 million, respectively. As permitted by business combinations accounting guidance, during the third quarter of 2017, Exelon updated those obligations based on a final valuation for Fitzpatrick employees as of the merger date of March 31, 2017. The updated obligations for pension and OPEB were $16 million and $17 million, respectively. Refer to Note 4 - Mergers, Acquisitions and Dispositions for additional discussion of the acquisition of FitzPatrick.

~~Defined Benefit Pension and Other Postretirement Benefits~~

~~During the first quarter of 2017,~~2021, Exelon received an updated valuation of its pension and ~~other postretirement benefit obligations~~OPEB to reflect actual census data as of January 1, ~~2017.~~2021. This valuation resulted in an increase to the pension ~~obligation~~obligations of ~~$92~~$33 million and ~~an increase~~a decrease to the ~~other postretirement benefit obligation~~OPEB obligations of ~~$57~~$9 million. Additionally, accumulated other comprehensive loss

101

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(Dollars in millions, except per share data, unless otherwise noted)

Note 11 — Retirement Benefits

increased by ~~approximately $59~~$1 million ~~(after tax),~~(after-tax) and regulatory assets ~~increased by approximately $57 million~~ and ~~regulatory~~ liabilities increased by ~~approximately $4 million.~~$21 million and $1 million, respectively.

The majority of the ~~2017~~2021 pension benefit cost for the Exelon-sponsored plans is calculated using an expected long-term rate of return on plan assets of 7.00% and a discount rate of ~~4.04%~~2.58%. The majority of the ~~2017 other postretirement benefit~~2021 OPEB cost is calculated using an expected long-term rate of return on plan assets of ~~6.58%~~6.46% for funded plans and a discount rate of ~~4.04%~~2.51%.

A portion of the net periodic benefit cost for all plans is capitalized ~~within~~in the Consolidated Balance Sheets. The following ~~tables present~~table presents the components of Exelon's net periodic benefit costs, prior to capitalization, for the three and nine months ended September 30, ~~2017~~2021 and ~~2016 and PHI's net periodic benefit costs, prior to capitalization, for the predecessor period of January 1, 2016 to March 23, 2016.~~2020.



	Pension Benefits				OPEB
	Three Months Ended September 30,				Three Months Ended September 30,
	2021		2020		2021		2020
Components of net periodic benefit cost:
Service cost	$	110	$	97	$	20	$	22
Interest cost	161		190		29		37
Expected return on assets	(335)		(317)		(40)		(41)
Amortization of:
Prior service cost (credit)	1		1		(8)		(30)
Actuarial loss	150		128		9		12
Settlement charges	12		8		—		—

Net periodic benefit cost	$	99	$	107	$	10	$	—



	Pension Benefits				OPEB
	Nine Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Components of net periodic benefit cost:
Service cost	$	330	$	290	$	60	$	67
Interest cost	481		569		86		114
Expected return on assets	(1,003)		(953)		(119)		(122)
Amortization of:
Prior service cost (credit)	3		3		(25)		(92)
Actuarial loss	449		384		27		36
Curtailment benefits	—		—		(1)		—
Settlement charges	16		14		—		—

Net periodic benefit cost	$	276	$	307	$	28	$	3

102

Pension Benefits
Three Months Ended September 30, Other Postretirement Benefits
Three Months Ended September 30,

2017^(a)

2016^(b)

2017^(a)

2016^(b)
Components of net periodic benefit cost:
Service cost $ 98
$ 92
$ 26
$ 27
Interest cost 211
215
45
47
Expected return on assets (300 ) (293 ) (39 ) (42 )
Amortization of:
Prior service (benefit) cost (1 ) 3
(47 ) (48 )
Actuarial loss 152
142
15
18
Settlement charges 1
—
—
—
Net periodic benefit cost $ 161
$ 159
$ —
$ 2

~~144~~

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(Dollars in millions, except per share data, unless otherwise noted)

Note 11 — Retirement Benefits

Pension Benefits
Nine Months Ended September 30, Other Postretirement Benefits
Nine Months Ended September 30,

2017^(a)

2016^(b)

2017^(a)

2016^(b)
Components of net periodic benefit cost:

Service cost $ 290
$ 262
$ 79
$ 80
Interest cost 632
616
136
138
Expected return on assets (898 ) (847 ) (121 ) (121 )
Amortization of:
Prior service cost (benefit) —
10
(140 ) (138 )
Actuarial loss 455
411
46
47
Settlement charges 3
—
—
—
Net periodic benefit cost $ 482

$ 452

$ —

$ 6

~~_________~~


~~(a)~~	~~FitzPatrick net benefit costs are included for the period after acquisition.~~


~~(b)~~	~~PHI net periodic benefit costs for the period prior to the merger are not included in the table above.~~

Predecessor
PHI
Pension Benefits Other Postretirement Benefits
January 1, 2016 to March 23, 2016 January 1, 2016 to March 23, 2016
Components of net periodic benefit cost:
Service cost $ 12
$ 1
Interest cost 26
6
Expected return on assets (30 ) (5 )
Amortization of:
Prior service cost (benefit) —
(3 )
Actuarial loss 14
2
Net periodic benefit cost $ 22
$ 1

The amounts below represent ~~Exelon's, Generation's, ComEd's, PECO's, BGE's, PHI's, Pepco's, DPL's, ACE's, BSC's and PHISCO's~~the Registrants' allocated ~~portion of the~~ pension and ~~postretirement benefit plan costs, which were~~OPEB costs. For Exelon, the service cost component is included in Operating and maintenance expense and Property, plant, and equipment, ~~within~~net while the ~~respective Consolidated Balance Sheets~~non-service cost components are included in Other, net and Regulatory assets. For Generation and the Utility Registrants, the service cost and non-service cost components are included in Operating and maintenance expense ~~within the Consolidated Statement of Operations~~ and ~~Comprehensive Income during the three~~Property, plant, and ~~nine months ended September 30, 2017 and 2016 and PHI's for the predecessor and successor periods of January 1, 2016 to March 23, 2016 and March 24, 2016 to September 30, 2016, respectively.~~equipment, net in their consolidated financial statements.


	Three Months Ended September 30,				Nine Months Ended September 30,
Pension and OPEB Costs	2021		2020		2021		2020
Exelon	$	109	$	107	$	304	$	310
Generation	36		30		92		89
ComEd	32		29		97		85
PECO	2		1		5		4
BGE	16		16		47		47
PHI	12		17		36		52
Pepco	2		4		5		11
DPL	1		2		2		6
ACE	3		3		8		10

Three Months Ended September 30, Nine Months Ended September 30,
Pension and Other Postretirement Benefit Costs 2017 2016 2017 2016
Exelon $ 161
$ 161
$ 482
$ 458
Generation^(a)
57
54
170
163
ComEd 44
41
131
124
PECO 7
8
21
25
BGE 16
17
48
51
BSC^(b)
13
13
40
37
Pepco^(c)
6
8
19
24
DPL^(c)
3
4
10
13
ACE^(c)
3
4
10
11
PHISCO^(c)(d)
12
12
33
33

~~145~~

~~Table of Contents~~

~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

Successor Predecessor
Pension and Other Postretirement Benefit Costs Three Months Ended September 30, 2017 Three Months Ended September 30, 2016 Nine Months Ended September 30, 2017 March 24, 2016 to September 30, 2016 January 1, 2016 to March 23, 2016
PHI $ 24
$ 28
$ 72
$ 58
$ 23

~~_________~~


~~(a)~~	~~FitzPatrick net benefit costs are included for the period after acquisition.~~


~~(b)~~	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.


~~(c)~~	Pepco's, DPL's, ACE's and PHISCO's pension and postretirement benefit costs for the nine months ended September 30, 2016 include $7 million, $4 million, $3 million and $9 million, respectively, of costs incurred prior to the closing of Exelon’s merger with PHI on March 23, 2016.


~~(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.~~

Defined Contribution Savings Plans

The Registrants participate in various 401(k) defined contribution savings plans that are sponsored by Exelon. The plans are qualified under applicable sections of the IRC and allow employees to contribute a portion of their pre-tax and/or after-tax income in accordance with specified guidelines. All Registrants match a percentage of the employee contributions up to certain limits. The following table presents the matching contributions to the savings plans ~~during~~for the three and nine months ended September 30, ~~2017~~2021 and ~~2016 and PHI's for the predecessor and successor periods of January 1, 2016 to March 23, 2016 and March 24, 2016 to September 30, 2016,~~2020, respectively.


	Three Months Ended September 30,				Nine Months Ended September 30,
Savings Plans Matching Contributions	2021		2020		2021		2020
Exelon	$	38	$	37	$	107	$	104
Generation	14		14		40		41
ComEd	9		9		27		25
PECO	2		3		8		8
BGE	4		4		8		8
PHI	5		3		12		9
Pepco	1		1		3		3
DPL	1		1		3		2
ACE	1		—		2		1

Three Months Ended September 30, Nine Months Ended September 30,
Savings Plan Matching Contributions 2017 2016 2017 2016
Exelon $ 34

$ 51

$ 97

$ 107
Generation 14
31
42
56
ComEd 9
10
24
23
PECO 3
3
7
7
BGE 3
2
7
5
BSC^(a)
2
2
7
9
Pepco^(b)
1
—
3
2
DPL^(b)
1
1
2
2
ACE —
—
1
1
PHISCO^(b)(c)
1
2
4
5

Successor Predecessor
Savings Plan Matching Contributions Three Months Ended September 30, 2017 Three Months Ended September 30, 2016 Nine Months Ended September 30, 2017 March 24, 2016 to September 30, 2016 January 1, 2016 to March 23, 2016
PHI $ 3
$ 3
$ 10
$ 7
$ 3

~~_________~~


~~(a)~~	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.


~~(b)~~	Pepco's, DPL's and PHISCO's matching contributions for the nine months ended September 30, 2016 include $1 million, $1 million, and $1 million, respectively, of costs incurred prior to the closing of Exelon’s merger with PHI on March 23, 2016, which is not included in Exelon’s matching contributions for the nine months ended September 30, 2016.


~~(c)~~	~~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.~~

~~15. Severance~~12. Derivative Financial Instruments (All Registrants)

The Registrants ~~have an~~use derivative instruments to manage commodity price risk, interest rate risk, and foreign exchange risk related to ongoing ~~severance plan under which, in general, the longer an employee worked prior to termination the greater the amount of severance benefits. The Registrants record a liability and expense~~business operations.

Authoritative guidance requires that derivative instruments be recognized as either assets or regulatory asset for severance once terminations are probable of occurrence and the related severance benefits can be reasonably estimated. For severance benefits that are incremental to its ongoing severance plan (“one-time termination benefits”), the Registrants measure the obligation and record the expenseliabilities at fair value, with changes in fair value of the derivative recognized in earnings immediately. Other accounting treatments are available through special election and designation, provided they meet specific, restrictive criteria both at the ~~communication date if there~~time of designation and on an ongoing basis. These alternative permissible accounting treatments include NPNS, cash flow hedges, and fair value hedges. All derivative economic hedges related to commodities, referred to as economic hedges, are no

recorded at fair value through earnings at Generation and are offset by a corresponding regulatory asset or liability at ComEd. For all NPNS derivative instruments, accounts receivable or accounts payable are recorded when derivatives settle and revenue or expense is recognized in earnings as the underlying physical commodity is sold or consumed.

~~146~~

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Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— ~~(Continued)~~

(Dollars in millions, except per share data, unless otherwise noted)

Note 12 — Derivative Financial Instruments

~~future service requirements, or, if future service is required~~Authoritative guidance about offsetting assets and liabilities requires the fair value of derivative instruments to ~~receive the termination benefit, ratably over the required service period.~~

~~Ongoing Severance Plans~~

~~The Registrants provide severance and health and welfare benefits under Exelon’s ongoing severance benefit plans to terminated employees~~be shown in the ~~normal course of business. These benefits are accrued for~~Combined Notes to Consolidated Financial Statements on a gross basis, even when the ~~benefits~~derivative instruments are ~~considered probable~~subject to legally enforceable master netting agreements and ~~can be reasonably estimated.~~ qualify for net presentation in the Consolidated Balance Sheets. A master netting agreement is an agreement between two counterparties that may have derivative and non-derivative contracts with each other providing for the net settlement of all referenced contracts via one payment stream, which takes place as the contracts deliver, when collateral is requested or in the event of default. In the tables below, which present fair value balances, Generation’s energy-related economic hedges and proprietary trading derivatives are shown gross. The impact of the netting of fair value balances with the same counterparty that are subject to legally enforceable master netting agreements, as well as netting of cash collateral, including margin on exchange positions, is aggregated in the collateral and netting columns.

~~For the three~~Generation’s and ~~nine months ended September 30, 2017 and 2016, Exelon,~~ComEd’s use of cash collateral is generally unrestricted unless Generation or ComEd ~~PHI,~~are downgraded below investment grade. Cash collateral held by PECO, BGE, Pepco, DPL, and ACE ~~recorded~~must be deposited in an unaffiliated major U.S. commercial bank or foreign bank with a U.S. branch office that meet certain qualifications.

Commodity Price Risk (All Registrants)

Each of the ~~following severance costs~~Registrants employ established policies and procedures to manage their risks associated with market fluctuations in commodity prices by entering into physical and financial derivative contracts, including swaps, futures, forwards, options, and short-term and long-term commitments to purchase and sell energy and commodity products. The Registrants believe these ~~ongoing severance benefits within Operating and maintenance expense~~instruments, which are either determined to be non-derivative or classified as economic hedges, mitigate exposure to fluctuations in ~~their Consolidated Statements~~commodity prices.

Generation. To the extent the amount of ~~Operations and Comprehensive Income.~~

Successor
Exelon
Generation^(a)

ComEd^(a)
PHI
Pepco^(a)

DPL^(a)

ACE^(a)
Three Months Ended
September 30, 2017 $ 1
$ —
$ —
$ 1
$ 1
$ —
$ —
September 30, 2016 8
7
—
1
—
—
—

Nine Months Ended
September 30, 2017 $ 10
$ 4
$ 2
$ 4
$ 2
$ 1
$ 1
September 30, 2016 12
10
1
1
—
—
—

~~_________~~

~~(a)~~

The amounts above for Generation include $2 million for amounts billed by BSC through intercompany allocations for the nine months ended September 30, 2017 and $1 million and $2 million for the three and nine months ended September 30, 2016, respectively. The amounts above for ComEd include $1 million for amounts billed by BSC through intercompany allocations for the three and nine months ended September 30, 2016. The amounts above for PHI include less than $1 million and $1 million billed by BSC through intercompany allocations for the three and nine months ended September 30, 2017, respectively, and $1 million for the three and nine months ended September 30, 2016. Amounts billed by PHISCO to Pepco were $1 million and $2 million for the three and nine months ended September 30, 2017, respectively. Amounts billed by PHISCO to DPL and ACE were $1 million, each, for the nine months ended September 30, 2017. Pepco, DPL and ACE did not have any ongoing severance plans for the three and nine months ended September 30, 2016.

~~Cost Management Program-Related Severance~~

~~In August 2015,~~energy Generation produces differs from the amount of energy it has contracted to sell, Exelon ~~announced a cost management program focused on cost savings at BSC~~ and Generation are exposed to market fluctuations in the prices of electricity, fossil fuels, and other commodities. Within Exelon, Generation has the most exposure to commodity price risk. As such, Generation uses a variety of derivative and non-derivative instruments to manage the commodity price risk of its electric generation facilities, including power and gas sales, fuel and power purchases, natural gas transportation and pipeline capacity agreements, and other energy-related products marketed and purchased. To manage these risks, Generation may enter into fixed-price derivative or non-derivative contracts to hedge the ~~elimination~~variability in future cash flows from expected sales of ~~approximately 500 positions. These actions~~power and gas and purchases of power and fuel. The objectives for executing such hedges include fixing the price for a portion of anticipated future electricity sales at a level that provides an acceptable return. Generation is also exposed to differences between the locational settlement prices of certain economic hedges and the hedged generating units. This price difference is actively managed through other instruments which include derivative congestion products, whose changes in fair value are recognized in ~~response~~earnings each period, and auction revenue rights, which are accounted for on an accrual basis.

Utility Registrants. The Utility Registrants procure electric and natural gas supply through a competitive procurement process approved by each of the ~~continuing economic challenges confronting all parts of Exelon’s business~~respective state utility commissions. The Utility Registrants’ hedging programs are intended to reduce exposure to energy and ~~industry, necessitating continued focus on cost management~~natural gas price volatility and have no direct earnings impact as the costs are fully recovered from customers through ~~enhanced efficiency and productivity. Exelon expects that approximately 250 corporate support positions in BSC and approximately 250 positions located throughout Generation will be eliminated.~~

For the three and nine months ended September 30, 2017 and 2016, the Registrants recorded the following severance costs related to the cost management program within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income, pursuant to the authoritative guidance for ongoing severance plans:regulatory-approved recovery

104

Exelon Generation ComEd PECO BGE
Three Months Ended
September 30, 2017^(a)
$ 7
$ 7
$ —
$ —
$ —
September 30, 2016^(b)
1
1
—
—
—

Nine Months Ended
September 30, 2017^(a)
$ 6
$ 6
$ —
$ —
$ —
September 30, 2016^(b)
18
13
3
1
1

~~_________~~


~~(a)~~	~~Amounts billed by BSC through intercompany allocations for the nine months ended September 30, 2017 were immaterial.~~


~~(b)~~	The amounts above for Generation, ComEd, PECO and BGE include $7 million, $3 million, $1 million and $1 million, respectively, for amounts billed by BSC through intercompany allocations for the nine months ended September 30, 2016.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— ~~(Continued)~~

(Dollars in millions, except per share data, unless otherwise noted)

Note 12 — Derivative Financial Instruments

~~Early Plant Retirement-Related Severance (Exelon and Generation)~~

Asmechanisms. The following table provides a ~~result~~summary of the ~~Three Mile Island plant retirement decision, Exelon~~Utility Registrants’ primary derivative hedging instruments, listed by commodity and Generation will incur certain employee-related costs, including severance benefit costs. Severance costs will be provided to management employees that are eligible under Exelon’s severance policy, to the extent that those employees are not redeployed to other locations. In June 2017, Exelon and Generation recognized severance costs of $17 million related to expected management employee severances resulting from the plant retirements within Operating and maintenance expense in their Consolidated Statements of Operation and Comprehensive Income. Approximately half of the employees at this location fall under a collective bargaining union agreement and are not eligible for severance benefits under an existing plan. The union and Exelon will negotiate terms of any severance benefits. If severance benefits are successfully negotiated, the amounts will be accrued as a one-time employee termination benefit once the established plan is communicated to employees. The final amount of the severance cost will ultimately depend on the specific employees severed. See Note 7 - Early Nuclear Plant Retirements for additional information regarding the announced early retirement of TMI.accounting treatment.

~~Severance Costs Related to the PHI Merger~~

Upon closing the PHI Merger, Exelon recorded a severance accrual for the anticipated employee position reductions as a result of the post-merger integration. Cash payments under the plan began in May 2016 and will continue through 2020.

For the three and nine months ended September 30, 2017 and the three months ended September 30, 2016, the PHI Merger severance costs were immaterial. For the nine months ended September 30, 2016, the Registrants recorded the following severance costs associated with the identified job reductions within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income, pursuant to the authoritative guidance for ongoing severance plans:

Successor
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Nine Months Ended September 30, 2016
Severance costs^(a)
$ 55
$ 9
$ 2
$ 1
$ 1
$ 42
$ 20
$ 12
$ 10

~~_________~~


~~(a)~~Registrant	~~The amounts above~~Commodity	Accounting Treatment	Hedging Instrument
ComEd	Electricity	NPNS	Fixed price contracts based on all requirements in the IPA procurement plans.
	Electricity	Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability(a)	20-year floating-to-fixed energy swap contracts beginning June 2012 based on the renewable energy resource procurement requirements in the Illinois Settlement Legislation of approximately 1.3 million MWhs per year.
PECO	Electricity	NPNS	Fixed price contracts for ~~Generation, ComEd, PECO,~~ default supply requirements through full requirements contracts.
	Gas	NPNS	Fixed price contracts to cover about 10% of planned natural gas purchases in support of projected firm sales.
BGE ~~Pepco, DPL and ACE include $8 million, $2 million, $1 million, $1 million, $19 million, $11 million and $10 million, respectively,~~	Electricity	NPNS	Fixed price contracts for ~~amounts billed by BSC and/or PHISCO~~all SOS requirements through ~~intercompany allocations~~full requirements contracts.
	Gas	NPNS	Fixed price contracts for between 10-20% of forecasted system supply requirements for flowing (i.e., non-storage) gas for the ~~nine months ended September 30, 2016.~~November through March period.
Pepco	Electricity	NPNS	Fixed price contracts for all SOS requirements through full requirements contracts.
DPL	Electricity	NPNS	Fixed price contracts for all SOS requirements through full requirements contracts.
	Gas	NPNS	Fixed and Index priced contracts through full requirements contracts.
		Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability(b)	Exchange traded future contracts for up to 50% of estimated monthly purchase requirements each month, including purchases for storage injections.
ACE	Electricity	NPNS	Fixed price contracts for all BGS requirements through full requirements contracts.

~~PHI, Pepco, DPL and ACE record regulatory assets for merger related integration costs which include a portion~~__________

(a)See Note 3 — Regulatory Matters of the ~~severance costs~~2020 Form 10-K for additional information.

(b)The fair value of the DPL economic hedge is not material as of September 30, 2021 and December 31, 2020 and is not presented in the ~~table above related to~~fair value tables below.

The following tables provide a summary of the ~~PHI Merger. These regulatory assets are either currently being recovered in rates or are deemed probable~~derivative fair value balances recorded by Exelon, Generation, and ComEd as of ~~recovery in future rates. See Note 5 - Regulatory Matters for further information.~~September 30, 2021 and December 31, 2020:

~~Severance Liability~~

Amounts included in the table below represent the severance liability recorded for the severance plans above for employees of each Registrant and exclude amounts included at Exelon and billed through intercompany allocations:


	Exelon		Generation										ComEd
September 30, 2021	Total Derivatives		Economic Hedges		Proprietary Trading		Collateral(a)(b)		Netting(a)		Subtotal		Economic Hedges
Mark-to-market derivative assets (current assets)	$	1,505	$	19,631	$	63	$	(790)	$	(17,399)	$	1,505	$	—
Mark-to-market derivative assets (noncurrent assets)	661		3,612		5		(201)		(2,755)		661		—
Total mark-to-market derivative assets	2,166		23,243		68		(991)		(20,154)		2,166		—
Mark-to-market derivative liabilities (current liabilities)	(1,710)		(18,490)		(55)		(559)		17,399		(1,705)		(5)
Mark-to-market derivative liabilities (noncurrent liabilities)	(720)		(3,168)		(3)		(95)		2,755		(511)		(209)
Total mark-to-market derivative liabilities	(2,430)		(21,658)		(58)		(654)		20,154		(2,216)		(214)
Total mark-to-market derivative net (liabilities) assets	$	(264)	$	1,585	$	10	$	(1,645)	$	—	$	(50)	$	(214)

105

Successor
Severance Liability Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Balance at December 31, 2016 $ 88
$ 36
$ 3
$ —
$ —
$ 29
$ —
$ —
$ —
Severance charges^(a)
33
25
1
—
—
3
—
—
—
Payments (24 ) (7 ) (1 ) —
—
(11 ) —
—
—
Balance at September 30, 2017 $ 97
$ 54
$ 3
$ —
$ —
$ 21
$ —
$ —
$ —

~~_________~~


~~(a)~~	~~Includes salary continuance and health and welfare severance benefits.~~

~~148~~

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— ~~(Continued)~~

(Dollars in millions, except per share data, unless otherwise noted)

Note 12 — Derivative Financial Instruments

~~16. Changes~~


	Exelon		Generation										ComEd
December 31, 2020	Total Derivatives		Economic Hedges		Proprietary Trading		Collateral(a)(b)		Netting(a)		Subtotal		Economic Hedges
Mark-to-market derivative assets (current assets)	$	639	$	2,757	$	40	$	103	$	(2,261)	$	639	$	—
Mark-to-market derivative assets (noncurrent assets)	554		1,501		4		64		(1,015)		554		—
Total mark-to-market derivative assets	1,193		4,258		44		167		(3,276)		1,193		—
Mark-to-market derivative liabilities (current liabilities)	(293)		(2,629)		(23)		131		2,261		(260)		(33)
Mark-to-market derivative liabilities (noncurrent liabilities)	(472)		(1,335)		(2)		118		1,015		(204)		(268)
Total mark-to-market derivative liabilities	(765)		(3,964)		(25)		249		3,276		(464)		(301)
Total mark-to-market derivative net assets (liabilities)	$	428	$	294	$	19	$	416	$	—	$	729	$	(301)

_________

(a)Exelon and Generation net all available amounts allowed under the derivative authoritative guidance in ~~Accumulated Other Comprehensive Income (Exelon,~~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 ~~PECO~~may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and ~~PHI)~~payables, transactions that do not qualify as derivatives, letters of credit, and other forms of non-cash collateral. As of September 30, 2021, $1 million of cash collateral posted with external counterparties and an additional $71 million of cash collateral posted with affiliates, including $50 million with ComEd, and as of December 31, 2020, $15 million of cash collateral held with external counterparties, was not offset against derivative positions because such collateral was not associated with any energy-related derivatives, was associated with accrual positions, or had no positions to offset as of the balance sheet date.

~~The following tables present changes in accumulated other comprehensive income (loss) (AOCI) by component for~~(b)Includes $2,084 million held and $209 million posted of variation margin with the exchanges as of September 30, 2021 and December 31, 2020 respectively.

Economic Hedges (Commodity Price Risk)

Generation. For the three and nine months ended September 30, ~~2017~~2021 and ~~2016:~~2020, Exelon and Generation recognized the following net pre-tax commodity mark-to-market gains (losses) which are also located in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows.


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Income Statement Location	(Loss) Gain				(Loss) Gain
Operating revenues	$	(637)	$	39	$	(961)	$	238
Purchased power and fuel	1,392		209		2,209		224
Total Exelon and Generation	$	755	$	248	$	1,248	$	462

Proprietary Trading (Commodity Price Risk)

Generation also executes commodity derivatives for proprietary trading purposes. Proprietary trading includes all contracts executed with the intent of benefiting from shifts or changes in market prices as opposed to those executed with the intent of hedging or managing risk. Gains and losses associated with proprietary trading are reported as Operating revenues in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income and are included in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows. For the three and nine months ended September 30, 2021 and 2020,

106

Nine Months Ended September 30, 2017 Gains
and
(losses)
on Cash Flow Hedges
Unrealized
Gains and
(losses) on
Marketable
Securities

Pension and
Non-Pension
Postretirement
Benefit Plan
Items

Foreign
Currency
Items

AOCI of
Equity
Investments
Total
Exelon^(a)

Beginning balance $ (17 ) $ 4
$ (2,610 ) $ (30 ) $ (7 ) $ (2,660 )
OCI before reclassifications 2
2
(55 ) 7
7
(37 )
Amounts reclassified from AOCI^(b)
3
—
105
—
—
108
Net current-period OCI 5
2
50
7
7
71
Ending balance $ (12 ) $ 6
$ (2,560 ) $ (23 ) $ —
$ (2,589 )
Generation^(a)

Beginning balance $ (19 ) $ 2
$ —
$ (30 ) $ (7 ) $ (54 )
OCI before reclassifications 2
—
—
7
6
15
Amounts reclassified from AOCI^(b)
3
—
—
—
—
3
Net current-period OCI 5
—
—
7
6
18
Ending balance $ (14 ) $ 2
$ —
$ (23 ) $ (1 ) $ (36 )
PECO^(a)

Beginning balance $ —
$ 1
$ —
$ —
$ —
$ 1
OCI before reclassifications —
—
—
—
—
—
Amounts reclassified from AOCI^(b)
—
—
—
—
—
—
Net current-period OCI —
—
—
—
—
—
Ending balance $ —
$ 1
$ —
$ —
$ —
$ 1

~~149~~

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— ~~(Continued)~~

(Dollars in millions, except per share data, unless otherwise noted)

Note 12 — Derivative Financial Instruments

net pre-tax commodity mark-to-market gains and losses for Exelon and Generation were not material. The Utility Registrants do not execute derivatives for proprietary trading purposes.

Interest Rate and Foreign Exchange Risk (Exelon and Generation)

Credit Risk (All Registrants)

107

Nine Months Ended September 30, 2016 Gains
and
(losses)
on Cash Flow Hedges
Unrealized
Gains and
(losses) on
Marketable
Securities

Pension and
Non-Pension
Postretirement
Benefit Plan
Items

Foreign
Currency
Items

AOCI of
Equity
Investments
Total
Exelon^(a)

Beginning balance $ (19 ) $ 3
$ (2,565 ) $ (40 ) $ (3 ) $ (2,624 )
OCI before reclassifications (9 ) —
(2 ) 3
(5 ) (13 )
Amounts reclassified from AOCI^(b)
5
—
104
5
—
114
Net current-period OCI (4 ) —
102
8
(5 ) 101
Ending balance $ (23 ) $ 3
$ (2,463 ) $ (32 ) $ (8 ) $ (2,523 )
Generation^(a)

Beginning balance $ (21 ) $ 1
$ —
$ (40 ) $ (3 ) $ (63 )
OCI before reclassifications (8 ) 1
—
3
1
(3 )
Amounts reclassified from AOCI^(b)
5
—
—
5
—
10
Net current-period OCI (3 ) 1
—
8
1
7
Ending balance $ (24 ) $ 2
$ —
$ (32 ) $ (2 ) $ (56 )
PECO^(a)

Beginning balance $ —
$ 1
$ —
$ —
$ —
$ 1
OCI before reclassifications —
—
—
—
—
—
Amounts reclassified from AOCI^(b)
—
—
—
—
—
—
Net current-period OCI —
—
—
—
—
—
Ending balance $ —
$ 1
$ —
$ —
$ —
$ 1
PHI Predecessor^(a)

Beginning balance January 1, 2016 $ (8 ) $ —
$ (28 ) $ —
$ —
$ (36 )
OCI before reclassifications —
—
—
—
—
—
Amounts reclassified from AOCI^(b)
—
—
1
—
—
1
Net current-period OCI —
—
1
—
—
1
Ending balance March 23, 2016^(c)
$ (8 ) $ —
$ (27 ) $ —
$ —
$ (35 )

~~_________~~


~~(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)~~	~~As a result of the PHI Merger, the PHI predecessor balances at March 23, 2016 were reduced to zero on March 24, 2016 due to purchase accounting adjustments applied to PHI.~~

~~150~~

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— ~~(Continued)~~

(Dollars in millions, except per share data, unless otherwise noted)

Note 12 — Derivative Financial Instruments

~~ComEd, PECO, BGE, Pepco, DPL and ACE did not have any reclassifications out of AOCI to Net income during the three and nine months ended September 30, 2017 and 2016.~~ The following tables ~~present amounts reclassified out~~provide information on Generation’s credit exposure for all derivative instruments, NPNS, and payables and receivables, net of ~~AOCI~~collateral and instruments that are subject to ~~Net income for Exelon, Generation and PHI during the three and nine months ended~~master netting agreements, as of September 30, ~~2017~~2021. The tables further delineate that exposure by credit rating of the counterparties and ~~2016.~~provide guidance on the concentration of credit risk to individual counterparties. The amounts in the tables below exclude credit risk exposure from individual retail counterparties, nuclear fuel procurement contracts, and exposure through RTOs, ISOs, NYMEX, ICE, NASDAQ, NGX, and Nodal commodity exchanges.

~~Three Months Ended~~


Rating as of September 30, 2021	Total Exposure Before Credit Collateral		Credit Collateral(a)		Net Exposure		Number of Counterparties Greater than 10% of Net Exposure	Net Exposure of Counterparties Greater than 10% of Net Exposure
Investment grade	$	701	$	254	$	447	—	$	—
Non-investment grade	23		2		21		—	—
No external ratings
Internally rated — investment grade	110		1		109		—	—
Internally rated — non-investment grade	309		48		261		—	—
Total	$	1,143	$	305	$	838	—	$	—


Net Credit Exposure by Type of Counterparty	As of September 30, 2021
Financial institutions	$	53
Investor-owned utilities, marketers, power producers	652
Energy cooperatives and municipalities	62
Other	71
Total	$	838

_________

(a)As of September 30, ~~2017~~2021, credit collateral held from counterparties where Generation had credit exposure included $188 million of cash and $117 million of letters of credit. The credit collateral does not include non-liquid collateral.

Details about AOCI components
Items reclassified out of AOCI^(a)
Affected line item in the Statement of Operations and Comprehensive Income
Exelon Generation
Gains (losses) on cash flow hedges
Other cash flow hedges $ 2
$ 2
Interest expense
Total before tax 2
2

Tax benefit (1 ) (1 )
Net of tax $ 1
$ 1
Comprehensive income

Amortization of pension and other postretirement benefit plan items
Prior service costs^(b)
$ 23
$ —

Actuarial losses^(b)
(81 ) —

Total before tax (58 ) —

Tax benefit 23
—

Net of tax $ (35 ) $ —

Total Reclassifications for the period $ (34 ) $ 1
Comprehensive income

~~Nine Months Ended~~Utility Registrants. The Utility Registrants have contracts to procure electric and natural gas supply that provide suppliers with a certain amount of unsecured credit. If the exposure on the supply contract exceeds the amount of unsecured credit, the suppliers may be required to post collateral. The net credit exposure is mitigated primarily by the ability to recover procurement costs through customer rates. As of September 30, ~~2017~~2021, the amount of cash collateral held with external counterparties by ComEd, BGE, and DPL was $56 million, $21 million, and $25 million, respectively, which is recorded in Other Current Liabilities in ComEd’s, BGE’s, and DPL’s Consolidated Balance Sheets. The amounts for PECO, Pepco, and ACE as of September 30, 2021 and for the Utility Registrants as of December 31, 2020 are not material. The amount for ComEd as of September 30, 2021 does not include cash collateral held from Generation, which is disclosed in the notes to the derivative fair value balances tables above.

Credit-Risk-Related Contingent Features (All Registrants)

108

Details about AOCI components
Items reclassified out of AOCI^(a)
Affected line item in the Statement of Operations and Comprehensive Income

Exelon Generation
Gains and (losses) on cash flow hedges
Other cash flow hedges $ (5 ) $ (5 ) Interest expense
Total before tax (5 )
(5 )

Tax benefit 2
2

Net of tax $ (3 ) $ (3 ) Comprehensive income

Amortization of pension and other postretirement benefit plan items
Prior service costs^(b)
$ 69
$ —

Actuarial losses^(b)
(243 ) —

Total before tax (174 ) —

Tax benefit 69
—

Net of tax $ (105 ) $ —

Total Reclassifications $ (108 ) $ (3 ) Comprehensive income

~~151~~

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— ~~(Continued)~~

(Dollars in millions, except per share data, unless otherwise noted)

Note 12 — Derivative Financial Instruments

~~Three Months Ended~~the contractual right of offset exists under applicable master netting agreements. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. In this case, Generation believes an amount of several months of future payments (i.e., capacity payments) rather than a calculation of fair value is the best estimate for the contingent collateral obligation, which has been factored into the disclosure below.


Credit-Risk Related Contingent Features	September 30, 2021		December 31, 2020
Gross fair value of derivative contracts containing this feature(a)	$	(5,289)	$	(834)
Offsetting fair value of in-the-money contracts under master netting arrangements(b)	2,735		537
Net fair value of derivative contracts containing this feature(c)	$	(2,554)	$	(297)

_________

(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.

As of September 30, ~~2016~~2021 and December 31, 2020, Exelon and Generation posted or held the following amounts of cash collateral and letters of credit on derivative contracts with external counterparties, after giving consideration to offsetting derivative and non-derivative positions under master netting agreements.


	September 30, 2021		December 31, 2020
Cash collateral posted	$	299	$	511
Letters of credit posted	477		226
Cash collateral held	1,872		110
Letters of credit held	130		40
Additional collateral required in the event of a credit downgrade below investment grade	3,001		1,432

Utility Registrants

The Utility Registrants’ electric supply procurement contracts do not contain provisions that would require them to post collateral.

109

Details about AOCI components
Items reclassified out of AOCI^(a)
Affected line item in the Statement of Operations and Comprehensive Income

Exelon Generation
Gains and (losses) on cash flow hedges
Other cash flow hedges $ (3 ) $ (3 ) Interest expense
Total before tax (3 ) (3 )
Tax expense 1
1

Net of tax $ (2 ) $ (2 ) Comprehensive income

Amortization of pension and other postretirement benefit plan items
Prior service costs^(b)
$ 19
$ —

Actuarial losses^(b)
(76 ) —

Total before tax (57 ) —

Tax benefit 22
—

Net of tax $ (35 ) $ —

Gains and (losses) on foreign currency translation
Other $ (5 ) $ (5 ) Other Income and (deductions)
Total before tax (5 ) (5 )
Tax expense —
—

Net of tax $ (5 ) $ (5 ) Comprehensive income

Total Reclassifications for the period $ (42 ) $ (7 ) Comprehensive income

~~152~~

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— ~~(Continued)~~

(Dollars in millions, except per share data, unless otherwise noted)

Note 13 — Debt and Credit Agreements

~~Nine Months Ended~~

13. Debt and Credit Agreements (All Registrants)

Short-Term Borrowings

Exelon Corporate, ComEd, and BGE meet their short-term liquidity requirements primarily through the issuance of commercial paper. Generation and PECO meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the Exelon intercompany money pool. Pepco, DPL, and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the PHI intercompany money pool. PHI Corporate meets its short-term liquidity requirements primarily through the issuance of short-term notes and the Exelon intercompany money pool. The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit.

Commercial Paper

The following table reflects the Registrants' commercial paper programs as of September 30, ~~2016~~2021 and December 31, 2020. PECO and BGE had no commercial paper borrowings as of September 30, 2021 and December 31, 2020.


	Outstanding Commercial Paper as of				Average Interest Rate on Commercial Paper Borrowings as of
Commercial Paper Issuer	September 30, 2021		December 31, 2020		September 30, 2021		December 31, 2020
Exelon(a)	$	287	$	1,031	0.19	%	0.25	%
Generation	—		340		—	%	0.27	%
ComEd	—		323		—	%	0.23	%


PHI(b)	287		368		0.19	%	0.24	%

Pepco	40		35		0.15	%	0.22	%
DPL	22		146		0.15	%	0.24	%
ACE	225		187		0.20	%	0.25	%

__________

(a)Exelon Corporate had no outstanding commercial paper borrowings as of September 30, 2021 and December 31, 2020.

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

See Note 17 — Debt and Credit Agreements of the Exelon 2020 Form 10-K for additional information on the Registrants' credit facilities.

Short-Term Loan Agreements

On March 23, 2017, Exelon Corporate entered into a term loan agreement for $500 million. The loan agreement was renewed on March 17, 2021 and will expire on March 16, 2022. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.65% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Exelon's Consolidated Balance Sheets within Short-term borrowings.

On March 24, 2021, Exelon Corporate entered into a 9-month term loan agreement for $200 million. The loan agreement has an expiration of December 24, 2021. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.65% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Exelon's Consolidated Balance Sheets within Short-term borrowings.

On March 31, 2021, Exelon Corporate entered into a 9-month and 364-day term loan agreement for $150 million each with variable interest rates of LIBOR plus 0.65% and expiration dates of December 31, 2021 and March 30, 2022, respectively. The loan agreements are reflected in Exelon's Consolidated Balance Sheets within Short-term borrowings.

110

Details about AOCI components
Items reclassified out of AOCI^(a)
Affected line item in the Statement of Operations and Comprehensive Income
Predecessor
Exelon Generation PHI
Gains and (losses) on cash flow hedges
Other cash flow hedges $ (8 ) $ (8 ) $ —
Interest expense
Total before tax (8 )
(8 )
—

Tax benefit 3
3
—

Net of tax $ (5 ) $ (5 ) $ —
Comprehensive income

Amortization of pension and other postretirement benefit plan items
Prior service costs^(b)
$ 57
$ —
$ —

Actuarial losses^(b)
(227 ) —
(1 )
Total before tax (170 ) —
(1 )
Tax benefit 66
—
—

Net of tax $ (104 ) $ —
$ (1 )

Gains and (losses) on foreign currency translation
Other $ (5 ) $ (5 ) $ —
Other income and (deductions)
Total before tax (5 ) (5 ) —

Tax expense —
—
—

Net of tax $ (5 ) $ (5 ) $ —

Total Reclassifications $ (114 ) $ (10 ) $ (1 ) Comprehensive income

~~_________~~


~~(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).~~

~~153~~

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— ~~(Continued)~~

(Dollars in millions, except per share data, unless otherwise noted)

Note 13 — Debt and Credit Agreements

On March 19, 2020, Generation entered into a term loan agreement for $200 million. The ~~following table presents income tax expense (benefit) allocated~~loan agreement was renewed on March 17, 2021 and will expire on March 16, 2022. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.875% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Exelon's and Generation's Consolidated Balance Sheets within Short-term borrowings.

On March 31, 2020, Generation entered into a term loan agreement for $300 million. The loan agreement was renewed on March 30, 2021 and will expire on March 29, 2022. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.70% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Exelon's and Generation's Consolidated Balance Sheets within Short-term borrowings.

On August 6, 2021, Generation entered into a 364-day term loan agreement for $880 million with a variable interest rate of LIBOR plus 0.875% until March 31, 2022 and a rate of LIBOR plus 1% thereafter and all indebtedness thereunder is unsecured. The loan agreement has an expiration date of August 5, 2022 and is reflected in Short-term borrowings in Exelon's and Generation's Consolidated Balance Sheets.

On January 25, 2021, ComEd entered into two 90-day term loan agreements for $125 million each ~~component~~with variable interest rates of ~~other comprehensive income (loss) during~~LIBOR plus 0.50% and LIBOR plus 0.75%, respectively. ComEd repaid the ~~three~~term loans on March 9, 2021.

Bilateral Credit Agreements

On January 11, 2013, Generation entered into a bilateral credit agreement for $100 million. The agreement was renewed on March 1, 2021 with a maturity date of March 1, 2023.

On February 21, 2019, Generation entered into a bilateral credit agreement for $100 million. The agreement was renewed on March 31, 2021 with a maturity date of March 31, 2022.

On January 5, 2016, Generation entered into a bilateral credit agreement for $150 million. The agreement was renewed on April 2, 2021 with a maturity date of April 5, 2023.

On October 26, 2012, Generation entered into a bilateral credit agreement for $200 million. The agreement had a maturity date of October 22, 2021, however, was terminated on August 27, 2021.

See Note 17 — Debt and Credit Agreements of the Exelon 2020 Form 10-K for additional information on Generation's bilateral credit agreements.

Credit Agreements

On July 15, 2021, each of the Registrants' respective syndicated revolving credit facilities had their maturity dates extended to May 26, 2024.

Long-Term Debt

Issuance of Long-Term Debt

During the nine months ended September 30, ~~2017 and 2016:~~

Three Months Ended September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Exelon
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost $ 9
$ 7
$ 27
$ 22
Actuarial loss reclassified to periodic benefit cost (32 ) (29 ) (96 ) (88 )
Pension and non-pension postretirement benefit plans valuation adjustment —
1
2
1
Change in unrealized (loss)/gain on cash flow hedges —
(1 ) (3 ) 3
Change in unrealized (loss)/gain on equity investments 1
—
(2 ) 3
Change in unrealized (loss)/gain on marketable securities —
(1 ) (2 ) (1 )
Total $ (22 ) $ (23 ) $ (74 ) $ (60 )

Generation
Change in unrealized (loss)/gain on cash flow hedges $ —
$ (2 ) $ (3 ) $ 1
Change in unrealized (loss)/gain on equity investments —
—
(2 ) 3
Change in unrealized gain on marketable securities —
—
(1 ) —
Total $ —
$ (2 ) $ (6 ) $ 4
2021, the following long-term debt was issued:

111



	~~Predecessor~~
~~PHI~~	~~January 1, 2016 to March 23, 2016~~
~~Pension and non-pension postretirement benefit plans:~~
~~Actuarial loss reclassified to periodic cost~~	$	—

~~17. Earnings Per Share and Equity (Exelon)~~

~~Earnings per Share~~

Diluted earnings per share is calculated by dividing Net income attributable to common shareholders by the weighted average number of shares of common stock outstanding, including shares to be issued upon exercise of stock options, performance share awards and restricted stock outstanding under Exelon’s LTIPs considered to be common stock equivalents. The following table sets forth the components of basic and diluted earnings per share and shows the effect of these stock options, performance share awards and restricted stock on the weighted average number of shares outstanding used in calculating diluted earnings per share:

Three Months Ended September 30,
Nine Months Ended September 30,
2017
2016
2017
2016
Exelon
Net income attributable to common shareholders $ 824
$ 490
$ 1,899
$ 930
Weighted average common shares outstanding — basic 962
925
941
924
Assumed exercise and/or distributions of stock-based awards 3
2
2
2
Weighted average common shares outstanding — diluted 965
927
943
926

~~154~~

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— ~~(Continued)~~

(Dollars in millions, except per share data, unless otherwise noted)

Note 13 — Debt and Credit Agreements

Company

Type

Interest Rate

Maturity

Amount

Use of Proceeds

Exelon

Long-Term Software License Agreements

3.62

December 1, 2025

Procurement of software licenses.

Generation

West Medway II
Nonrecourse Debt

LIBOR + 3%

(a)

March 31, 2026

150

Funding for general corporate purposes.

Generation

Energy Efficiency Project Financing(b)

2.53

November 30, 2021

Funding to install energy conservation measures for the Fort AP Hill project.

Generation

Energy Efficiency Project Financing(b)

4.24

November 30, 2021

Funding to install energy conservation measures for the Marine Corps. Logistics Project.

ComEd

First Mortgage Bonds, Series 130

3.13

March 15, 2051

700

Repay a portion of outstanding commercial paper obligations and two outstanding term loans, and to fund other general corporate purposes.

ComEd

First Mortgage Bonds, Series 131

2.75

September 1, 2051

450

Refinance existing indebtedness and for general corporate purposes.

PECO

First and Refunding Mortgage Bonds

3.05

March 15, 2051

375

Funding for general corporate purposes.

PECO

First and Refunding Mortgage Bonds

2.85

September 15, 2051

375

Refinance existing indebtedness and for general corporate purposes.

BGE

Senior Notes

2.25

June 15, 2031

600

Repay a portion of outstanding commercial paper obligations, repay existing indebtedness, and to fund other general corporate purposes.

Pepco

First Mortgage Bonds

2.32

March 30, 2031

150

Repay existing indebtedness and for general corporate purposes.

Pepco

First Mortgage Bonds

3.29

September 28, 2051

125

Repay existing indebtedness and for general corporate purposes.

DPL

First Mortgage Bonds

3.24

March 30, 2051

125

Repay existing indebtedness and for general corporate purposes.

ACE

First Mortgage Bonds

2.30

March 15, 2031

350

Refinance existing indebtedness, repay outstanding commercial paper obligations, and for general corporate purposes.

__________

(a)The nonrecourse debt has an average blended interest rate.

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

Debt Covenants

As of September 30, 2021, the Registrants are in compliance with debt covenants.

Nonrecourse Debt

Exelon and Generation have issued nonrecourse debt financing. Borrowings under these agreements are secured by the assets and equity of each respective project. The lenders do not have recourse against Exelon or Generation in the event of a default.

West Medway II, LLC. On May 13, 2021, West Medway II, LLC (West Medway II), an indirect subsidiary of Generation, entered into a financing agreement for a $150 million nonrecourse senior secured term loan credit facility with a maturity date of March 31, 2026. The term loan bears interest at an average blended interest rate of

112

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(Dollars in millions, except per share data, unless otherwise noted)

Note 13 — Debt and Credit Agreements

LIBOR plus 3%, paid quarterly. In addition to the financing, West Medway II, entered into interest rate swaps with an initial notional amount of $113 million at an interest rate of 0.61%, paid quarterly, to manage a portion of the interest rate exposure in connection with the financing. The net proceeds were distributed to Generation for general corporate purposes. Generation’s interests in West Medway II, were pledged as collateral for this financing. As of September 30, 2021, approximately $145 million was outstanding.

See Note 17 — Debt and Credit Agreements of the Exelon 2020 Form 10-K for additional information on nonrecourse debt and Note 12 — Derivative Financial Instruments for additional information on interest rate swaps.

14. Fair Value of Financial Assets and Liabilities (All Registrants)

Exelon measures and classifies fair value measurements in accordance with the hierarchy as defined by GAAP. The hierarchy prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:

•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.

113

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(Dollars in millions, except per share data, unless otherwise noted)

Note 14 — Fair Value of Financial Assets and Liabilities

Fair Value of Financial Liabilities Recorded at Amortized Cost

The ~~number~~following tables present the carrying amounts and fair values of ~~stock options~~the Registrants’ short-term liabilities, long-term debt, SNF obligation, and trust preferred securities (long-term debt to financing trusts or junior subordinated debentures) as of September 30, 2021 and December 31, 2020. The Registrants have no financial liabilities classified as Level 1.

The carrying amounts of the Registrants’ short-term liabilities as presented in their Consolidated Balance Sheets are representative of their fair value (Level 2) because of the short-term nature of these instruments.


	September 30, 2021								December 31, 2020
	Carrying Amount		Fair Value						Carrying Amount		Fair Value
			Level 2		Level 3		Total				Level 2		Level 3		Total
Long-Term Debt, including amounts due within one year(a)
Exelon	$	38,644	$	40,570	$	3,289	$	43,859	$	36,912	$	40,688	$	3,064	$	43,752
Generation	6,130		5,835		1,111		6,946		6,087		5,648		1,208		6,856
ComEd	9,772		11,344		—		11,344		8,983		11,117		—		11,117
PECO	4,196		4,738		50		4,788		3,753		4,553		50		4,603
BGE	3,960		4,416		—		4,416		3,664		4,366		—		4,366
PHI	7,482		6,030		2,128		8,158		7,006		6,099		1,806		7,905
Pepco	3,441		3,226		990		4,216		3,165		3,336		748		4,084
DPL	1,808		1,433		559		1,992		1,677		1,484		455		1,939
ACE	1,510		1,107		579		1,686		1,413		1,018		602		1,620
Long-Term Debt to Financing Trusts(a)
Exelon	$	390	$	—	$	479	$	479	$	390	$	—	$	467	$	467
ComEd	205		—		255		255		205		—		246		246
PECO	184		—		224		224		184		—		221		221
SNF Obligation
Exelon	$	1,209	$	1,021	$	—	$	1,021	$	1,208	$	909	$	—	$	909
Generation	1,209		1,021		—		1,021		1,208		909		—		909

__________

(a)Includes unamortized debt issuance costs which are not ~~included~~fair valued.

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(Dollars in millions, except per share data, unless otherwise noted)

Note 14 — Fair Value of Financial Assets and Liabilities

Recurring Fair Value Measurements

The following tables present assets and liabilities measured and recorded at fair value in the ~~calculation~~Registrants' Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of ~~diluted common shares outstanding due to their antidilutive effect was approximately 7~~September 30, 2021 and December 31, 2020:

Exelon and Generation


	Exelon										Generation
As of September 30, 2021	Level 1		Level 2		Level 3		Not subject to leveling		Total		Level 1		Level 2		Level 3		Not subject to leveling		Total
Assets
Cash equivalents(a)	$	2,573	$	—	$	—	$	—	$	2,573	$	1,673	$	—	$	—	$	—	$	1,673
NDT fund investments
Cash equivalents(b)	647		135		—		—		782		647		135		—		—		782



Equities	4,373		1,717		1		1,559		7,650		4,373		1,717		1		1,559		7,650
Fixed income
Corporate debt(c)	—		1,155		287		—		1,442		—		1,155		287		—		1,442
U.S. Treasury and agencies	2,192		29		—		—		2,221		2,192		29		—		—		2,221
Foreign governments	—		54		—		—		54		—		54		—		—		54
State and municipal debt	—		29		—		—		29		—		29		—		—		29
Other	31		29		—		1,259		1,319		31		29		—		1,259		1,319
Fixed income subtotal	2,223		1,296		287		1,259		5,065		2,223		1,296		287		1,259		5,065
Private credit	—		—		187		592		779		—		—		187		592		779
Private equity	—		—		—		654		654		—		—		—		654		654
Real estate	—		—		—		802		802		—		—		—		802		802

NDT fund investments subtotal(d)(e)	7,243		3,148		475		4,866		15,732		7,243		3,148		475		4,866		15,732
Rabbi trust investments
Cash equivalents	65		—		—		—		65		4		—		—		—		4
Mutual funds	104		—		—		—		104		35		—		—		—		35
Fixed income	—		10		—		—		10		—		—		—		—		—
Life insurance contracts	—		99		34		—		133		—		33		—		—		33
Rabbi trust investments subtotal	169		109		34		—		312		39		33		—		—		72
Investments in equities(f)	137		—		—		—		137		137		—		—		—		137
Commodity derivative assets
Economic hedges	5,527		10,633		7,083		—		23,243		5,527		10,633		7,083		—		23,243
Proprietary trading	—		56		12		—		68		—		56		12		—		68
Effect of netting and allocation of collateral(g)(h)	(4,468)		(9,869)		(6,808)		—		(21,145)		(4,468)		(9,869)		(6,808)		—		(21,145)
Commodity derivative assets subtotal	1,059		820		287		—		2,166		1,059		820		287		—		2,166
DPP consideration	—		501		—		—		501		—		501		—		—		501

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in millions, except per share data, unless otherwise noted)

Note 14 — Fair Value of Financial Assets and Liabilities


	Exelon										Generation
As of September 30, 2021	Level 1		Level 2		Level 3		Not subject to leveling		Total		Level 1		Level 2		Level 3		Not subject to leveling		Total
Total assets	11,181		4,578		796		4,866		21,421		10,151		4,502		762		4,866		20,281
Liabilities
Commodity derivative liabilities
Economic hedges	(4,126)		(9,192)		(8,554)		—		(21,872)		(4,126)		(9,192)		(8,340)		—		(21,658)
Proprietary trading	—		(32)		(26)		—		(58)		—		(32)		(26)		—		(58)
Effect of netting and allocation of collateral(g)(h)	4,123		9,159		6,218		—		19,500		4,123		9,159		6,218		—		19,500
Commodity derivative liabilities subtotal	(3)		(65)		(2,362)		—		(2,430)		(3)		(65)		(2,148)		—		(2,216)
Deferred compensation obligation	—		(149)		—		—		(149)		—		(44)		—		—		(44)
Total liabilities	(3)		(214)		(2,362)		—		(2,579)		(3)		(109)		(2,148)		—		(2,260)
Total net assets (liabilities)	$	11,178	$	4,364	$	(1,566)	$	4,866	$	18,842	$	10,148	$	4,393	$	(1,386)	$	4,866	$	18,021


	Exelon										Generation
As of December 31, 2020	Level 1		Level 2		Level 3		Not subject to leveling		Total		Level 1		Level 2		Level 3		Not subject to leveling		Total
Assets
Cash equivalents(a)	$	686	$	—	$	—	$	—	$	686	$	124	$	—	$	—	$	—	$	124
NDT fund investments
Cash equivalents(b)	210		95		—		—		305		210		95		—		—		305



Equities	3,886		2,077		—		1,562		7,525		3,886		2,077		—		1,562		7,525
Fixed income
Corporate debt(c)	—		1,485		285		—		1,770		—		1,485		285		—		1,770
U.S. Treasury and agencies	1,871		126		—		—		1,997		1,871		126		—		—		1,997
Foreign governments	—		56		—		—		56		—		56		—		—		56
State and municipal debt	—		101		—		—		101		—		101		—		—		101
Other	—		41		—		961		1,002		—		41		—		961		1,002
Fixed income subtotal	1,871		1,809		285		961		4,926		1,871		1,809		285		961		4,926
Private credit	—		—		212		629		841		—		—		212		629		841
Private equity	—		—		—		504		504		—		—		—		504		504
Real estate	—		—		—		679		679		—		—		—		679		679

NDT fund investments subtotal(d)(e)	5,967		3,981		497		4,335		14,780		5,967		3,981		497		4,335		14,780
Rabbi trust investments
Cash equivalents	60		—		—		—		60		4		—		—		—		4
Mutual funds	91		—		—		—		91		29		—		—		—		29
Fixed income	—		11		—		—		11		—		—		—		—		—
Life insurance contracts	—		87		34		—		121		—		28		—		—		28
Rabbi trust investments subtotal	151		98		34		—		283		33		28		—		—		61
Investments in equities(f)	195		—		—		—		195		195		—		—		—		195
Commodity derivative assets
Economic hedges	745		1,914		1,599		—		4,258		745		1,914		1,599		—		4,258
Proprietary trading	—		17		27		—		44		—		17		27		—		44

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in millions, except per share data, unless otherwise noted)

Note 14 — Fair Value of Financial Assets and Liabilities


	Exelon										Generation
As of December 31, 2020	Level 1		Level 2		Level 3		Not subject to leveling		Total		Level 1		Level 2		Level 3		Not subject to leveling		Total
Effect of netting and allocation of collateral(g)(h)	(607)		(1,597)		(905)		—		(3,109)		(607)		(1,597)		(905)		—		(3,109)
Commodity derivative assets subtotal	138		334		721		—		1,193		138		334		721		—		1,193
DPP consideration	—		639		—		—		639		—		639		—		—		639
Total assets	7,137		5,052		1,252		4,335		17,776		6,457		4,982		1,218		4,335		16,992
Liabilities
Commodity derivative liabilities
Economic hedges	(682)		(1,928)		(1,655)		—		(4,265)		(682)		(1,928)		(1,354)		—		(3,964)
Proprietary trading	—		(21)		(4)		—		(25)		—		(21)		(4)		—		(25)
Effect of netting and allocation of collateral(g)(h)	540		1,918		1,067		—		3,525		540		1,918		1,067		—		3,525
Commodity derivative liabilities subtotal	(142)		(31)		(592)		—		(765)		(142)		(31)		(291)		—		(464)
Deferred compensation obligation	—		(145)		—		—		(145)		—		(42)		—		—		(42)
Total liabilities	(142)		(176)		(592)		—		(910)		(142)		(73)		(291)		—		(506)
Total net assets	$	6,995	$	4,876	$	660	$	4,335	$	16,866	$	6,315	$	4,909	$	927	$	4,335	$	16,486

__________

(a)Exelon excludes cash of $689 million and 9$409 million at September 30, 2021 and December 31, 2020, respectively, and restricted cash of $222 million and $59 million at September 30, 2021 and December 31, 2020, respectively, and includes long-term restricted cash of $54 million and $53 million at September 30, 2021 and December 31, 2020, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. Generation excludes cash of $292 million and $171 million at September 30, 2021 and December 31, 2020, respectively, and restricted cash of $54 million and $20 million at September 30, 2021 and December 31, 2020, respectively.

(b)Includes $109 million and $116 million of cash received from outstanding repurchase agreements at September 30, 2021 and December 31, 2020, respectively, and is offset by an obligation to repay upon settlement of the agreement as discussed in (e) below.

(c)Includes investments in equities sold short of $(50) million and $(62) million as of September 30, 2021 and December 31, 2020, respectively, held in an investment vehicle primarily to hedge the equity option component of its convertible debt.

(d)Includes net derivative liabilities of less than $1 million and net derivative assets of $2 million, which have total notional amounts of $728 million and $1,043 million at September 30, 2021 and December 31, 2020, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the periods ended and do not represent the amount of Exelon and Generation's exposure to credit or market loss.

(e)Excludes net liabilities of $130 million and $181 million at September 30, 2021 and December 31, 2020, respectively, which include certain derivative assets that have notional amounts of $194 million and $104 million at September 30, 2021 and December 31, 2020, 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.

(f)Includes equity investments held by Generation which were previously designated as equity investments without readily determinable fair value but are now publicly traded and therefore have readily determinable fair values. The first investment became publicly traded in the fourth quarter of 2020. Generation records the fair value of these investments in Other current assets in Exelon's and Generation's Consolidated Balance Sheets based on the quoted market prices of the stocks as of the respective balance sheet date. There were no equity investments without readily determinable fair value that became publicly traded during the third quarter of 2021. For investments that became publicly traded during the first half of 2021, unrealized gains of $220 million were recorded in Other, net in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.

(g)Collateral (received) from counterparties, net of collateral paid to counterparties, totaled $(345) million, $(710) million, and $(590) million allocated to Level 1, Level 2, and Level 3 mark-to-market derivatives, respectively, as of September 30, 2021. Collateral (received)/posted from counterparties, net of collateral paid to counterparties, totaled $(67) million, $321 million, and $162 million allocated to Level 1, Level 2, and Level 3 mark-to-market derivatives, respectively, as of December 31, 2020.

(h)Includes $2,084 million held and $209 million posted of variation margin with the exchanges as of September 30, 2021 and December 31, 2020, respectively.

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(Dollars in millions, except per share data, unless otherwise noted)

Note 14 — Fair Value of Financial Assets and Liabilities

As of September 30, 2021, Exelon and Generation have outstanding commitments to invest in private credit, private equity, and real estate investments of approximately $359 million, $174 million, and $371 million, respectively. These commitments will be funded by Generation’s existing NDT funds.

Exelon and Generation held investments without readily determinable fair values with carrying amounts of $44 million and $32 million as of September 30, 2021, respectively. Exelon and Generation held investments without readily determinable fair values with carrying amounts of $73 million and $55 million as of December 31, 2020, respectively. Changes in fair value, cumulative adjustments, and impairments were not material for the three and nine months ended September 30, ~~2017,~~2021 and for the year ended December 31, 2020.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in millions, except per share data, unless otherwise noted)

Note 14 — Fair Value of Financial Assets and Liabilities

ComEd, PECO, and BGE


	ComEd								PECO								BGE
As of September 30, 2021	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Cash equivalents(a)	$	309	$	—	$	—	$	309	$	247	$	—	$	—	$	247	$	169	$	—	$	—	$	169
Rabbi trust investments

Mutual funds	—		—		—		—		10		—		—		10		14		—		—		14
Life insurance contracts	—		—		—		—		—		15		—		15		—		—		—		—
Rabbi trust investments subtotal	—		—		—		—		10		15		—		25		14		—		—		14
Total assets	309		—		—		309		257		15		—		272		183		—		—		183
Liabilities
Deferred compensation obligation	—		(9)		—		(9)		—		(8)		—		(8)		—		(6)		—		(6)
Mark-to-market derivative liabilities(b)	—		—		(214)		(214)		—		—		—		—		—		—		—		—
Total liabilities	—		(9)		(214)		(223)		—		(8)		—		(8)		—		(6)		—		(6)
Total net assets (liabilities)	$	309	$	(9)	$	(214)	$	86	$	257	$	7	$	—	$	264	$	183	$	(6)	$	—	$	177


	ComEd								PECO								BGE
As of December 31, 2020	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Cash equivalents(a)	$	285	$	—	$	—	$	285	$	8	$	—	$	—	$	8	$	120	$	—	$	—	$	120
Rabbi trust investments
Mutual funds	—		—		—		—		9		—		—		9		10		—		—		10
Life insurance contracts	—		—		—		—		—		13		—		13		—		—		—		—
Rabbi trust investments subtotal	—		—		—		—		9		13		—		22		10		—		—		10
Total assets	285		—		—		285		17		13		—		30		130		—		—		130
Liabilities
Deferred compensation obligation	—		(8)		—		(8)		—		(9)		—		(9)		—		(5)		—		(5)
Mark-to-market derivative liabilities(b)	—		—		(301)		(301)		—		—		—		—		—		—		—		—
Total liabilities	—		(8)		(301)		(309)		—		(9)		—		(9)		—		(5)		—		(5)
Total net assets (liabilities)	$	285	$	(8)	$	(301)	$	(24)	$	17	$	4	$	—	$	21	$	130	$	(5)	$	—	$	125

__________

(a)ComEd excludes cash of $145 million and $83 million at September 30, 2021 and December 31, 2020, respectively, and 11restricted cash of $107 million and 12$37 million at September 30, 2021 and December 31, 2020, respectively, and includes long-term restricted cash of $44 million and $43 million at September 30, 2021 and December 31, 2020, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. PECO excludes cash of $105 million and $18 million at September 30, 2021 and December 31, 2020, respectively. BGE excludes cash of $56 million and $24 million at September 30, 2021 and December 31, 2020, respectively, and restricted cash of $27 million and $1 million at September 30, 2021 and December 31, 2020, respectively.

(b)The Level 3 balance consists of the current and noncurrent liability of $5 million and $209 million, respectively, at September 30, 2021 and $33 million and $268 million, respectively, at December 31, 2020 related to floating-to-fixed energy swap contracts with unaffiliated suppliers.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in millions, except per share data, unless otherwise noted)

Note 14 — Fair Value of Financial Assets and Liabilities

PHI, Pepco, DPL, and ACE



	As of September 30, 2021								As of December 31, 2020
PHI	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Cash equivalents(a)	$	100	$	—	$	—	$	100	$	86	$	—	$	—	$	86




Rabbi trust investments
Cash equivalents	59		—		—		59		55		—		—		55
Mutual funds	14		—		—		14		14		—		—		14
Fixed income	—		10		—		10		—		11		—		11
Life insurance contracts	—		27		34		61		—		26		34		60
Rabbi trust investments subtotal	73		37		34		144		69		37		34		140
Total assets	173		37		34		244		155		37		34		226
Liabilities
Deferred compensation obligation	—		(19)		—		(19)		—		(17)		—		(17)



Total liabilities	—		(19)		—		(19)		—		(17)		—		(17)
Total net assets	$	173	$	18	$	34	$	225	$	155	$	20	$	34	$	209


	Pepco								DPL								ACE
As of September 30, 2021	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Cash equivalents(a)	$	36	$	—	$	—	$	36	$	26	$	—	$	—	$	26	$	14	$	—	$	—	$	14




Rabbi trust investments
Cash equivalents	58		—		—		58		—		—		—		—		—		—		—		—
Fixed income	—		—		—		—		—		—		—		—		—		—		—		—
Life insurance contracts	—		27		34		61		—		—		—		—		—		—		—		—
Rabbi trust investments subtotal	58		27		34		119		—		—		—		—		—		—		—		—
Total assets	94		27		34		155		26		—		—		26		14		—		—		14
Liabilities
Deferred compensation obligation	—		(2)		—		(2)		—		—		—		—		—		—		—		—



Total liabilities	—		(2)		—		(2)		—		—		—		—		—		—		—		—
Total net assets	$	94	$	25	$	34	$	153	$	26	$	—	$	—	$	26	$	14	$	—	$	—	$	14

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(Dollars in millions, except per share data, unless otherwise noted)

Note 14 — Fair Value of Financial Assets and Liabilities


	Pepco								DPL								ACE
As of December 31, 2020	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Cash equivalents(a)	$	35	$	—	$	—	$	35	$	—	$	—	$	—	$	—	$	13	$	—	$	—	$	13




Rabbi trust investments
Cash equivalents	53		—		—		53		—		—		—		—		—		—		—		—

Fixed income	—		2		—		2		—		—		—		—		—		—		—		—
Life insurance contracts	—		26		34		60		—		—		—		—		—		—		—		—
Rabbi trust investments subtotal	53		28		34		115		—		—		—		—		—		—		—		—
Total assets	88		28		34		150		—		—		—		—		13		—		—		13
Liabilities
Deferred compensation obligation	—		(2)		—		(2)		—		—		—		—		—		—		—		—



Total liabilities	—		(2)		—		(2)		—		—		—		—		—		—		—		—
Total net assets	$	88	$	26	$	34	$	148	$	—	$	—	$	—	$	—	$	13	$	—	$	—	$	13

__________

(a)PHI excludes cash of $57 million and $74 million at September 30, 2021 and December 31, 2020, respectively, and restricted cash of $5 million and none at September 30, 2021 and December 31, 2020, respectively, and includes long-term restricted cash of $9 million and $10 million at September 30, 2021 and December 31, 2020, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. Pepco excludes cash of $19 million and $30 million at September 30, 2021 and December 31, 2020, respectively, and restricted cash of $5 million and none at September 30, 2021 and December 31, 2020, respectively. DPL excludes cash of $13 million and $15 million at September 30, 2021 and December 31, 2020, respectively. ACE excludes cash of $16 million and $17 million at September 30, 2021 and December 31, 2020, respectively, and includes long-term restricted cash of $9 million and $10 million at September 30, 2021 and December 31, 2020, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets.

Reconciliation of Level 3 Assets and Liabilities

The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the three and nine months ended September 30, 2021 and 2020:



	Exelon		Generation					ComEd		PHI and Pepco
Three Months Ended September 30, 2021	Total		NDT Fund Investments		Mark-to-Market Derivatives			Total Generation		Mark-to-Market Derivatives			Life Insurance Contracts		Eliminated in Consolidation
Balance as of June 30, 2021	$	(235)	$	461	$	(465)		$	(4)	$	(265)		$	34	$	—
Total realized / unrealized gains (losses)
Included in net income	(967)		3		(970)		(a)	(967)		—			—		—
Included in noncurrent payables to affiliates	—		11		—			11		—			—		(11)

Included in regulatory assets	62		—		—			—		51		(b)	—		11
Change in collateral	(413)		—		(413)			(413)		—			—		—
Purchases, sales, and settlements
Purchases	8		2		6			8		—			—		—
Sales	6		—		6			6		—			—		—

Settlements	(2)		(2)		—			(2)		—			—		—
Transfers into Level 3	2		—		2		(c)	2		—			—		—
Transfers out of Level 3	(27)		—		(27)		(c)	(27)		—			—		—
Balance at September 30, 2021	$	(1,566)	$	475	$	(1,861)		$	(1,386)	$	(214)		$	34	$	—
The amount of total (losses) gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2021	$	(1,001)	$	3	$	(1,004)		$	(1,001)	$	—		$	—	$	—

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(Dollars in millions, except per share data, unless otherwise noted)

Note 14 — Fair Value of Financial Assets and Liabilities


	Exelon		Generation					ComEd		PHI and Pepco
Nine months ended September 30, 2021	Total		NDT Fund Investments		Mark-to-Market Derivatives			Total Generation		Mark-to-Market Derivatives			Life Insurance Contracts		Eliminated in Consolidation
Balance as of December 31, 2020	$	660	$	497	$	430		$	927	$	(301)		$	34	$	—
Total realized / unrealized gains (losses)
Included in net income	(1,600)		4		(1,606)		(a)	(1,602)		—			2		—
Included in noncurrent payables to affiliates	—		18		—			18		—			—		(18)

Included in regulatory assets	105		—		—			—		87		(b)	—		18
Change in collateral	(751)		—		(751)			(751)		—			—		—
Purchases, sales, and settlements
Purchases	123		3		120			123		—			—		—
Sales	7		—		7			7		—			—		—

Settlements	(50)		(48)		—			(48)		—			(2)		—
Transfers into Level 3	4		1		3		(c)	4		—			—		—
Transfers out of Level 3	(64)		—		(64)		(c)	(64)		—			—		—
Balance as of September 30, 2021	$	(1,566)	$	475	$	(1,861)		$	(1,386)	$	(214)		$	34	$	—
The amount of total (losses) gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2021	$	(1,521)	$	4	$	(1,527)		$	(1,523)	$	—		$	2	$	—



	Exelon		Generation					ComEd		PHI and Pepco
Three Months Ended September 30, 2020	Total		NDT Fund Investments		Mark-to-Market Derivatives			Total Generation		Mark-to-Market Derivatives			Life Insurance Contracts		Eliminated in Consolidation
Balance as of June 30, 2020	$	883	$	499	$	659		$	1,158	$	(318)		$	43	$	—
Total realized / unrealized gains (losses)
Included in net income	(327)		3		(318)		(a)	(315)		—			(12)		—
Included in noncurrent payables to affiliates	—		18		—			18		—			—		(18)
Included in regulatory assets/liabilities	32		—		—			—		14		(b)	—		18
Change in collateral	(79)		—		(79)			(79)		—			—		—
Purchases, sales, and settlements
Purchases	66		1		65			66		—			—		—
Sales	(3)		—		(3)			(3)		—			—		—

Settlements	—		(3)		—			(3)		—			3		—

Transfers out of Level 3	9		—		9		(c)	9		—			—		—
Balance as of September 30, 2020	$	581	$	518	$	333		$	851	$	(304)		$	34	$	—
The amount of total (losses) gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2020	$	(222)	$	3	$	(213)		$	(210)	$	—		$	(12)	$	—

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(Dollars in millions, except per share data, unless otherwise noted)

Note 14 — Fair Value of Financial Assets and Liabilities


	Exelon		Generation					ComEd		PHI and Pepco
Nine Months Ended September 30, 2020	Total		NDT Fund Investments		Mark-to-Market Derivatives			Total Generation		Mark-to-Market Derivatives			Life Insurance Contracts		Eliminated in Consolidation
Balance as of December 31, 2019	$	1,068	$	511	$	817		$	1,328	$	(301)		$	41	$	—
Total realized / unrealized gains (losses)
Included in net income	(483)		1		(474)		(a)	(473)		—			(10)		—
Included in noncurrent payables to affiliates	—		17		—			17		—			—		(17)

Included in regulatory assets	14		—		—			—		(3)		(b)	—		17
Change in collateral	(120)		—		(120)			(120)		—			—		—
Purchases, sales, and settlements
Purchases	136		6		130			136		—			—		—
Sales	(27)		—		(27)			(27)		—			—		—

Settlements	(15)		(18)		—			(18)		—			3		—
Transfers into Level 3	(5)		1		(6)		(c)	(5)		—			—		—
Transfers out of Level 3	13		—		13		(c)	13		—			—		—
Balance as of September 30, 2020	$	581	$	518	$	333		$	851	$	(304)		$	34	$	—
The amount of total (losses) gains included in income attributed to the change in unrealized (losses) gains related to assets and liabilities as of September 30, 2020	$	(107)	$	1	$	(98)		$	(97)	$	—		$	(10)	$	—

__________

(a)Includes an addition of $34 million for realized losses and a reduction of $80 million for realized gains due to the settlement of derivative contracts for the three and nine months ended September 30, ~~2016, respectively. There were no equity units related~~2021. Includes a reduction of $105 million and $376 million for realized gains due to the ~~PHI Merger not included in the calculation~~settlement of ~~diluted common shares outstanding due to their antidilutive effect~~derivative contracts for the three and nine months ended September 30, ~~2017.~~ 2020.

(b)Includes $49 million of increases in fair value and an increase for realized losses due to settlements of $2 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended September 30, 2021. Includes $72 million of increases in fair value and an increase for realized losses due to settlements of $15 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the nine months ended September 30, 2021. Includes $9 million of increases 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 September 30, 2020. Includes $26 million of decrease in fair value and an increase for realized losses due to settlements of $23 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the nine months ended September 30, 2020.

(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.

The ~~number~~following tables present the income statement classification of ~~equity units related to~~ the ~~PHI Merger not~~total realized and unrealized gains (losses) included in ~~the calculation of diluted common shares outstanding due to their antidilutive effect was less than 1 million~~income for Level 3 assets and liabilities measured at fair value on a recurring basis during the three and nine months ended September 30, ~~2016. Refer~~2021 and 2020:




	Exelon								Generation						PHI and Pepco
	Operating Revenues		Purchased Power and Fuel		Operating and Maintenance		Other, net		Operating Revenues		Purchased Power and Fuel		Other, net		Operating and Maintenance
Total (losses) gains included in net income for the three months ended September 30, 2021	$	(1,274)	$	304	$	—	$	3	$	(1,274)	$	304	$	3	$	—
Total (losses) gains included in net income for the nine months ended September 30, 2021	(1,944)		338		2		4		(1,944)		338		4		2
Total unrealized (losses) gains for the three months ended September 30, 2021	(1,361)		357		—		3		(1,361)		357		3		—
Total unrealized (losses) gains for the nine months ended September 30, 2021	(1,969)		443		2		4		(1,969)		443		4		2

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(Dollars in millions, except per share data, unless otherwise noted)

Note 14 — Fair Value of Financial Assets and Liabilities



	Exelon								Generation						PHI and Pepco
	Operating Revenues		Purchased Power and Fuel		Operating and Maintenance		Other, net		Operating Revenues		Purchased Power and Fuel		Other, net		Operating and Maintenance
Total losses included in net income for the three months ended September 30, 2020	$	(305)	$	(13)	$	(12)	$	—	$	(305)	$	(13)	$	—	$	(12)
Total losses included in net income for the nine months ended September 30, 2020	(370)		(104)		(10)		—		(370)		(104)		—		(10)
Total unrealized (losses) gains for the three months ended September 30, 2020	(216)		3		(12)		3		(216)		3		3		(12)
Total unrealized gains (losses) for the nine months ended September 30, 2020	(50)		(48)		(10)		1		(50)		(48)		1		(10)

Valuation Techniques Used to Determine Fair Value

Exelon’s valuation techniques used to measure the fair value of the assets and liabilities shown in the tables below are in accordance with the policies discussed in Note 2018 — ~~Shareholders' Equity~~Fair Value of Financial Assets and Liabilities of the Exelon ~~2016~~2020 Form ~~10-K for~~10-K.

Valuation Techniques Used to Determine Net asset Value (Exelon and Generation)

Certain NDT Fund Investments are not classified within the fair value hierarchy and are included under the heading “Not subject to leveling” in the table above. These investments are measured at fair value using NAV per share as a practical expedient and include commingled funds, mutual funds which are not publicly quoted, managed private credit funds, private equity and real estate funds.

For commingled funds and mutual funds, which are not publicly quoted, the fair value is primarily derived from the quoted prices in active markets on the underlying securities and can typically be redeemed monthly with 30 or less days of notice and without further ~~information regarding~~restrictions. For managed private credit funds, the fair value is determined using a combination of valuation models including cost models, market models, and income models and typically cannot be redeemed until maturity of the term loan. Private equity ~~units.~~and real estate investments include those in limited partnerships that invest in operating companies and real estate holding companies that are not publicly traded on a stock exchange, such as, leveraged buyouts, growth capital, venture capital, distressed investments, investments in natural resources, and direct investments in pools of real estate properties. These investments typically cannot be redeemed and are generally liquidated over a period of 8 to 10 years from the initial investment date, which is based on Exelon’s understanding of the investment funds. Private equity and real estate valuations are reported by the fund manager and are based on the valuation of the underlying investments, which include inputs such as cost, operating results, discounted future cash flows, market based comparable data, and independent appraisals from sources with professional qualifications. These valuation inputs are unobservable.

~~On June 1, 2017, Exelon settled~~

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Note 14 — Fair Value of Financial Assets and Liabilities

Mark-to-Market Derivatives (Exelon, Generation, and ComEd)

The table below discloses the significant inputs to the forward ~~purchase contract, which was a component~~curve used to value mark-to-market derivatives.


Type of trade	Fair Value at September 30, 2021		Fair Value at December 31, 2020		Valuation Technique	Unobservable Input	2021 Range & Arithmetic Average				2020 Range & Arithmetic Average
Mark-to-market derivatives — Economic Hedges (Exelon and Generation)(a)(b)	$	(1,257)	$	245	Discounted Cash Flow	Forward power price	$9.77	-	$301	$55	$2.25	-	$163	$30
						Forward gas price	$1.76	-	$23.00	$4.16	$1.57	-	$7.88	$2.59
					Option Model	Volatility percentage	35%	-	197%	49%	11%	-	237%	32%

Mark-to-market derivatives — Proprietary trading (Exelon and Generation)(a)(b)	$	(14)	$	23	Discounted Cash Flow	Forward power price	$16	-	$156	$53	$10	-	$106	$27

Mark-to-market derivatives (Exelon and ComEd)	$	(214)	$	(301)	Discounted Cash Flow	Forward heat rate(c)	9x	-	10x	9.13x	8x	-	9x	8.85x
						Marketability reserve	3%	-	7%	4.77%	3%	-	8%	4.93%
						Renewable factor	95%	-	122%	100%	91%	-	123%	99%

__________

(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 (received)/posted on level three positions of $(590) million and $162 million as of September 30, 2021 and December 31, 2020, 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 ~~June 2014 equity units, through~~contract’s delivery.

The inputs listed above, which are as of the ~~issuance~~balance sheet date, would have a direct impact on the fair values of ~~approximately 33 million shares of Exelon common stock from treasury stock.~~the above instruments if they were adjusted. The ~~issuance of shares on June 1, 2017, triggered full dilution~~significant unobservable inputs used in the ~~EPS calculation, which prior to settlement were included~~fair value measurement of Generation’s commodity derivatives are forward commodity prices and for options is price volatility. Increases (decreases) in the ~~calculation~~forward commodity price in isolation would result in significantly higher (lower) fair values for long positions (contracts that give Generation the obligation or option to purchase a commodity), with offsetting impacts to short positions (contracts that give Generation the obligation or right to sell a commodity). Increases (decreases) in volatility would increase (decrease) the value for the holder of ~~diluted EPS using~~ the ~~treasury stock method.~~

~~Prior~~option (writer of the option). Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of volatility of prices. An increase to the ~~June 2017 issuance Exelon had approximately 35 million shares~~reserves listed above would decrease the fair value of ~~treasury stock with~~the positions. An increase to the heat rate or renewable factors would increase the fair value accordingly. Generally, interrelationships exist between market prices of natural gas and power. As such, an increase in natural gas pricing would potentially have a cost of $2.3 billion. After issuance, Exelon has approximately 2 million shares of Treasury stock remaining, at a historical cost of $123 million. In 2008, Exelon management decided to defer indefinitely any share repurchases.similar impact on forward power markets.

~~18.~~

15. Commitments and Contingencies (All Registrants)

The following is an update to the current status of commitments and contingencies set forth in Note ~~24 of the Exelon 2016 Form 10-K . See Note 4 - Mergers, Acquisitions and Dispositions for further discussion on the PHI Merger commitments.~~

~~Commitments~~

~~Constellation Merger Commitments (Exelon and Generation)~~

In February 2012, the MDPSC issued an Order approving the Exelon and Constellation merger. As part of the MDPSC Order, Exelon agreed to provide a package of benefits to BGE customers, the City of Baltimore and the State of Maryland, resulting in an estimated direct investment in the State of Maryland of approximately $1 billion.

The direct investment includes the construction of a new 21-story headquarters building in Baltimore for Generation’s competitive energy business that was substantially complete in November 2016 and is now occupied by approximately 1,500 Exelon employees. Generation’s investment includes leasehold improvements that are not expected to exceed $110 million. In addition, Generation entered into a 20 year operating lease as the primary lessee of the building. Refer to Note 24 -19 — Commitments and Contingencies of the ~~Combined Notes to~~Exelon 2020 Form 10-K.

Commitments

PHI Merger Commitments (Exelon, PHI, Pepco, DPL, and ACE). Approval of the ~~Consolidated Financial Statements~~PHI Merger in Delaware, New Jersey, Maryland, and the ~~Exelon 2016 Form 10-K for additional information regarding Generation’s future minimum lease payments.~~

~~The direct investment commitment also includes $450 million to $500 million relating to~~District of Columbia was conditioned upon Exelon and ~~Generation’s development or assistance in~~PHI agreeing to certain commitments. The following amounts represent total commitment costs that have been recorded since the ~~development of 285-300 MWs of new generation in Maryland, which is expected to be completed within a period of 10 years.~~ The MDPSC order contemplates various options for complying with the new generation development commitments, including building or acquiring generating assets, making subsidy or compliance payments, or in circumstances in which the generation build is delayed or certain specified provisions are elected, making liquidated damages payments. Exelon and Generation have incurred $457 million towards satisfying the commitment for new generation development in the state of Maryland, with approximately 220 MW of the new generation commencing with commercial operations toacquisition date and ~~an additional 10 MW commitment satisfied through a liquidated damages payment made in~~ the ~~fourth quarter~~total remaining obligations for Exelon, PHI, Pepco, DPL, and ACE as of 2016. Additionally, during the fourth quarter of 2016, given continued declines in projected energy and capacity prices, Generation terminated rights to certain development projects originally intended to meet its remaining 55 MW commitment amount. The commitment will now most likely be satisfied via payment of liquidated damages or execution of a third party PPA, rather than by Generation constructing renewable generating assets. As a result, Exelon and Generation recorded a pre-tax~~$50 million loss contingency in Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2016.~~

September 30, 2021:

~~155~~

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(Dollars in millions, except per share data, unless otherwise noted)

Note 15 — Commitments and Contingencies

~~Equity~~


Description	Exelon		PHI		Pepco		DPL		ACE
Total commitments	$	513	$	320	$	120	$	89	$	111
Remaining commitments(a)	74		62		51		7		4

__________

(a)Remaining commitments extend through 2026 and include rate credits, energy efficiency programs and delivery system modernization.

In addition, Exelon is committed to develop or to assist in the commercial development of approximately 37 MWs of new solar generation in Maryland, District of Columbia, and Delaware at an estimated cost of approximately $135 million, which will generate future earnings at Exelon and Generation. Investment ~~Commitments (Exelon~~costs, which are expected to be primarily capital in nature, are recognized as incurred and ~~Generation)~~

~~As part of~~recorded in Exelon's and Generation's recent investments in technology development, Generation enters into equity purchase agreements that include commitments to invest additional equity through incremental payments to fund the anticipated needs of the planned operations of the associated companies.financial statements. As of September 30, ~~2017, Generation’s estimated commitments relating to its equity purchase agreements, including~~2021, approximately 33 MWs of new generation were developed and Exelon and Generation have incurred costs of $121 million. Approximately 30 MWs of the ~~in-kind services contributions, is anticipated to be as follows:~~

Total
2017 (remainder of year) $ 12
2018 6
2019 3
Total $ 21

~~Commercial Commitments (All Registrants)~~

~~The Registrants’ commercial commitments as~~new generation developed was part of ~~September 30, 2017, representing commitments potentially triggered by future events were as follows:~~

Successor
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Letters of credit (non-debt)^(a)
$ 1,276
$ 1,193
$ 14
$ 22
$ 2
$ 1
$ 1
$ —
$ —
Surety bonds^(b)
1,206
1,079
20
40
11
21
13
4
4
Financing trust guarantees 378
—
200
178
—
—
—
—
—
Guaranteed lease residual values^(c)
19
—
—
—
—
19
6
7
5
Total commercial commitments $ 2,879
$ 2,272
$ 234
$ 240
$ 13

$ 41
$ 20
$ 11
$ 9

~~_________~~


~~(a)~~	~~Letters of credit (non-debt) - Exelon and certain subsidiaries maintain non-debt letters of credit to provide credit support for certain transactions as requested by third parties.~~


~~(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 $49 million, $14 million of which is a guarantee by Pepco, $19 million by DPL and $13 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.

~~Nuclear Insurance (Exelon and Generation)~~

~~Generation is subject to liability, property damage and other risks associated with major incidents at any~~Generation's first quarter 2021 sale of a significant portion of its ~~nuclear stations, including~~solar business. Refer to Note 2 — Mergers, Acquisitions, and Dispositions for additional information on the ~~CENG nuclear stations. Generation~~solar business. Exelon has ~~mitigated its financial exposure~~also committed to ~~these risks through insurance and other industry risk-sharing provisions.~~

~~The Price-Anderson Act was enacted~~purchase 100 MWs of wind energy in PJM. DPL has committed to ~~ensure~~conducting three RFPs to procure up to a total of 120 MWs of wind RECs for the ~~availability~~purpose of ~~funds for public liability claims arising from an incident at any~~meeting Delaware's renewable portfolio standards. DPL has conducted two of the ~~U.S. licensed nuclear facilities~~three wind REC RFPs. The first 40 MW wind REC tranche was conducted in 2017 and also to limit the liability of nuclear reactor owners for such claims from any single incident. As of September 30, 2017, the current liability limit per incident is $13.4 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors at least once every five years with the last adjustment effective September 10, 2013. In accordance with the Price-Anderson Act, Generation maintains financial protection at levels equal to the amount of liability insurance available from private sources through the purchase of private nuclear energy liability insurance for public liability claims that could arise in the event of an incident. Effective January 1, 2017, the required amount of nuclear energy liability insurance purchased is $450 million for each operating site. Claims exceeding that amount are covered through mandatory participationdid not result in a ~~financial protection pool, as required~~purchase agreement. The second 40 MW wind REC tranche was conducted in 2018 and resulted in a proposed REC purchase agreement that was approved by the ~~Price Anderson-Act, which provides the additional $13.0 billion per incident~~DPSC in ~~funds available for public liability claims. Participation~~2019. The third and final 40 MW wind REC tranche will be conducted in this secondary financial protection pool requires the operator of each reactor to fund its proportionate share of costs for any single incident that exceeds the primary layer of financial protection. Exelon’s share of this secondary layer would be approximately $2.8 billion, including CENG's related liability, however any amounts payable under this secondary layer would be capped at $420 million per year.2022.

~~156~~

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(Dollars in millions, except per share data, unless otherwise noted)

Note 15 — Commitments and Contingencies

~~In addition,~~Commercial Commitments (All Registrants). The Registrants’ commercial commitments as of September 30, 2021, representing commitments potentially triggered by future events were as follows:


			Expiration within
	Total		2021		2022		2023		2024		2025		2026 and beyond
Exelon
Letters of credit	$	2,241	$	268	$	1,860	$	113	$	—	$	—	$	—
Surety bonds(a)	971		403		566		—		2		—		—
Financing trust guarantees	378		—		—		—		—		—		378
Guaranteed lease residual values(b)	31		—		3		3		6		6		13
Total commercial commitments	$	3,621	$	671	$	2,429	$	116	$	8	$	6	$	391

Generation
Letters of credit	$	2,223	$	264	$	1,846	$	113	$	—	$	—	$	—
Surety bonds(a)	826		352		474		—		—		—		—
Total commercial commitments	$	3,049	$	616	$	2,320	$	113	$	—	$	—	$	—

ComEd
Letters of credit	$	7	$	2	$	5	$	—	$	—	$	—	$	—
Surety bonds(a)	17		5		10		—		2		—		—
Financing trust guarantees	200		—		—		—		—		—		200
Total commercial commitments	$	224	$	7	$	15	$	—	$	2	$	—	$	200

PECO
Letters of credit	$	1	$	—	$	1	$	—	$	—	$	—	$	—
Surety bonds(a)	2		—		2		—		—		—		—
Financing trust guarantees	178		—		—		—		—		—		178
Total commercial commitments	$	181	$	—	$	3	$	—	$	—	$	—	$	178

BGE
Letters of credit	$	2	$	—	$	2	$	—	$	—	$	—	$	—
Surety bonds(a)	3		2		1		—		—		—		—
Total commercial commitments	$	5	$	2	$	3	$	—	$	—	$	—	$	—

PHI

Surety bonds(a)	$	23	$	3	$	20	$	—	$	—	$	—	$	—
Guaranteed lease residual values(b)	31		—		3		3		6		6		13
Total commercial commitments	$	54	$	3	$	23	$	3	$	6	$	6	$	13

Pepco

Surety bonds(a)	$	14	$	—	$	14	$	—	$	—	$	—	$	—
Guaranteed lease residual values(b)	10		—		1		1		2		2		4
Total commercial commitments	$	24	$	—	$	15	$	1	$	2	$	2	$	4

DPL

Surety bonds(a)	$	5	$	2	$	3	$	—	$	—	$	—	$	—
Guaranteed lease residual values(b)	13		—		1		1		3		3		5
Total commercial commitments	$	18	$	2	$	4	$	1	$	3	$	3	$	5

ACE
Surety bonds(a)	$	4	$	1	$	3	$	—	$	—	$	—	$	—
Guaranteed lease residual values(b)	8		—		1		1		1		1		4
Total commercial commitments	$	12	$	1	$	4	$	1	$	1	$	1	$	4

__________

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

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Note 15 — Commitments and Contingencies

(b)Represents the ~~U.S. Congress could impose revenue-raising measures on the nuclear industry to pay public liability claims exceeding the $13.4 billion limit for a single incident.~~

As part of the execution of the NOSA on April 1, 2014, Generation executed an Indemnity Agreement pursuant to which Generation agreed to indemnify EDF and its affiliates 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. See Note 5 — Investment in Constellation Energy Nuclear Group, LLC of the Exelon 2016 Form 10-K for additional information on Generation’s operations relating to CENG.

Generation is required each year to report to the NRC the current levels and sources of property insurance that demonstrates Generation possesses sufficient financial resources to stabilize and decontaminate a reactor and reactor station sitemaximum potential obligation in the event that the fair value of ~~an accident.~~certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The ~~property insurance maintained for each facility is currently provided through insurance policies purchased~~lease term associated with these assets ranges from ~~NEIL, an industry mutual insurance company~~1 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $75 million guaranteed by Exelon and PHI, of which ~~Generation~~$25 million, $32 million, and $18 million is ~~a member.~~

~~Premiums paid to NEIL~~guaranteed by ~~its members are also subject to a potential assessment for adverse loss experience in~~Pepco, DPL, and ACE, respectively. Historically, payments under the ~~form~~guarantees have not been made and PHI believes the likelihood of ~~a retrospective premium obligation. NEIL has never assessed this retrospective premium since its formation in 1973, and Generation cannot predict~~payments being required under the ~~level of future assessments if any. The current maximum aggregate annual retrospective premium obligation for Generation~~guarantees is approximately $360 million. NEIL requires its members to maintain an investment grade credit rating or to ensure collectability of their annual retrospective premium obligation by providing a financial guarantee, letter of credit, deposit premium, or some other means of assurance.

NEIL provides “all risk” property damage, decontamination and premature decommissioning insurance for each station for losses resulting from damage to its nuclear plants, either due to accidents or acts of terrorism. If the decision is made to decommission the facility, a portion of the insurance proceeds will be allocated to a fund, which Generation is required by the NRC to maintain, to provide for decommissioning the facility. In the event of an insured loss, Generation is unable to predict the timing of the availability of insurance proceeds to Generation and the amount of such proceeds that would be available. In the event that one or more acts of terrorism cause accidental property damage within a twelve-month period from the first accidental property damage under one or more policies for all insured plants, the maximum recovery by Exelon will be an aggregate ~~of $3.2 billion plus such additional amounts as the insurer may recover for all such losses from reinsurance, indemnity and any other source, applicable to such losses.~~

For its insured losses, Generation is self-insured to the extent that losses are within the policy deductible or exceed the amount of insurance maintained. Uninsured losses and other expenses, to the extent not recoverable from insurers or the nuclear industry, could also be borne by Generation. Any such losses could have a material adverse effect on Exelon’s and Generation’s financial condition, results of operations and liquidity.remote.

Environmental ~~Issues~~Remediation Matters

General (All Registrants)

~~General.~~. The Registrants’ operations have in the past, and may in the future, require substantial expenditures ~~in order~~ to comply with environmental laws. Additionally, under Federal and state environmental laws, the Registrants are generally liable for the costs of remediating environmental contamination of property now or formerly owned by them and of property contaminated by hazardous substances generated by them. The Registrants own or lease a number of real estate parcels, including parcels on which their operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. In addition, the Registrants are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future. Unless otherwise disclosed, the Registrants cannot reasonably estimate whether they will incur significant liabilities for additional investigation and remediation costs at these or additional sites identified by the Registrants, environmental agencies or others, or whether such costs will be recoverable from third parties, including customers. Additional costs could have a material, unfavorable impact on the Registrants' financial statements.

MGP Sites (Exelon and the Utility Registrants). ComEd, PECO, BGE, and DPL have identified sites where former MGP or gas purification activities have or may have resulted in actual site contamination. For almost all of these sites, there are additional PRPs that may share responsibility for the ultimate remediation of each location.

•ComEd has ~~identified 42~~21 sites ~~19 of which the remediation has been completed and approved by the Illinois EPA or the U.S. EPA and 23~~ 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.~~2027.

•PECO has ~~identified 26~~6 sites ~~17 of which have been remediated in accordance with applicable PA DEP regulatory requirements. The remaining 9 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.~~2023.

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~~(Dollars in millions, except per share data, unless otherwise noted)~~

•BGE has ~~identified 13 former gas manufacturing or purification~~4 sites that it currently ~~owns or owned at one time through a predecessor’s acquisition. Two of the gas manufacturing sites~~ require some level of remediation ~~and~~and/or ongoing ~~monitoring under~~activity. BGE expects the ~~direction~~majority of the ~~MDE. The required costs~~remediation at these ~~two~~ sites ~~are not considered material.~~In May 2017, BGE completed the additional work requested by MDE. All the sample testing produced results that were below the cleanup action level established by MDE and no further investigation is required. For more information, see the discussion of the Riverside site below.

to continue through at least 2023.

•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. The remaining~~1 site that is currently under study and the required cost at the site is not ~~considered~~expected to be material.

ComEd, pursuant to an ICC order, and PECO, pursuant to settlements of natural gas distribution rate cases with the PAPUC, are currently recovering environmental remediation costs of former MGP facility sites through customer rates. ~~ComEd and PECO have recorded regulatory assets for the recovery of these costs.~~ ~~See Note 5 — Regulatory Matters for additional information regarding the associated regulatory assets.~~ BGE is authorized to recover, and is currently recovering, environmental costs for the remediation of the former MGP facility sites from customers; however, while BGE does not have a rider for MGP clean-up costs, BGE has historically received recovery of actual clean-up costs in distribution rates. DPL has historically received recovery of actual clean-up costs in distribution rates.

As of September 30, 2017 and December 31, 2016, the Registrants had accrued the following undiscounted amounts for environmental liabilities in Other current liabilities and Other deferred credits and other liabilities within their respective Consolidated Balance Sheets:

September 30, 2017
Total Environmental
Investigation and
Remediation Reserve

Portion of Total Related to
MGP Investigation and
Remediation
Exelon $ 429

$ 327
Generation 76
—
ComEd 294
293
PECO 33
32
BGE 3
2
PHI (Successor) 23

—
Pepco 21
—
DPL 1
—
ACE 1
—

December 31, 2016
Total Environmental
Investigation and
Remediation Reserve

Portion of Total Related to
MGP Investigation and
Remediation
Exelon $ 429

$ 325
Generation 72
—
ComEd 292
291
PECO 33
31
BGE 2
2
PHI (Successor) 30

1
Pepco 27
—
DPL 2
1
ACE 1
—

The historical nature of the MGP and gas purification sites and the fact that many of the sites have been buried and built over, impacts the ability to determine a precise estimate of the ultimate costs prior to initial sampling and determination of the exact scope and method of remedial activity. Management determines its best estimate of remediation costs using all available information at the time of each study, including probabilistic and deterministic modeling for ComEd and PECO, and

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~~(Dollars in millions, except per share data, unless otherwise noted)~~

the remediation standards currently required by the applicable state environmental agency. Prior to completion of any significant clean up, each site remediation plan is approved by the appropriate state environmental agency.

~~During~~ComEd, pursuant to an ICC order, and PECO, pursuant to settlements of natural gas distribution rate cases with the ~~third quarter~~PAPUC, are currently recovering environmental remediation costs of ~~2017, ComEd, PECO,~~former MGP facility sites through customer rates. While BGE and ~~PHI completed an annual study~~DPL do not have riders for MGP clean-up costs, they have historically received recovery of ~~their future estimated MGP remediation requirements. The study resulted~~actual clean-up costs in ~~a $13 million~~distribution rates.

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Note 15 — Commitments and ~~$2 million increase to~~Contingencies

As of September 30, 2021 and December 31, 2020, the Registrants had accrued the following undiscounted amounts for environmental liabilities in Other current liabilities and ~~related regulatory assets for ComEd and PECO, respectively, and no change at BGE and PHI.~~

The Registrants cannot reasonably estimate whether they will incur other significant liabilities for additional investigation and remediation costs at these or additional sites identified by the Registrants, environmental agencies or others, or whether such costs will be recoverable from third parties, including customers.

~~Water Quality~~

~~Benning Road Site NPDES Permit Limit Exceedances~~. Pepco holds an NPDES permit issued by EPA with a July 19, 2009 effective date, which authorizes discharges from the Benning Road service facility. The 2009 permit for the first time imposed numerical limits on the allowable concentration of certain metals in storm water discharged from the site into the Anacostia River. The permit contemplated that Pepco would meet these limits over time through the use of best management practices (BMPs). The BMPs were effective in reducing metal concentrations in storm water discharges, but were not sufficient to meet all of the numerical limits for all metals.

The 2009 permit remains in effect pending EPA’s action on the Pepco renewal application, including resolution of the stormwater compliance issues. On October 30, 2015, EPA filed a Clean Water Act civil enforcement action against Pepco in federal district court, and in March 2016 the court granted a motion by the Anacostia Riverkeeper to intervene in this case as a plaintiff along with EPA. Since 2009 Pepco has installed runoff mitigation measures and implemented new operating procedures to comply with regulations. In January 2017, the parties agreed to a settlement in the form of a Consent Decree whereby Pepco will pay a civil penalty in the amount of $1.6 million, continue the BMPs to manage stormwater, construct a new stormwater treatment system, and make certain other capital improvements to the stormwater management system. On May 19, 2017, the Consent Decree was entered with the Court and became final. The Civil Penalty assessed under the Consent Decree of $1.6 million was paid on June 5, 2017Other deferred credits and other ~~requirements of the Decree are now being implemented.~~liabilities in their respective Consolidated Balance Sheets:

~~Solid~~


	September 30, 2021				December 31, 2020
	Total environmental investigation and remediation liabilities		Portion of total related to MGP investigation and remediation		Total environmental investigation and remediation liabilities		Portion of total related to MGP investigation and remediation
Exelon	$	474	$	310	$	483	$	314
Generation	119		—		121		—
ComEd	284		284		293		293
PECO	23		21		23		21
BGE	6		5		2		—
PHI	42		—		44		—
Pepco	40		—		42		—
DPL	1		—		1		—
ACE	1		—		1		—

Cotter Corporation (Exelon and ~~Hazardous Waste~~

~~Cotter Corporation.~~Generation). The EPA has advised Cotter Corporation (Cotter), a former ComEd subsidiary, that it is potentially liable in connection with radiological contamination at a site known as the West Lake Landfill in Missouri. In 2000, ComEd sold Cotter to an unaffiliated third-party. As part of the sale, ComEd agreed to indemnify Cotter for any liability arising in connection with the West Lake Landfill. In connection with Exelon’s 2001 corporate restructuring, this responsibility to indemnify Cotter was transferred to Generation. ~~On May 29, 2008, the EPA issued a Record of Decision approving the remediation option submitted by~~Including Cotter, ~~and the two other~~there are three PRPs that required additional landfill cover. By letter dated January 11, 2010, the EPA requested that the PRPs perform a supplemental feasibility study for a remediation alternative that would involve complete excavation of the radiological contamination. On September 30, 2011, the PRPs submitted the supplemental feasibility study to the EPA for review. Since June 2012, the EPA has requested that the PRPs perform a series of additional analyses and groundwater and soil sampling as part of the supplemental feasibility study. This further analysis has focused on a partial excavation remedial option. The PRPs have provided a draft Remedial Investigation and Feasibility Study (RI/FS) report to the EPA for its review and comment. The final RI/FS will form the basis of EPA’s selection of a remedy from among the alternatives of a landfill cover, and partial or complete excavation. ~~The EPA has advised the PRPs that the EPA announcement of the proposed remedy will take place~~participating in the ~~first quarter of 2018. Thereafter, the EPA will select a final remedy and seek to enter into a Consent Decree with the PRPs to effectuate the remedy. Recent investigation~~West Lake Landfill remediation proceeding. Investigation by Generation has identified a number of other parties who also may be PRPs and could be liable to contribute to the final remedy. Further investigation is ongoing.

In September 2018, the EPA issued its Record of Decision Amendment (RODA) for the selection of a final remedy. The RODA modified the remedy previously selected by EPA in its 2008 Record of Decision (ROD). While the ROD required only that the radiological materials and other wastes at the site be capped, the 2018 RODA requires partial excavation of the radiological materials in addition to the previously selected capping remedy. The RODA also allows for variation in depths of excavation depending on ~~going.~~

radiological concentrations. The EPA and the PRPs have entered into a Consent Agreement to perform the Remedial Design, which is expected to be completed in late 2024. In March 2019 the PRPs received Special Notice Letters from the EPA to perform the Remedial Action work. On October 8, 2019, Cotter (Generation’s indemnitee) provided a non-binding good faith offer to conduct, or finance, a portion of the remedy, subject to certain conditions. The total estimated cost of the ~~landfill cover~~ remedy, ~~(taking~~taking into account the current EPA technical requirements ~~incorporated~~and the total costs expected to be incurred collectively by the PRPs in fully executing the ~~third quarter 2017)~~remedy, is approximately ~~$110~~$290 million, including cost escalation on an undiscounted basis, which ~~will~~would be allocated among ~~all~~the final group of PRPs. Generation has ~~accrued what it believes to be an adequate amount to cover its anticipated share of~~determined that a loss associated with the EPA’s partial excavation and enhanced landfill cover ~~which~~remedy is probable and has recorded a liability included in the table ~~above.~~ ~~Generation believes~~above, that ~~a partial excavation~~reflects management’s best estimate of Cotter’s allocable share of the ultimate cost. Given the joint and several nature of this liability, the magnitude of Generation’s ultimate liability will depend on the actual costs incurred to implement the required remedy ~~is reasonably possible,~~as well as on the nature and ~~the partial excavation costs, inclusive~~terms of ~~a landfill cover, could range from approximately $225 million to $650~~ ~~million; such costs would likely be shared by~~any cost-sharing arrangements with the final group of ~~identified~~ PRPs. ~~Generation believes the likelihood~~Therefore, it is reasonably possible that the ~~EPA would require a complete excavation remedy is remote. The~~ultimate cost ~~of a partial or complete excavation~~and Cotter's associated allocable share could differ significantly once these uncertainties are resolved, which could have a material ~~unfavorable~~ impact ~~on Generation’s~~in Exelon's and ~~Exelon’s~~Generation's future ~~results~~financial statements.

One of ~~operations and cash flows.~~

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~~(Dollars in millions, except per share data, unless otherwise noted)~~

~~During December 2015,~~ the ~~EPA took two actions related to the West Lake Landfill designed to abate what~~other PRPs has indicated it ~~termed as imminent and dangerous conditions at the landfill. The first involved installation by the PRPs of~~will be making a ~~non-combustible surface cover to protect~~contribution claim against ~~surface fires in areas where radiological materials are believed to have been disposed. Generation has accrued what it believes to be an adequate amount to cover its anticipated liability~~Cotter for ~~this interim action. The second action involved EPA's public statement~~costs that it ~~will require the PRPs to construct a barrier wall in an adjacent landfill~~has incurred to prevent a subsurface fire from spreading to those areas of the West Lake Landfill where radiological materials are believed to have been disposed. At this time, ~~EPA~~Exelon and Generation do not possess sufficient information to assess this claim and therefore are unable to estimate a range of loss, if any. As such, no liability has ~~not provided sufficient details related to the basis~~been recorded for and the requirements and design of a barrier wall to enable Generation to determine the likelihood such a remedy will ultimately be implemented, assess the degree to which Generation may have liability as a potentially responsible party, or develop a reasonable estimate of the potential ~~incremental costs.~~contribution claim. It is reasonably possible, however, that resolution of this matter could have a material, unfavorable impact onin Exelon’s and Generation's ~~and Exelon's future results of operations and cash flows. Finally, one of~~financial statements.

In January 2018, the ~~other~~ PRPs were advised by the ~~landfill owner and operator of the adjacent landfill, has indicated~~EPA that it will ~~be making a contribution claim against Cotter~~begin an additional investigation and evaluation of groundwater conditions at the West Lake Landfill. In September 2018, the PRPs agreed to an Administrative

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Note 15 — Commitments and Contingencies

Settlement Agreement and Order on Consent for ~~costs that it has incurred~~the performance by the PRPs of the groundwater Remedial Investigation and Feasibility Study (RI/FS). The purpose of this RI/FS is to ~~prevent~~define the ~~subsurface fire~~nature and extent of any groundwater contamination from ~~spreading to those areas of~~ the West Lake Landfill ~~where radiological materials are believed~~site and evaluate remedial alternatives. Generation estimates the undiscounted cost for the groundwater RI/FS to ~~have been disposed.~~be approximately $40 million. Generation determined a loss associated with the RI/FS is probable and has recorded a liability included in the table above that reflects management’s best estimate of Cotter’s allocable share of the cost among the PRPs. At this time Generation cannot predict the likelihood or the extent to which, if any, remediation activities may be required and ~~Exelon do not possess sufficient information to assess~~therefore cannot estimate a reasonably possible range of loss for response costs beyond those associated with the RI/FS component. It is reasonably possible, however, that resolution of this ~~claim~~matter could have a material, unfavorable impact in Exelon’s and ~~are therefore unable to determine the impact on their~~Generation’s future ~~results of operations and cash flows.~~financial statements.

On February 2, 2016, the U.S. Senate passed a bill to transfer remediation authority over the West Lake Landfill from the EPA to the U.S. Army Corps of Engineers, under the Formerly Utilized Sites Remedial Action Program (FUSRAP). The legislation was not passed in the U.S. House of Representatives, and would therefore require reintroduction in the Senate for consideration in the current session of Congress. Should such proposed legislation ultimately become law, it would be subject to annual funding appropriations in the U.S. Budget. Remediation under FUSRAP would not alter the liability of the PRPs, but would likely delay the determination of a final remedy and its implementation.

~~On August 8,~~In August 2011, Cotter was notified by the DOJ that Cotter is considered a PRP with respect to the government’s clean-up costs for contamination attributable to low level radioactive residues at a former storage and reprocessing facility named Latty Avenue near St. Louis, Missouri. The Latty Avenue site is included in ComEd’s (now Generation's) indemnification responsibilities discussed above as part of the sale of Cotter. The radioactive residues had been generated initially in connection with the processing of uranium ores as part of the U.S. ~~government’s~~Government’s Manhattan Project. Cotter purchased the residues in 1969 for initial processing at the Latty Avenue facility for the subsequent extraction of uranium and metals. In 1976, the NRC found that the Latty Avenue site had radiation levels exceeding NRC criteria for decontamination of land areas. Latty Avenue was investigated and remediated by the United States Army Corps of Engineers pursuant to funding under ~~the~~ FUSRAP. ~~The DOJ has not yet formally advised~~Pursuant to a series of annual agreements since 2011, the ~~PRPs of the amount that it is seeking, but it is believed to be approximately $90 million. The~~ DOJ and the PRPs ~~agreed to toll~~have tolled the statute of limitations until ~~August 2018~~February 28, 2022 so that settlement discussions ~~could~~can proceed. ~~Based on Generation’s preliminary~~On August 3, 2020, the DOJ advised Cotter and the other PRPs that it is seeking approximately $90 million from all the PRPs and has directed that the PRPs must submit a good faith joint proposed settlement offer. At this time, the DOJ has stayed their request for a good faith offer while the parties review ~~it appears probable that~~cost documentation associated with the cost claim. Generation has ~~liability to Cotter~~determined that a loss associated with this matter is probable under ~~the~~its indemnification agreement with Cotter and has ~~established~~recorded an ~~appropriate accrual for this~~estimated liability, which is included in the table above.

Commencing in February 2012, a number of lawsuits have been filed in the U.S. District Court for the Eastern District of Missouri. Among the defendants were Exelon, Generation and ComEd, all of which were subsequently dismissed from the case, as well as Cotter, which remains a defendant. The suits allege that individuals living in the North St. Louis area developed some form of cancer or other serious illness due to Cotter's negligent or reckless conduct in processing, transporting, storing, handling and/or disposing of radioactive materials. Plaintiffs are asserting public liability claims under the Price-Anderson Act. Their state law claims for negligence, strict liability, emotional distress, and medical monitoring have been dismissed. The complaints do not contain specific damage claims. In the event of a finding of liability against Cotter, it is reasonably possible that Exelon would be financially responsible due to its indemnification responsibilities of Cotter described above. The court has dismissed a number of lawsuits, and is expected to dismiss additional lawsuits based on a recent ruling. Pre-trial motions and discovery are proceeding in the remaining cases and a pre-trial scheduling order has been filed with the court. At this stage of the litigation, Generation and ComEd cannot estimate a range of loss, if any.

68^th ~~Street Dump.~~ In 1999, the EPA proposed to add the 68th Street Dump in Baltimore, Maryland to the Superfund National Priorities List, and notified BGE and 19 others that they are PRPs at the site. In connection with BGE's 2000 corporate restructuring the responsibility for this liability was transferred to Constellation and as a result of the 2012 Exelon and CEG merger is now Generation's responsibility. In March 2004, the PRPs formed the 68th Street Coalition and entered into consent order negotiations with the U.S. EPA to investigate clean-up options for the site under the Superfund Alternative Sites Program. In May 2006, a settlement among the U.S. EPA and the PRPs

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~~(Dollars in millions, except per share data, unless otherwise noted)~~

with respect to investigation of the site became effective. The settlement requires the PRPs, over the course of several years, to identify contamination at the site and recommend clean-up options. The PRPs submitted their investigation of the range of clean-up options in the first quarter of 2011. On September 30, 2013, EPA issued the Record of Decision identifying its preferred remedial alternative for the site. The estimated cost for the alternative chosen by EPA is consistent with the PRPs estimated range of costs noted above. In July, 2017 the PRPs and EPA finalized the terms of a Consent Decree which has been executed by the Parties and lodged with the U.S. District Court. After publication in the Federal Register there will be a 30-day public comment period after which it is anticipated it will be approved by the Court without any significant change in the costs for cleanup, Generation has elected to be a non-performing cash-out party and following payment of the allocated cost for its share of the clean-up. Generation will have no remaining liability at the site, except for unknown conditions that could manifest themselves after the settlement. The cash-out payment is included in the table above and is immaterial to the Generation and Exelon financial statements.

~~Rossville Ash Site.~~ The Rossville Ash Site is a 32-acre property located in Rosedale, Baltimore County, Maryland, which was used for the placement of fly ash from 1983-2007. The property is owned by Constellation Power Source Generation, LLC (CPSG), a wholly owned subsidiary of Generation. In 2008, CPSG investigated and remediated the property by entering it into the Maryland Voluntary Cleanup Program (VCP) to address any historic environmental concerns and ready the site for appropriate future redevelopment. The site was accepted into the program in 2010 and is currently going through the process to remediate the site and receive closure from MDE. Exelon currently estimates the cost to close the site to be approximately $1 million which has been fully reserved and included in the table above as of September 30, 2017.

~~Sauer Dump.~~ On May 30, 2012, BGE was notified by the U.S. EPA that it is considered a PRP at the Sauer Dump Superfund site in Dundalk, Maryland. The U.S. EPA offered BGE and three other PRPs the opportunity to conduct an environmental investigation and present cleanup recommendations at the site. In addition, the U.S. EPA is seeking recovery from the PRPs for past cleanup and investigation costs at the site. On March 11, 2013, BGE and three other PRPs signed an Administrative Settlement Agreement and Order on Consent with the U.S. EPA which requires the PRPs to conduct a remedial investigation and feasibility study at the site to determine what, if any, are the appropriate and recommended cleanup activities for the site. Although the ultimate outcome of this proceeding is uncertain based on the information complied to date, BGE has developed an estimate of the range of the probable liability; such costs would be shared by the 4 identified PRPs. BGE has accrued an appropriate reserve for its share of the estimated liabilities that is included it in the table above. ~~It is possible, however, that final resolution of this matter could have a material, unfavorable impact on BGE’s future results of operations and cash flows.~~

~~Riverside.~~ In 2013, the MDE, at the request of EPA, conducted a site inspection and limited environmental sampling of certain portions of the 170 acre Riverside property owned by BGE. The site consists of several different parcels with different current and historical uses. The sampling included soil and groundwater samples for a number of potential environmental contaminants. The sampling confirmed the existence of contaminants consistent with the known historical uses of the various portions of the site. In March 2014, the MDE requested that BGE conduct an investigation which included a site-wide investigation of soils, sediment, groundwater, and surface water to complement the MDE sampling. The field investigation was completed in January 2015, and a final report was provided to MDE in June 2015. In November 2015, MDE provided BGE with its comments and recommendations on the report which require BGE to conduct further investigation and sampling at the site to better delineate the nature and extent of historic contamination, including off-site sediment and soil sampling. MDE did not request any interim remediation at this time and in May 2017 BGE completed the additional work requested by MDE. All the offsite sample testing produced results that were below the cleanup action level established by MDE and no further investigation is required. MDE has provided BGE with the required clean-up levels for the on-site contamination and BGE is moving forward with the necessary remediation as directed by MDE. BGE has established what it believes is an appropriate reserve based upon the information available to date, and this amount is included in the table above. As the remediation proceeds, it is possible that additional reserves could be established, in amounts that could be material to BGE.

BGE is authorized to recover, and is currently recovering, environmental costs for the remediation of the former MGP facility sites from customers; however, while BGE does not have a rider for MGP clean-up costs, BGE has historically received recovery of actual clean-up costs in distribution rates. Additionally, legislation was passed during the 2017 Maryland General Assembly session that should further support BGE’s recovery of its clean-up costs.

Benning Road ~~Site.~~ Site (Exelon, Generation, PHI, and Pepco). In September 2010, PHI received a letter from EPA identifying the Benning Road site as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. A portion of the site was formerly the location of a Pepco Energy Services electric generating ~~facility. That generating~~ facility, which was deactivated

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~~(Dollars in millions, except per share data, unless otherwise noted)~~

in June ~~2012 and plant structure demolition was completed in July 2015.~~2012. The remaining portion of the site consists of a Pepco transmission and distribution service center that remains in operation. In December 2011, the U.S. District Court for the District of Columbia approved a ~~consent decree~~Consent Decree entered into by Pepco and Pepco Energy Services with the DOEE, which requires Pepco and Pepco Energy Services to conduct a ~~Remediation Investigation (RI)/ Feasibility Study (FS)~~RI/FS for the Benning Road site and an approximately 10 to ~~15 acre~~15-acre portion of the adjacent Anacostia River. The RI/FS will form the basis for the remedial actions for the Benning Road site and for the Anacostia River sediment associated with the site. The consent decree does not obligate Pepco or Pepco Energy Services to pay for or perform any remediation work, but it is anticipated that DOEE will look to

Since 2013, Pepco and Pepco Energy Services ~~to assume responsibility for cleanup of any conditions in the river that are determined to be attributable to past activities at the Benning Road site. Pursuant~~(now Generation, pursuant to Exelon's ~~March 23,~~ 2016 acquisition of ~~PHI, Pepco Energy Services was transferred to Generation. On July 1, 2017, Pepco Energy Services was merged into Constellation New Energy, a subsidiary of Generation.~~

~~The initial~~PHI) have been performing RI ~~field~~ work ~~began in January 2013~~ and ~~was completed in December 2014. In April 2015, Pepco and Pepco Energy Services~~have submitted amultiple draft RI ~~Report~~reports to the DOEE. After review, DOEE determined that additional field investigation and data analysis was required to complete the RI process (much of which was beyond the scope of the original DOEE-approved RI work plan). In the meantime, Pepco and Pepco Energy Services revised the draft RI Report to address DOEE’s comments and DOEE released the draft RI Report for public review in February 2016. Once the additional RI work has been completed,September 2019, Pepco and Generation ~~will issue~~issued a draft “final” RI report ~~for review and comment by~~which DOEE ~~and the public.~~approved on February 3, 2020. Pepco and Generation ~~will then proceed to develop an~~are developing a FS to evaluate possible remedial alternatives for submission to DOEE. The Court has established a schedule for completion of the ~~RI and~~ FS, and approval by the DOEE, by ~~June 2018.~~

~~Upon DOEE’s~~March 16, 2022. After completion and approval of the ~~final RI and~~ FS, ~~Reports, Pepco and Generation will have satisfied their obligations under the consent decree. At that point,~~ DOEE will prepare a Proposed Plan ~~regarding further response actions. After considering~~for public comment ~~on the Proposed Plan, DOEE will~~and then issue a ~~Record of Decision~~ROD identifying any further response actions determined to be necessary.

PHI, Pepco, and Generation have determined that a loss associated with this matter ~~for PHI, Pepco and Generation~~ is probable and have accrued an estimated liability, ~~for this issue has been accrued,~~ which is included in the table above. As the remedial investigation proceeds and potential remedies are identified, it is possible that additional accruals could be established in amounts that could be material to PHI and Pepco. The ultimate resolution of this matter is currently not expected to have any significant financial impact on Generation.

Anacostia River Tidal Reach (Exelon, PHI, and Pepco). Contemporaneous with the Benning Road site RI/FS being performed by Pepco and Generation, DOEE and ~~certain federal agencies~~NPS have been conducting a separate RI/FS focused on the entire tidal reach of the Anacostia River extending from just north of the ~~Maryland-D.C.~~Maryland-District of Columbia boundary line to the confluence of the Anacostia and Potomac Rivers. ~~In March 2016, DOEE released a draft of the river-wide RI Report for public review and comment.~~ The river-wide RI incorporated the results of the river sampling performed by Pepco and Pepco Energy Services as part of the Benning RI/FS, as well as similar sampling efforts conducted by owners of other sites adjacent to this segment of the river and supplemental river sampling conducted by DOEE’s contractor. In April 2018, DOEE ~~asked~~released a draft RI report for public review and comment. Pepco ~~along with parties responsible for other sites along~~submitted written comments to the ~~river, to participate~~draft RI and participated in a “Consultative Working Group” to provide input into the process for future remedial actions addressing the entire tidal reach of the river and to ensure proper coordination with the other river cleanup efforts currently underway, including cleanup of the river segment adjacent to the Benning Road site resulting from the Benning Road RI/FS. public hearing.

Pepco ~~responded~~has determined that it is probable that costs for remediation will ~~participate~~be incurred and recorded a liability in the ~~Consultative Working Group but~~third quarter 2019 for management’s best estimate of its ~~participation is not an acceptance~~share of ~~any financial responsibility beyond the work that will be performed at the Benning Road site described above.~~those costs. On September 30, 2020, DOEE has advised the Consultative Working Group that the federal and DOEE authorities are conducting phase 2 of a remedial investigation and that a feasibility study of potential remedies is expected to be completed in December 2017. A proposed remedy for the clean-up of sediments in this section of the river is expected to be released for public comment in February 2018 and the DOEE has targeted June 2018 as the date for remedy selection. The Consultative Working Group and the other possible PRPs have provided input into the proposed clean-up process and schedule. At this time, it is not possible to predict the extent of Pepco’s participation in the river-wide RI/FS process, and Pepco cannot estimate the reasonably possible range of loss for response costs beyond those associated with the Benning RI/FS component of the river-wide initiative. It is possible, however, that resolution of this matter could have a material, unfavorable impact on Exelon's and Pepco’s future results of operations and cash flows.

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(Dollars in millions, except per share data, unless otherwise noted)

Note 15 — Commitments and Contingencies

~~Conectiv Energy Wholesale Power Generation Sites.~~ ~~In July 2010, PHI sold~~released its Interim ROD. The Interim ROD reflects an adaptive management approach which will require several identified “hot spots” in the ~~wholesale power generation business of Conectiv Energy Holdings, Inc.~~river to be addressed first while continuing to conduct studies and ~~substantially all of its subsidiaries (Conectiv Energy)~~ to ~~Calpine Corporation (Calpine). Under New Jersey’s Industrial Site Recovery Act (ISRA),~~monitor the ~~transfer of ownership~~river to ~~Calpine triggered an obligation on~~evaluate improvements and determine potential future remediation plans. The adaptive management process chosen by DOEE is less intrusive, provides more long-term environmental certainty, is less costly, and allows for site specific remediation plans already underway, including the part of Conectiv Energy to remediate any environmental contamination at each of the nine Conectiv Energy generating facility sites located in New Jersey. Under the terms of the sale, Calpine assumed responsibility for performing the ISRA-required remediation andplan for the ~~payment of all related ISRA compliance costs up~~Benning Road site to ~~$10 million. Predecessor PHI was obligated~~proceed to indemnify Calpine for any ISRA compliance remediation costs in excess of $10 million. According to PHI’s estimates, the costs of ISRA-required remediation activities at the 9 generating facility sites are in theconclusion. Pepco concluded that incremental exposure remains reasonably possible, but management cannot reasonably estimate a range of ~~approximately $7 million to $18 million~~, ~~and predecessor PHI established an appropriate accrual for its share of~~loss beyond the estimated clean-up costs. Pursuant to Exelon’s March 2016 acquisition of PHI, the Conectiv Energy legal entity was transferred to Generation and the accrual for Predecessor PHI's share of the estimated clean- up costs was also transferred to Generation and isamounts recorded, which are included in the table above.

On July 12, 2021, DOEE and NPS held a virtual meeting with the PRP's in response to a General Notice Letter sent by each agency inviting the PRP's to participate in discussions, which PEPCO attended.

In addition to the activities associated with the remedial process outlined above, CERCLA separately requires federal and state (here including Washington, D.C.) Natural Resource Trustees (federal or state agencies designated by the President or the relevant state, respectively, or Indian tribes) to conduct an assessment of any damages to natural resources within their jurisdiction as a ~~liability~~result of ~~Generation.~~the contamination that is being remediated. The ~~responsibility to indemnify Calpine is shared by PHI and Generation. The ultimate resolution~~Trustees can seek compensation from responsible parties for such damages, including restoration costs. During the second quarter of ~~this matter is currently not expected to have a material financial impact on PHI and Generation.~~

~~Rock Creek Mineral Oil Release.~~ ~~In late August 2015, a~~2018, Pepco ~~underground transmission line~~became aware that the Trustees are in the District of Columbia suffered a breach, resulting in the release of non-toxic mineral oil surrounding the transmission line into the surrounding soil, and a small amount reached Rock Creek through a storm drain. Pepco notified regulatory authorities, and Pepco and its spill response contractors placed booms in Rock Creek, blocked the storm drain to prevent the release of mineral oil into the creek and commenced remediation of soil around the transmission line and the Rock Creek shoreline. Pepco estimates that approximately 6,100 gallons of mineral oil were released and that its remediation efforts recovered approximately 80% of the amount released. Pepco’s remediation efforts are ongoing under the direction of the DOEE, including the requirementsbeginning stages of a ~~February 29, 2016 compliance order which requires~~Natural Resources Damages (NRD) assessment, a process that often takes many years beyond the remedial decision to complete. Pepco to prepare a full incident investigation report and prepare a removal action work plan to remove all impacted soils in the vicinity of the storm drain outfall, and in collaboration with the National Park Service, the Smithsonian Institution/National Zoo and EPA. Pepco’s investigation presently indicates that the damage to Pepco’s facilities occurred prior to the release of mineral oil when third-party excavators struck the Pepco underground transmission line while installing cable for another utility.

PHI and Pepco have reached a settlement with a third party who contributed to the loss. Exelon, PHI and Pepco do not believe that the balance of the remediation costs to resolve this matter will have a material adverse effect on their respective financial condition, results of operations or cash flows.

~~Brandywine Fly Ash Disposal Site.~~ In February 2013, Pepco received a letter from the MDE requesting that Pepco investigate the extent of waste on a Pepco right-of-way that traverses the Brandywine fly ash disposal site in Brandywine, Prince George’s County, Maryland, owned by NRG Energy, Inc. (as successor to GenOn MD Ash Management, LLC) (NRG). In July 2013, while reserving its rights and related defenses under a 2000 agreement covering the sale of this site, Pepco indicated its willingness to investigate the extent of, and propose an appropriate closure plan to address, ash on the right-of-way. Pepco submitted a schedule for development of a closure plan to MDE on September 30, 2013 and, by letter dated October 18, 2013, MDE approved the schedule.

~~Exelon, PHI and Pepco have determined~~has concluded that a loss associated with ~~this matter~~the eventual NRD assessment is ~~probable and have estimated that~~reasonably possible. Due to the ~~costs for implementation~~very early stage of ~~a closure plan and cap on~~ the ~~site are in~~assessment process, Pepco cannot reasonably estimate the range of approximately $3 million to $6 million, for which an appropriate reserve has been established and is included in the table above. Exelon, PHI and Pepco believe that the costs incurred in this matter will be recoverable from NRG under the 2000 sale agreement.loss.

Litigation and Regulatory Matters

Asbestos Personal Injury Claims (Exelon ~~Generation, ComEd, PECO~~ and ~~BGE)~~

~~Exelon, Generation and PECO~~Generation). Generation maintains a reserve for claims associated with asbestos-related personal injury actions in certain facilities that are currently owned by Generation or were previously owned by ComEd and PECO. The ~~reserve is~~estimated liabilities are recorded on an undiscounted basis and ~~excludes~~exclude the estimated legal costs associated with handling these matters, which could be material.

At September 30, ~~2017~~2021 and December 31, ~~2016,~~2020, Exelon and Generation had ~~reserved~~recorded estimated liabilities of approximately ~~$80~~$82 million and ~~$83~~$89 million, respectively, in total for asbestos-related bodily injury claims. As of September 30, ~~2017,~~2021, approximately ~~$22~~$19 million of this amount related to ~~227~~211 open claims presented to Generation, while the remaining ~~$58~~$63 million ~~of the reserve~~ is for estimated future asbestos-related bodily injury claims anticipated to arise through ~~2050,~~2055, based on actuarial

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~~(Dollars in millions, except per share data, unless otherwise noted)~~

assumptions and analyses, which are updated on an annual basis. On a quarterly basis, Generation monitors actual experience against the number of forecasted claims to be received and expected claim payments and evaluates whether ~~an adjustment~~adjustments to the ~~reserve~~estimated liabilities are necessary.

It is ~~necessary.~~

~~On November 22, 2013, the Supreme Court of Pennsylvania held~~reasonably possible that the Pennsylvania Workers Compensation Act does not apply to an employee’s disability or death resulting from occupational disease, such as diseases related to asbestos exposure, which manifests more than 300 weeks after the employee’s last employment-based exposure, and that therefore the exclusivity provision of the Act does not preclude such employee from suing his or her employer in court. The Supreme Court’s ruling reverses previous rulings by the Pennsylvania Superior Court precluding current and former employees from suing their employers in court, despite the fact that the same employee was not eligible for workers compensation benefits for diseases that manifest more than 300 weeks after the employee’s last employment-based exposure to asbestos. Since the Pennsylvania Supreme Court's ruling in November 2013, Exelon, Generation, and PECO have experienced an increase in asbestos-related personal injury claims brought by former PECO employees, all of which have been reserved for on a claim by claim basis. Those additional claims are taken into account in projecting estimates of future asbestos-related bodily injury claims.

On November 4, 2015, the Illinois Supreme Court found that the provisions of the Illinois' Workers' Compensation Act and the Workers' Occupational Diseases Act barred an employee from bringing a direct civil action against an employer for latent diseases, including asbestos-related diseases that fall outside the 25-year limit of the statute of repose. The Illinois Supreme Court's ruling reversed previous rulings by the Illinois Court of Appeals, which initially ruled that the Illinois Worker's Compensation law should not apply in cases where the diagnosis of an asbestos related disease occurred after the 25-year maximum time period for filing a Worker's Compensation claim. Since the Illinois Supreme Court’s ruling in November 2015, Exelon, Generation, and ComEd have not experienced a significant increase in asbestos-related personal injury claims brought by former ComEd employees.

~~There is a reasonable possibility that Exelon may have~~ additional exposure to estimated future asbestos-related bodily injury claims in excess of the amount accrued ~~and the increases~~ could have a material, ~~adverse effect on Exelon's, Generation's, ComEd's, PECO~~unfavorable impact in Exelon’s and ~~BGE's future results~~Generation’s financial statements. However, management cannot reasonably estimate a range of ~~operations~~loss beyond the amounts recorded.

Deferred Prosecution Agreement (DPA) and ~~cash flows.~~

~~BGE~~. ~~Since 1993, BGE~~Related Matters (Exelon and ComEd). Exelon and ComEd received a grand jury subpoena in the second quarter of 2019 from the U.S. Attorney’s Office for the Northern District of Illinois (USAO) requiring production of information concerning their lobbying activities in the State of Illinois. On October 4, 2019, Exelon and ComEd received a second grand jury subpoena from the USAO requiring production of records of any communications with certain ~~Constellation (now Generation) subsidiaries have been involved in several actions concerning asbestos. The actions are based upon~~individuals and entities. On October 22, 2019, the ~~theory of “premises liability,”~~SEC notified Exelon and ComEd that it had also opened an investigation into their lobbying activities. On July 17, 2020, ComEd entered into a DPA with the USAO to resolve the USAO investigation. Under the DPA, the USAO filed a single charge alleging that ~~BGE~~ComEd improperly gave and ~~Generation knew~~offered to give jobs, vendor subcontracts, and payments associated with those jobs and subcontracts for the benefit of ~~and exposed individuals to an asbestos hazard. In addition to BGE and Generation, numerous other parties are defendants in these cases.~~

To date, most asbestos claims which have been resolved relating to BGE and certain Constellation subsidiaries have been dismissed or resolved without any payment and a small minority of these cases has been resolved for amounts that were not material to BGE or Generation’s financial results. Presently, there are an immaterial number of asbestos cases pending against BGE and certain Constellation subsidiaries.

~~Continuous Power Interruption (Exelon and ComEd)~~

~~Section 16-125~~the Speaker of the Illinois ~~Public Utilities Act~~House of Representatives and the Speaker’s associates, with the intent to influence the Speaker’s action regarding legislation affecting ComEd’s interests. The DPA provides that in the ~~event an electric utility,~~USAO will defer any prosecution of such ascharge and any other criminal or civil case against ComEd experiences a continuous power interruption of four hours or more that affects (in ComEd’s case) more than 30,000 customers, the utility may be liable for actual damages suffered by customers as a result of the interruption and may be responsible for reimbursement of local governmental emergency and contingency expenses incurred in connection with the ~~interruption. Recovery~~matters identified therein for a three-year period subject to certain obligations of ~~consequential damages is barred.~~ComEd, including payment to the U.S. Treasury of $200 million, which was paid in November 2020. Exelon was not made a party to the DPA, and therefore the investigation by the USAO into Exelon’s activities ended with no charges being brought against Exelon. The ~~affected utility may seek from~~SEC’s investigation remains ongoing and Exelon and ComEd have cooperated fully and intend to continue to cooperate fully with the ICC a waiver of these liabilities when the utility can show that the cause of the interruption was unpreventable damage due to weather events or conditions, customer tampering, or certain other causes enumerated in the law. As of September 30, 2017 and December 31, 2016, ComEd did not have any material liabilities recorded for these storm events.

~~Baltimore City Franchise Taxes (Exelon and BGE)~~

The City of Baltimore claims that BGE has maintained electric facilities in the City’s public right-of-ways for over one hundred years without the proper franchise rights from the City. BGE has reviewed the City's claim and believes that it lacks merit. BGE has not recorded an accrual for payment of franchise fees for past periods as a range of loss, if any, cannot be reasonably estimated at this time. Franchise fees assessed in future periods may be material to BGE’s results of operations and cash flows.

~~164~~

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(Dollars in millions, except per share data, unless otherwise noted)

Note 15 — Commitments and Contingencies

~~Conduit Lease~~SEC. Exelon and ComEd cannot predict the outcome of the SEC investigation. No loss contingency has been reflected in Exelon's and ComEd's consolidated financial statements with ~~City~~respect to the SEC investigation, as this contingency is neither probable nor reasonably estimable at this time.

Subsequent to Exelon announcing the receipt of ~~Baltimore (Exelon~~the subpoenas, various lawsuits were filed, and ~~BGE~~)various demand letters were received related to the subject of the subpoenas, the conduct described in the DPA and the SEC's investigation, including:

•Four putative class action lawsuits against ComEd and Exelon were filed in federal court in the third quarter of 2020 alleging, among other things, civil violations of federal racketeering laws. In addition, the Citizens Utility Board (CUB) filed a motion to intervene in these cases on October 22, 2020 which was granted on December 23, 2020. On December 2, 2020, the court appointed interim lead plaintiffs in the federal cases which consisted of counsel for three of the four federal cases. These plaintiffs filed a consolidated complaint on January 5, 2021. CUB also filed its own complaint against ComEd only on the same day. The remaining federal case, Potter, et al. v. Exelon et al, differed from the other lawsuits as it named additional individual defendants not named in the consolidated complaint. However, the Potter plaintiffs voluntarily dismissed their complaint without prejudice on April 5, 2021. ComEd and Exelon moved to dismiss the consolidated class action complaint and CUB’s complaint on February 4, 2021 and briefing was completed on March 22, 2021. On March 25, 2021, the parties agreed, along with state court plaintiffs, discussed below, to jointly engage in mediation. The parties participated in a one-day mediation on June 7, 2021 but no settlement was reached. On September 9, 2021, the federal court granted Exelon’s and ComEd’s motion to dismiss and dismissed the plaintiffs’ and CUB’s federal law claim with prejudice. The federal court also dismissed the related state law claims made by the federal plaintiffs and CUB on jurisdictional grounds. Plaintiffs have appealed the ruling to the Seventh Circuit Court of Appeals. Plaintiffs' opening appeal brief is due January 14, 2022, Exelon's and ComEd's response brief is due February 14, 2022, and Plaintiffs' reply brief is due March 7, 2022. Plaintiffs also refiled their state law claims in state court and have moved to consolidate that action with the already pending consumer state court class action, discussed below. CUB also refiled its state law claims in state court.

•Three putative class action lawsuits against ComEd and Exelon were filed in Illinois state court in the third quarter of 2020 seeking restitution and compensatory damages on behalf of ComEd customers. The cases were consolidated into a single action in October of 2020. In November 2020, CUB filed a motion to intervene in the cases pursuant to an Illinois statute allowing CUB to intervene as a party or otherwise participate on behalf of utility consumers in any proceeding which affects the interest of utility consumers. On November 23, ~~2015,~~2020, the ~~Baltimore City~~court allowed CUB’s intervention, but denied its request to stay these cases. Plaintiffs subsequently filed a consolidated complaint, and ComEd and Exelon filed a motion to dismiss on jurisdictional and substantive grounds on January 11, 2021. Briefing on that motion was completed on March 2, 2021. The parties agreed, on March 25, 2021, along with the federal court plaintiffs discussed above, to jointly engage in mediation. The parties participated in a one-day mediation on June 7, 2021 but no settlement was reached. Oral argument on the state court pending motion to dismiss was held on August 4, 2021. On September 27, 2021, the court set a tentative ruling date on the motion to dismiss for November 30, 2021. It is unclear at this time what impact the recent filings by the federal court plaintiffs and CUB will have on this action and the pending motion to dismiss.

•A putative class action lawsuit against Exelon and certain officers of Exelon and ComEd was filed in federal court in December 2019 alleging misrepresentations and omissions in Exelon’s SEC filings related to ComEd’s lobbying activities and the related investigations. The complaint was amended on September 16, 2020, to dismiss two of the original defendants and add other defendants, including ComEd. Defendants filed a motion to dismiss in November 2020. The court denied the motion in April 2021. On May 26, 2021, defendants moved the court to certify its order denying the motion to dismiss for interlocutory appeal. Briefing on the motion was completed in June 2021 and the motion remains pending. Litigation has proceeded and in May 2021, the parties each filed respective initial discovery disclosures. On June 9, 2021, defendants filed their answer and affirmative defenses to the complaint. The parties are currently engaged in discovery; however, on September 9, 2021, the U.S. government moved to intervene in this lawsuit and stay discovery relating to the U.S. government’s ongoing criminal proceedings until the parties to the litigation agree to an acceptable protective order. The court granted the U.S. government’s motion on September 23, 2021 and discovery remains stayed until further order of the court.

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(Dollars in millions, except per share data, unless otherwise noted)

Note 15 — Commitments and Contingencies

•Five shareholders sent letters to the Exelon Board of ~~Estimates approved an increase in annual rental fees for access~~Directors between 2020 and 2021 demanding, among other things, that the Exelon Board of Directors investigate and address alleged breaches of fiduciary duties and other alleged violations by Exelon and ComEd officers and directors related to the ~~Baltimore City underground conduit system effective November 1, 2015, from $12 million~~conduct described in the DPA. In the first quarter of 2021, the Exelon Board of Directors appointed a Special Litigation Committee (“SLC”) consisting of disinterested and independent parties to ~~$42 million, subject~~investigate and address these shareholders’ allegations and make recommendations to ~~an annual increase thereafter~~the Exelon Board of Directors based on the ~~Consumer Price Index. BGE subsequently entered into~~outcome of the SLC’s investigation. In July 2021, one of the demand letter shareholders filed a derivative action against current and former Exelon and ComEd officers and directors, and against Exelon, as nominal defendant, asserting the same claims made in its demand letter. On October 12, 2021, the parties to the derivative action filed an agreed motion to stay that litigation for 120 days in order to allow the SLC to continue its investigation, which the court granted. The parties will confer in advance of the 120-day deadline to determine whether the stay should be extended.

•A separate shareholder demand seeking a review of certain Exelon books and records was received in August 2021. Exelon is in the process of responding to this demand.

No loss contingencies have been reflected in Exelon’s and ComEd’s consolidated financial statements with respect to these matters, as such contingencies are neither probable nor reasonably estimable at this time.

On August 12, 2021, the ICC commenced a proceeding, under its general regulatory authority, to investigate whether the conduct described in the DPA resulted in ComEd’s recovery, through rates, of costs that were not properly recoverable under law and, if so, what remedial action should be taken. The Staff Report cited by the ICC in its initiating order expressed “concerns” about whether ComEd improperly recovered DPA-related costs from customers. The Illinois Attorney General and CUB have intervened in the proceeding. Counsel for plaintiffs in the putative consumer class actions pending in Illinois Circuit Court have also sought to “partially” intervene, which request is pending. On October 14, 2021, as required by provisions of the Clean Energy Law, the ICC initiated a separate docket to investigate the rate treatment of costs associated with the ~~City regarding~~DPA, including the ~~amount~~fine paid by ComEd, and whether ComEd “collected, spent, allocated, transferred, remitted, or caused in any other way to be expended ratepayer funds that were not lawfully recoverable through rates, and which should accordingly be refunded to ratepayers ….” That proceeding must be completed within 330 days. On October 19, 2021, the ICC moved to consolidate these two proceedings because they address "similar issues and facts." That motion is pending. No schedule has been set for submission of testimony or for an evidentiary hearing in either docket. A status hearing is set in both matters for November 4, 2021. Exelon and ~~basis~~ComEd cannot predict the outcome of these proceedings.

Impacts of the February 2021 Extreme Cold Weather Event and Texas-based Generating Assets Outages (Exelon and Generation). Beginning on February 15, 2021, Generation’s Texas-based generating assets within the ERCOT market, specifically Colorado Bend II, Wolf Hollow II, and Handley, experienced outages as a result of extreme cold weather conditions. In addition, those weather conditions drove increased demand for ~~establishing the conduit fee. On November 30, 2016, the Baltimore City Board of Estimates approved a settlement agreement entered into between BGE~~service, dramatically increased wholesale power prices, and ~~the City to resolve the disputes and pending litigation~~also increased gas prices in certain regions. See Note 3 — Regulatory Matters for additional information.

Various lawsuits have been filed against Generation since March 2021 related to ~~BGE's use~~these events, including:

•On March 5, 2021, Generation, along with more than 160 power generators and transmission and distribution companies, was sued by approximately 160 individually named plaintiffs, purportedly on behalf of ~~and payment for the underground conduit system. As~~all Texans who allegedly suffered loss of life or sustained personal injury, property damage or other losses as a result of the ~~settlement,~~weather events. The plaintiffs allege that the ~~parties have entered into a six-year lease that reduces the annual expense~~defendants failed to $25 million in the first three years and caps the annual expense in the last three years to not more than $29 million. BGE recorded a credit to Operating and maintenance expense in the fourth quarter of 2016 of approximately $28 millionproperly prepare for the ~~reversal of the previously higher fees accrued in the current year~~cold weather and failed to properly conduct their operations, seeking compensatory as well as punitive damages. On April 26, 2021, another multi-plaintiff lawsuit was filed on behalf of approximately 90 plaintiffs against more than 300 defendants, including Generation, involving similar allegations of liability and claims of personal injury and property damage. Since March 2021, approximately 60 additional lawsuits, naming multiple defendants including Generation, were filed by individual or multiple plaintiffs in different Texas counties, all arising out of the ~~settlement~~February weather events. These additional lawsuits allege wrongful death, property damage, or other losses. Co-defendants in these lawsuits include ERCOT, transmission and distribution utilities and other generators. Generation disputes liability and denies that it is responsible for any of ~~prior year disputed fee true-up amounts.~~plaintiffs’ alleged claims and is vigorously contesting them. No loss contingencies have been reflected in Exelon’s and Generation’s consolidated

~~Deere Wind Energy Assets (Exelon~~

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(Dollars in millions, except per share data, unless otherwise noted)

Note 15 — Commitments and ~~Generation)~~Contingencies

~~In 2013, Deere & Company (“Deere”)~~financial statements with respect to these matters, as such contingencies are neither probable nor reasonably estimable at this time.

•On March 22, 2021, an LDC filed a lawsuit in Missouri federal court against Generation in the Delaware Superior Court relating to Generation’s acquisition of the Deere wind energy assets. Under the purchase agreement, Deere was entitled to receive earn-out payments if certain specific wind projects already under development in Michigan met certain development and construction milestones following the sale. In the complaint, Deere seeks to recover a $14 million earn-out payment associated with one such project, which was never completed. Generation has filed counterclaims against Deere for breach of contract ~~with a right~~and unjust enrichment, seeking damages of ~~recoupment~~approximately $40 million. The plaintiff claims that Generation failed to deliver gas to its customers in February of 2021, causing the plaintiff to incur damages by forcing it to purchase gas for Generation’s customers and ~~set off.~~by Generation’s refusal to pay the resulting penalties. On ~~June 2, 2016, the Delaware Superior Court entered summary judgment in favor of Deere. On January 17, 2017,~~March 26, 2021, Generation filed ~~an appeal~~a complaint with the MPSC against the LDC to void the OFO penalties, or alternatively to grant a waiver or variance from the tariff requirements, to prohibit the LDC from billing or otherwise attempting to collect from Generation or any Missouri customer any portion of the ~~Superior Court’s summary judgment decision~~penalties claimed by the LDC until the resolution of the complaint, and to prohibit the LDC from taking any retaliatory measure, including termination of service. On September 1, 2021, the MPSC consolidated Generation’s complaint with two other similar complaints from other companies. The evidentiary hearing for the ~~Supreme Court of Delaware. Generation has accrued an amount to cover its potential liability.~~

~~City of Everett Tax Increment Financing Agreement (Exelon)~~

The City of Everett has filed a petition with the Massachusetts Economic Assistance Coordinating Council (EACC) to revoke the 1999 tax increment financing agreement (TIF Agreement) relating to Mystic 8 & 9three consolidated complaint cases is scheduled for March 2022. Based on the ~~grounds~~penalty provisions within the tariff that was in effect at the ~~total investment in Mystic 8 & 9 materially deviates from the investment set forth in the TIF Agreement. The EACC has appointed~~relevant time, Exelon and Generation have recorded a three-member panel to conduct an administrative hearing on the City’s petition. Generation has reviewed the City’s claim and believes that it lacks merit. Generation has not recorded an accrual for payment resulting from such a revocation because the rangeliability of ~~loss, if any, cannot be reasonably estimated at this time. Property taxes assessed in future periods could be material to Generation’s results~~approximately $40 million as of ~~operations and cash flows.~~September 30, 2021.

General (All Registrants)

.The Registrants are involved in various other litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or ~~a reasonable possibility,~~reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. The Registrants maintain accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of reasonably possible loss, particularly where (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.

16. Changes in Accumulated Other Comprehensive Income ~~Taxes (Exelon, Generation, ComEd, PECO and BGE)~~(Exelon)

~~See Note 12 — Income Taxes for information regarding the Registrants’ income~~The following tables present changes in Exelon's AOCI, net of tax, ~~refund claims and certain tax positions, including the 1999 sale of fossil generating assets.~~by component:


Three Months Ended September 30, 2021	Losses on Cash Flow Hedges		Pension and Non-Pension Postretirement Benefit Plan Items(a)		Foreign Currency Items		Total
Beginning balance	$	(5)	$	(3,264)	$	(20)	$	(3,289)
OCI before reclassifications	—		14		(3)		11
Amounts reclassified from AOCI	—		55		—		55
Net current-period OCI	—		69		(3)		66
Ending balance	$	(5)	$	(3,195)	$	(23)	$	(3,223)


Three Months Ended September 30, 2020	Losses on Cash Flow Hedges		Pension and Non-Pension Postretirement Benefit Plan Items(a)		Foreign Currency Items		Total
Beginning balance	$	(3)	$	(3,096)	$	(33)	$	(3,132)
OCI before reclassifications	(1)		(13)		3		(11)
Amounts reclassified from AOCI	—		39		—		39
Net current-period OCI	(1)		26		3		28
Ending balance	$	(4)	$	(3,070)	$	(30)	$	(3,104)

~~165~~

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(Dollars in millions, except per share data, unless otherwise noted)

Note 16 — Changes in Accumulated Other Comprehensive Income

~~19.~~


Nine Months Ended September 30, 2021	Losses on Cash Flow Hedges		Pension and Non-Pension Postretirement Benefit Plan Items(a)		Foreign Currency Items		Total
Beginning balance	$	(5)	$	(3,372)	$	(23)	$	(3,400)
OCI before reclassifications	(1)		15		—		14
Amounts reclassified from AOCI	—		163		—		163
Net current-period OCI	(1)		178		—		177
Ending balance	$	(6)	$	(3,194)	$	(23)	$	(3,223)


Nine Months Ended September 30, 2020	Losses on Cash Flow Hedges		Pension and Non-Pension Postretirement Benefit Plan Items(a)		Foreign Currency Items		Total
Beginning balance	$	(2)	$	(3,165)	$	(27)	$	(3,194)
OCI before reclassifications	(2)		(17)		(3)		(22)
Amounts reclassified from AOCI	—		112		—		112
Net current-period OCI	(2)		95		(3)		90
Ending balance	$	(4)	$	(3,070)	$	(30)	$	(3,104)

______

(a)AOCI amounts are included in the computation of net periodic pension and OPEB cost. See Note 11 — Retirement Benefits for additional information. See Exelon's Statements of Operations and Comprehensive Income for individual components of AOCI.

The following table presents income tax benefit (expense) allocated to each component of Exelon's other comprehensive income (loss):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	$	1	$	4	$	3	$	12
Actuarial loss reclassified to periodic benefit cost	(19)		(16)		(57)		(50)
Pension and non-pension postretirement benefit plans valuation adjustment	(7)		3		(8)		6

17. Variable Interest Entities (Exelon, Generation, PHI, and ACE)

At September 30, 2021 and December 31, 2020, Exelon, Generation, PHI, and ACE collectively consolidated several VIEs or VIE groups for which the applicable Registrant was the primary beneficiary (see Consolidated VIEs below) and had significant interests in several other VIEs for which the applicable Registrant does not have the power to direct the entities’ activities and, accordingly, was not the primary beneficiary (see Unconsolidated VIEs below). Consolidated and unconsolidated VIEs are aggregated to the extent that the entities have similar risk profiles.

Consolidated VIEs

The table below shows the carrying amounts and classification of the consolidated VIEs’ assets and liabilities included in the consolidated financial statements of Exelon, Generation, PHI, and ACE as of September 30, 2021 and December 31, 2020. The assets, except as noted in the footnotes to the table below, can only be used to settle obligations of the VIEs. The liabilities, except as noted in the footnote to the table below, are such that creditors, or beneficiaries, do not have recourse to the general credit of Exelon, Generation, PHI, and ACE.

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(Dollars in millions, except per share data, unless otherwise noted)

Note 17 — Variable Interest Entities


	September 30, 2021								December 31, 2020
	Exelon		Generation		PHI(a)		ACE		Exelon		Generation		PHI(a)		ACE
Cash and cash equivalents	$	38	$	38	$	—	$	—	$	98	$	98	$	—	$	—
Restricted cash and cash equivalents	47		42		5		5		47		44		3		3
Accounts receivable
Customer	25		25		—		—		148		148		—		—
Other	7		7		—		—		36		36		—		—
Unamortized energy contract assets	21		21		—		—		22		22		—		—
Inventories, net

Materials and supplies	14		14		—		—		244		244		—		—
Assets held for sale(b)	—		—		—		—		101		101		—		—
Other current assets	517		513		4		—		674		669		5		—
Total current assets	669		660		9		5		1,370		1,362		8		3
Property, plant, and equipment, net	2,052		2,052		—		—		5,803		5,803		—		—
Nuclear decommissioning trust funds	—		—		—		—		3,007		3,007		—		—

Unamortized energy contract assets	210		210		—		—		249		249		—		—
Other noncurrent assets	22		13		9		9		52		42		10		10
Total noncurrent assets	2,284		2,275		9		9		9,111		9,101		10		10
Total assets(c)	$	2,953	$	2,935	$	18	$	14	$	10,481	$	10,463	$	18	$	13
Long-term debt due within one year	$	80	$	70	$	10	$	6	$	94	$	68	$	26	$	21
Accounts payable	11		11		—		—		81		81		—		—
Accrued expenses	14		14		—		—		70		70		—		—

Unamortized energy contract liabilities	—		—		—		—		4		4		—		—
Liabilities held for sale(b)	—		—		—		—		16		16		—		—
Other current liabilities	—		—		—		—		5		5		—		—
Total current liabilities	105		95		10		6		270		244		26		21
Long-term debt	832		832		—		—		889		889		—		—
Asset retirement obligations	149		149		—		—		2,318		2,318		—		—


Other noncurrent liabilities	3		3		—		—		129		129		—		—
Total noncurrent liabilities	984		984		—		—		3,336		3,336		—		—
Total liabilities(d)	$	1,089	$	1,079	$	10	$	6	$	3,606	$	3,580	$	26	$	21

_________

(a)Includes certain purchase accounting adjustments from the PHI merger not pushed down to ACE.

(b)In the fourth quarter of 2020, Generation entered into an agreement for the sale of a significant portion of Generation's solar business, and as a result of this transaction, Exelon and Generation reclassified the consolidated VIEs' solar assets and liabilities as held for sale. Completion of the transaction occurred in the first quarter of 2021. Refer to Note 2 — Mergers, Acquisitions, and Dispositions for additional information on the solar business.

(c)Exelon’s and Generation’s balances include unrestricted assets for current unamortized energy contract assets of $21 million and $22 million, non-current unamortized energy contract assets of $210 million and $249 million, assets held for sale of $0 millionand $9 million, and other unrestricted assets of $0 million and $1 million as of September 30, 2021 and December 31, 2020, respectively.

(d)Exelon’s and Generation’s balances include liabilities with recourse of $1 million and $8 million as of September 30, 2021 and December 31, 2020, respectively.

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(Dollars in millions, except per share data, unless otherwise noted)

Note 17 — Variable Interest Entities

As of September 30, 2021 and December 31, 2020, Exelon's and Generation's consolidated VIEs included the following:


Consolidated VIE or VIE groups:	Reason entity is a VIE:	Reason Generation is primary beneficiary:
CENG - A joint venture between Generation and EDF. Generation had a 50.01% equity ownership in CENG as of December 31, 2020 and acquired EDF's 49.99% equity interest on August 6,2021 resulting in CENG no longer being classified as a consolidated VIE beginning in the third quarter of 2021. See additional discussion below.	Disproportionate relationship between equity interest and operational control as a result of the NOSA described further below.	Generation conducts the operational activities.
EGRP - A collection of wind and solar project entities. Generation has a 51% equity ownership in EGRP. See additional discussion below.	Similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner.	Generation conducts the operational activities.
Bluestem Wind Energy Holdings, LLC - A Tax Equity structure which is consolidated by EGRP. Generation has a noncontrolling interest.	Similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner.	Generation conducts the operational activities.
Antelope Valley - A solar generating facility, which is 100% owned by Generation. Antelope Valley sells all of its output to PG&E through a PPA.	The PPA contract absorbs variability through a performance guarantee.	Generation conducts all activities.
Equity investment in distributed energy company - Generation has a 31% equity ownership. This distributed energy company has an interest in an unconsolidated VIE. (See Unconsolidated VIEs disclosure below). Generation fully impaired this investment in 2019.	Similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner.	Generation conducts the operational activities.
NER - A bankruptcy remote, special purpose entity which is 100% owned by Generation, which purchases certain of Generation’s customer accounts receivable arising from the sale of retail electricity. NER’s assets will be available first and foremost to satisfy the claims of the creditors of NER. See Note 6 - Accounts Receivable for additional information on the sale of receivables.	Equity capitalization is insufficient to support its operations.	Generation conducts all activities.

CENG - On April 1, 2014, Generation, CENG, and subsidiaries of CENG executed the NOSA pursuant to which Generation conducts all activities associated with the operations of the CENG fleet and provides corporate and administrative services to CENG and the CENG fleet for the remaining life of the CENG nuclear plants as if they were a part of the Generation nuclear fleet, subject to the CENG member rights of EDF.

On November 20, 2019, Generation received notice of EDF's intention to exercise the put option to sell its 49.99% equity interest in CENG to Generation and the put automatically exercised on January 19, 2020. On August 6, 2021, Generation and EDF entered into a settlement agreement pursuant to which Generation purchased EDF's equity interest in CENG and resulted in CENG no longer being classified as a consolidated VIE beginning in the third quarter of 2021. Refer to Note 2 — Mergers, Acquisitions, and Dispositions for additional information.

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

•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 19 — Commitments and Contingencies of the Exelon 2020 Form 10-K for more details.

•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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(Dollars in millions, except per share data, unless otherwise noted)

Note 17 — Variable Interest Entities

Prior to August 6, 2021, Generation and EDF shared in the $688 million of contingent payment obligations for the payment of contingent retrospective premium adjustments for the nuclear liability insurance. Following the execution of the settlement agreement, EDF no longer shares in the obligation.

EGRP - EGRP is a collection of wind and solar project entities and some of these project entities are VIEs that are consolidated by EGRP. Generation owns a number of limited liability companies that build, own, and operate solar and wind power facilities some of which are owned by EGRP. While Generation or EGRP owns 100% of the solar entities and 100% of the majority of the wind entities, it has been determined that certain of the solar and wind entities are VIEs because the entities require additional subordinated financial support in the form of a parental guarantee of debt, loans from the customers in order to obtain the necessary funds for construction of the solar facilities, or the customers absorb price variability from the entities through the fixed price power and/or REC purchase agreements. Generation is the primary beneficiary of these solar and wind entities that qualify as VIEs because Generation controls the design, construction, and operation of the facilities. There is limited recourse to Generation related to certain solar and wind entities.

In 2017, Generation’s interests in EGRP were contributed to and are pledged for the ExGen Renewables IV non-recourse debt project financing structure. Refer to Note 17 — Debt and Credit Agreements of the Exelon 2020 Form 10-K for additional information on ExGen Renewables IV.

As of September 30, 2021 and December 31, 2020, Exelon's, PHI's, and ACE's consolidated VIE consists of:


Consolidated VIEs:	Reason entity is a VIE:	Reason ACE is the primary beneficiary:
ACE Funding - 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. 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.	ACE’s equity investment is a variable interest as, by design, it absorbs any initial variability of ATF. The bondholders also have a variable interest for the investment made to purchase the Transition Bonds.	ACE controls the servicing activities.

Unconsolidated VIEs

Exelon’s and Generation’s variable interests in unconsolidated VIEs generally include equity investments and energy purchase and sale contracts. For the equity investments, the carrying amount of the investments is reflected in Exelon’s and Generation’s Consolidated Balance Sheets in Investments. For the energy purchase and sale contracts (commercial agreements), the carrying amount of assets and liabilities in Exelon’s and Generation’s Consolidated Balance Sheets that relate to their involvement with the VIEs are predominately related to working capital accounts and generally represent the amounts owed by, or owed to, Exelon and Generation for the deliveries associated with the current billing cycles under the commercial agreements.

As of September 30, 2021 and December 31, 2020, Exelon and Generation had significant unconsolidated variable interests in several VIEs for which Exelon or Generation, as applicable, was not the primary beneficiary. These interests include certain equity method investments and certain commercial agreements.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in millions, except per share data, unless otherwise noted)

Note 17 — Variable Interest Entities

The following table presents summary information about Exelon's and Generation’s significant unconsolidated VIE entities:


	September 30, 2021						December 31, 2020
	Commercial Agreement VIEs		Equity Investment VIEs		Total		Commercial Agreement VIEs		Equity Investment VIEs		Total
Total assets(a)	$	781	$	370	$	1,151	$	777	$	401	$	1,178
Total liabilities(a)	80		209		289		61		223		284
Exelon's ownership interest in VIE(a)	—		143		143		—		157		157
Other ownership interests in VIE(a)	701		18		719		716		21		737

_________

(a)These items represent amounts in the unconsolidated VIE balance sheets, not in Exelon’s or Generation’s Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs. 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 September 30, 2021 and December 31, 2020.

As of September 30, 2021 and December 31, 2020, Exelon's and Generation's unconsolidated VIEs consist of:


Unconsolidated VIE groups:	Reason entity is a VIE:	Reason Generation is not the primary beneficiary:
Equity investments in distributed energy companies - 1) Generation has a 90% equity ownership in a distributed energy company. 2) Generation, via a consolidated VIE, has a 90% equity ownership in another distributed energy company (See Consolidated VIEs disclosure above). Generation fully impaired this investment in 2019.	Similar structures to a limited partnership and the limited partners do not have kick out rights with respect to the general partner.	Generation does not conduct the operational activities.
Energy Purchase and Sale agreements - Generation has several energy purchase and sale agreements with generating facilities.	PPA contracts that absorb variability through fixed pricing.	Generation does not conduct the operational activities.

18. Supplemental Financial Information (All Registrants)

Supplemental Statement of Operations Information

The following tables provide additional information about material items recorded in the ~~Registrants’~~Registrants' Consolidated Statements of Operations and Comprehensive ~~Income for the three and nine months ended September 30, 2017 and 2016.~~Income.

139

Three Months Ended September 30, 2017
Successor
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning trust funds^(a)

Regulatory agreement units $ 159
$ 159
$ —
$ —
$ —
$ —
$ —
$ —
$ —
Non-regulatory agreement units 59
59
—
—
—
—
—
—
—
Net unrealized gains on decommissioning trust funds
Regulatory agreement units 44
44
—
—
—
—
—
—
—
Non-regulatory agreement units 111
111
—
—
—
—
—
—
—
Net unrealized losses on pledged assets
Zion Station decommissioning (4 ) (4 ) —
—
—
—
—
—
—
Regulatory offset to decommissioning trust fund-related activities^(b)
(161 ) (161 ) —
—
—
—
—
—
—
Total decommissioning-related activities 208
208
—
—
—

—
—
—
—
Investment income 2
1
—
—
—
1
1
—
—
Interest income related to uncertain income tax positions 4
—
—
—
—
—
—
—
—
AFUDC — Equity 17
—
2
2
4
9
6
2
1
Other 6
—
3
—
—
3
—
2
—
Other, net $ 237

$ 209

$ 5

$ 2

$ 4

$ 13

$ 7

$ 4

$ 1

Nine Months Ended September 30, 2017
Successor
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning trust funds^(a)

Regulatory agreement units $ 439
$ 439
$ —
$ —
$ —
$ —
$ —
$ —
$ —
Non-regulatory agreement units 165
165
—
—
—
—
—
—
—
Net unrealized gains on decommissioning trust funds
Regulatory agreement units 253
253
—
—
—
—
—
—
—
Non-regulatory agreement units 347
347
—
—
—
—
—
—
—
Net unrealized losses on pledged assets
Zion Station decommissioning (5 ) (5 ) —
—
—
—
—
—
—
Regulatory offset to decommissioning trust fund-related activities^(b)
(558 ) (558 ) —
—
—
—
—
—
—
Total decommissioning-related activities 641
641
—
—
—
—

—
—
—
Investment income 6
4
—
—
—
2
1
—
—
Interest income related to uncertain income tax positions 3
—
—
—
—
—
—
—
—
Benefit related to uncertain income tax positions^(c)
2
—
—
—
—
—
—
—
—
AFUDC — Equity 51
—
6
6
12
27
17
5
5
Other 22
3
8
—
—
11
4
5
1
Other, net $ 725

$ 648

$ 14

$ 6

$ 12
$ 40

$ 22

$ 10

$ 6

~~166~~

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(Dollars in millions, except per share data, unless otherwise noted)

Note 18 — Supplemental Financial Information

Three Months Ended September 30, 2016
Successor
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning trust funds^(a)

Regulatory agreement units $ 57
$ 57
$ —
$ —
$ —
$ —
$ —
$ —
$ —
Non-regulatory agreement units 35
35
—
—
—
—
—
—
—
Net unrealized gains on decommissioning trust funds
Regulatory agreement units 155
155
—
—
—
—
—
—
—
Non-regulatory agreement units 116
116
—
—
—
—
—
—
—
Net unrealized losses on pledged assets
Zion Station decommissioning (5 ) (5 ) —
—
—
—
—
—
—
Regulatory offset to decommissioning trust fund-related activities^(b)
(168 ) (168 ) —
—
—
—
—
—
—
Total decommissioning-related activities 190
190
—
—
—

—

—
—
—
Investment income (expense) 2
1
—
(1 ) —
—
—
—
—
Interest income related to uncertain income tax positions 8
—
—
—
—
—
—
—
—
Penalty related to uncertain income tax positions^(c)
(106 ) —
(86 ) —
—
—
—
—
—
AFUDC — Equity 19
—
5
2
5
7
5
1
1
Other 7
(6 ) 1
1
—
12
7
2
1
Other, net $ 120

$ 185

$ (80 )
$ 2

$ 5
$ 19

$ 12

$ 3

$ 2


	Operating revenues
	Exelon		Generation		PHI		DPL
Three Months Ended September 30, 2021
Operating lease income	$	30	$	29	$	1	$	1
Variable lease income	71		71		—		—

Three Months Ended September 30, 2020
Operating lease income	$	30	$	28	$	1	$	1
Variable lease income	76		76		—		—

Nine Months Ended September 30, 2021
Operating lease income	$	47	$	44	$	3	$	3
Variable lease income	208		207		1		1

Nine Months Ended September 30, 2020
Operating lease income	$	48	$	43	$	3	$	3
Variable lease income	225		224		1		1


	Taxes other than income taxes
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Three Months Ended September 30, 2021
Utility taxes(a)	$	242	$	27	$	67	$	41	$	21	$	86	$	80	$	6	$	—
Property	165		66		13		5		46		34		23		10		1
Payroll	57		26		7		4		5		7		2		1		1

Three Months Ended September 30, 2020
Utility taxes(a)	$	237	$	26	$	66	$	41	$	21	$	83	$	77	$	5	$	1
Property	152		66		7		4		42		32		21		10		1
Payroll	59		29		7		4		4		6		2		1		1

Nine Months Ended September 30, 2021
Utility taxes(a)	$	665	$	73	$	188	$	107	$	66	$	231	$	212	$	17	$	2
Property	470		199		30		13		131		97		65		30		2
Payroll	180		83		20		12		14		21		5		4		2

Nine Months Ended September 30, 2020
Utility taxes(a)	$	651	$	75	$	181	$	102	$	65	$	228	$	210	$	16	$	2
Property	449		199		23		12		121		94		63		29		2
Payroll	183		88		21		12		13		21		6		4		3

~~167~~

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~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

Successor Predecessor
Nine Months Ended September 30, 2016 March 24, 2016 to September 30, 2016 January 1, 2016 to March 23, 2016
Exelon Generation ComEd PECO BGE Pepco DPL ACE PHI PHI
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning trust funds^(a)

Regulatory agreement units $ 181
$ 181
$ —
$ —
$ —
$ —
$ —
$ —
$ —
$ —
Non-regulatory agreement units 95
95
—
—
—
—
—
—
—
—
Net unrealized gains on decommissioning trust funds
Regulatory agreement units 286
286
—
—
—
—
—
—
—
—
Non-regulatory agreement units 216
216
—
—
—
—
—
—
—
—
Net unrealized losses on pledged assets
Zion Station decommissioning (2 ) (2 ) —
—
—
—
—
—
—
—
Regulatory offset to decommissioning trust fund-related activities^(b)
(380 ) (380 ) —
—
—
—
—
—
—
—
Total decommissioning-related activities 396
396
—
—
—

—
—
—
—
—
Investment income (expense) 14
6
—
(1 ) 2
—
—
—
1
—
Long-term lease income 4
—
—
—
—
—
—
—
—
—
Interest income related to uncertain income tax positions 13
—
—
—
—
1
—
1
—
—
Penalty related to uncertain income tax positions^(c)
(106 ) —
(86 ) —
—
—
—
—
—
—
AFUDC — Equity 43
—
8
6
14
14
3
5
15
7
Loss on debt extinguishment (3 ) (2 ) —
—
—
—
—
—
—
—
Other 16
(5 ) 6
1
—
13
6
2
15
(11 )
Other, net $ 377

$ 395

$ (72 )
$ 6

$ 16

$ 28
$ 9
$ 8
$ 31
$ (4 )

~~_________~~


~~(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 16 — Asset Retirement Obligations of the Exelon 2016 Form 10-K for additional information regarding the accounting for nuclear decommissioning.


~~(c)~~	~~See Note~~ 12 ~~- Income Taxes for discussion of the penalty related to the Tax Court's decision on Exelon's like-kind exchange tax position.~~

~~The following utility taxes are included in revenues and expenses for the three and nine months ended September 30, 2017 and 2016.~~ (a)Generation’s utility tax ~~expense~~ represents gross receipts tax related to its retail operations, and the Utility Registrants' utility ~~registrants' utility tax expense~~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 onin the Registrants’ Consolidated Statements of Operations and Comprehensive Income.

140

Three Months Ended September 30, 2017
Successor
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Utility taxes $ 245

$ 35

$ 65

$ 35

$ 22
$ 88
$ 83

$ 5

$ —

Nine Months Ended September 30, 2017
Successor
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Utility taxes $ 682

$ 97

$ 181

$ 95

$ 69
$ 240
$ 226

$ 14

$ —

~~168~~

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(Dollars in millions, except per share data, unless otherwise noted)

Note 18 — Supplemental Financial Information


	Other, Net
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Three Months Ended September 30, 2021
Decommissioning-related activities:
Net realized income on NDT funds(a)
Regulatory Agreement Units	$	263	$	263	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-Regulatory Agreement Units	102		102		—		—		—		—		—		—		—
Net unrealized losses on NDT funds
Regulatory Agreement Units	(195)		(195)		—		—		—		—		—		—		—
Non-Regulatory Agreement Units	(88)		(88)		—		—		—		—		—		—		—
Regulatory offset to NDT fund-related activities(b)	(38)		(38)		—		—		—		—		—		—		—
Decommissioning-related activities	44		44		—		—		—		—		—		—		—
AFUDC — Equity	36		—		10		7		7		12		9		2		1
Non-service net periodic benefit cost	19		—		—		—		—		—		—		—		—
Net unrealized losses from equity investments(c)	(179)		(179)		—		—		—		—		—		—		—

Three Months Ended September 30, 2020
Decommissioning-related activities:
Net realized income on NDT funds(a)
Regulatory Agreement Units	$	50	$	50	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-Regulatory Agreement Units	23		23		—		—		—		—		—		—		—
Net unrealized gains on NDT funds
Regulatory Agreement Units	398		398		—		—		—		—		—		—		—
Non-Regulatory Agreement Units	254		254		—		—		—		—		—		—		—
Regulatory offset to NDT fund-related activities(b)	(359)		(359)		—		—		—		—		—		—		—
Decommissioning-related activities	366		366		—		—		—		—		—		—		—
AFUDC — Equity	27		—		7		5		6		9		7		1		1
Non-service net periodic benefit cost	15		—		—		—		—		—		—		—		—

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in millions, except per share data, unless otherwise noted)

Note 18 — Supplemental Financial Information

Three Months Ended September 30, 2016
Successor
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Utility taxes $ 255

$ 35

$ 67

$ 40

$ 21
$ 92
$ 87

$ 5

$ —


	Other, net
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Nine Months Ended September 30, 2021
Decommissioning-related activities:
Net realized income on NDT funds(a)
Regulatory Agreement Units	$	698	$	698	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-Regulatory Agreement Units	392		392		—		—		—		—		—		—		—
Net unrealized gains on NDT funds
Regulatory Agreement Units	84		84		—		—		—		—		—		—		—
Non-Regulatory Agreement Units	38		38		—		—		—		—		—		—		—
Regulatory offset to NDT fund-related activities(b)	(607)		(607)		—		—		—		—		—		—		—
Decommissioning-related activities	605		605		—		—		—		—		—		—		—

AFUDC — Equity	99		—		23		19		21		36		30		4		2
Non-service net periodic benefit cost	64		—		—		—		—		—		—		—		—
Net unrealized losses from equity investments(c)	(83)		(83)		—		—		—		—		—		—		—

Nine Months Ended September 30, 2020
Decommissioning-related activities:
Net realized income on NDT funds(a)
Regulatory Agreement Units	$	127	$	127	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-Regulatory Agreement Units	127		127		—		—		—		—		—		—		—
Net unrealized gains on NDT funds
Regulatory Agreement Units	111		111		—		—		—		—		—		—		—
Non-Regulatory Agreement Units	1		1		—		—		—		—		—		—		—
Regulatory offset to NDT fund-related activities(b)	(192)		(192)		—		—		—		—		—		—		—
Decommissioning-related activities	174		174		—		—		—		—		—		—		—


AFUDC — Equity	76		—		22		12		16		26		20		3		3
Non-service net periodic benefit cost	38		—		—		—		—		—		—		—		—

__________

Successor Predecessor
Nine Months Ended September 30, 2016 March 24, 2016 to September 30, 2016 January 1, 2016 to March 23, 2016
Exelon Generation ComEd PECO BGE Pepco DPL ACE PHI PHI
Utility taxes $ 624

$ 90

$ 186

$ 106

$ 66
$ 240

$ 14

$ —
$ 176
$ 78
(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 except for decommissioning-related impacts that were not offset for the Byron units starting in the second quarter of 2021, including the elimination of income taxes related to all NDT fund activity for those units. With Generation's September 15, 2021 reversal of the previous decision to retire Byron, Generation resumed contractual offset for Byron as of that date. See Note 10 — Asset Retirement Obligations of the Exelon 2020 Form 10-K for additional information regarding the accounting for nuclear decommissioning and Note 8 — Nuclear Decommissioning for additional information on the contractual offset suspension for the Byron units.

(c)Net unrealized losses from equity investments that became publicly traded entities in the fourth quarter of 2020 and the first half of 2021.

Supplemental Cash Flow Information

The following tables provide additional information ~~regarding~~about material items recorded in the ~~Registrants’~~Registrants' Consolidated Statements of Cash ~~Flows for the nine months ended September 30, 2017 and 2016.~~Flows.

142

Nine Months Ended September 30, 2017
Successor
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Depreciation, amortization and accretion
Property, plant and equipment^(a)
$ 2,416
$ 1,010
$ 579
$ 194
$ 233
$ 342
$ 153
$ 92
$ 66
Amortization of regulatory assets^(a)
355
—
52
19
115
169
89
32
47
Amortization of intangible assets, net^(a)
43
36
—
—
—
—
—
—
—
Amortization of energy contract assets and liabilities^(b)
19
19
—
—
—
—
—
—
—
Nuclear fuel^(c)
816
816
—
—
—
—
—
—
—
ARO accretion^(d)
350
350
—
—
—
—
—
—
—
Total depreciation, amortization and accretion $ 3,999

$ 2,231

$ 631

$ 213

$ 348
$ 511
$ 242

$ 124

$ 113

Successor Predecessor
Nine Months Ended September 30, 2016 March 24, 2016 to September 30, 2016 January 1, 2016 to March 23, 2016
Exelon Generation ComEd PECO BGE Pepco DPL ACE PHI PHI
Depreciation, amortization and accretion
Property, plant and equipment^(a)
$ 2,490
$ 1,297
$ 524
$ 181
$ 223
$ 128
$ 82
$ 61
$ 215
$ 94
Amortization of regulatory assets^(a)
293
—
49
20
84
93
38
69
140
58
Amortization of intangible assets, net^(a)
38
32
—
—
—
—
—
—
—
—
Amortization of energy contract assets and liabilities^(b)
(7 ) (7 ) —
—
—
—
—
—
—
—
Nuclear fuel^(c)
862
862
—
—
—
—
—
—
—
—
ARO accretion^(d)
333
332
1
—
—
—
—
—
—
—
Total depreciation, amortization and accretion $ 4,009

$ 2,516

$ 574

$ 201

$ 307
$ 221

$ 120

$ 130
$ 355
$ 152

~~_________~~


~~(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.~~

~~169~~

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— ~~(Continued)~~

(Dollars in millions, except per share data, unless otherwise noted)

Note 18 — Supplemental Financial Information


	Depreciation, amortization, and accretion
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Nine Months Ended September 30, 2021
Property, plant, and equipment(a)	$	4,505	$	2,698	$	721	$	249	$	324	$	467	$	204	$	126	$	115
Amortization of regulatory assets(a)	439		—		172		10		110		147		98		31		18
Amortization of intangible assets, net(a)	44		37		—		—		—		—		—		—		—
Amortization of energy contract assets and liabilities(b)	23		23		—		—		—		—		—		—		—
Nuclear fuel(c)	810		810		—		—		—		—		—		—		—
ARO accretion(d)	383		383		—		—		—		—		—		—		—
Total depreciation, amortization, and accretion	$	6,204	$	3,951	$	893	$	259	$	434	$	614	$	302	$	157	$	133

Nine Months Ended September 30, 2020
Property, plant, and equipment(a)	$	2,831	$	1,121	$	689	$	238	$	293	$	436	$	191	$	116	$	104
Amortization of regulatory assets(a)	434		—		152		21		112		149		91		27		30
Amortization of intangible assets, net(a)	47		40		—		—		—		—		—		—		—
Amortization of energy contract assets and liabilities(b)	24		22		—		—		—		—		—		—		—
Nuclear fuel(c)	708		708		—		—		—		—		—		—		—
ARO accretion(d)	375		375		—		—		—		—		—		—		—
Total depreciation, amortization, and accretion	$	4,419	$	2,266	$	841	$	259	$	405	$	585	$	282	$	143	$	134

__________

(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.

143

Nine Months Ended September 30, 2017
Successor
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs $ 482
$ 170
$ 131
$ 21
$ 47
$ 72
$ 19
$ 10
$ 10
Loss from equity method investments 26
26
—
—
—
—
—
—
—
Provision for uncollectible accounts 103
31
25
17
4
26
11
1
14
Stock-based compensation costs 76
—
—
—
—
—
—
—
—
Other decommissioning-related activity^(a)
(213 ) (213 ) —
—
—
—
—
—
—
Energy-related options^(b)
15
15
—
—
—
—
—
—
—
Amortization of regulatory asset related to debt costs 7
—
3
1
—
3
1
1
1
Amortization of rate stabilization deferral (7 ) —
—
—
7
(14 ) (12 ) (2 ) —
Amortization of debt fair value adjustment (13 ) (9 ) —
—
—
(4 ) —
—
—
Discrete impacts from EIMA and FEJA^(c)
(61 ) —
(61 ) —
—
—
—
—
—
Amortization of debt costs 57
33
3
1
1
1
1
—
—
Provision for excess and obsolete inventory

52
50
1
—
—
1
—
1
—
Merger-related commitments^(d)
—
—
—
—
—
(8 ) (6 ) (2 ) —
Severance costs 33
25
—
—
—
3
—
—
—
Other 46
4
10
(2 ) (7 ) (14 ) (6 ) (3 ) (4 )
Total other non-cash operating activities $ 603

$ 132

$ 112

$ 38

$ 52
$ 66
$ 8

$ 6

$ 21
Non-cash investing and financing activities:
Change in capital expenditures not paid $ (101 ) $ 20
$ (79 ) $ (29 ) $ 16
$ (6 ) $ 7
$ 14
$ (18 )
Fair value of pension obligation transferred in connection with the FitzPatrick acquisition —
33
—
—
—
—
—
—
—
Change in PPE related to ARO update (141 ) (141 ) —
—
—
—
—
—
—
Indemnification of like-kind exchange position^(g)
—
—
21
—
—
—
—
—
—
Non-cash financing of capital projects 16
16
—
—
—
—
—
—
—
Dividends on stock compensation 5
—
—
—
—
—
—

—
—
Dissolution of financing trust due to long-term debt retirement 8
—
—
—
8
—
—
—
—
Fair value adjustment of long-term debt due to retirement (5 ) —
—
—
—
—
—
—
—

~~170~~

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— ~~(Continued)~~

(Dollars in millions, except per share data, unless otherwise noted)

Note 18 — Supplemental Financial Information


	Other non-cash operating activities
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Nine Months Ended September 30, 2021
Pension and non-pension postretirement benefit costs	$	304	$	92	$	97	$	5	$	45	$	36	$	5	$	2	$	8
Allowance for credit losses	155		59		34		36		7		18		9		3		6
Other decommissioning-related activity(a)	(810)		(810)		—		—		—		—		—		—		—
Energy-related options(b)	45		45		—		—		—		—		—		—		—
True-up adjustments to decoupling mechanisms and formula rates(c)	(129)		—		(32)		(20)		17		(94)		(54)		(17)		(23)
Severance costs	(67)		(75)		1		—		—		1		—		—		—

Long-term incentive plan	94		—		—		—		—		—		—		—		—


Amortization of operating ROU asset	146		98		2		—		22		21		5		7		3


AFUDC — Equity	(99)		—		(23)		(19)		(21)		(36)		(30)		(4)		(2)

Nine Months Ended September 30, 2020
Pension and non-pension postretirement benefit costs	$	310	$	89	$	85	$	4	$	46	$	52	$	11	$	6	$	10
Allowance for credit losses	130		16		23		38		12		41		24		15		2
Other decommissioning-related activity(a)	(301)		(301)		—		—		—		—		—		—		—
Energy-related options(b)	79		79		—		—		—		—		—		—		—
True-up adjustments to decoupling mechanisms and formula rates(c)	66		—		51		(10)		10		15		(20)		15		20
Severance costs	96		88		1		—		—		—		—		—		—
Provision for excess and obsolete inventory	119		118		1		1		—		(1)		—		(1)		—
Long-term incentive plan	(8)		—		—		—		—		—		—		—		—


Amortization of operating ROU asset	185		135		1		—		23		21		5		6		2
Deferred Prosecution Agreement payments(d)	200		—		200		—		—		—		—		—		—

AFUDC — Equity	(76)		—		(22)		(12)		(16)		(26)		(20)		(3)		(3)

__________

(a)Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units except for decommissioning-related impacts that were not offset for the Byron units starting in the second quarter of 2021, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income, and income taxes related to all NDT fund activity for these units. With Generation's September 15, 2021 reversal of the previous decision to retire Byron, Generation resumed contractual offset for Byron as of that date. See Note 10 — Asset Retirement Obligations of the Exelon 2020 Form 10-K for additional information regarding the accounting for nuclear decommissioning and Note 8 — Nuclear Decommissioning for additional information on the contractual offset suspension for the Byron units.

(b)Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations.

(c)For ComEd, reflects the true-up adjustments in regulatory assets and liabilities associated with its distribution, energy efficiency, distributed generation, and transmission formula rates. For BGE, Pepco, DPL, and ACE, reflects the change in regulatory assets and liabilities associated with their decoupling mechanisms and transmission formula rates. For PECO, reflects the change in regulatory assets and liabilities associated with its transmission formula rates. See Note 3 — Regulatory Matters for additional information.

(d)See Note 15 — Commitments and Contingencies for additional information related to the Deferred Prosecution Agreement.

144

Successor Predecessor
Nine Months Ended September 30, 2016 March 24, 2016 to September 30, 2016 January 1, 2016 to March 23, 2016
Exelon Generation ComEd PECO BGE Pepco DPL ACE PHI PHI
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs $ 458
$ 163
$ 124
$ 25
$ 50
$ 24
$ 13
$ 11
$ 58
$ 23
Loss from equity method investments 15
16
—
—
—
—
—
—
—
—
Provision for uncollectible accounts 107
14
31
24
12
15
12
18
27
16
Stock-based compensation costs 88
—
—
—
—
—
—
—
—
3
Other decommissioning-related activity^(a)
(237 ) (237 ) —
—
—
—
—
—
—
—
Energy-related options^(b)
(20 ) (20 ) —
—
—
—
—
—
—
—
Amortization of regulatory asset related to debt costs 7
—
3
1
—
2
—
1
2
1
Amortization of rate stabilization deferral 62
—
—
—
62
3
3
—
—
5
Amortization of debt fair value adjustment (9 ) (9 ) —
—
—
—
—
—
—
—
Discrete impacts from EIMA ^(c)
(36 ) —
(36 ) —
—
—
—
—
—
—
Amortization of debt costs 26
12
(3 ) 2
3
—
—
—
—
—
Provision for excess and obsolete inventory
74
70
4
—
—
1
1
1
—
1
Merger-related commitments ^(d)(e)
508
3
—
—
—
125
73
110
308
—
Severance costs 130
57
—
—
—
—
—
—
53
—
Asset retirement costs —
—
—
—
—
—
5
2
—
—
Lower of cost or net realizable value inventory adjustment 36
36
—
—
—
—
—
—
—
—
Other 15
24
(1 ) (3 ) (18 ) (2 ) (8 ) (5 ) (7 ) (3 )
Total other non-cash operating activities $ 1,224

$ 129

$ 122

$ 49

$ 109
$ 168

$ 99

$ 138
$ 441
$ 46
Non-cash investing and financing activities:
Change in capital expenditures not paid $ (338 ) $ (289 ) $ (42 ) $ (4 ) $ 17
$ 15
$ (10 ) $ 2
$ (5 ) $ 11
Fair value of net assets contributed to Generation in connection with the PHI Merger, net of cash^(d)(f)
—
119
—
—
—
—
—
—
—
—
Fair value of net assets distributed to Exelon in connection with the PHI Merger, net of cash^(d)(f)
—
—
—
—
—
—
—
—
129
—
Fair value of pension obligation transferred in connection with the PHI Merger —
—
—
—
—
—
—
—
53
—
Assumption of member purchase liability —
—
—
—
—
—
—
—
29
—
Assumption of merger commitment liability —
—
—
—
—
33
—
—
33
—
Change in PPE related to ARO update
476
476
—
—
—
—
—
—
—
—
Indemnification of like-kind exchange position^(g)
—
—
157
—
—
—
—
—
—
—
Non-cash financing of capital projects 84
84
—
—
—
—
—
—
—
—
Dividends on stock compensation 2
—
—
—
—
—
—
—
—
—

~~_________~~

~~(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 16 - Asset Retirement Obligations of the Exelon 2016 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.~~

~~171~~

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— ~~(Continued)~~

(Dollars in millions, except per share data, unless otherwise noted)

Note 18 — Supplemental Financial Information

~~(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 5 — Regulatory Matters for more information.


~~(d)~~	~~See Note 4 — Mergers, Acquisitions and Dispositions for additional information related to the merger with PHI.~~


~~(e)~~	~~Excludes $5 million of forgiveness of Accounts receivable related to merger commitments recorded in connection with the PHI Merger, the balance is included within Provision for uncollectible accounts.~~


~~(f)~~	Immediately following closing of the PHI Merger, the net assets associated with PHI's unregulated business interests were distributed by PHI to Exelon. Exelon contributed a portion of such net assets to Generation.


~~(g)~~	~~See Note 12— Income Taxes for discussion of the like-kind exchange tax position.~~

The following tables provide a reconciliation of cash, cash equivalents, and restricted cash reported within the Registrants’ Consolidated Balance Sheets that sum to the total of the same amounts in their Consolidated Statements of Cash Flows.


	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
September 30, 2021
Cash and cash equivalents	$	2,957	$	1,957	$	241	$	344	$	225	$	82	$	19	$	13	$	16
Restricted cash and cash equivalents	473		62		276		8		27		71		41		26		5
Restricted cash included in other long-term assets	54		—		44		—		—		9		—		—		9
Total cash, restricted cash, and cash equivalents	$	3,484	$	2,019	$	561	$	352	$	252	$	162	$	60	$	39	$	30

December 31, 2020
Cash and cash equivalents	$	663	$	226	$	83	$	19	$	144	$	111	$	30	$	15	$	17
Restricted cash and cash equivalents	438		89		279		7		1		39		35		—		3
Restricted cash included in other long-term assets	53		—		43		—		—		10		—		—		10
Cash, restricted cash, and cash equivalents - Held for Sale	12		12		—		—		—		—		—		—		—
Total cash, restricted cash, and cash equivalents	$	1,166	$	327	$	405	$	26	$	145	$	160	$	65	$	15	$	30

September 30, 2020
Cash and cash equivalents	$	1,858	$	623	$	76	$	242	$	326	$	196	$	125	$	26	$	13
Restricted cash and cash equivalents	485		100		305		7		1		38		33		—		4
Restricted cash included in other long-term assets	137		—		127		—		—		10		—		—		10
Total cash, restricted cash, and cash equivalents	$	2,480	$	723	$	508	$	249	$	327	$	244	$	158	$	26	$	27

December 31, 2019
Cash and cash equivalents	$	587	$	303	$	90	$	21	$	24	$	131	$	30	$	13	$	12
Restricted cash and cash equivalents	358		146		150		6		1		36		33		—		2
Restricted cash included in other long-term assets	177		—		163		—		—		14		—		—		14
Total cash, restricted cash, and cash equivalents	$	1,122	$	449	$	403	$	27	$	25	$	181	$	63	$	13	$	28

For additional information on restricted cash see Note 1 — Significant Accounting Policies of the Exelon 2020 Form 10-K.

Supplemental Balance Sheet Information

The following tables provide additional information about ~~assets and liabilities of the Registrants as of September 30, 2017 and December 31, 2016.~~

Successor
September 30, 2017 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Property, plant and equipment:
Accumulated depreciation and amortization $ 20,591
^(a)
$ 11,193
^(a)
$ 4,191

$ 3,366

$ 3,351
$ 448
$ 3,171

$ 1,231

$ 1,060
Accounts receivable:
Allowance for uncollectible accounts $ 339

$ 111

$ 72

$ 57

$ 25
$ 74
$ 29

$ 17

$ 28

Successor

December 31, 2016 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Property, plant and equipment:
Accumulated depreciation and amortization $ 19,169
^(b)
$ 10,562
^(b)
$ 3,937

$ 3,253

$ 3,254
$ 195
$ 3,050

$ 1,175

$ 1,016
Accounts receivable:
Allowance for uncollectible accounts $ 334

$ 91
$ 70

$ 61

$ 32
$ 80
$ 29

$ 24

$ 27

~~_________~~


~~(a)~~	~~Includes accumulated amortization of nuclear fuel in the reactor core of $3,303 million.~~


~~(b)~~	~~Includes accumulated amortization of nuclear fuel in the reactor core of $3,186 million.~~

~~PECO Installment Plan Receivables (Exelon and PECO)~~

PECO enters into payment agreements with certain delinquent customers, primarily residential, seeking to restore their service, as required by the PAPUC. Customers with past due balances that meet certain income criteria are provided the option to enter into an installment payment plan, some of which have terms greater than one year, to repay past due balances in addition to paying for their ongoing service on a current basis. The receivable balance for these payment agreement receivables ismaterial items recorded in ~~accounts receivable for~~ the current portion and other deferred debits and other assets for the noncurrent portion. The net receivable balance for installment plans with terms greater than one year was $11 million and $9 million as of September 30, 2017 and December 31, 2016, respectively. The allowance for uncollectible accounts reserve methodology and assessment of the credit quality of the installment plan receivables are consistent with the customer accounts receivable methodology discussed in Note 1 — Significant Accounting Policies of the Exelon 2016 Form 10-K. The allowance for uncollectible accounts balance associated with these receivables at September 30, 2017 of $12 million consists of $3 million and $9 million for medium risk and high risk segments, respectively. The allowance for uncollectible accounts balance at December 31, 2016 of $13 million consists of $1 million, $3 million and $9 million for low risk, medium risk and high risk segments, respectively. The balance of the payment agreement is billed to the customer in equal monthly installments over the term of the agreement. Installment receivables outstanding as of September 30, 2017 and December 31, 2016 include balances not yet presented on the customer bill, accounts currently billed and an immaterial amount of past due receivables. When a customer defaults on its payment agreement, the terms of which are defined by plan type, the entire balance of the agreement becomes due and the balance is reclassified to current customer accounts receivable and reserved for in accordance with the methodology discussed in Note 1 — Significant Accounting Policies of the Exelon 2016 Form 10-K.

Registrants' Consolidated Balance Sheets.

~~172~~

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— ~~(Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

~~20. Segment Information (All Registrants)~~

Operating segments for each of the Registrants are determined based on information used by the chief operating decision maker(s) (CODM) in deciding how to evaluate performance and allocate resources at each of the Registrants.

In the first quarter of 2016, following the consummation of the PHI Merger, three new reportable segments were added: Pepco, DPL and ACE. As a result, Exelon has twelve reportable segments, which include ComEd, PECO, BGE, PHI's three reportable segments consisting of Pepco, DPL, and ACE, and Generation’s sixreportable segments consisting of the Mid-Atlantic, Midwest, New England, New York, ERCOT and all other power regions referred to collectively as “Other Power Regions”, which includes activities in the South, West and Canada. ComEd, PECO, BGE, Pepco, DPL and ACE each represent a single reportable segment, and as such, no separate segment information is provided for these Registrants. Exelon, ComEd, PECO, BGE, Pepco, DPL and ACE's CODMs evaluate the performance of and allocate resources to ComEd, PECO, BGE, Pepco, DPL and ACE based on net income and return on equity.

Effective with the consummation of the PHI Merger, PHI's reportable segments have changed based on the information used by the CODM to evaluate performance and allocate resources. PHI's reportable segments consist of Pepco, DPL and ACE. PHI's Predecessor periods' segment information has been recast to conform to the current presentation. The reclassification of the segment information did not impact PHI's reported consolidated revenues or net income. PHI's CODM evaluates the performance of and allocates resources to Pepco, DPL and ACE based on net income and return on equity.

The basis for Generation's reportable segments is the integrated management of its electricity business that is located in different geographic regions, and largely representative of the footprints of ISO/RTO and/or NERC regions, which utilize multiple supply sources to provide electricity through various distribution channels (wholesale and retail). Generation's hedging strategies and risk metrics are also aligned to these same geographic regions. Descriptions of each of Generation’s six reportable segments are as follows:

~~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.~~

The CODMs for Exelon and Generation evaluate the performance of Generation’s electric business activities and allocate resources based on revenues net of purchased power and fuel expense (RNF). Generation believes that RNF is a useful measurement of operational performance. RNF 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

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~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

in this report. Generation’s operating revenues include all sales to third parties and affiliated sales to the Utility Registrants. Purchased power costs include all costs associated with the procurement and supply of electricity including capacity, energy and ancillary services. Fuel expense includes the fuel costs for Generation’s owned generation and fuel costs associated with tolling agreements. The results of Generation's other business activities are not regularly reviewed by the CODM and are therefore not classified as operating segments or included in the regional reportable segment amounts. These activities include natural gas, as well as other miscellaneous business activities that are not significant to Generation's overall operating revenues or results of operations. Further, Generation’s unrealized mark-to-market gains and losses on economic hedging activities and its amortization of certain intangible assets and liabilities relating to commodity contracts recorded at fair value from mergers and acquisitions are also excluded from the regional reportable segment amounts. Exelon and Generation do not use a measure of total assets in making decisions regarding allocating resources to or assessing the performance of these reportable segments.

~~Three Months Ended September 30, 2017 and 2016~~

Successor

Generation^(a)
ComEd PECO BGE
PHI^(b)

Other^(c)
Intersegment
Eliminations Exelon
Operating revenues^(d):

2017
Competitive businesses electric revenues $ 4,042
$ —
$ —
$ —
$ —
$ —
$ (295 ) $ 3,747
Competitive businesses natural gas revenues 460
—
—
—
—
—
—
460
Competitive businesses other revenues 249
—
—
—
—
—
—
249
Rate-regulated electric revenues —
1,571
662
658
1,280
—
(7 ) 4,164
Rate-regulated natural gas revenues —
—
53
80
18
—
(2 ) 149
Shared service and other revenues —
—
—
—
12
446
(458 ) —
2016
Competitive businesses electric revenues $ 4,322
$ —
$ —
$ —
$ —
$ —
$ (499 ) $ 3,823
Competitive businesses natural gas revenues 326
—
—
—
—
—
—
326
Competitive businesses other revenues 387
—
—
—
—
—
(1 ) 386
Rate-regulated electric revenues —
1,497
740
735
1,366
—
(8 ) 4,330
Rate-regulated natural gas revenues —
—
48
77
17
—
(5 ) 137
Shared service and other revenues —
—
—
—
11
362
(373 ) —
Intersegment revenues^(e):

2017 $ 294
$ 3
$ 2
$ 3
$ 12
$ 445
$ (759 ) $ —
2016 500
4
2
7
11
362
(885 ) 1
Net income (loss):
2017 $ 348
$ 189
$ 112
$ 62
$ 153
$ 3
$ —
$ 867
2016 271
37
122
56
166
(125 ) (1 ) 526
Total assets:
September 30, 2017 $ 47,744
$ 29,649
$ 11,480
$ 8,923
$ 21,301
$ 10,662
$ (11,286 ) $ 118,473
December 31, 2016 46,974
28,335
10,831
8,704
21,025
10,369
(11,334 ) 114,904

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~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

~~_________~~

~~(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 September 30, 2017 include revenue from sales to PECO of $31 million, sales to BGE of $98 million, sales to Pepco of $57 million, sales to DPL of $47 million, and sales to ACE of $7 million in the Mid-Atlantic region, and sales to ComEd of $54 million in the Midwest region. For the three months ended September 30, 2016, intersegment revenues for Generation include revenue from sales to PECO of $91 million, sales to BGE of $183 million, sales to Pepco of $128 million, sales to DPL of $63 million, and sales to ACE of $15 million in the Mid-Atlantic region, and sales to ComEd of $20 million in the Midwest region.


~~(b)~~	~~Amounts included represent activity for PHI's successor period, three months ended September 30, 2017 and 2016. PHI includes the three reportable segments: Pepco, DPL and ACE.~~


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


~~(d)~~	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 19 — Supplemental Financial Information for total utility taxes for the three months ended September 30, 2017 and 2016.

~~(e)~~

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.

~~Successor PHI:~~

Pepco DPL ACE
Other^(b)
Intersegment
Eliminations PHI
Operating revenues^(a):
Three Months Ended September 30, 2017 - Successor
Rate-regulated electric revenues $ 604
$ 309
$ 370
$ —
$ (3 ) $ 1,280
Rate-regulated natural gas revenues —
18
—
—
—
18
Shared service and other revenues —
—
—
12
—
12
Three Months Ended September 30, 2016 - Successor
Rate-regulated electric revenues $ 635
$ 314
$ 421
$ —
$ (4 ) $ 1,366
Rate-regulated natural gas revenues —
17
—
—
—
17
Shared service and other revenues —
—
—
11
—
11
Intersegment revenues:
Three Months Ended September 30, 2017 - Successor $ 1
$ 2
$ —
$ 13
$ (4 ) $ 12
Three Months Ended September 30, 2016 - Successor 1
2
1
11
(4 ) 11
Net income (loss):
Three Months Ended September 30, 2017 - Successor $ 87
$ 31
$ 41
$ (18 ) $ 12
$ 153
Three Months Ended September 30, 2016 - Successor 79
44
47
(15 ) 11
166
Total assets:
September 30, 2017 - Successor $ 7,775
$ 4,276
$ 3,510
$ 10,724
$ (4,984 ) $ 21,301
December 31, 2016 - Successor 7,335
4,153
3,457
10,804
(4,724 ) 21,025

~~_________~~


~~(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 19 — Supplemental Financial Information for total utility taxes for the three months ended September 30, 2017 and 2016.


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

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~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

~~Generation total revenues:~~

Three Months Ended September 30, 2017 Three Months Ended September 30, 2016

Revenues
from external
customers^(a)

Intersegment
revenues
Total
Revenues
Revenues
from external
customers^(a)

Intersegment
revenues
Total
Revenues
Mid-Atlantic $ 1,421
$ 11
$ 1,432
$ 1,813
$ (13 ) $ 1,800
Midwest 1,049
(11 ) 1,038
1,163
1
1,164
New England 482
(1 ) 481
455
(4 ) 451
New York 434
(6 ) 428
331
(8 ) 323
ERCOT 308
6
314
289
6
295
Other Power Regions 348
(13 ) 335
271
(33 ) 238
Total Revenues for Reportable Segments 4,042
(14 ) 4,028
4,322
(51 ) 4,271
Other^(b)
709
14
723
713
51
764
Total Generation Consolidated Operating Revenues $ 4,751
$ —
$ 4,751
$ 5,035
$ —
$ 5,035

~~_________~~


~~(a)~~	~~Includes all wholesale and retail electric sales 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 $13 million and $21 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 September 30, 2017 and 2016, respectively, unrealized mark-to-market gain of $52 million and $187 million for the three months ended September 30, 2017 and 2016, respectively, and elimination of intersegment revenues.

~~Generation total revenues net of purchased power and fuel expense:~~

Three Months Ended September 30, 2017 Three Months Ended September 30, 2016

RNF
from external
customers^(a)

Intersegment
RNF
Total RNF
RNF
from external
customers^(a)

Intersegment
RNF
Total RNF
Mid-Atlantic $ 817
$ 38
$ 855
$ 881
$ 6
$ 887
Midwest 697
—
697
782
(1 ) 781
New England 151
(6 ) 145
170
(10 ) 160
New York 296
—
296
195
(1 ) 194
ERCOT 229
(111 ) 118
144
(51 ) 93
Other Power Regions 118
(50 ) 68
143
(66 ) 77
Total Revenues net of purchased power and fuel for Reportable Segments 2,308

(129 )
2,179

2,315

(123 )
2,192
Other^(b)
112
129
241
131
123
254
Total Generation Revenues net of purchased power and fuel expense $ 2,420

$ —

$ 2,420

$ 2,446

$ —

$ 2,446

~~_________~~


~~(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 $19 million and $22 million decrease to RNF for the amortization of intangible assets and liabilities related to commodity contracts for the three months ended September 30, 2017 and 2016, respectively, unrealized mark-to-market gains of $73 million and $88 million for the three months ended September 30, 2017 and 2016, 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 $6 million and $28 million decrease to revenue net of purchased power and fuel expense for the three months ended September 30, 2017 and 2016, respectively, and the elimination of intersegment revenue net of purchased power and fuel expense.

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~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

~~Nine Months Ended September 30, 2017 and 2016~~

Successor

Generation^(a)
ComEd PECO BGE
PHI^(b)

Other^(c)
Intersegment
Eliminations Exelon
Operating revenues^(d):
2017
Competitive businesses electric revenues $ 11,485
$ —
$ —
$ —
$ —
$ —
$ (888 ) $ 10,597
Competitive businesses natural gas revenues 1,807
—
—
—
—
—
—
1,807
Competitive businesses other revenues 520
—
—
—
—
—
—
520
Rate-regulated electric revenues —
4,227
1,802
1,895
3,417
—
(23 ) 11,318
Rate-regulated natural gas revenues —
—
339
468
105
—
(6 ) 906
Shared service and other revenues —
—
—
—
35
1,316
(1,350 ) 1
2016
Competitive businesses electric revenues $ 11,677
$ —
$ —
$ —
$ —
$ —
$ (1,118 ) $ 10,559
Competitive businesses natural gas revenues 1,515
—
—
—
—
—
—
1,515
Competitive businesses other revenues 171
—
—
—
—
—
(2 ) 169
Rate-regulated electric revenues —
4,031
1,971
1,998
2,485
—
(24 ) 10,461
Rate-regulated natural gas revenues —
—
322
423
46
—
(10 ) 781
Shared service and other revenues —
—
—
—
34
1,166
(1,199 ) 1
Intersegment revenues^(e):

2017 $ 888
$ 12
$ 5
$ 12
$ 35
$ 1,312
$ (2,262 ) $ 2
2016 1,121
12
5
16
34
1,166
(2,351 ) 3
Net income (loss):
2017 $ 491
$ 447
$ 327
$ 231
$ 359
$ 58
$ (2 ) $ 1,911
2016 556
297
346
191
(91 ) (340 ) (3 ) 956

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~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

~~_________~~

~~(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 nine months ended September 30, 2017 include revenue from sales to PECO of $111 million, sales to BGE of $330 million, sales to Pepco of $209 million, sales to DPL of $138 million, and sales to ACE of $23 million in the Mid-Atlantic region, and sales to ComEd of $77 million in the Midwest region. For the nine months ended September 30, 2016, intersegment revenues for Generation include revenue from sales to PECO of $234 million and sales to BGE of $489 million in the Mid-Atlantic region, and sales to ComEd of $38 million in the Midwest region. For the Successor period of March 24, 2016 to September 30, 2016, intersegment revenues for Generation include revenue from sales to Pepco of $223 million, sales to DPL of $109 million, and sales to ACE of $28 million in the Mid-Atlantic region.


~~(b)~~	Amounts included represent activity for PHI's successor period, nine months ended September 30, 2017 and March 24, 2016 through September 30, 2016. PHI includes the three reportable segments: Pepco, DPL and ACE. See tables below for PHI's predecessor period, including Pepco, DPL and ACE, for January 1, 2016 to March 23, 2016.


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


~~(d)~~	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 19 — Supplemental Financial Information for total utility taxes for the nine months ended September 30, 2017 and 2016.

~~(e)~~

~~Successor and Predecessor PHI:~~

Pepco DPL ACE
Other^(b)
Intersegment
Eliminations PHI
Operating revenues^(a):

Nine Months Ended September 30, 2017 - Successor
Rate-regulated electric revenues $ 1,649
$ 866
$ 915
$ —
$ (13 ) $ 3,417
Rate-regulated natural gas revenues —
105
—
—
—
105
Shared service and other revenues —
—
—
37
(2 ) 35
March 24, 2016 to September 30, 2016 - Successor
Rate-regulated electric revenues $ 1,184
$ 593
$ 714
$ 3
$ (9 ) $ 2,485
Rate-regulated natural gas revenues —
46
—
—
—
46
Shared service and other revenues —
—
—
34
—
34
January 1, 2016 to March 23, 2016 - Predecessor
Rate-regulated electric revenues $ 511
$ 279
$ 268
$ 42
$ (4 ) $ 1,096
Rate-regulated natural gas revenues —
56
—
1
—
57
Shared service and other revenues —
—
—
—
—
—
Intersegment revenues:
Nine Months Ended September 30, 2017 - Successor $ 4
$ 6
$ 2
$ 37
$ (14 ) $ 35
March 24, 2016 to September 30, 2016 - Successor 2
4
2
35
(9 ) 34
January 1, 2016 to March 23, 2016 - Predecessor 1
2
1
—
(4 ) —
Net income (loss):
Nine Months Ended September 30, 2017 - Successor $ 188
$ 107
$ 77
$ (48 ) $ 35
$ 359
March 24, 2016 to September 30, 2016 - Successor (12 ) (42 ) (55 ) (16 ) 34
(91 )
January 1, 2016 to March 23, 2016 - Predecessor 32
26
5
(44 ) —
19

~~_________~~


~~(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 19 — Supplemental Financial Information for total utility taxes for the nine months ended September 30, 2017 and 2016.


~~(b)~~	Other primarily includes PHI’s corporate operations, shared service entities and other financing and investment activities. For the predecessor period presented, Other includes the activity of PHI’s unregulated businesses which were distributed to Exelon and Generation as a result of the PHI Merger.

~~178~~

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~~COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~ — ~~(Continued)~~

~~(Dollars in millions, except per share data, unless otherwise noted)~~

~~Generation total revenues:~~

Nine Months Ended September 30, 2017 Nine Months Ended September 30, 2016

Revenues
from external
customers^(a)
Intersegment
revenues Total
Revenues
Revenues
from external
customers^(a)
Intersegment
revenues Total
Revenues
Mid-Atlantic $ 4,207
$ 15
$ 4,222
$ 4,776
$ (40 ) $ 4,736
Midwest 3,158
(17 ) 3,141
3,330
13
3,343
New England 1,469
(8 ) 1,461
1,278
(6 ) 1,272
New York 1,095
(14 ) 1,081
906
(33 ) 873
ERCOT 749
4
753
659
6
665
Other Power Regions 807
(28 ) 779
728
(42 ) 686
Total Revenues for Reportable Segments 11,485

(48 )
11,437

11,677

(102 )
11,575
Other^(b)
2,327
48
2,375
1,686
102
1,788
Total Generation Consolidated Operating Revenues $ 13,812

$ —

$ 13,812

$ 13,363

$ —

$ 13,363

~~_________~~


~~(a)~~	~~Includes all wholesale and retail electric sales 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 $30 million and $10 million decrease to revenues for the amortization of intangible assets and liabilities related to commodity contracts recorded at fair value for the nine months ended September 30, 2017 and 2016, respectively, unrealized mark-to-market losses of $47 million and $366 million for the nine months ended September 30, 2017 and 2016, respectively, and elimination of intersegment revenues.

~~Generation total revenues net of purchased power and fuel expense:~~

Nine Months Ended September 30, 2017 Nine Months Ended September 30, 2016

RNF
from external
customers^(a)

Intersegment
RNF
Total RNF
RNF
from external
customers^(a)

Intersegment
RNF
Total RNF
Mid-Atlantic $ 2,330
$ 81
$ 2,411
$ 2,541
$ 15
$ 2,556
Midwest 2,129
11
2,140
2,225
4
2,229
New England 423
(20 ) 403
373
(23 ) 350
New York 679
(1 ) 678
607
(15 ) 592
ERCOT 446
(188 ) 258
335
(104 ) 231
Other Power Regions 359
(139 ) 220
357
(104 ) 253
Total Revenues net of purchased power and fuel expense for Reportable Segments 6,366

(256 )
6,110

6,438

(227 )
6,211
Other^(b)
160
256
416
316
227
543
Total Generation Revenues net of purchased power and fuel expense $ 6,526

$ —

$ 6,526

$ 6,754

$ —

$ 6,754

~~_________~~


~~(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 $41 million and $15 million decrease to RNF for the amortization of intangible assets and liabilities related to commodity contracts for the nine months ended September 30, 2017 and 2016, respectively, unrealized mark-to-market losses of $161 million and $113 million for the nine months ended September 30, 2017 and 2016, 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 $8 million and $38 million decrease to revenue net of purchased power and fuel expense for the nine months ended September 30, 2017 and 2016, respectively, and the elimination of intersegment revenue net of purchased power and fuel expense.

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~~Table of Contents~~

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

(Dollars in millions, except per share data, unless otherwise noted)

Note 18 — Supplemental Financial Information


	Accrued expenses
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
September 30, 2021
Compensation-related accruals(a)	$	894	$	318	$	148	$	66	$	72	$	108	$	34	$	21	$	16
Taxes accrued	508		222		80		61		90		98		67		16		7
Interest accrued	415		77		65		36		39		75		37		20		15

December 31, 2020
Compensation-related accruals(a)	$	1,069	$	426	$	170	$	73	$	84	$	109	$	36	$	18	$	17
Taxes accrued	527		229		94		16		73		117		90		18		12
Interest accrued	331		44		109		37		46		51		26		7		12

__________

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

19. Related Party Transactions (All Registrants)

Operating revenues from affiliates

Generation

The following table presents Generation’s Operating revenues from affiliates, which are primarily recorded as Purchased power from affiliates and an immaterial amount recorded as Operating and maintenance expense from affiliates at the Utility Registrants:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Operating revenues from affiliates:
ComEd(a)(b)	$	96	$	71	$	249	$	241
PECO(c)	59		68		142		146
BGE(d)	65		84		195		252
PHI	99		105		276		288
Pepco(e)	69		80		199		219
DPL(f)	25		21		63		60
ACE(g)	5		4		14		9
Other	5		3		10		5
Total operating revenues from affiliates (Generation)	$	324	$	331	$	872	$	932

__________

(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 and nine months ended September 30, 2021, respectively, ComEd’s Purchased power from Generation of $94 million and $256 million is recorded as Operating revenues from ComEd of $96 million and $249 million and as Purchased power and fuel from ComEd of $2 million and $(7) million at Generation. For the three and nine months ended September 30, 2020, respectively, ComEd’s Purchased power from Generation of $71 million and$252 million is recorded as Operating revenues from ComEd of $71 million and $241 million and as Purchased power and fuel from ComEd of less than $1 million and $11 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.

(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 commodity programs.

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

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in millions, except per share data, unless otherwise noted)

Note 19 — Related Party Transactions

PHI

PHI’s Operating revenues from affiliates are primarily with BSC for services that PHISCO provides to BSC.

Service Company Costs for Corporate Support

The Registrants receive a variety of corporate support services from BSC. Pepco, DPL, and ACE also receive corporate support services from PHISCO. See Note 1 — Significant Accounting Policies for additional information regarding BSC and PHISCO.

The following table presents the service company costs allocated to the Registrants:


	Operating and maintenance from affiliates								Capitalized costs
	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020		2021		2020		2021		2020
Exelon
BSC									$	149	$	148	$	431	$	390
PHISCO									18		15		54		45
Generation
BSC	$	145	$	133	$	424	$	406	43		13		76		37
ComEd
BSC	71		65		214		204		47		49		148		133
PECO
BSC	41		34		120		107		12		20		57		53
BGE
BSC	45		38		133		120		20		30		62		88
PHI
BSC	40		36		116		107		27		36		88		79
PHISCO	—		—		—		—		18		15		54		45
Pepco
BSC	23		20		68		61		11		14		36		29
PHISCO	26		28		84		90		7		7		22		20
DPL
BSC	14		13		43		38		10		12		29		26
PHISCO	24		24		73		73		6		4		17		13
ACE
BSC	14		11		37		32		7		10		22		22
PHISCO	21		21		64		65		5		4		15		12

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in millions, except per share data, unless otherwise noted)

Note 19 — Related Party Transactions

Current Receivables from/Payables to affiliates

The following tables present current receivables from affiliates and current payables to affiliates:

September 30, 2021


				Receivables from affiliates:
	Payables to affiliates:			Generation			ComEd			PECO			BGE			Pepco			DPL			ACE			BSC			PHISCO			Other			Total
Generation					$	36		$	9		$	—		$	—		$	—		$	—		$	86		$	—		$	23		$	154
ComEd		$	103	(a)				—			—			—			—			—			49			—			6			158
PECO		24			3						1			—			—			—			25			—			7			60
BGE		15			—			—						—			—			—			32			—			2			49
PHI		—			—			—			—			—			—			—			2			—			10			12
Pepco		22			—			—			—						1			—			15			13			—			51
DPL		4			—			—			—			—						—			9			11			—			24
ACE		7			—			—			—			—			—						9			9			1			26
Other		9			2			—			1			—			—			1			2			—						15
Total		$	184		$	41		$	9		$	2		$	—		$	1		$	1		$	229		$	33		$	49		$	549

December 31, 2020


				Receivables from affiliates:
	Payables to affiliates:			Generation			ComEd			PECO			BGE			Pepco			DPL			ACE			BSC			PHISCO			Other			Total
Generation					$	13		$	—		$	—		$	—		$	—		$	—		$	72		$	—		$	22		$	107
ComEd		$	78	(a)				—			—			—			—			—			59			—			9			146
PECO		17			1						—			—			—			—			28			—			4			50
BGE		11			—			—						—			—			—			47			—			3			61
PHI		—			—			—			—			—			—			—			4			—			11			15
Pepco		13			2			—			1						—			—			25			14			—			55
DPL		3			1			—			—			—						—			21			10			1			36
ACE		6			—			—			—			—			—						15			9			1			31
Other		25			5			2			2			2			1			6			—			—						43
Total		$	153		$	22		$	2		$	3		$	2		$	1		$	6		$	271		$	33		$	51		$	544

__________

(a)As of September 30, 2021 and December 31, 2020, Generation had a contract liability with ComEd for $27 million and $50 million, respectively, that was included in Other current liabilities on Generation’s Consolidated Balance Sheets. As of September 30, 2021 and December 31, 2020, ComEd had a Current Payable to Generation of $76 million and $28 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.

Borrowings from Exelon/PHI intercompany money pool

To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing both Exelon and PHI operate an intercompany money pool. Generation, ComEd, PECO, and PHI Corporate participate in the Exelon money pool. Pepco, DPL, and ACE participate in the PHI intercompany money pool.

Noncurrent Receivables from/Payables to affiliates

Generation has long-term payables to ComEd and PECO as a result of the nuclear decommissioning contractual construct whereby, to the extent NDT funds are greater than the underlying ARO at the end of decommissioning, such amounts are due back to ComEd and PECO, as applicable, for payment to their respective customers. See Note 10 — Asset Retirement Obligations of the Exelon 2020 Form 10-K for additional information.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in millions, except per share data, unless otherwise noted)

Note 19 — Related Party Transactions

The following table presents noncurrent receivables from affiliates at ComEd and PECO which are recorded as noncurrent payables to affiliates at Generation:


	September 30, 2021		December 31, 2020
ComEd	$	2,597	$	2,541
PECO	546		475

Long-term debt to financing trusts

The following table presents Long-term debt to financing trusts:


	September 30, 2021						December 31, 2020
	Exelon		ComEd		PECO		Exelon		ComEd		PECO
ComEd Financing III	$	206	$	205	$	—	$	206	$	205	$	—
PECO Trust III	81		—		81		81		—		81
PECO Trust IV	103		—		103		103		—		103
Total	$	390	$	205	$	184	$	390	$	205	$	184

Long-term debt to affiliates

In connection with the debt obligations assumed by Exelon as part of the Constellation merger, Exelon and subsidiaries of Generation (former Constellation subsidiaries) assumed intercompany loan agreements that mirror the terms and amounts of the third-party debt obligations of Exelon, resulting in intercompany notes payable included in Long-term debt to affiliates in Generation’s Consolidated Balance Sheets and intercompany notes receivable at Exelon Corporate.

20. Planned Separation

On February 21, 2021, Exelon’s Board of Directors approved a plan to separate the Utility Registrants and Generation, creating two publicly traded companies. Under the separation plan, Exelon shareholders will retain their current shares of Exelon stock and receive a pro-rata distribution of shares of the new company’s stock in a transaction that is expected to be tax-free to Exelon and its shareholders for U.S. federal income tax purposes. The actual number of shares to be distributed to Exelon shareholders will be determined prior to closing.

Exelon is targeting to complete the separation in the first quarter of 2022, subject to final approval by Exelon’s Board of Directors, a Form 10 registration statement being declared effective by the SEC, regulatory approvals, and satisfaction of other conditions. The transaction is subject to approval by FERC, NRC, and NYPSC and receipt of a private letter ruling from the IRS and tax opinion from Exelon’s tax advisors.

On February 25, 2021, Exelon and Generation filed applications with FERC, NYPSC, and NRC seeking approvals for the separation of Generation. On March 25, 2021, Exelon filed a request for a private letter ruling with the IRS to confirm the tax-free treatment of the planned separation, which was received on September 23, 2021. On August 24, 2021, Exelon and Generation received approval from FERC for the planned separation. Exelon and Generation expect a decision from the NRC in the fourth quarter of 2021 and have requested a decision from the NYPSC before the end of 2021. Exelon and Generation cannot predict if the remaining applications will be approved as filed.

There can be no assurance that any separation transaction will ultimately occur or, if one does occur, of its terms or timing.

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ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

(Dollars in millions except per share data, unless otherwise noted)

Exelon

Executive Overview

Exelon ~~a utility services holding company, operates through the following principal subsidiaries:~~

~~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 of natural gas 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 natural 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.~~

~~Pepco, DPL and ACE are operating companies of PHI, which~~ is a utility services holding company engaged in the generation, delivery, and ~~a wholly owned subsidiary~~marketing of ~~Exelon.~~energy through Generation and the energy distribution and transmission businesses through ComEd, PECO, BGE, Pepco, DPL, and ACE.

Exelon has ~~twelve~~eleven reportable segments consisting of Generation’s ~~six~~five reportable segments (Mid-Atlantic, Midwest, ~~New England,~~ New York, ERCOT, and Other Power ~~Regions in Generation)~~Regions), ComEd, PECO, BGE, ~~and PHI's three utility reportable segments (Pepco,~~Pepco, DPL, and ~~ACE).~~ACE. See Note ~~20 -~~1 — Significant Accounting Policies and Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information regarding Exelon's principal subsidiaries and reportable segments.

Through its business services subsidiary BSC, Exelon provides its operating subsidiaries with a variety of support services at cost. The costs of these services are directly charged or allocated to the applicable operating segments. Additionally, the results of Exelon’s corporate operations include costs for corporate governance and interest costs and income from various investment and financing activities.

PHI Service Company, a wholly owned subsidiary of PHI, provides a variety of support services at cost, including legal, accounting, engineering, distribution and transmission planning, asset management, system operations, and power procurement, to PHI and its operating subsidiaries. These services are directly charged or allocated pursuant to service agreements among PHI Service Company and the participating operating subsidiaries.

Exelon’s consolidated financial information includes the results of its eight separate operating subsidiary registrants, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE, which, along with Exelon, are collectively

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referred to as the Registrants. The following combined Management’s Discussion and Analysis of Financial Condition and Results of Operations is separately filed by Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE. However, none of the Registrants makes any representation as to information related solely to any of the other Registrants.

Financial Results of Operations

GAAP Results of ~~Operations~~

Operations. The following ~~tables set~~table sets forth Exelon's GAAP consolidated ~~results of operations~~Net Income attributable to common shareholders by Registrant for the three and nine months ended September 30, ~~2017~~2021 compared to the same period in 2016. The 2016 amounts include the operations of PHI, Pepco, DPL and ACE from March 24, 2016 through September 30, 2016. All amounts presented below are before the impact of income taxes, except as noted.

Three Months Ended September 30, Favorable
(Unfavorable)
Variance
2017 2016
Generation ComEd PECO BGE PHI Other Exelon
Exelon^(b)

Operating revenues $ 4,751
$ 1,571
$ 715
$ 738
$ 1,310
$ (316 ) $ 8,769
$ 9,002
$ (233 )
Purchased power and fuel 2,331
529
235
269
473
(295 ) 3,542
3,754
212
Revenue net of purchased power and fuel^(a)
2,420
1,042
480
469
837
(21 ) 5,227
5,248
(21 )
Other operating expenses
Operating and maintenance 1,374
346
197
175
251
(43 ) 2,300
2,338
38
Depreciation and amortization 410
212
72
109
179
20
1,002
1,195
193
Taxes other than income 141
80
42
61
122
10
456
449
(7 )
Total other operating expenses 1,925
638
311
345
552
(13 ) 3,758
3,982
224
(Loss) Gain on sales of assets (2 ) —
—
—
—
1
(1 ) 1
(2 )
Bargain purchase gain 7
—
—
—
—
—
7
—
7
Operating income (loss) 500
404
169
124
285
(7 ) 1,475
1,267
208
Other income and (deductions)
Interest expense, net (113 ) (89 ) (31 ) (26 ) (62 ) (65 ) (386 ) (516 ) 130
Other, net 209
5
2
4
13
4
237
120
117
Total other income and (deductions) 96
(84 ) (29 ) (22 ) (49 ) (61 ) (149 ) (396 ) 247
Income (loss) before income taxes 596
320
140
102
236
(68 ) 1,326
871
455
Income taxes 240
131
28
40
83
(70 ) 452
340
(112 )
Equity in (losses) earnings of unconsolidated affiliates (8 ) —
—
—
—
1
(7 ) (5 ) (2 )
Net income 348
189
112
62
153
3
867
526
341
Net income attributable to noncontrolling interests and preference stock dividends 43
—
—
—
—
—
43
36
(7 )
Net income attributable to common shareholders $ 305
$ 189
$ 112
$ 62
$ 153
$ 3
$ 824
$ 490
$ 334

~~_________~~

~~(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.


~~(b)~~	~~As a result of the PHI Merger, Exelon includes the consolidated results of PHI, Pepco, DPL and ACE from July 1, 2016 through September 30, 2016.~~

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~~Table of Contents~~

Nine Months Ended September 30,
Favorable
(Unfavorable)
Variance
2017 2016
Generation ComEd PECO BGE PHI Other Exelon
Exelon^(b)

Operating revenues $ 13,812
$ 4,227
$ 2,141
$ 2,363
$ 3,557
$ (951 ) $ 25,149
$ 23,486
$ 1,663
Purchased power and fuel expense 7,286
1,241
719
853
1,318
(890 ) 10,527
9,462
(1,065 )
Revenue net of purchased power and fuel expense^(a)
6,526

2,986

1,422

1,510

2,239
(61 )
14,622

14,024
598
Other operating expenses

Operating and maintenance 4,871
1,096
595
532
774
(136 ) 7,732
7,677
(55 )
Depreciation and amortization 1,046
631
213
348
511
65
2,814
2,821
7
Taxes other than income 425
223
116
180
344
25
1,313
1,168
(145 )
Total other operating expenses 6,342

1,950

924

1,060

1,629
(46 )
11,859

11,666
(193 )
Gain on sales of assets 3
—
—
—
1
—
4
41
(37 )
Bargain purchase gain 233
—
—
—
—
—
233
—
233
Operating income (loss) 420

1,036

498

450

611
(15 )
3,000

2,399
601
Other income and (deductions)
Interest expense, net (342 ) (275 ) (93 ) (80 ) (183 ) (221 ) (1,194 ) (1,179 ) (15 )
Other, net 648
14
6
12
40
5
725
377
348
Total other income and (deductions) 306

(261 )
(87 )
(68 )
(143 ) (216 )
(469 )
(802 ) 333
Income (loss) before income taxes 726
775
411
382
468
(231 ) 2,531
1,597
934
Income taxes 209
328
84
151
109
(286 ) 595
625
30
Equity in (losses) earnings of unconsolidated affiliates (26 ) —
—
—
—
1
(25 ) (16 ) (9 )
Net income 491

447

327

231

359

56

1,911

956
955
Net income attributable to noncontrolling interests and preference stock dividends 12
—
—
—
—
—
12
26
14
Net income attributable to common shareholders $ 479

$ 447

$ 327

$ 231

$ 359
$ 56

$ 1,899

$ 930
$ 969

~~_________~~

~~(a)~~


~~(b)~~	~~As a result of the PHI Merger, Exelon includes the consolidated results of PHI, Pepco, DPL and ACE from March 24, 2016 through September 30, 2016.~~

~~Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016.~~ Exelon’s Net income attributable to common shareholders was $824 million for the three months ended September 30, 2017 as compared to $490 million for the three months ended September 30, 2016, and diluted earnings per average common share were $0.85 for the three months ended September 30, 2017 as compared to $0.53 for the three months ended September 30, 2016.

Revenue net of purchased power and fuel expense, which is a non-GAAP measure discussed below, decreased by $21 million for the three months ended September 30, 2017 as compared to the same period in 2016. The quarter-over-quarter decrease in Revenue net of purchased power and fuel expense was primarily due to the following unfavorable factors:

~~Decrease of $36 million at PECO primarily due to unfavorable weathers conditions;~~

~~Decrease of $15 million at Generation due to mark-to-market gains of $73 million in 2017 compared to $88 million in 2016; and~~

Decrease of $11 million at Generation due to the unfavorable impacts of lower load volumes delivered due to mild weather and lower realized energy prices related to Exelon's ratable hedging strategy, partially offset by the impact of the New York CES, increased capacity prices, increased nuclear volumes primarily as a result of the acquisition of FitzPatrick and decreased nuclear outage days, and the addition of two combined-cycle gas turbines in Texas.

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~~The quarter-over-quarter decrease in Revenue net of purchase power and fuel expense was partially offset by the following favorable factors:~~

~~Increase of $26 million at PHI primarily due to increased distribution revenue as a result of rate increases; and~~

~~Increase of $17 million at BGE primarily due to increased transmission revenue as a result of rate increases.~~

~~Operating and maintenance expense decreased by $38 million for the three months ended September 30, 2017 as compared to the same period in 2016 primarily due to the following favorable factors:~~

~~Decrease of $32 million at Exelon due to the net recovery of $2 million of merger-related costs in 2017 compared to merger-related costs of $30 million in 2016; and~~

~~Decrease of $31 million at ComEd primarily due to the change to defer and recover over time energy efficiency costs pursuant to the Illinois Future Energy Jobs Act.~~

The quarter-over-quarter decrease in Operating and maintenance expense was partially offset by an increase of $38 million at Generation primarily due to the announcement of the early retirement of Generation's TMI nuclear facility in 2017 compared to the previous decision to early retire Generation's Clinton and Quad Cities nuclear facilities in 2016 and higher asset impairment charges, partially offset by decreased nuclear refueling outage costs and labor, contracting and materials expense.

Depreciation and amortization expense decreased by $193 million primarily due to lower accelerated depreciation and amortization as a result of the 2017 decision to early retire the TMI nuclear facility compared to the previous decision in 2016 to early retire the Clinton and Quad Cities nuclear facilities, partially offset by increased depreciation expense as a result of ongoing capital expenditures across all operating companies for the three months ended September 30, 2017 as compared to the same period in 2016.

~~Taxes other than income increased by $7 millionprimarily due to increased property taxes as a result of the addition of FitzPatrick at Generation for the three months ended September 30, 2017 as compared to the same period in 2016.~~

~~Gain on sales of assets remained relatively consistent for the three months ended September 30, 2017 as compared to the same period in 2016.~~

Bargain purchase gain increased by $7 million due to a measurement period adjustment to the bargain purchase gain for the FitzPatrick acquisition for the three months ended September 30, 2017 as compared to the same period in 2016.

Interest expense, net decreased by $130 million primarily due to additional interest recorded in the third quarter 2016 related to Exelon's like-kind exchange tax position, partially offset by the the impact of project in-service dates on the capitalization of interest and higher outstanding debt at Generation for the three months ended September 30, 2017 as compared to the same period in 2016.

Other, net increased by $117 million primarily due to the penalty recorded in the third quarter of 2016 related to Exelon's like-kind exchange tax position and higher net realized gains on NDT funds at Generation for the three months ended September 30, 2017 as compared to the same period in 2016.

Exelon’s effective income tax rates for the three months ended September 30, 2017 and 2016 were 34.1% and 39.0%, respectively. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for2020. For additional information ~~regarding the components of the effective income tax rates.~~

~~Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016.~~ Exelon’s Net income attributable to common shareholders was $1,899 million for the nine months ended September 30, 2017 as compared to $930 million for the nine months ended September 30, 2016, and diluted earnings per average common share were $2.01 for the nine months ended September 30, 2017 as compared to $1.00 for the nine months ended September 30, 2016.

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~~Table of Contents~~

Revenue net of purchased power and fuel expense, which is a non-GAAP measure discussed below, increased by $598 million for the nine months ended September 30, 2017 as compared to the same period in 2016. The year-over-year increase in Revenue net of purchased power and fuel expense was primarily due to the following favorable factors:

Increase of $96 million at ComEd primarily due to higher electric distribution and transmission formula rate revenues resulting from increased capital investment and higher allowed electric distribution ROE, partially offset by the impact of favorable weather conditions in 2016;

Increase of $83 million at BGE primarily due to the impacts of the electric and natural gas distribution rate increases issued by the MDPSC in June 2016 and July 2016 and an increase in transmission formula rate revenues; and

Increase of $711 million in Revenue net of purchased power and fuel due to the inclusion of PHI's results for the nine months ended September 30, 2017 compared to the period March 24, 2016 to September 30, 2016, as well as distribution rate increases effective in 2016 and 2017.

~~The year-over-year increase in Revenue net of purchased power and fuel expense was partially offset by the following unfavorable factors:~~

Decrease of $180 million at Generation primarily due to the conclusion of the Ginna Reliability Support Services Agreement, the impact of declining natural gas prices on Generation's natural gas portfolio, the impacts of lower load volumes delivered due to mild weather and lower realized energy prices related to Exelon's ratable hedging strategy, partially offset by the impact of the New York CES, increased nuclear volumes primarily as a result of the acquisition of FitzPatrick, the addition of two combined-cycle gas turbines in Texas and the absence of oil inventory write downs in 2017.

~~Decrease of $62 million at PECO primarily due to unfavorable weather conditions; and~~

~~Decrease of $48 million at Generation due to mark-to-market losses of $161 million in 2017 compared to $113 million in 2016.~~

~~Operating and maintenance expense increased by $55 million for the nine months ended September 30, 2017 as compared to the same period in 2016 primarily due to the following unfavorable factors:~~

~~Increase of $288 million at Generation due to higher asset impairment charges;~~

~~Increase of $88 million at Generation due to increased nuclear outage costs;~~

~~Increase in Generation's labor, contracting and materials costs of $74 million primarily due to the acquisition of FitzPatrick beginning on March 31, 2017; and~~

~~Increase of $253 million at PHI due to the inclusion of PHI's results for the nine months ended September 30, 2017 compared to the period March 24, 2016 to September 30, 2016.~~

~~The year-over-year increase in Operating and maintenance expense was partially offset by the following favorable factors:~~

~~Decrease of $589 million at Exelon due to merger commitment and other merger-related costs of $63 million in 2017 compared to $652 million in 2016; and~~

~~Decrease of $56 million at BGE primarily due to certain disallowances contained in the June and July 2016 rate orders.~~

Depreciation and amortization expense decreased by $7 million primarily due to lower accelerated depreciation and amortization expense as a result of the 2017 decision to early retire the TMI nuclear facility compared to the previous decision in 2016 to early retire the Clinton and Quad Cities nuclear facilities, partially offset by increased depreciation expense as a result of ongoing capital expenditures across all operating companies and the inclusion of PHI's results for the nine months ended September 30, 2017 compared to the period March 24, 2016 to September 30, 2016.

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Taxes other than income increased by $145 million primarily due to increased property taxes as a result of the addition of FitzPatrick, increased gross receipts tax expense and increased sales and use tax expense at Generation, as well as the inclusion of PHI's results for the nine months ended September 30, 2017 compared to the period March 24, 2016 to September 30, 2016.

~~Gain on sales of assets decreased by $37 million primarily due to Generation's gain associated with the sale of the New Boston generating site in 2016.~~

~~Bargain purchase gain increased by $233 million due to the gain associated with Generation's acquisition of FitzPatrick in 2017.~~

Interest expense, net increased by $15 million primarily due to additional interest recorded in the second quarter 2017 related to Exelon's like-kind exchange tax position, higher outstanding debt and the inclusion of PHI's results for the nine months ended September 30, 2017 compared to the period March 24, 2016 to September 30, 2016, partially offset by additional interest recorded in the third quarter 2016 related to Exelon's like-kind exchange tax position.

Other, net increased by $348 million primarily due to higher net unrealized and realized gains on NDT funds at Generation for the nine months ended September 30, 2017 as compared to the same period in 2016 and the penalty recorded in 2016 related to Exelon's like-kind exchange tax position.

Exelon’s effective income tax rates for the nine months ended September 30, 2017 and 2016 were 23.5% and 39.1%, respectively. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

~~For further detail~~ regarding the financial results for the three and nine months ended September 30, ~~2017, including explanation of the non-GAAP measure Revenue net of purchased power~~2021 and ~~fuel expense,~~2020 see the discussions of Results of Operations by ~~Segment below.~~Registrant.


	Three Months Ended September 30,				Favorable (unfavorable) variance		Nine Months Ended September 30,				Favorable (unfavorable) variance
	2021		2020				2021		2020
Exelon	$	1,203	$	501	$	702	$	1,315	$	1,604	$	(289)
Generation	607		49		558		(247)		570		(817)
ComEd	220		196		24		609		304		305
PECO	111		138		(27)		383		317		66
BGE	36		53		(17)		290		273		17
PHI	266		216		50		535		418		117
Pepco	130		118		12		264		227		37
DPL	50		27		23		135		91		44
ACE	90		75		15		141		106		35
Other(a)	(37)		(151)		114		(255)		(278)		23

__________

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

Three Months Ended September 30, 2021 Compared to Three Months Ended September 30, 2020. Net income attributable to common shareholders increased by $702 million and diluted earnings per average common share increased to $1.23 in 2021 from $0.51 in 2020 primarily due to:

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•Absence of an impairment in the New England asset group;

•Absence of one time charges recorded in the third quarter of 2020 associated with Generation's decision to early retire the Byron and Dresden nuclear facilitiesand Mystic Units 8 and 9, and the reversal of one-time charges resulting from the reversal of the previous decision to early retire Byron and Dresden on September 15, 2021;

•Higher mark-to-market gains;

•Higher New York ZEC revenues due to higher generation and an increase in ZEC prices;

•Higher electric distribution earnings from higher rate base and higher allowed ROE due to an increase in treasury rates at ComEd; and

•The favorable impacts of the multi-year plan at BGE and regulatory rate increases at DPL and Pepco.

The increases were partially offset by:

•Lower net unrealized and realized gains on NDT funds;

•Decommissioning-related activities that were not offset for the Byron units beginning in the second quarter of 2021 through September 15, 2021. With Generation's September 15, 2021 reversal of the previous decision to retire Byron, Generation resumed contractual offset for Byron as of that date;

•Accelerated depreciation and amortization associated with Generation's previous decision in the third quarter of 2020 to early retire Byron and Dresden nuclear facilities in 2021, a decision which was reversed on September 15, 2021, and Generation's decision in the third quarter of 2020 to early retire Mystic Units 8 and 9 in 2024; and

•Higher net unrealized and realized losses on equity investments.

Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020. Net income attributable to common shareholders decreased by $289 million and diluted earnings per average common share decreased to $1.34 in 2021 from $1.64 in 2020 primarily due to:

•Impacts of the February 2021 extreme cold weather event;

•Impairments at Generation of the New England asset group, the Albany Green Energy biomass facility, and a wind project, partially offset by the absence of an impairment of the New England asset group in the third quarter of 2020; and

•The absence of a prior year one-time tax settlement.

The decreases were partially offset by:

•Higher mark-to-market gains;

•Higher net unrealized and realized gains on NDT funds;

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•Absence of one time charges recorded in the third quarter of 2020 associated with Generation's decision to early retire the Byron and Dresden nuclear facilities and Mystic generating station assets, and the reversal of one-time charges;

•Lower nuclear outage days;

•Higher New York ZEC revenues due to higher generation and an increase in ZEC prices;

•Lower operating and maintenance expense at ComEd due to the payments that ComEd made in 2020 under the Deferred Prosecution Agreement;

•Higher electric distribution earnings from higher rate base and higher allowed ROE due to an increase in treasury rates at ComEd;

•The favorable impacts of the multi-year plan at BGE and regulatory rate increases at Pepco, DPL, and ACE;

•Favorable weather conditions at PECO and DPL's Delaware service territory;

•Favorable volume at PECO; and

•Lower storm costs at PECO and DPL due to the absence of the June 2020 and August 2020 storms, respectively.

Adjusted (non-GAAP) Operating ~~Earnings~~

Exelon’s adjusted (non-GAAP) operating earnings for the three months ended September 30, 2017 were $821 million, or $0.85 per diluted share, compared with adjusted (non-GAAP) operating earnings of $841 million, or $0.91 per diluted share for the same period in 2016. Exelon’s adjusted (non-GAAP) operating earnings for the nine months ended September 30, 2017 were $1,935 million, or $2.05 per diluted share, compared with adjusted (non-GAAP) operating earnings of $2,078 million, or $2.24 per diluted share for the same period in 2016. Earnings. In addition to net income, Exelon evaluates its operating performance using the measure of ~~adjusted~~Adjusted (non-GAAP) operating earnings because management believes it represents earnings directly related to the ongoing operations of the business. Adjusted (non-GAAP) operating earnings exclude certain costs, expenses, gains and losses, and other specified items. This information is intended to enhance an investor’s overall understanding of ~~period-over-period~~year-to-year operating results and provide an indication of Exelon’s baseline operating performance excluding items that are considered by management to be not directly related to the ongoing operations of the business. In addition, this information is among the primary indicators management uses as a basis for evaluating performance, allocating resources, setting incentive compensation targets, and planning and forecasting of future periods. Adjusted (non-GAAP) operating earnings 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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The following tables provide a reconciliation between net income attributable to common shareholders as determined in accordance with GAAP and adjusted (non-GAAP) operating earnings for the three and nine months ended September 30, ~~2017 as~~2021 compared to the same period in ~~2016.~~2020.

152

Three Months Ended September 30,
2017 2016
(All amounts in millions after tax)
Earnings per
Diluted Share

Earnings per
Diluted Share
Net Income Attributable to Common Shareholders $ 824
$ 0.85
$ 490
$ 0.53
Mark-to-Market Impact of Economic Hedging Activities^(a)(net of taxes of $29 and $35, respectively)
(45 ) (0.05 ) (54 ) (0.06 )
Unrealized Gains Related to NDT Fund Investments^(b) (net of taxes of $45 and $48, respectively)
(67 ) (0.07 ) (70 ) (0.07 )
Amortization of Commodity Contract Intangibles^(c) (net of taxes of $8 and $8, respectively)
12
0.01
13
0.01
Merger and Integration Costs^(d)(net of taxes of $1 and $10, respectively)
(1 ) —
13
0.01
Merger Commitments^(e)(net of taxes of $1)
—
—
5
0.01
Long-Lived Asset Impairments^(f)(net of taxes of $16 and $5, respectively)
24
0.03
11
0.01
Plant Retirements and Divestitures^(g)(net of taxes of $47 and $129, respectively)
71
0.08
204
0.22
Cost Management Program^(h)(net of taxes of $8 and $5, respectively)
13
0.01
7
0.01
Like-Kind Exchange Tax Position⁽ⁱ⁾(net of taxes of $61)
—
—
199
0.21
Asset Retirement Obligation^(j) (net of taxes of $1)
(2 ) —
—
—
Bargain Purchase Gain^(k) (net of taxes of $0)
(7 ) (0.01 ) —
—
Reassessment of State Deferred Income Taxes^(l) (entire amount represents tax expense)
(21 ) (0.02 ) —
—
Noncontrolling Interests^(m)(net of taxes of $4 and $5, respectively)
20
0.02
23
0.03
Adjusted (non-GAAP) Operating Earnings $ 821
$ 0.85
$ 841
$ 0.91

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	Three Months Ended September 30,
	2021				2020
(In millions, except per share data)			Earnings per Diluted Share				Earnings per Diluted Share
Net Income Attributable to Common Shareholders	$	1,203	$	1.23	$	501	$	0.51
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $192 and $62, respectively)	(559)		(0.57)		(183)		(0.19)
Unrealized (Gains) Losses Related to NDT Fund Investments (net of taxes of $70 and $161, respectively)(a)	55		0.06		(172)		(0.18)
Asset Impairments (net of taxes of $11 and $126, respectively)(b)	33		0.03		375		0.38
Plant Retirements and Divestitures (net of taxes of $71 and $111, respectively)(c)	211		0.22		329		0.34
Cost Management Program (net of taxes of $1 and $5, respectively)(d)	6		0.01		15		0.02
Change in Environmental Liabilities (net of taxes of $1 and $6, respectively)	4		—		17		0.02
COVID-19 Direct Costs (net of taxes of $1 and $3, respectively)(e)	7		0.01		10		0.01

ERP System Implementation Costs (net of taxes $1)(h)	4		—		—		—
Planned Separation Costs (net of taxes of $10)(i)	27		0.03		—		—
Costs Related to Suspension of Contractual Offset (net of taxes of $33)(j)	107		0.11		—		—
Asset Retirement Obligation (net of taxes of $12 and $1, respectively)(k)	(35)		(0.04)		3		—
Acquisition Related Costs (net of taxes of $2 and $1, respectively)(g)	7		0.01		2		—
Income Tax-Related Adjustments (entire amount represents tax expense)(l)	19		0.02		62		0.06
Noncontrolling Interests (net of taxes of $5 and $12, respectively)(m)	(17)		(0.02)		57		0.06
Adjusted (non-GAAP) Operating Earnings	$	1,070	$	1.09	$	1,017	$	1.04

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Nine Months Ended September 30,
2017 2016
(All amounts in millions after tax)
Earnings per
Diluted Share

Earnings per
Diluted Share
Net Income Attributable to Common Shareholders $ 1,899
$ 2.01
$ 930
$ 1.00
Mark-to-Market Impact of Economic Hedging Activities^(a) (net of taxes of $62 and $46, respectively)
97
0.10
67
0.07
Unrealized Gains Related to NDT Fund Investments^(b)(net of taxes of $137 and $89, respectively)
(211 ) (0.22 ) (127 ) (0.13 )
Amortization of Commodity Contract Intangibles^(c)(net of taxes of $17 and $6, respectively)
27
0.03
8
0.01
Merger and Integration Costs^(d)(net of taxes of $24 and $36, respectively)
39
0.04
92
0.10
Merger Commitments^(e)(net of taxes of $137 and $114, respectively)
(137 ) (0.15 ) 400
0.43
Long-Lived Asset Impairments^(f)(net of taxes of $188 and $67, respectively)
293
0.31
104
0.11
Plant Retirements and Divestitures^(g)(net of taxes of $89 and $214, respectively)
137
0.15
338
0.37
Cost Management Program^(h)(net of taxes of $15 and $17, respectively)
24
0.03
26
0.03
Like-Kind Exchange Tax Position⁽ⁱ⁾(net of taxes of $66 and $61, respectively)
(26 ) (0.03 ) 199
0.21
Asset Retirement Obligation^(j) (net of taxes of $1)
(2 ) —
—
—
Bargain Purchase Gain^(k)(net of taxes of $0)
(233 ) (0.25 ) —
—
Reassessment of State Deferred Income Taxes^(l)(entire amount represents tax expense)
(42 ) (0.04 ) —
—
Tax Settlements⁽ⁿ⁾(net of taxes of $1)
(5 ) (0.01 ) —
—
Noncontrolling Interests^(m)(net of taxes of $16 and $8, respectively)
75
0.08
41
0.04
Adjusted (non-GAAP) Operating Earnings $ 1,935
$ 2.05
$ 2,078
$ 2.24


	Nine Months Ended September 30,
	2021				2020
(In millions, except per share data)			Earnings per Diluted Share				Earnings per Diluted Share
Net Income Attributable to Common Shareholders	$	1,315	$	1.34	$	1,604	$	1.64
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $317 and $112, respectively)	(924)		(0.94)		(329)		(0.34)
Unrealized (Gains) Losses Related to NDT Fund Investments (net of taxes of $24 and $31, respectively)(a)	(32)		(0.03)		8		0.01
Asset Impairments (net of taxes of $135 and $134, respectively)(b)	401		0.41		396		0.40
Plant Retirements and Divestitures (net of taxes of $290 and $117, respectively)(c)	865		0.88		348		0.36
Cost Management Program (net of taxes of $2 and $11, respectively)(d)	10		0.01		34		0.03

Change in Environmental Liabilities (net of taxes of $2 and $6, respectively)	6		0.01		18		0.02
COVID-19 Direct Costs (net of taxes of $9 and $13, respectively)(e)	24		0.02		37		0.04
Deferred Prosecution Agreement Payments (net of taxes of $0)(f)	—		—		200		0.20

ERP System Implementation Costs (net of taxes of $2)(h)	10		0.01		—		—
Planned Separation Costs (net of taxes of $16)(i)	46		0.05		—		—
Costs Related to Suspension of Contractual Offset (net of taxes of $45)(j)	148		0.15		—		—
Asset Retirement Obligation (net of taxes of $12 and $1, respectively)(k))	(35)		(0.04)		3		—
Acquisition Related Costs (net of taxes of $5 and $1, respectively)(g)	15		0.02		2		—
Income Tax-Related Adjustments (entire amount represents tax expense)(l)	15		0.02		66		0.07
Noncontrolling Interests (net of taxes of $2 and $2, respectively)(m)	16		0.02		17		0.02
Adjusted (non-GAAP) Operating Earnings	$	1,879	$	1.92	$	2,403	$	2.46

~~_________~~__________

Note:

Amounts may not sum due to rounding.

Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net Income and Adjusted (non-GAAP) Operating Earnings is based on the marginal statutory federal and state income tax rates for each Registrant, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part. For all items except the unrealized gains and losses related to NDT fund investments, the marginal statutory income tax rates for 2021 and 2020 ranged from ~~39.0 percent~~25.0% to ~~41.0 percent.~~29.0%. Under IRS regulations, NDT fund investment returns are taxed at ~~differing~~different rates for investments if they are in qualified ~~vs.~~or non-qualified funds. The effective tax rates ~~applied to~~for the unrealized gains and losses related to NDT ~~Fund~~fund investments were ~~43.2 percent~~56.2% and ~~46.2 percent~~48.3% for the three months ended September 30, 2021 and 2020, respectively. The effective tax rates for the unrealized gains and losses related to NDT fund investments were 42.4% and 134.1% for the nine months ended September 30, 2021 and 2020, respectively.

(a)Reflects the impact of net unrealized gains and losses on Generation’s NDT fund investments for Non-Regulatory Agreement Units.

(b)In 2021, reflects an impairment in the New England asset group, an impairment recorded as a result of the agreement to sell the Albany Green Energy biomass facility, and an impairment of a wind project at Generation. In 2020, reflects an impairment at ComEd related to the acquisition of transmission assets and an impairment in the New England asset group in the third quarter of 2020.

(c)In 2021, primarily reflects accelerated depreciation and amortization associated with Generation's decisions to early retire Byron, Dresden, and Mystic Units 8 and 9, partially offset by reversal of one-time charges resulting from the reversal of the previous decision to retire Byron and Dresden on September 15, 2021 and a gain on sale of Generation's solar business.

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Depreciation for Byron and Dresden was adjusted beginning September 15, 2021 to reflect the extended useful life estimates. In 2020, primarily reflects one-time charges and accelerated depreciation and amortization expenses associated with Generation’s decisions in the third quarter of 2020 to early retire Byron and Dresden nuclear facilities in 2021 and Mystic Units 8 and 9 in 2024.

(d)Primarily represents reorganization and severance costs related to cost management programs.

(e)Represents direct costs related to COVID-19 consisting primarily of costs to acquire personal protective equipment, costs for cleaning supplies and services, and costs to hire healthcare professionals to monitor the health of employees.

(f)Reflects the payments made by ComEd under the Deferred Prosecution Agreement, which ComEd entered in July 2020 with the U.S. Attorney’s Office for the Northern District of Illinois.

(g)Reflects costs related to the acquisition of EDF's interest in CENG, which was completed in the third quarter of 2021.

(h)Reflects costs related to a multi-year Enterprise Resource Program (ERP) system implementation.

(i)Represents costs related to the planned separation primarily comprised of system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the planned separation, and employee-related severance costs.

(j)Decommissioning-related activities for the former ComEd and PECO units (Regulatory Agreement Units), net of applicable taxes, including realized and unrealized gains and losses on the NDT funds, depreciation of the ARC, and accretion of the decommissioning obligation, are generally offset within Exelon’s and Generation’s consolidated statements of operations. These costs reflect the impact of suspension of contractual offset for the Byron units beginning in the second quarter of 2021 through September 15, 2021. With Generation's September 15, 2021 reversal of the previous decision to retire Byron, Generation resumed contractual offset for Byron as of that date.

(k)For Generation, reflects an adjustment to the nuclear asset obligation for the Non-Regulatory Agreement Units resulting from the annual update in the third quarter of 2021.

(l)Primarily reflects the adjustment to deferred income taxes due to changes in forecasted apportionment.

(m)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 prior to Generation's acquisition of EDF's interest in CENG on August 6, 2021 and the noncontrolling interest portion of a wind project impairment.

Significant 2021 Transactions and Developments

Planned Separation

On February 21, 2021, Exelon’s Board of Directors approved a plan to separate the Utility Registrants and Generation, creating two publicly traded companies with the resources necessary to best serve customers and sustain long-term investment and operating excellence. The separation gives each company the financial and strategic independence to focus on its specific customer needs, while executing its core business strategy.

On February 25, 2021, Exelon and Generation filed applications with FERC, NYPSC, and NRC seeking approvals for the separation of Generation. On March 25, 2021, Exelon filed a request for a private letter ruling with the IRS to confirm the tax-free treatment of the planned separation, which was received on September 23, 2021. On August 24, 2021, Exelon and Generation received approval from FERC for the planned separation. Exelon and Generation expect a decision from the NRC in the fourth quarter of 2021 and have requested a decision from the NYPSC before the end of 2021. Exelon and Generation cannot predict if the remaining applications will be approved as filed.

In connection with the planned separation, Exelon incurred transaction costs of approximately $36 million and $64 million on a pre-tax basis for the three and nine months ended September 30, ~~2017,~~2021, respectively, which are excluded from Adjusted (non-GAAP) Operating Earnings. The transaction costs are primarily comprised of system-related costs, third-party costs paid to advisors, consultants, lawyers, and ~~52.6 percent~~other experts assisting in the planned separation, and ~~52.5 percent~~employee-related severance costs.

There can be no assurance that any separation transaction will ultimately occur or, if one does occur, of its terms or timing. See Note 20 — Planned Separation of the Combined Notes to Consolidated Financial Statements for additional information.

CENG Put Option

EDF had the ~~three~~option to sell its 49.99% equity interest in CENG to Generation exercisable beginning on January 1, 2016 and ~~nine months ended September~~thereafter until June 30, ~~2016, respectively.~~

~~(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~~2022. On November 20, 2019, Generation received notice of EDF’s intention to exercise the put option and sell its 49.99% equity interest in CENG to Generation and the put automatically exercised on January 19, 2020 at the end of the sixty-day advance notice period. On August 6, 2021, Generation and EDF entered into a settlement agreement pursuant to which Generation, through a wholly owned subsidiary, purchased EDF’s equity interest in CENG for a net purchase price of $885 million, which includes, among other things, an adjustment for EDF’s share of the balance of the preferred distribution payable by CENG to ~~Consolidated Financial Statements for additional detail related to Generation’s hedging activities.~~


~~(b)~~	Reflects the impact of net unrealized gains 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)~~	Reflects the non-cash amortization of intangible assets, net, primarily related to commodity contracts recorded at fair value related to the ConEdison Solutions and FitzPatrick acquisitions in 2017, and in 2016, the Integrys and ConEdison Solutions acquisitions.


~~(d)~~	Reflects certain costs incurred for the PHI acquisition in 2017 and 2016 and Generation's FitzPatrick acquisition in 2017, including professional fees, employee-related expenses and integration activities. See Note 4 - Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional detail related to merger and acquisition costs.

~~(e)~~

Represents 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 in 2017, and costs and adjustments incurred as part of the settlement orders approving the PHI acquisition in 2017 and 2016. See Note 4 - Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional detail related to PHI Merger commitments.


~~(f)~~	~~Primarily reflects impairments as a result of the ExGenTexas Power, LLC assets held for sale in 2017 and impairments of Upstream assets and certain wind projects at Generation in 2016.~~

~~(g)~~

Primarily reflects accelerated depreciation and amortization expenses, increases to materials and supplies inventory reserves, charges for severance reserves and construction work in progress impairments associated with Generation's previous decision to early retire the Clinton and Quad Cities nuclear facilities in 2016, partially offset in 2016 by a gain associated with Generation's sale of the New Boston generating site and Generation's decision to early retire the Three Mile Island nuclear facility in 2017.


~~(h)~~	~~Reflects severance and reorganization costs related to a cost management program.~~

~~187~~

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~~(i)~~

~~Represents adjustments to income tax, penalties~~Generation. The difference between the net purchase price and EDF’s noncontrolling interest ~~expenses in 2017~~ as a result of the finalization of the IRS tax computation related to Exelon’s like-kind exchange tax position, and in 2016, the recognition of a penalty and associated interest expense in 2016 as a result of a tax court decision on Exelon’s like-kind exchange tax position.


~~(j)~~	~~Reflects a non-cash benefit pursuant to the annual update of the Generation nuclear decommissioning obligation related to the nonregulatory units.~~


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


~~(l)~~	Reflects the non-cash impact of the remeasurement of state deferred income taxes, primarily as a result of changes in forecasted apportionment related to the PHI acquisition in 2016, and in 2017, changes in the Illinois and District of Columbia statutory tax rates and changes in forecasted apportionment.


~~(m)~~	Represents elimination from Generation’s results of the noncontrolling interest related to certain exclusion items, primarily related to the impact of unrealized gains and losses on NDT fund investments at CENG.


~~(n)~~	~~Reflects benefits related to the favorable settlement in 2017 of certain income tax positions related to PHI's unregulated business interests that were transferred to Generation.~~

~~Merger, Integration and Acquisition Costs~~

~~As a result~~ of the ~~PHI Merger that~~closing date was ~~completed~~recorded to Common Stock in Exelon’s Consolidated Balance Sheet and Membership Interest in Generation’s Consolidated Balance Sheet.

In connection with the settlement agreement, on ~~March 23, 2016,~~August 6, 2021, Generation issued approximately $880 million under a term loan credit agreement to fund the ~~Registrants have incurred costs associated with evaluating, structuring~~transaction, which will expire on August 5, 2022.

See Note 2 – Mergers, Acquisitions, and ~~executing the PHI Merger transaction itself,~~Dispositions and ~~will continue to incur cost associated with meeting the various commitments set forth by regulators~~Note 13 — Debt and ~~agreed-upon with other interested parties as part~~Credit Agreements of the ~~merger approval~~Combined Notes to Consolidated Financial Statements for additional information.

Clean Energy Law

On September 15, 2021, the Illinois Public Act 102-0662 was signed into law by the Governor of Illinois (“Clean Energy Law”). The Clean Energy Law is designed to achieve 100% carbon-free power by 2045 to enable the state’s transition to a clean energy economy. The Clean Energy Law establishes decarbonization requirements for Illinois as well as programs to support the retention and development of emissions-free sources of electricity. Among other things, the Clean Energy Law authorizes the IPA to procure up to 54.5 million CMCs from qualifying nuclear plants for a five-year period beginning on June 1, 2022 through May 31, 2027. CMCs are credits for the carbon-free attributes of eligible nuclear power plants in PJM. The Byron, Dresden, and Braidwood nuclear plants located in Illinois will be eligible to participate in the CMC procurement process and, integrating the former PHI businesses into Exelon. In addition, as a result of the acquisition of the FitzPatrick nuclear generating station on March 31, 2017, Exelon and Generation incurred costs associated with evaluating, structuring, and executing the transaction and integrating FitzPatrick into Exelon.

~~For the three and nine months ended September 30, 2017 and 2016, expense has been recognized for the PHI Merger and Generation's FitzPatrick acquisition as follows:~~

Pre-tax Expense
Three Months Ended September 30, 2017
Merger, Integration and Acquisition Costs:
Exelon^(a)

Generation^(a)
ComEd PECO BGE
PHI^(a)(b)

Pepco^(a)(c)

DPL^(a)

ACE^(a)(d)
Transaction^(e)
$ —
$ —
$ —
$ —
$ —
$ —
$ —
$ —
$ —
Other^(f)
(3 ) 11
—
1
1
(15 ) (8 ) 1
(8 )
Total $ (3 ) $ 11
$ —
$ 1
$ 1
$ (15 ) $ (8 ) $ 1
$ (8 )

Pre-tax Expense
Three Months Ended September 30, 2016
Merger, Integration and Acquisition Costs:
Exelon^(a)

Generation^(a)
ComEd PECO BGE
PHI^(a)

Pepco^(a)

DPL^(a)

ACE^(a)
Transaction^(e)
$ 1
$ —
$ —
$ —
$ —
$ —
$ —
$ —
$ —
Employee-Related^(g)
1
—
—
—
—
1
—
—
—
Other^(f)
21
11
—
2
2
7
3
2
2
Total $ 23
$ 11
$ —
$ 2
$ 2
$ 8
$ 3
$ 2
$ 2

Pre-tax Expense
Nine Months Ended September 30, 2017
Merger, Integration and Acquisition Costs:
Exelon^(a)

Generation^(a)
ComEd PECO BGE
PHI^(a)(b)

Pepco^(a)(c)

DPL^(a)(h)

ACE^(a)(d)
Transaction^(e)
$ 5
$ 4
$ —
$ —
$ —
$ —
$ —
$ —
$ —
Other^(f)
57
67
1
3
3
(17 ) (6 ) (6 ) (6 )
Total $ 62
$ 71
$ 1
$ 3
$ 3
$ (17 ) $ (6 ) $ (6 ) $ (6 )

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Pre-tax Expense
Nine Months Ended September 30, 2016
Merger, Integration and Acquisition Costs:
Exelon^(a)

Generation^(a)

ComEd⁽ⁱ⁾
PECO
BGE^(j)

PHI^(a)(b)

Pepco^(a)(c)

DPL^(a)(h)

ACE^(a)
Transaction^(e)
$ 36
$ —
$ —
$ —
$ —
$ —
$ —
$ —
$ —
Employee-Related^(g)
74
10
1
1
1
61
29
17
14
Other^(f)
16
21
(8 ) 3
(3 ) 2
(3 ) 1
3
Total $ 126
$ 31

$ (7 )
$ 4

$ (2 ) $ 63
$ 26
$ 18
$ 17

~~_________~~


~~(a)~~	~~For Exelon, Generation, PHI, Pepco, DPL, and ACE, includes the operations of the acquired businesses beginning on March 24, 2016.~~

~~(b)~~

~~(c)~~


~~(d)~~	For the three and nine months ended September 30, 2017, includes the reversal of previously incurred acquisition, integration and financing costs of $8 million incurred at ACE that have been deferred and recorded as a regulatory asset for anticipated recovery. See Note 5—Regulatory Matters for more information.


~~(e)~~	External, third party costs paid to advisors, consultants, lawyers and other experts to integrate PHI processes and systems into Exelon, to assist in the due diligence and regulatory approval processes and in the closing of transactions.


~~(f)~~	~~Costs to integrate PHI processes and systems into Exelon. For the three and nine months ended September 30, 2017, also includes costs to integrate FitzPatrick processes and systems into Exelon.~~


~~(g)~~	~~Costs primarily for employee severance, pension and OPEB expense and retention bonuses.~~

~~(h)~~


~~(i)~~	For the nine months ended September 30, 2016, includes the reversal of previously incurred acquisition, integration and financing costs of $8 million, incurred at ComEd that have been deferred and recorded as a regulatory asset for anticipated recovery. See Note 5—Regulatory Matters for more information.


~~(j)~~	For the nine months ended September 30, 2016, includes the reversal of previously incurred acquisition, integration and financing costs of $6 million incurred at BGE that have been deferred and recorded as a regulatory asset for anticipated recovery. See Note 5—Regulatory Matters for more information.

As of September 30, 2017, Exelon expects to incur total PHI acquisition and integration related costs of approximately $700 million, excluding merger commitments. Of this amount, including costs incurred from 2014 through September 30, 2017, Exelon and PHI have incurred approximately $675 million.

~~Significant 2017 Transactions and Developments~~

~~Early Retirement of Three Mile Island Facility~~

On May 30, 2017, Generation announced it will permanently cease generation operations at Three Mile Island Generating Station (TMI) on or about September 30, 2019. The TMI nuclear plant did not clear in the May 2017 PJM capacity auction for the 2020-2021 planning year and will not receive capacity revenue for that period, the third consecutive year that TMI failed to clear the PJM base residual capacity auction. The plant is currentlyif awarded contracts, would be committed to operate through May ~~2019. In 2017, as a result~~31, 2027. Selected generators will by December 3, 2021 contract directly with ComEd for the procurement of the ~~plant retirement~~CMCs based upon the number of MWhs produced annually by the eligible facilities, subject to specified caps and minimum performance requirements. ComEd is required to purchase CMCs from eligible nuclear facilities and all its costs of doing so will be recovered through a new rider.

Following enactment of the Clean Energy Law, Generation announced on September 15, 2021, that it has reversed its previous decision to retire Byron and Dresden given the opportunity for additional revenue. In addition, Generation no longer considers the Braidwood or LaSalle nuclear plants to be at risk for premature retirement. See Note 7 – Early Plant Retirements for additional information and Early Retirement of ~~TMI,~~Generation Facilities below.

The Clean Energy Law also contains requirements associated with ComEd’s transition away from the performance-based electric distribution formula rate. The law authorizing that rate setting process sunsets at the end of 2022. The Clean Energy Law, and tariffs adopted under it, governs both the remaining reconciliations of rates set under that process and requires ComEd to file in 2023 its choice of either a general rate case or a four-year multi-year plan to set rates that take effect in 2024. If ComEd elects to file a multi-year plan, that plan would set rates for 2024 – 2027, based on forecasted revenue requirements and an ICC determined rate of return on rate base, including the cost of common equity. See Note 3 – Regulatory Matters for additional information and other features of the Clean Energy Law.

Early Retirement of Generation Facilities

In August 2020, Generation announced that it intended to retire the Byron Generating Station in September 2021, Dresden Generating Station in November 2021, and Mystic Units 8 and 9 at the expiration of the cost of service commitment in May 2024. As a result, Exelon and Generation recognized certain one-time charges in ~~Operating~~the third and ~~maintenance expense~~fourth quarters of $76 million related to materials and supplies inventory reserve adjustments, employee-related costs and construction work-in-progress (CWIP) impairments, among other items. In addition to these one-time charges,2020.Further, there ~~will be~~were ongoing annual ~~incremental non-cash charges to earnings~~financial impacts stemming from shortening the expected economic useful ~~life~~lives of ~~TMI~~these facilities, primarily related to accelerated depreciation of plant assets (including any ~~asset retirement costs (ARC)),~~ARC) and accelerated amortization of nuclear ~~fuel,~~fuel.

Also, as a result, in the third quarter of 2020, Exelon and Generation recognized a $500 million pre-tax impairment for the New England asset group. In the second quarter of 2021, an incremental decline in value resulted in an additional pre-tax impairment charge of $350 million for the New England asset ~~retirement obligation (ARO) accretion expense~~group.

Further, in the second quarter and third quarter of 2021, Exelon and Generation recorded a pre-tax charge of $53 million and $140 million, respectively for decommissioning-related activities that were not offset for the Byron units due to the inability to recognize a regulatory asset at ComEd.

All of the charges above were excluded from Exelon's and Generation’s Adjusted (non-GAAP) Operating Earnings.

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On September 15, 2021, Generation reversed its previous decision to early retire Byron and Dresden and updated the expected economic useful life for both facilities to 2044 and 2046 for Byron Units 1 and 2, respectively, and to 2029 and 2031 for Dresden Units 2 and 3, respectively. Depreciation was therefore adjusted beginning September 15, 2021, to reflect these extended useful life estimates. In addition, in the third quarter of 2021, Exelon and Generation reversed approximately $81 million of severance benefit costs and $13 million of other one-time charges initially recorded in the third and fourth quarters of 2020 associated with the ~~changes~~early retirements, which were excluded from Exelon's and Generation’s Adjusted (non-GAAP) Operating Earnings.

The following table summarizes the incremental expense for Byron, Dresden, and Mystic Units 8 and 9 and the reversal of one-time charges for Byron and Dresden recorded in ~~decommissioning timing and cost assumptions. During~~ the three and nine months ended September 30, ~~2017, both Exelon’s~~2021. For Mystic Units 8 and ~~Generation’s results include an~~9, the projected amounts for the remainder of 2021 and through the retirement date of 2024 are not expected to be material.


Income statement expense (pre-tax)	Three Months Ended September 30, 2021		Nine Months Ended September 30, 2021
Depreciation and amortization
Accelerated depreciation(a)	$	574	$	1,845
Accelerated nuclear fuel amortization	42		148
Operating and maintenance
Reversal of one-time charges	(94)		(94)
Other charges	4		8

Contractual offset(b)	(60)		(451)
Total	$	466	$	1,456

__________

(a)Reflects incremental ~~$112 million~~accelerated depreciation of plant assets, including any ARC.

(b)Reflects contractual offset for ARO accretion, ARC depreciation, and ~~$149 million, respectively, of pre-tax expense for these items.~~

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~~The following table summarizes~~net impacts associated with the ~~estimated annual amount and timing of expected incremental non-cash expense items through 2019.~~

September 30, 2017
Projected^(a)
Income statement expense (pre-tax) 2017 2018 2019
Depreciation and Amortization
Accelerated depreciation^(b)
$ 141
$ 250
$ 430
$ 325
Accelerated nuclear fuel amortization 8
10
20
5
Total $ 149
$ 260
$ 450
$ 330

~~_________~~


~~(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 of plant assets, including any ARC.~~

~~EGTP Consent Agreement~~

~~In September 2014, EGTP, an indirect subsidiary of Exelon and Generation, issued $675 million~~ aggregate principal amount of a nonrecourse senior secured term loan. EGTP’s operating cash flows have been negatively impacted by certain market conditions and the seasonality of its cash flows. On May 2, 2017, EGTP entered into a consent agreement with its lenders to permit EGTP to draw on its revolving credit facility and initiate an orderly sales process to sell the assets of its wholly owned subsidiaries, the proceeds from which will first be used to pay the administrative costsremeasurement of the ~~sale,~~ARO for Byron and Dresden and exclude any changes in earnings in the ~~normal and ordinary costs of operating~~NDT funds. Decommissioning-related activities were not offset for the ~~plants and repayment of the secured debt of EGTP, including the revolving credit facility. As a result,~~Byron units starting in the second quarter ~~2017, Exelon and~~of 2021 due to the inability to recognize a regulatory asset at ComEd. With Generation’s September 15, 2021 reversal of the previous decision to retire Byron, Generation ~~classified certain EGTP assets and liabilities~~resumed contractual offset for Byron as of that date. Based on ~~Exelon’s and Generation’s Consolidated Balance Sheets as held for sale at their respective fair values less costs to sell and included~~the regulatory agreement with the ICC, decommissioning-related activities are offset in the other current assets and other current liabilities balances on Exelon's and Generation's Consolidated Balance Sheets. For the three and nine months ended September 30, 2017, a $40 million and $458 million pre-tax impairment loss was recorded within Operating and maintenance expense on Exelon's and Generation's Consolidated Statements of Operations and Comprehensive ~~Income.~~ Income as long as the net cumulative decommissioning-related activities result in a regulatory liability at ComEd. Recognition of a regulatory asset for nuclear decommissioning-related activities at ComEd is not permissible. The offset results in an equal adjustment to the noncurrent payables to ComEd at Generation and an adjustment to the regulatory liabilities at ComEd.

See Note ~~4 - Mergers, Acquisitions and Dispositions,~~7 — Early Plant Retirements, Note ~~6 - Impairment of Long-Lived Assets~~8 — Nuclear Decommissioning, and Note 119 - ~~Debt and Credit Agreements for more information~~Asset Impairments of the Combined Notes to Consolidated Financial Statements for additional ~~information regarding EGTP~~information.

Impacts of the February 2021 Extreme Cold Weather Event and Texas-based Generating Assets Outages

The estimated impact to Exelon’s and Generation’s Net income for the nine months ended September 30, 2021 arising from these market and weather conditions was a reduction of approximately $880 million. The estimated impact to Exelon's and Generation's Net income for the three months ended September 30, 2021 was not material. The nine months ended estimated impact includes certain charges associated ~~nonrecourse debt.~~with the natural gas business that may be reduced through waivers and/or recoveries from customers. Therefore, such charges are not included in the estimated full year earnings impact. Exelon and Generation estimate a reduction in Net income of approximately $670 million to $820 million for the full year 2021. The ultimate impact to Exelon’s and Generation’s consolidated financial statements may be affected by a number of factors, the impacts of customer and counterparty credit losses, any state or federal solutions to address the financial challenges caused by the event, and related litigation and contract disputes. See Note 3 — Regulatory Matters and Note 15 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.

~~Acquisition~~

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Table of ~~James A. FitzPatrick Nuclear Generating Station~~Contents

Exelon expects to offset between $410 million and $490 million of this impact for the full year 2021 primarily at Generation through a combination of enhanced revenue opportunities, deferral of selected non-essential maintenance, and primarily one-time cost savings.

Agreement for the Sale of a Generation Biomass Facility

On ~~March 31, 2017,~~April 28, 2021, Generation ~~acquired~~and ReGenerate entered into a purchase agreement, under which ReGenerate agreed to purchase Generation's interest in the ~~838 MW single-unit James A. FitzPatrick (FitzPatrick) nuclear generating station for~~Albany Green Energy biomass facility. As a ~~total purchase price~~result, in the second quarter of ~~$289 million. In accounting for the acquisition as a business combination,~~2021, Exelon and Generation recorded ~~an after-tax bargain purchase gain~~a pre-tax impairment charge of ~~$233~~$140 million which is ~~included within Exelon's~~excluded from Exelon’s and ~~Generation's Consolidated Statements~~Generation’s Adjusted (non-GAAP) Operating Earnings. The sale was completed on June 30, 2021 for a net purchase price of ~~Operations and Comprehensive Income.~~$36 million. See Note ~~4 -~~2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to ~~the~~ Consolidated Financial Statements for additional ~~information regarding the Generation's acquisition of FitzPatrick and related costs.~~

~~Illinois Future Energy Jobs Act~~

On December 7, 2016, FEJA was signed into law by the Governor of Illinois. FEJA was effective June 1, 2017, and includes, among other provisions, (1) a Zero Emission Standard (ZES) providing compensation for certain nuclear-powered generating facilities, (2) an extension of and certain adjustments to ComEd’s electric distribution formula rate, (3) new cumulative persisting annual energy efficiency MWh savings goals for ComEd, (4) revisions to the Illinois RPS requirements, (5) provisions for adjustments to or termination of FEJA programs if the average impact on ComEd’s customer rates exceeds specified limits, (6) revisions to the existing net metering statute and (7) support for low income rooftop and community solar programs. FEJA establishes new or adjusts existing rate recovery mechanisms for ComEd to recover costs associated with the new or expanded energy efficiency and RPS requirements. Regulatory or legal challenges over the validity of FEJA are possible. See Note 5 - Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for additional information regarding FEJA. See Note 7 - Early Nuclear Plant Retirements of the Combined Notes to the Consolidated Financial Statements for additional information regarding the economic challenges facing Generation's Clinton and Quad Cities nuclear plants and the expected benefits of the ZES.

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~~Table of Contents~~

~~Dismissal of Litigation Challenging ZEC Programs~~

On July 14, 2017, the U.S. District Court for the Northern District of Illinois dismissed two lawsuits challenging the ZEC program contained in FEJA. On July 17, 2017, the plaintiffs appealed the court’s decisions to the U.S. Court of Appeals for the Seventh Circuit. Plaintiffs-Appellants initial brief was filed on August 28, 2017 and the state’s and Exelon’s briefs were filed on October 27, 2017. Reply briefs are due on December 12, 2017.

Additionally, on July 25, 2017, the U.S. District Court for the Southern District of New York dismissed a lawsuit challenging the ZEC program contained in the New York CES. On August 24, 2017, the plaintiffs appealed the decision to the Second Circuit. Plaintiffs-Appellants’ initial brief was filed on October 13 and the state’s and Exelon’s briefs are due on November 17, 2017. Reply briefs are due on December 1, 2017.

These court decisions uphold the ZEC programs which support Illinois’s and New York’s efforts to advance clean energy and preserve affordable and reliable energy resources for customers. See Note 5 - Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for additional information regarding FEJA and the New York CES.

~~Merger Commitment Unrecognized Tax Benefits~~

Exelon established a liability for an uncertain tax position associated with the tax deductibility of certain merger commitments incurred by Exelon in connection with the acquisitions of Constellation in 2012 and PHI in 2016. In the first quarter 2017, as a part of its examination of Exelon’s return, the IRS National Office issued guidance concurring with Exelon’s position that the merger commitments were deductible. As a result, Exelon, Generation, PHI, Pepco, DPL, and ACE decreased their liability for unrecognized tax benefits by $146 million, $19 million, $59 million, $21 million, $16 million, and $22 million, respectively, as of September 30, 2017, resulting in a benefit to Income taxes on Exelon’s, Generation’s, PHI’s, Pepco’s, DPL’s and ACE’s Consolidated Statements of Operations and Comprehensive Income and corresponding decreases in their effective tax rates.

~~Combined-Cycle Gas Turbine Projects~~

In June 2017, Generation commenced commercial operations of two new combined-cycle gas turbines (CCGTs) at the Colorado Bend and Wolf Hollow Generating Stations in Texas. The two new CCGTs have added nearly 2,200 MWs of capacity to Generation’s fleet, enhancing Generation’s strategy to match generation to customer load. Generation invested approximately $1.5 billion over the past three years to complete the new plant construction, which utilizes new General Electric technology to make them among the cleanest, most efficient CCGTs in the nation.information.

Utility Rates and Base Rate Proceedings

The Utility Registrants file base rate cases with their regulatory commissions seeking increases or decreases to their electric transmission and distribution, and gas distribution rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Utility Registrants’ current and future ~~results of operations, cash flows and~~ financial ~~position.~~

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~~Table of Contents~~

statements.

The following tables show the Utility Registrants’ completed and pending distribution base rate case proceedings in ~~2017.~~

~~Completed Distribution Rate Case Proceedings~~

Company Jurisdiction
Approved Revenue Requirement Increase
(in millions)
Approved Return on Equity Completion Date Rate Effective Date
DPL Maryland (Electric) $ 38
9.6 % February 15, 2017 February 15, 2017
DPL Delaware (Electric) $ 31.5
9.7 % May 23, 2017 June 1, 2017
DPL Delaware (Natural Gas) $ 4.9
9.7 % June 6, 2017 July 1, 2017
Pepco District of Columbia (Electric) $ 37
9.5 % July 25, 2017 August 15, 2017
ACE New Jersey (Electric) $ 43
9.6 % September 22, 2017 October 1, 2017
Pepco Maryland (Electric) $ 32
9.5 % October 27, 2017 October 20, 2017

~~Pending Distribution Rate Case Proceedings~~

Company Jurisdiction
Requested Revenue Requirement Increase
(in millions)
Requested Return on Equity Filing Date Expected Completion Timing
ComEd
Illinois (Electric)^(a)
$ 96
^(b)
8.4 %
^(c)
April 13, 2017 Fourth quarter 2017
DPL Maryland (Electric) $ 22
10.1 % July 14, 2017 (Updated on September 28, 2017) First quarter 2018
DPL Delaware (Electric) $ 31
10.1 % August 17, 2017 (Updated on October 18, 2017) Third quarter 2018
DPL Delaware (Natural Gas) $ 13
10.1 % August 17, 2017 Third quarter 2018

~~________~~

~~(a)~~

Pursuant to EIMA, ComEd’s electric distribution rates are established through a performance-based formula through which ComEd is required to file an annual update on or before May 1, with resulting rates effective in January of the following year. ComEd’s annual electric distribution formula rate update is based on prior year actual costs and current year projected capital additions (initial year revenue requirement). The update also reconciles any differences between the revenue requirement in effect for the prior year and actual costs incurred for the year (annual reconciliation).


~~(b)~~	~~Reflects an increase of $78 million for the initial revenue requirement for 2017 and an increase of $18 million related to the annual reconciliation.~~

~~(c)~~

ComEd’s allowed ROE under its electric distribution formula rate is the annual average rate on 30-year treasury notes plus 580 basis points and is subject to reduction if ComEd does not deliver certain reliability and customer service benefits. The initial revenue requirement for 2017 reflects an allowed ROE of 8.40%, while the annual reconciliation reflects an allowed ROE of 8.34%, which is inclusive of a 6 basis point performance penalty.

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~~Transmission Formula Rates~~

~~The following total increases/(decreases) were included in ComEd’s, BGE’s, Pepco's, DPL's and ACE's 2017 annual electric transmission formula rate filings:~~

~~_________~~


~~(a)~~	~~All rates are effective June 2017, subject to review by the FERC and other parties, which is due by fourth quarter 2017.~~


~~(b)~~	~~BGE's transmission revenues include a FERC approved dedicated facilities charge to recover the costs of providing transmission service to specifically designated load by BGE.~~


~~(c)~~	~~Represents the weighted average debt and equity return on transmission rate bases.~~

~~(d)~~

~~PECO Transmission Formula Rate~~

On May 1, 2017, PECO filed a request with FERC seeking approval to update its transmission rates and change the manner in which PECO’s transmission rate is determined from a fixed rate to a formula rate. The formula rate would be updated annually to ensure that under this rate customers pay the actual costs of providing transmission services. The formula rate filing includes a requested increase of $22 million to PECO’s annual transmission revenues and a requested rate of return on common equity of 11%, inclusive of a 50 basis point adder for being a member of a regional transmission organization. PECO requested that the new transmission rate be effective as of July 2017. On June 27, 2017, FERC issued an Order accepting the filing and suspending the proposed rates until December 1, 2017, subject to refund, and set the matter for hearing and settlement judge procedures. PECO cannot predict the final outcome of the settlement or hearing proceedings, or the transmission formula FERC may approve.

2021. See Note ~~5 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for further details on these regulatory proceedings.~~

~~Westinghouse Electric Company LLC Bankruptcy~~

On March 29, 2017, Westinghouse Electric Company LLC (Westinghouse) and its affiliated debtors filed petitions for relief under Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of New York. In the petitions and supporting documents, Westinghouse makes clear that its requests for relief center on one business area that is losing money3 — the construction of nuclear power plants in Georgia and South Carolina. Through the bankruptcy, Westinghouse seeks to reorganize around its profitable core business, which includes nuclear fuel fabrication and related services and other services provided to existing nuclear power plants in the U.S. and around the world. For these reasons, at this time, Generation does not anticipate disruption to the Westinghouse fuel fabrication contracts for Braidwood, Byron, or Ginna or other existing contracts for Generation's nuclear power plants. Generation is monitoring the bankruptcy proceeding to ensure that its rights are protected.

~~ExGen Renewables Holdings, LLC Transaction~~

On July 6, 2017, ExGen Renewables Holdings, LLC, a wholly owned subsidiary of Generation, completed the sale of a 49% interest of ExGen Renewables Partners, LLC, a newly formed owner and operator of approximately 1,296 megawatts of Generation's operating wind and solar electric generating facilities. ExGen Renewables Holdings will be the managing member of ExGen Renewables Partners, LLC, and have day-to-day control and management

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over its renewable generation portfolio. The closing of the transaction was subject to certain regulatory approvals, including the Federal Energy Regulatory Commission (FERC) and the Public Utility Commission of Texas (PUCT) which were received during the second quarter of 2017. The sale price was $400 million plus immaterial working capital and other customary post-closing adjustments. The net proceeds, after approximately $100 million of income taxes, will be used to pay down debt and for general corporate purposes. Generation will continue to consolidate ExGen Renewables Partners, LLC and will record a noncontrolling interest on its Consolidated Balance Sheet for the investor's initial equity share as well as earnings attributable to the noncontrolling interest in the Consolidated Statements of Operations and Comprehensive Income each period going forward.

~~Hurricanes Harvey, Irma and Maria Impacts~~

Although Exelon subsidiaries provided substantial assistance to recovery efforts following Hurricanes Harvey and Irma, Hurricanes Harvey, Irma and Maria are not expected to have a material impact on the Registrants’ businesses or financial results given the limited operations in the areas affected by the storms.

~~Exelon’s Strategy and Outlook for 2017 and Beyond~~

Exelon’s value proposition and competitive advantage come from its scope and its core strengths of operational excellence and financial discipline. Exelon leverages its integrated business model to create value. Exelon’s regulated and competitive businesses feature a mix of attributes that, when combined, offer shareholders and customers a unique value proposition:

~~Exelon’s utilities 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.~~

~~Exelon believes its strategy provides a platform for optimal success in an energy industry experiencing fundamental and sweeping change.~~

Exelon’s utility strategy is to improve reliability and operations and enhance the customer experience, while ensuring ratemaking mechanisms provide the utilities fair financial returns. The Exelon utilities only invest in rate base where it provides a benefit to customers and the community by improving reliability and the service experience or otherwise meeting customer needs. The Exelon utilities make these investments at the lowest reasonable cost to customers. Exelon seeks to leverage its scale and expertise across the utilities platform through enhanced standardization and sharing of resources and best practices to achieve improved operational and financial results. Additionally, the Utility Registrants anticipate making significant future investments in smart meter technology, transmission projects, gas infrastructure, and electric system improvement projects, providing greater reliability and improved service for our customers and a stable return for the company.

Generation’s competitive businesses create value for customers by providing innovative energy solutions and reliable, clean and affordable energy. Generation’s electricity generation strategy is to pursue opportunities that provide stable revenues and generation to load matching to reduce earnings volatility. Generation leverages its energy generation portfolio to deliver energy to both wholesale and retail customers. Generation’s customer-facing activities foster development and delivery of other innovative energy-related products and services for its customers. Generation operates in well-developed energy markets and employs an integrated hedging strategy to manage commodity price volatility. Its generation fleet, including its nuclear plants which consistently operate at high capacity factors, also provide geographic and supply source diversity. These factors help Generation mitigate the current challenging conditions in competitive energy markets.

Exelon’s financial priorities are to maintain investment grade credit metrics at each of the Registrants, to maintain optimal capital structure and to return value to Exelon’s shareholders with an attractive dividend throughout the energy commodity market cycle and through stable earnings growth. Exelon's Board of Directors has approved a dividend policy providing a raise of 2.5% each year for three years, beginning with the June 2016 dividend.

Various market, financial, regulatory, legislative and operational factors could affect the Registrants' success in pursuing their strategies. Exelon continues to assess infrastructure, operational, commercial, policy, and legal solutions to these issues. One key issue is ensuring the ability to properly value nuclear generation assets in the market, solutions

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~~to which Exelon is actively pursuing in a variety of jurisdictions and venues. See ITEM 1A. RISK FACTORS of the Exelon 2016 Form 10-K for additional information regarding market and financial factors.~~

Continually optimizing the cost structure is a key component of Exelon’s financial strategy. In a cost management program initiated late in 2015, the company committed to reducing operation and maintenance expenses and capital costs by approximately $350 million and $50 million, respectively, of which approximately 35% of run-rate savings was achieved by the end of 2016. Approximately 60% of run-rate savings are expected to be achieved by the end of 2017 and fully realized in 2018. At least 75% of the savings are expected to be related to Generation, with the remaining amount related to the Utility Registrants.

In November 2017, Exelon announced the elimination of approximately $250 million of annual ongoing costs, primarily at Generation, by 2020. This announcement is a result of Exelon’s continuous focus on improving its cost profile through enhanced efficiency and productivity. These cost reductions result in a cost profile that better aligns with current market conditions. The targeted cost savings are incremental to the expected savings from previous cost management initiatives.

~~Growth Opportunities~~

~~Management continually evaluates growth opportunities aligned with Exelon’s businesses, assets and markets, leveraging Exelon’s expertise in those areas and offering sustainable returns.~~

~~Regulated Energy Businesses~~. The PHI merger provides an opportunity to accelerate Exelon’s regulated growth to provide stable cash flows, earnings accretion, and dividend support. Additionally, the Utility Registrants anticipate investing approximately $25 billion over the next five years in electric and natural gas infrastructure improvements and modernization projects, including smart meter and smart grid initiatives, storm hardening, advanced reliability technologies, and transmission projects, which is projected to result in an increase to current rate base of approximately $9 billion by the end of 2021. The Utility Registrants invest in rate base where beneficial to customers and the community by increasing reliability and the service experience or otherwise meeting customer needs. These investments are made at the lowest reasonable cost to customers.

~~See Note 5—~~Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on ~~the Smart Meter~~these and ~~Smart Grid Initiatives and infrastructure development and enhancement programs.~~other regulatory proceedings.

~~Competitive Energy Businesses~~.Generation continually assesses the optimal structure and composition of its generation assets as well as explores wholesale and retail opportunities within the power and gas sectors. Generation’s long-term growth strategy is to ensure appropriate valuation of its generation assets, in part through public policy efforts, identify and capitalize on opportunities that provide generation to load matching as a means to provide stable earnings, and identify emerging technologies where strategic investments provide the option for significant future growth or influence in market development. As of September 30, 2017, Generation has currently approved plans to invest a total of approximately $300 million through 2018 to complete new plant construction currently in progress.Completed Distribution Base Rate Case Proceedings

~~Liquidity Considerations~~

Each of the Registrants annually evaluates its financing plan, dividend practices and credit line sizing, focusing on maintaining its investment grade ratings while meeting its cash needs to fund capital requirements, retire debt, pay dividends, fund pension and OPEB obligations and invest in new and existing ventures. A broad spectrum of financing alternatives beyond the core financing options can be used to meet its needs and fund growth including monetizing assets in the portfolio via project financing, asset sales, and the use of other financing structures (e.g., joint ventures, minority partners, etc.). The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs and capital expenditure requirements.

Exelon, Generation, ComEd, PECO, BGE, Pepco, DPL and ACE have unsecured syndicated revolving credit facilities with aggregate bank commitments of $0.6 billion, $5.3 billion, $1 billion, $0.6 billion, $0.6 billion, $0.3 billion, $0.3 billion and $0.3 billion, respectively. Generation also has bilateral credit facilities with aggregate maximum availability of $0.5 billion. See Liquidity and Capital Resources - Credit Matters - Exelon Credit Facilities below.

~~For further detail regarding the Registrants' liquidity for the nine months ended September 30, 2017, see Liquidity and Capital Resources discussion below.~~


Registrant/Jurisdiction	Filing Date	Service	Requested Revenue Requirement (Decrease) Increase		Approved Revenue Requirement (Decrease) Increase		Approved ROE		Approval Date	Rate Effective Date
ComEd - Illinois	April 16, 2020	Electric	$	(11)	$	(14)	8.38	%	December 9, 2020	January 1, 2021
PECO - Pennsylvania	September 30, 2020	Natural Gas	69		29		10.24	%	June 22, 2021	July 1, 2021
BGE - Maryland	May 15, 2020 (amended September 11, 2020)	Electric	203		140		9.50	%	December 16, 2020	January 1, 2021
		Natural Gas	108		74		9.65	%
Pepco - District of Columbia	May 30, 2019 (amended June 1, 2020)	Electric	136		109		9.275	%	June 8, 2021	July 1, 2021
Pepco - Maryland	October 26, 2020 (amended March 31, 2021)	Electric	104		52		9.55	%	June 28, 2021	June 28, 2021
DPL - Delaware	March 6, 2020 (amended February 2, 2021)	Electric	23		14		9.60	%	September 15, 2021	October 6, 2020
ACE - New Jersey	December 9, 2020 (amended February 26, 2021)	Electric	67		41		9.60	%	July 14, 2021	January 1, 2022

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Pending Distribution Base Rate Case Proceedings

~~Project Financing~~

Registrant/Jurisdiction

Filing Date

Service

Requested Revenue Requirement Increase

Requested ROE

Expected Approval Timing

ComEd - Illinois

April 16, 2021

Electric

7.36

Fourth quarter of 2021

PECO - Pennsylvania

March 30, 2021

Electric

246

10.95

Fourth quarter of 2021

DPL - Maryland

September 1, 2021

Electric

10.10

First quarter of 2022

Generation utilizes individual project financings as a means to finance the construction of various generating asset projects. Project financing is based upon a nonrecourse financial structure, in which project debt and equity used to finance the project are paid back from the cash generated by the newly constructed asset once operational. Borrowings under these agreements are secured by the assets and equity of each respective project. Transmission Formula Rates

The ~~lenders do not have recourse against Exelon or Generation~~following total increases/(decreases) were included in the event of a default. If a specific project financing entity does not maintain compliance with its specific debt financing covenants, there could be a requirement to accelerate repayment of the associated debt or other project-related borrowings earlier than the stated maturity dates. In these instances, if such repayment was not satisfied, or restructured, the lenders or security holders would generally have rights to foreclose against the project-specific assets and related collateral. The potential requirement to satisfy its associated debt or other borrowings earlier than otherwise anticipated could lead to impairments due to a higher likelihood of disposing of the respective project-specific assets significantly before the end of their useful lives.Utility Registrants' 2021 electric transmission formula rate updates. See Note ~~6 Impairment of Long-Lived Assets and Note 11 - Debt and Credit Agreements~~3 — Regulatory Matters of the Combined Notes to ~~the~~ Consolidated Financial Statements for additional ~~information on nonrecourse debt.~~information.


Registrant	Initial Revenue Requirement Increase (Decrease)		Annual Reconciliation Increase		Total Revenue Requirement Increase		Allowed Return on Rate Base		Allowed ROE
ComEd	$	33	$	12	$	45	8.20	%	11.50	%
PECO	(2)		26		24		7.37	%	10.35	%
BGE	38		27		65		7.35	%	10.50	%
Pepco	(9)		21		12		7.68	%	10.50	%
DPL	19		33		52		7.20	%	10.50	%
ACE	27		24		51		7.45	%	10.50	%

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Other Key Business Drivers and Management Strategies

~~Power Markets~~

~~Price~~The following discussion of ~~Fuels~~

~~The use~~other key business driver and management strategies includes current developments of previously disclosed matters and new ~~technologies to recover natural gas from shale deposits is increasing natural gas supply~~issues arising during the period that may impact future financial statements. This section should be read in conjunction with ITEM 1. Business and ~~reserves, which places downward pressure on natural gas prices~~ITEM 7. Management's Discussion and ~~therefore, on wholesale~~Analysis of Financial Condition and retail power prices, which results in a reduction in Exelon’s revenues. Forward natural gas prices have declined significantly over the last several years; in part reflecting an increase in supply due to strong natural gas production (due to shale gas development).

~~Capacity Market Changes in PJM~~

~~In the wake~~Results of ~~the January 2014 Polar Vortex that blanketed much of the Eastern~~Operations — Other Key Business Drivers and Midwestern United States, it became clear that while a major outage event was narrowly avoided, resources in PJM were not providing the level of reliability expected by customers. As a result, on December 12, 2014, PJM filed at FERC a proposal to make significant changes to its current capacity market construct, the Reliability Pricing Model (RPM). PJM’s proposed changes generally sought to improve resource performance and reliability largely by limiting the excuses for non-performance and by increasing the penalties for performance failures. The proposal permits suppliers to include in capacity market offers additional costs and risk so they can meet these higher performance requirements. While offers are expected to put upward pressure on capacity clearing prices, operational improvements made as a result of PJM’s proposal are expected to improve reliability, to reduce energy production costs as a result of more efficient operations and to reduce the need for out of market energy payments to suppliers. Generation participated actively in PJM’s stakeholder process through which PJM developed the proposal and also actively participatedManagement Strategies in the FERC proceeding including filing comments. On June 9, 2015, FERC approved PJM's filing largely as proposed by PJM, including transitional auction rules for delivery years 2016/2017 through 2017/2018. As a result of thisRegistrants' combined 2020 Form 10-K and ~~several related orders, PJM hosted its 2018/2019 Base Residual Auction (results posted on August 21, 2015)~~Note 15 — Commitments and its transitional auction for delivery year 2016/2017 (results posted on August 31, 2015) and its transitional auction for delivery years 2017/2018 (results posted on September 9, 2015). On May 10, 2016, FERC largely denied rehearing, and a number of parties appealed to the U.S. Court of Appeals for the DC Circuit for review of the decision. On June 20, 2017, the DC Circuit denied all the appeals.

~~MISO Capacity Market Results~~

On April 14, 2015, the Midcontinent Independent System Operator (MISO) released the results of its capacity auction covering the June 2015 through May 2016 delivery year. As a result of the auction, capacity prices for the zone 4 region in downstate Illinois increased to $150 per MW per day beginning in June 2015, an increase from the prior pricing of $16.75 per MW per day that was in effect from June 2014 to May 2015. Generation had an offer that was selected in the auction. However, due to Generation's ratable hedging strategy, the results of the capacity auction have not had a material impact on Exelon's and Generation's consolidated results of operations and cash flows.

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Additionally, in late May and June 2015, separate complaints were filed at the FERC by each of the State of Illinois, the Southwest Electric Cooperative, Public Citizens, Inc., and the Illinois Industrial Energy Consumers challenging the results of this MISO capacity auction for the 2015/2016 delivery in MISO delivery zone 4. The complaints allege generally that 1) the results of the capacity auction for zone 4 are not just and reasonable, 2) the results should be suspended, set for hearing and replaced with a new just and reasonable rate, 3) a refund date should be established and that 4) certain alleged behavior by one of the market participants other than Exelon or Generation, be investigated.

On October 1, 2015, FERC announced that it was conducting a non-public investigation (that does not involve Exelon or Generation) into whether market manipulation or other potential violations occurred related to the auction. On December 31, 2015, FERC issued a decision that certain of the rules governing the establishment of capacity prices in downstate Illinois are “not just and reasonable” on a prospective basis. FERC ordered that certain rules be changed prior to the April 2016 auction which set capacity prices for the 2016/2017 planning year. In response to this order, MISO filed certain rule changes with FERC. On March 18, 2016, FERC largely denied rehearing of its December 31, 2015 order. FERC continues to conduct its non-public investigation to determine if the April 2015 auction results were manipulated and, if so, whether refunds are appropriate. FERC did establish May 28, 2015, the day the first complaint was filed, as the date from which refunds (if ordered) would be calculated, and it also made clear that the findings in the December 31, 2015 order do not prejudge the investigation or related proceedings. Generation cannot predict the impact the FERC order may ultimately have on future auction results, capacity pricing or decisions related to the potential early retirement of the Clinton nuclear plant, however, such impacts could be material to Generation's future results of operations and cash flows. ~~See Note 7 - Early Nuclear Plant Retirements of the Combined Notes~~Contingencies to the Consolidated Financial Statements in this report for additional information on ~~the impacts of the MISO announcement.~~various environmental matters.

~~Subsidized Generation~~Power Markets

~~The rate of expansion of subsidized generation, in the markets in which Generation’s output is sold can negatively impact wholesale power prices, and in turn, Generation’s results of operations.~~

Various states have attempted to implement or propose legislation, regulations or other policies to subsidize new generation development which may result in artificially depressed wholesale energy and capacity prices. For example, the New Jersey legislature enacted into law in January 2011, the Long Term Capacity Pilot Program Act (LCAPP). LCAPP provides eligible generators with 15-year fixed contracts for the sale of capacity in the PJM capacity market. Under LCAPP, the local utilities in New Jersey are required to pay (or receive) the difference between the price eligible generators receive in the capacity market and the price guaranteed under the 15-year contract. New Jersey ultimately selected three proposals to participate in LCAPP and build new generation in the state. In addition, on April 12, 2012, the MDPSC issued an order directing the Maryland electric utilities to enter into a 20-year contract for differences (CfD) with CPV Maryland, LLC (CPV), under which CPV was required to construct an approximately 700 MW combined cycle gas turbine in Waldorf, Maryland. The CfD mandated that utilities (including BGE, Pepco and DPL) pay (or receive) the difference between CPV’s contract price and the revenues it receives for capacity and energy from clearing the unit in the PJM capacity market.

Exelon and others challenged the constitutionality and other aspects of the New Jersey legislation in federal court. The actions taken by the MDPSC were also challenged in federal court in an action to which Exelon was not a party. The federal trial courts in both the New Jersey and Maryland actions effectively invalidated the actions taken by the New Jersey legislature and the MDPSC, respectively. Each of those decisions was upheld by the U.S. Court of Appeals for the Third Circuit and the U.S. Court of Appeals for the Fourth Circuit, respectively. On April 19, 2016, the U.S. Supreme Court affirmed the decision of the U.S. Court of Appeals for the Fourth Circuit, and subsequently denied certiorari with respect to the appeal from the U.S. Court of Appeals for the Third Circuit, leaving in place that Court’s decision. The matter is now considered closed.

As required under their contracts, generator developers who were selected in the New Jersey and Maryland programs (including CPV) offered and cleared in PJM’s capacity market auctions. To the extent that the state-required customer subsidies are included under their respective contracts, Exelon believes that these projects may have artificially suppressed capacity prices in PJM in these auctions and may continue to do so in future auctions to the detriment of Exelon. While the court decisions are positive developments, continuation of these state efforts, if successful and unabated by an effective minimum offer price rule (MOPR) for future capacity auctions, could continue to result in artificially depressed wholesale capacity and/or energy prices. Other states could seek to establish programs, which could substantially impact Exelon’s position and could have a significant effect on Exelon’s financial results of operations, financial position and cash flows.

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One such state is Ohio, where state-regulated utility companies FirstEnergy Ohio (FE) and AEP Ohio (AEP) initiated actions at the Public Utilities Commission of Ohio (PUCO) to obtain approval for Riders that would effectively allow these two companies to pass through to all customers in their service territories the differences between their costs and market revenues on PPAs entered into between the utility and its merchant generation affiliate for what was collectively more than 6,000 MW of primarily coal-fired generation. Thus, the Riders were similar to the CfDs described above (except that the PPA Riders in Ohio would apply to existing generation facilities whereas the CfDs applied to new generation facilities). While FERC orders on April 27, 2016 largely alleviated the concerns related to the Riders by holding that the PPAs ran afoul of affiliate restrictions on FE and AEP, we continue to closely monitor developments in Ohio.

In addition, Exelon continues to monitor developments in Maryland, New Jersey, and other states and participates in stakeholder and other processes to ensure that similar state subsidies are not developed. Exelon remains active in advocating for competitive markets, while opposing policies that require taxpayers and/ or consumers to subsidize or give preferential treatment to generation providers or technologies that do not provide superior reliability or environmental benefits, or that would threaten the reliability and value of the integrated electricity grid.

~~Complaints~~Complaint at FERC Seeking to ~~Mitigate Illinois and New York Programs Providing ZECs~~Alter Capacity Market Default Offer Caps

On February 21, 2019, PJM's Independent Market Monitor (IMM) filed a complaint alleging that the number of performance assessment intervals used to calculate the default offer cap for bids to supply capacity in PJM ~~and NYISO capacity markets include a Minimum Offer Price Rule (MOPR)~~is too high, resulting in an overstated default offer cap that ~~is intended~~obviates the need for most sellers to ~~preclude buyers from exercising buyer~~seek unit-specific approval of their offers. The IMM argued that this allows for the exercise of market power. IfThe IMM asked FERC to require PJM to reduce the number of performance assessment intervals used to calculate the opportunity costs of a ~~resource is subjected~~capacity supplier assuming a capacity obligation. This would, in turn, lower the default offer cap and allow the IMM to review more offers on a ~~MOPR, its~~unit-specific basis. Several consumer advocates filed a complaint seeking similar relief several months after the IMM’s complaint. On March 18, 2021, FERC granted the complaints, finding the current estimate of performance assessment intervals to be excessive compared to the reasonably expected number of performance assessment intervals which results in an unjust and unreasonable default offer ~~is adjusted~~cap. FERC did not establish the number of performance assessment intervals that should be used to ~~remove~~calculate the ~~revenues it receives through a federal, state or other government-provided financial support program - resulting~~default offer cap and instead requested briefs on the matter, including alternative approaches to mitigation in ~~a higher offer that may not clear~~ the capacity market. ~~Currently,~~Exelon submitted an initial and reply briefs on May 3, 2021 and June 9, 2021, respectively, and an answer to briefs filed by other parties on June 24, 2021. On September 2, 2021, FERC issued an order adopting the ~~MOPRs in~~IMM’s unit-specific avoidable cost offer review methodology and directed PJM ~~and NYISO apply only~~ to certain new resources. Exelon has generally opposed policies that require subsidies or give preferential treatment to generation providers or technologies that do not provide superior reliability or environmental benefits, or that would threaten the reliability and value of the integrated electricity grid. Thus, Exelon has supportedsubmit a MOPR as a means of minimizing the detrimental impact certain subsidized resources could have on capacity markets (such as the New Jersey (LCAPP) and Maryland (CfD) programs). However, in Exelon’s view, MOPRs should not be applied to resources that receive compensation for providing superior reliability or environmental benefits.

On January 9, 2017, the Electric Power Supply Association (EPSA) filed two requests with FERC: one seeking to amend a prior complaint against PJM and another seeking expedited action on a pending NYISO compliance filing inestablishing new deadlines for offer review and related other activities leading up to the base residual auction for the 2023-2024 planning year and an ~~existing proceeding. Both filings allege that~~additional compliance filing revising the ~~relevant MOPR should be expanded~~PJM Tariff to ~~also apply to existing resources receiving ZEC compensation under the New York CES and Illinois ZES programs. The EPSA parties have~~comply with FERC’s order. Exelon filed ~~motion to expedite both proceedings. Exelon has filed protests~~ at FERC ~~in response to each filing, arguing generally that ZEC payments provide compensation~~ for ~~an environmental attribute that is distinct from the energy and capacity sold in the FERC-jurisdictional markets~~, and therefore, are no different than other renewable support programs like the PTC and RPS that have generally not been subject to a MOPR. However, if successful, for Generation's facilities in NYISO and PJM expected to receive ZEC compensation (Quad Cities, Ginna, Nine Mile Point and FitzPatrick), an expanded MOPR could require exclusion of ZEC compensation when bidding into future capacity auctions such that these facilities would have an increased risk of not clearing in those auctions and thus no longer receiving capacity revenues during the respective ZEC programs. Any such mitigation of these generating resources could have a material effectrehearing on Exelon’s and Generation’s future cash flows and results of operations. On August 30, 2017, EPSA filed motions to lodge the district court decisions dismissing the complaints and urging FERC to act expeditiouslythis matter on its requests to expand the MOPR. On September 14, 2017, Exelon filed a response in each docket noting that it does not oppose the motions to lodge but arguing that the requests to expedite a decision on the requests to expand the MOPR have no merit. The timing of FERC’s decision with respect to both proceedings is currently unknown andOctober 4, 2021. Generation cannot predict the outcome of these ~~matters is currently uncertain.~~

~~DOE Notice of Proposed Rulemaking~~

~~On August 23, 2017,~~proceedings or the DOE released its report on the reliability of the electric grid. One aspect of the wide-ranging report is the DOE’s recognition that the electricity markets do not currently value the resiliency provided by baseload generation, such as nuclear plants. On September, 28, 2017, the DOE issued a Notice of Proposed Rulemaking (NOPR) that would entitle certain eligible resilient generating units (i.e., those located in organized markets, with a 90-day supply of fuel on site, not already subject to state cost of service regulation and satisfying certain other requirements) to recover fully allocated costs and earn a fair return on equity on their investment. On October 2, 2017, the FERC issued a notice inviting comments regarding the DOE NOPR within 21 days and established a new docket wherein the FERC will consider the matter. On October 23, 2017, Exelon filed comments with the FERC, supporting the goals of the NOPR and urging the agency to take swift action to protect customers from power supply interruptionsfinancial statement impact.

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and ensure resiliency in a way that appropriately balances the value and cost to customers. Exelon cannot predict the final outcome of the proceeding or its potential impact, if any, on Exelon or Generation.

~~Energy Demand~~

Modest economic growth partially offset by energy efficiency initiatives is resulting in flat to declining load growth in electricity for the utilities. There is a decrease in projected load for electricity for ComEd, PECO, BGE, and ACE, and an essentially flat projected load for electricity for DPL. ComEd, PECO, BGE, Pepco, DPL, and ACE are projecting load volumes to decrease by (1.2)%, (0.4)%, (2.9)%, (2.3)%, (0.4)%, and (3.5)% respectively, in 2017 compared to 2016.

~~Retail Competition~~

Generation’s retail operations compete for customers in a competitive environment, which affect the margins that Generation can earn and the volumes that it is able to serve. The market experienced high price volatility in the first quarter of 2014 which contributed to bankruptcies and consolidations within the industry during the year. However, forward natural gas and power prices are expected to remain low and thus we expect retail competitors to stay aggressive in their pursuit of market share, and that wholesale generators (including Generation) will continue to use their retail operations to hedge generation output.

~~Strategic Policy Alignment~~

As part of its strategic business planning process, Exelon routinely reviews its hedging policy, dividend policy, operating and capital costs, capital spending plans, strength of its balance sheet and credit metrics, and sufficiency of its liquidity position, by performing various stress tests with differing variables, such as commodity price movements, increases in margin-related transactions, changes in hedging practices, and the impacts of hypothetical credit downgrades.

Exelon's board of directors declared first quarter 2017 dividends of $0.3275 per share on Exelon's common stock. The first quarter 2017 dividend was paid on March 10, 2017. The dividend increased from fourth quarter 2016 amount to reflect the Board's decision to raise Exelon's dividend 2.5% each year for the next three years, beginning with the June 2016 dividend.

~~Exelon's Board of Directors declared the second quarter 2017 dividends of $0.3275 per share each on Exelon's common stock. The second quarter 2017 dividend was paid on June 9, 2017.~~

~~Exelon's Board of Directors declared the third quarter 2017 dividends of $0.3275 per share each on Exelon's common stock. The third quarter 2017 dividend was paid on September 8, 2017.~~

~~Exelon's Board of Directors declared the fourth quarter 2017 dividends of $0.3275 per share each on Exelon's common stock. The fourth quarter 2017 dividend is payable on December 8, 2017.~~

~~All future quarterly dividends require approval by Exelon's Board of Directors.~~

Hedging Strategy

Exelon’s policy to hedge commodity risk on a ratable basis over three-year periods is intended to reduce the financial impact of market price volatility. Generation is exposed to commodity price risk associated with the unhedged portion of its electricity portfolio. Generation enters into non-derivative and derivative contracts, including financially-settled swaps, futures contracts and swap options, and physical options and physical forward contracts, all with credit-approved counterparties, to hedge this anticipated exposure. Generation has hedges in place that significantly mitigate this risk for 2017 and 2018. However, Generation is exposed to relatively greater commodity price risk in the subsequent years with respect to which a larger portion of its electricity portfolio is currently unhedged. As of September 30, ~~2017,~~2021, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York, and ERCOT reportable segments is ~~98%-101%, 79%-82% and 45%-48%~~96%-99% for ~~2017, 2018, and 2019 respectively. The percentage~~the remainder of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted generating facilities based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products, and options. Equivalent sales represent all hedging products, such as wholesale and retail sales of power, options and

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~~swaps.~~2021. Generation has been and will continue to be proactive in using hedging strategies to mitigate commodity price ~~risk in subsequent years as well.~~risk.

Generation procures ~~oil and~~ natural gas through long-term and short-term contracts and spot-market purchases. Nuclear fuel isassemblies are obtained predominantly through long-term uranium concentrate supply contracts, contracted conversion services, contracted enrichment services, or a combination thereof, and contracted fuel fabrication services. The supply markets for uranium concentrates and certain nuclear fuel services ~~coal, oil and natural gas~~ are subject to price fluctuations and availability restrictions. Supply market conditions may make Generation’s procurement contracts subject to credit risk related to the potential non-performance of counterparties to deliver the contracted commodity or service at the contracted prices. Approximately 60% of Generation’s uranium concentrate requirements from ~~2017~~2021 through ~~2021~~2025 are supplied by three ~~producers.~~suppliers. In the event of non-performance by these or other suppliers, Generation believes that replacement uranium concentrate can be obtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements. Non-performance by these counterparties could have a material adverse impact on Exelon’s and Generation’s ~~results~~consolidated financial statements.

See Note 12 — Derivative Financial Instruments of ~~operations, cash flows~~the Combined Notes to Consolidated Financial Statements and ~~financial position.~~ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for additional information.

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The Utility Registrants mitigate commodity price risk through regulatory mechanisms that allow them to recover procurement costs from retail customers.

~~Tax Matters~~

~~Potential Corporate Tax Reform~~

President Trump and Congressional Republicans have stated that one of their top priorities is enactment of comprehensive tax reform. On September 27, 2017, the Trump Administration and Republican Congressional leaders issued a unified framework which outlines their goals for comprehensive tax reform. Specifically, the framework proposes a reduction in the corporate tax rate from the current 35% to 20%, immediate expensing of new investments in depreciable assets for at least five years, elimination of the domestic production activities deduction and partial limitation of the deduction for interest. It is uncertain whether, to what extent, or when any changes in federal tax policies will be enacted or the transition time frame for such changes. The Utility Registrants’ regulators may impose rate reductions to provide the benefit of any reduction in income tax expense to customers as well as to refund the "excess" deferred income taxes previously collected through rates. The amount and timing of any such rate changes would be subject to the discretion of the rate regulator in each specific jurisdiction. For these reasons, the Registrants cannot predict the impact any potential changes may have on their future results of operations, cash flows or financial position, and such changes could be material.

Environmental ~~Legislative and Regulatory Developments~~Regulation

Exelon ~~was actively involved in the Obama Administration’s development~~is well positioned to support increasingly ambitious government climate policy and ~~implementation of environmental regulations for the electric industry, in pursuit of its business strategy~~ to ~~provide reliable, clean, affordable~~partner with our customers and innovative energy products. These efforts have most frequently involved air, water and waste controls for fossil-fueled electric generating units, as set forth in the discussion below. These regulations have had a disproportionate adverse impact on coal-fired power plants, requiring significant expenditures of capital and variable operating and maintenance expense, and have resulted in the retirement of older, marginal facilities. Duecommunities to its low emission generation portfolio, Generation has not been significantly affected by these regulations, representing a competitive advantage relative to electric generators that are more reliant on fossil-fuel plants.

Through the issuance of a series of Executive Orders (EO), President Trump has initiated review of a number of EPA and other regulations issued during the Obama Administration, with the expectation that the Administration will seek repeal or significant revision of these rules. Under these EOs, each executive agency is required to evaluate existing regulations and make recommendations regarding repeal, replacement, or modification. The Administration’s actions are intended to result in less stringent compliance requirements under air, water, and waste regulations. The exact nature, extent, and timing of the regulatory changes are unknown, as well as the ultimate impact on Exelon’s and its subsidiaries results of operations and cash flows.reduce GHG emissions.

In ~~particular,~~August 2021, the ~~Administration has targeted existing EPA regulations for repeal, including notably the Clean Power Plan, as well as revoking many Executive Orders, reports, and guidance issued~~Utility Registrants announced a “path to clean” goal to collectively reduce their operations-driven emissions 50% by the Obama Administration on the topic of climate change or the regulation of greenhouse gases. The Executive Order also disbanded the Interagency Working Group that developed the social cost of carbon used in rulemakings, and withdrew all technical support documents supporting the calculation. Other regulations that have been specifically identified for review are

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~~the Clean Water Act rule relating to jurisdictional waters of the U.S., the Steam Electric Effluent Guidelines relating to waste water discharges from coal-fired power plants, and the~~2030 against a 2015 ~~National Ambient Air Quality Standard (NAAQS) for ozone. The review of final rules could extend over several years as formal notice and comment rulemaking process proceeds.~~

~~Air Quality~~

~~Mercury and Air Toxics Standard Rule (MATS).~~ On December 16, 2011, the EPA signed a final rule to reduce emissions of toxic air pollutants from power plants and signed revisions to the NSPS for electric generating units. The final rule, known as MATS, requires coal-fired electric generation plants to achieve high removal rates of mercury, acid gases and other metals,baseline, and to ~~make capital investments in pollution control equipment and incur higher operating expenses. The initial compliance deadline~~reach net zero operations-driven emissions by 2050. This goal builds upon Exelon’s long-standing commitment to meet the new standards was April 16, 2015; however, facilities may have been granted an additional one or two year extension in limited cases. Numerous entities challenged MATS in the D.C. Circuit Court, and Exelon intervened in support of the rule. In April 2014, the D.C. Circuit Court issued an opinion upholding MATS in its entirety. On appeal, the U.S. Supreme Court decided in June 2015 that the EPA unreasonably refused to consider costs in determining whether it is appropriate and necessary to regulate hazardous air pollutants emitted by electric utilities. The U.S. Supreme Court, however, did not vacate the rule; rather, it was remanded to the D.C. Circuit Court to take further action consistent with the U.S. Supreme Court’s opinion on this single issue. On April 27, 2017, the D.C. Circuit granted EPA’s motion to hold the litigation in abeyance, pending EPA’s review of the MATS rule pursuant to President Trump’s EO discussed above. Following EPA’s review and determination of its course of action for the MATS rule, the parties will have 30 days to file motions on future proceedings. Notwithstanding the Court’s order to hold the litigation in abeyance, ~~the MATS rule remains in effect. Exelon will continue to participate in the remanded proceedings before the D.C. Circuit Court as an intervenor in support of the rule.~~

~~Clean Power Plan~~. On April 28, 2017, the D.C. Circuit Court issued orders in separate litigation related to the EPA’s actions under the Clean Power Plan (CPP) to amend Clean Air Act Section 111(d) regulation of existing fossil-fired electric generating units and Section 111(b) regulation of new fossil-fired electric generating units. In both cases, the Court has determined to hold the litigation in abeyance pending a determination whether the rule should be remanded to the EPA. On October 10, 2017, EPA issued a proposed rule to repeal the CPP in its entirety, based on a proposed change in the Agency’s legal interpretation of Clean Air Act Section 111(d) regarding actions that the Agency can consider when establishing the Best System of Emission Reduction (“BSER”) for existing power plants. Under the proposed interpretation, the Agency exceeded its authority under the Clean Air Act by regulating beyond individual sources ofreducing our GHG emissions. The ~~EPA has also indicated its intent~~Utility Registrants “path to ~~issue an advance notice of proposed rulemaking~~clean” will include efficiency and clean electricity for operations, vehicle fleet electrification, equipment and processes to solicit information on systems of emission reduction that are in accord with the Agency’s proposed revised legal interpretation; namely, only by regulating emission reductions that can be implemented at and to individual sources.

~~2015 Ozone National Ambient Air Quality Standards (NAAQS).~~ On April 11, 2017, the D.C. Circuit ordered that the consolidated 2015 ozone NAAQS litigation be held in abeyance pending EPA’s further review of the 2015 Rule. EPA did not meet the October 1, 2017 deadline to promulgate initial designations for areas in attainment or non-attainment of the standard. A number of states and environmental organizations have notified the EPA of their intent to file suit to compel EPA to issue the designations.

~~Water Quality~~

~~Section 316(b) of the Clean Water Act requires that cooling water intake structures at electric power plants reflect the best technology available~~reduce sulfur hexafluoride (SF6) leakage, modern natural gas infrastructure to minimize ~~adverse environmental impacts,~~methane leaks and increase safety and reliability, and investment and collaboration to develop new technologies.

Generation produces electricity predominantly from low- and zero-carbon generating facilities (such as nuclear, hydroelectric, natural gas, wind, and solar PV) and neither owns nor operates any coal-fueled generating assets. Generation’s natural gas fired generating plants produce GHG emissions, most notably CO2. However, Generation’s owned-asset emission intensity, or rate of carbon dioxide equivalent (CO2e) emitted per unit of electricity generated, is ~~implemented through state-level NPDES permit programs.~~ ~~All~~among the lowest in the industry.

The United States has set an economy-wide target of Generation’s power generation facilities with cooling water systems are subject to the regulations. Facilities without closed-cycle recirculating systems (e.g., cooling towers) are potentially most affectedreducing its net GHG emissions by changes to the existing regulations. Those facilities are Calvert Cliffs, Clinton, Dresden, Eddystone, Fairless Hills, FitzPatrick, Ginna, Gould Street, Handley, Mountain Creek, Mystic 7, Nine Mile Point Unit 1, Oyster Creek, Peach Bottom, Quad Cities, Riverside and Salem. ~~See ITEM 1.—BUSINESS, "Water Quality" of the Exelon 2016 Form 10-K for further discussion.~~

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~~Solid and Hazardous Waste~~

~~In October 2015, the first federal regulation for the disposal of coal combustion residuals (CCR) from power plants became effective. The rule classifies CCR as non-hazardous waste under RCRA.~~ ~~Under the regulation, CCR will continue to be regulated~~50-52% below 2005 levels by most states subject to coordination with the federal regulations. Generation has previously recorded accruals consistent with state regulation for its owned coal ash sites, and as such, the regulation is not expected to impact Exelon’s and Generation’s financial results. Generation does not have sufficient information to reasonably assess the potential likelihood or magnitude of any remediation requirements that may be asserted under the new federal regulations for coal ash disposal sites formerly owned by Generation. For these reasons, Generation is unable to predict whether and to what extent it may ultimately be held responsible for remediation and other costs relating to formerly owned coal ash disposal sites under the new regulations.2030.

See Note 18—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for further detail related to environmental matters, including the impact of environmental regulation.

Other Legislative and Regulatory Developments

~~NRC Task Force on Fukushima Daiichi Accident (Exelon and Generation).~~FERC Supplemental Notice of Proposed Rulemaking

In July 2011, an NRC Task Force formed in the aftermath of the March 11, 2011, 9.0 magnitude earthquake and ensuing tsunami, that seriously damaged the nuclear units at the Fukushima Daiichi Nuclear Power Station,On April 15, 2021, FERC issued a ~~report~~Supplemental Notice of ~~its review~~Proposed Rulemaking (NOPR) proposing to modify the current regulation permitting a continuous 50-basis-point ROE incentive adder for a transmission utility that joins and remains a member of a RTO. Under the ~~accident, including tiered recommendations~~NOPR, the ROE incentive adder would only be available for ~~future regulatory action by~~a period of up to three years after a transmission utility newly joins a RTO and all existing ROE incentive adders would end for transmission utilities that have been members for three or more years. The Utility Registrants’ existing transmission rates include the ~~NRC~~ROE incentive adder. Exelon submitted comments to be taken in the near and longer term. The Task Force’s report concluded that nuclear reactors in the United States are operating safely and do not present an imminent risk to public health and safety. The NRC and its staff have issued orders and implementation guidance for commercial reactor licensees operating in the United States. Generation has assessed the impacts of the Tier 1 orders and information requests and will continue monitoring the additional recommendations under review by the NRC staff, both from an operational and a financial impact standpoint. Generation’s current assessments are specific to the Tier 1 recommendations. In May 2017, the NRC finalized its decision that no actions are required with respect to the Tier 2 and Tier 3 recommendations. Generation will continue to engage in nuclear industry assessments and actions and obtain stakeholder input.

~~Employees~~

In January 2017, an election was held at BGE which resulted in union representation for approximately 1,400 employees. BGE and IBEW Local 410 have begun negotiations for an initial agreement which could result in some modifications to wages, hours and other terms and conditions of employment. No agreement has been finalized to date and managementFERC on this matter on June 25, 2021. Exelon cannot predict the outcome, but a final rule as proposed could have an adverse impact to Exelon’s and the Utility Registrants’ financial statements. See Note 3 — Regulatory Matters of ~~such negotiations.~~the Combined Notes to Consolidated Financial Statements for additional information regarding the Utility Registrants’ transmission formula rates and regulatory proceedings at FERC.

City of Chicago Franchise Agreement

ComEd has had a Franchise Agreement with the City of Chicago (the City) since 1992. The Franchise Agreement grants rights to use the public right of way to install, maintain, and operate the wires, poles, and other infrastructure required to deliver electricity to residents and businesses across the City. The Franchise Agreement became terminable on one year notice as of December 31, 2020. It now continues in effect indefinitely unless and until either party issues a notice of termination, effective one year later, or it is replaced by mutual agreement with a new franchise agreement between ComEd and the City. If either party terminates and no new agreement is reached between the parties, the parties could continue with ComEd providing electric services within the City with no franchise agreement in place. The City also has an option to terminate and purchase the ComEd system (“municipalize”), which also requires one year notice. Neither party has issued a notice of termination at this time, the City has not exercised its municipalization option, and no new agreement has been reached. Accordingly, the 1992 Franchise Agreement remains in effect at this time. In April ~~2017,~~2021, the City invited interested parties to respond to a Request for Information (RFI) regarding the franchise for electricity delivery. Under this process, the City could choose to terminate the ComEd Franchise Agreement on one year notice and grant a franchise to another party instead. Final responses to the RFI were due on July 30, 2021, however, on July 29, 2021, the City chose to extend the final submission deadline to September 30, 2021. ComEd submitted its response to the RFI by the due date and looks forward to continuing engagement with the City about its response. While Exelon ~~Nuclear Security successfully~~and ComEd cannot predict the ultimate outcome of the RFI and the

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Franchise Agreement, fundamental changes in the agreement or other adverse actions affecting ComEd’s business in the City would require changes in their business planning models and operations and could have a material adverse impact on Exelon’s and ComEd’s consolidated financial statements. If the City were to disconnect from the ComEd system, ComEd would seek full compensation for the business and its associated property taken by the City, as well as for all damages resulting to ComEd and its system. ComEd would also seek appropriate compensation for stranded costs with FERC.

Employees

In the second quarter of 2021, Generation and PECO ratified CBAs as follows:

•Generation ratified its CBA with UGSOA, which covers 73 security officers at Three Mile Island. The CBA will expire in 2023.

•PECO ratified two CBAs with IBEW Local 614 which covers 1,140 operations employees and 185 customer service employees, respectively. Both CBAs expire in 2026.

In the third quarter of 2021, Generation ratified its CBA with the ~~SPFPA Local 238 at Quad Cities to an extension~~National Union of ~~three years. In June 2017, Exelon~~ Nuclear Security ~~successfully ratified its~~Officers, which covers 88 security officers at Braidwood. The CBA ~~with the UGSOA Local 12 at Limerick to an extension of three years.~~will expire in 2024.

Critical Accounting Policies and Estimates

Management of each of the Registrants makes a number of significant estimates, assumptions, and judgments in the preparation of its financial statements. At September 30, 2021, the Registrants’ critical accounting policies and estimates had not changed significantly from December 31, 2020. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — ~~CRITICAL ACCOUNTING POLICIES AND ESTIMATES~~Critical Accounting Policies and Estimates in ~~Exelon’s, Generation’s, ComEd’s, PECO’s, BGE’s, PHI's, Pepco's, DPL's and ACE's combined 2016~~the Registrants' 2020 Form 10-K for a discussion of the estimates and judgments necessary in the Registrants’ accounting for AROs, goodwill, purchase accounting, unamortized energy assets and liabilities, asset impairments, depreciable lives of property, plant and equipment, defined benefit pension and other postretirement benefits, regulatory accounting, derivative instruments, taxation, contingencies, revenue recognition, and allowance for uncollectible accounts. At September 30, 2017, the Registrants’ critical accounting policies and estimates had not changed significantly from December 31, 2016.further information.

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Results of Operations ~~By Registrant~~

~~Net Income (Loss) Attributable to Common Shareholders~~ by Registrant

Three Months Ended
September 30,
Favorable
(Unfavorable)
Variance
Nine Months Ended
September 30,
Favorable
(Unfavorable)
Variance
2017 2016 2017
2016^(a)

Exelon $ 824
$ 490
$ 334
$ 1,899
$ 930
$ 969
Generation 305
236
69
479
538
(59 )
ComEd 189
37
152
447
297
150
PECO 112
122
(10 ) 327
346
(19 )
BGE 62
54
8
231
183
48
Pepco 87
79
8
188
20
168
DPL 31
44
(13 ) 107
(16 ) 123
ACE 41
47
(6 ) 77
(50 ) 127

~~_________~~


~~(a)~~	For Pepco, DPL and ACE, reflects that Registrant's operations for the nine months ended September 30, 2016. For Exelon and Generation, includes the operations of the PHI acquired businesses for the period of March 24, 2016 through September 30, 2016.

Successor Predecessor
Three Months Ended September 30, 2017 Three Months Ended September 30, 2016 Nine Months Ended September 30, 2017 March 24, 2016 to September 30, 2016 January 1, 2016 to March 23, 2016
PHI $ 153
$ 166
$ 359
$ (91 ) $ 19

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Results of Operations — Generation


	Three Months Ended September 30,				(Unfavorable) Favorable Variance		Nine Months Ended September 30,				Favorable (Unfavorable) Variance
	2021		2020				2021		2020
Operating revenues	$	4,406	$	4,659	$	(253)	$	14,117	$	13,272	$	845
Operating expenses
Purchased power and fuel	1,546		2,314		768		8,103		6,961		(1,142)
Operating and maintenance	938		1,737		799		3,413		4,188		775
Depreciation and amortization	866		558		(308)		2,735		1,161		(1,574)
Taxes other than income taxes	115		118		3		354		364		10
Total operating expenses	3,465		4,727		1,262		14,605		12,674		(1,931)

Gain on sales of assets and businesses	65		—		65		144		12		132


Operating income (loss)	1,006		(68)		1,074		(344)		610		(954)
Other income and (deductions)
Interest expense, net	(77)		(80)		3		(225)		(277)		52
Other, net	(115)		367		(482)		561		199		362
Total other income and (deductions)	(192)		287		(479)		336		(78)		414
Income (loss) before income taxes	814		219		595		(8)		532		(540)
Income taxes	177		100		(77)		108		41		(67)
Equity in losses of unconsolidated affiliates	(4)		(2)		(2)		(6)		(6)		—
Net income (loss)	633		117		516		(122)		485		(607)
Net income (loss) attributable to noncontrolling interests	26		68		(42)		125		(85)		210
Net income (loss) attributable to membership interest	$	607	$	49	$	558	$	(247)	$	570	$	(817)

Three Months Ended
September 30,
Favorable
(Unfavorable)
Variance
Nine Months Ended
September 30,
Favorable
(Unfavorable)
Variance
2017 2016 2017 2016
Operating revenues $ 4,751
$ 5,035
$ (284 ) $ 13,812
$ 13,363
$ 449
Purchased power and fuel expense 2,331
2,589
258
7,286
6,609
(677 )
Revenues net of purchased power and fuel expense^(a)
2,420
2,446
(26 ) 6,526
6,754
(228 )
Other operating expenses
Operating and maintenance 1,374
1,336
(38 ) 4,871
4,333
(538 )
Depreciation and amortization 410
632
222
1,046
1,329
283
Taxes other than income 141
136
(5 ) 425
380
(45 )
Total other operating expenses 1,925
2,104
179
6,342
6,042
(300 )
(Loss) Gain on sales of assets (2 ) —
(2 ) 3
31
(28 )
Bargain purchase gain 7
—
7
233
—
233
Operating income 500

342
158
420

743
(323 )
Other income and (deductions)
Interest expense, net (113 ) (77 ) (36 ) (342 ) (273 ) (69 )
Other, net 209
185
24
648
395
253
Total other income and (deductions) 96
108
(12 ) 306
122
184
Income before income taxes 596
450
146
726
865
(139 )
Income taxes 240
173
(67 ) 209
293
84
Equity in losses of unconsolidated affiliates (8 ) (6 ) (2 ) (26 ) (16 ) (10 )
Net income 348

271

77

491

556

(65 )
Net income attributable to noncontrolling interests 43
35
(8 ) 12
18
6
Net income attributable to membership interest $ 305
$ 236
$ 69
$ 479
$ 538
$ (59 )

~~_________~~

~~(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.

~~Net Income Attributable to Membership Interest~~

Three Months Ended September 30, ~~2017~~2021 Compared to Three Months Ended September 30, ~~2016.~~ ~~Generation’s~~ 2020. Net income attributable to membership ~~interest for~~interest increased by $558 million primarily due to:

•Absence of an impairment in the ~~three months ended September 30, 2017 increased compared to~~New England asset group;

•Absence of one time charges recorded in the ~~same period in 2016, primarily due to lower Depreciation and amortization expenses, a Bargain purchase gain in 2017, and higher other income, partially offset by lower Revenue net~~third quarter of purchased power and fuel expense, higher Operating and maintenance expenses, and higher interest expense. The decrease in Depreciation and amortization is primarily due to lower accelerated depreciation and amortization as a result of the 20172020 associated with Generation's decision to early retire the ~~TMI~~Byron and Dresden nuclear ~~facility compared to~~facilities and Mystic Units 8 and 9, and the

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reversal of one-time charges resulting from the reversal of the previous decision ~~in 2016~~ to early retire ~~Clinton~~Byron and ~~Quad Cities nuclear facilities. The Bargain purchase gain is primarily due to a measurement period adjustment for the FitzPatrick Acquisition. The increase in other income is primarily~~Dresden on September 15, 2021;

•Higher mark-to-market gains; and

•Higher New York ZEC revenues due to higher ~~realized NDT fund gains.~~ generation and an increase in ZEC prices.

The decrease in Revenue net of purchased power and fuel expense primarily relates to the impacts of lower load volumes delivered due to mild weather and lower realized energy prices related to Exelon's ratable hedging strategy,increases were partially offset byby:

•Lower net unrealized and realized gains on NDT funds;

•Decommissioning-related activities that were not offset for the ~~impact~~Byron units beginning in the second quarter of 2021 through September 15, 2021. With Generation's September 15, 2021 reversal of the ~~New York CES,~~previous decision to retire Byron, Generation resumed contractual offset for Byron as of that date;

•Accelerated depreciation and amortization associated with Generation's previous decision in the ~~acquisition~~third quarter of 2020 to early retire Byron and Dresden nuclear facilities in 2021, a decision which was reversed on September 15, 2021, and Generation's decision in the ~~FitzPatrick nuclear facility, a decrease~~third quarter of 2020 to early retire Mystic Units 8 and 9 in ~~nuclear outage days, increased capacity prices,~~2024; and ~~the addition of the two combined-cycle gas turbines in Texas. The increase in Operating~~

•Higher net unrealized and ~~maintenance is primarily due to the impairment of ExGen Texas Power in 2017. The increase in interest expense is primarily due to the impact of project in-service dates~~realized losses on ~~the capitalization of interest and higher outstanding debt.~~equity investments.

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Nine Months Ended September 30, ~~2017~~2021 Compared to Nine Months Ended September 30, ~~2016.~~ ~~Generation’s~~ 2020.Net income attributable to membership ~~interest~~interest decreased by $817 million primarily due to:

•Impacts of the February 2021 extreme cold weather event;

•Decommissioning-related activities that were not offset for the ~~nine months ended~~Byron units beginning in the second quarter of 2021 through September 30, 2017 decreased compared to the same period in 2016, primarily due to lower Revenue net of purchased power and fuel expense, higher Operating and maintenance expenses, higher taxes other than income, and higher interest expense, partially offset by lower Depreciation and amortization, a bargain purchase gain in 2017, and higher other income. The decrease in Revenue net of purchased power and fuel expense primarily relates to the conclusion15, 2021. With Generation's September 15, 2021 reversal of the ~~Ginna Reliability Support Services Agreement,~~previous decision to retire Byron, Generation resumed contractual offset for Byron as of that date;

•Impairments of the ~~impact of declining natural gas prices on Generation's natural gas portfolio,~~New England asset group, the ~~impacts of lower load volumes due to mild weather~~Albany Green Energy biomass facility at Generation, and ~~lower realized energy prices related to Exelon's ratable hedging strategy,~~a wind project at Generation, partially offset by the ~~impact~~absence of an impairment of the New ~~York CES,~~England asset group in the ~~acquisition~~third quarter of ~~the FitzPatrick nuclear facility, increased capacity prices, the addition of two combined-cycle gas turbines in Texas, the~~2020; and

•The absence of ~~oil inventory write downs in 2017,~~a prior year one-time tax settlement.

The decreases were partially offset by:

•Higher mark-to-market gains;

•Higher net unrealized and ~~decreased fuel prices. The increase in operating and maintenance expenses primarily relates to the impairment~~realized gains on NDT funds;

•Absence of ~~EGTP assets held for sale compared to the impairment of upstream assets and certain wind projects in 2016, an increase~~one time charges recorded in the ~~number~~third quarter of nuclear outage days in 2017 and increased salaries, wages and contracting costs related to the acquisition of the FitzPatrick nuclear facility. The increase in taxes other than income relates to increased sales and use tax, increased gross receipts tax, and increased property taxes due to the FitzPatrick Acquisition. The increase in interest expense is primarily due to the impact of project in-service dates on the capitalization of interest and higher outstanding debt. The decrease in Depreciation and amortization is primarily due to lower accelerated depreciation and amortization as a result of the 20172020 associated with Generation's decision to early retire the ~~TMI~~Byron and Dresden nuclear ~~facility compared to~~facilities and Mystic Units 8 and 9, and the reversal of one-time charges resulting from the reversal of the previous decision ~~in 2016~~ to early retire ~~Clinton~~Byron and ~~Quad Cities~~Dresden on September 15, 2021;

•Lower nuclear ~~facilities. The bargain purchase gain is the result of the FitzPatrick acquisition in Q1 2017. The~~outage days; and

•Higher New York ZEC revenues due to higher generation and an increase in ~~other income is primarily due to increased unrealized gains on NDT funds in 2017 compared to 2016.~~ZEC prices.

~~Revenues Net of Purchased Power and Fuel Expense~~

Operating revenues. The basis for Generation's reportable segments is the integrated management of its electricity business that is located in different geographic regions, and largely representative of the footprints of ISO/RTO and/or NERC regions, which utilize multiple supply sources to provide electricity through various distribution channels (wholesale and retail). Generation's hedging strategies and risk metrics are also aligned

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with these same geographic regions. ~~Descriptions of each of Generation’s six~~Generation's five reportable segments are ~~as follows:~~

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~~ and Other Power Regions. See Note 5 — Segment Information of the ~~state of Texas.~~

~~Other Power Regions~~:

~~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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Combined Notes to Consolidated Financial Statements for additional information on these reportable segments.

The following business activities are not allocated to a region and are reported under Other: natural gas, as well as other miscellaneous business activities that are not significant to ~~Generation's~~ overall operating revenues or results of operations. Further, the following activities are not allocated to a region, and are reported in Other: amortization of certain intangible assets relating to commodity contracts recorded at fair value from mergers and acquisitions; accelerated nuclear fuel amortization associated with nuclear decommissioning; and other miscellaneous revenues.

Generation evaluates the operating performance of its electric business activities using the measure of Revenue net of purchased power and fuel expense, which is a non-GAAP measurement. Generation’s operating revenues include all sales to third parties and affiliated sales to the Utility Registrants. Purchased power costs include all costs associated with the procurement and supply of electricity including capacity, energy and ancillary services. Fuel expense includes the fuel costs for owned generation and fuel costs associated with tolling agreements.

For the three and nine months ended September 30, ~~2017 and 2016, Generation’s Revenue net of purchased power and fuel expense~~2021 compared to 2020, Operating revenues by region were as follows:


	Three Months Ended September 30,				Variance		% Change(a)		Nine Months Ended September 30,				Variance		% Change(a)
	2021		2020						2021		2020
Mid-Atlantic(b)	$	1,272	$	1,313	$	(41)	(3.1)	%	$	3,527	$	3,561	$	(34)	(1.0)	%
Midwest(c)	985		1,043		(58)		(5.6)	%	2,945		3,007		(62)		(2.1)	%
New York	455		406		49		12.1	%	1,173		1,061		112		10.6	%
ERCOT	358		330		28		8.5	%	890		754		136		18.0	%
Other Power Regions	1,260		1,109		151		13.6	%	3,729		2,984		745		25.0	%
Total electric revenues	4,330		4,201		129		3.1	%	12,264		11,367		897		7.9	%
Other	711		421		290		68.9	%	2,811		1,667		1,144		68.6	%
Mark-to-market (losses) gains	(635)		37		(672)				(958)		238		(1,196)
Total Operating revenues	$	4,406	$	4,659	$	(253)	(5.4)	%	$	14,117	$	13,272	$	845	6.4	%

Three Months Ended
September 30, Variance % Change Nine Months Ended
September 30, Variance % Change
2017 2016 2017 2016
Mid-Atlantic^(a)
$ 855
$ 887
$ (32 ) (3.6 )% $ 2,411
$ 2,556
$ (145 ) (5.7 )%
Midwest^(b)
697
781
(84 ) (10.8 )% 2,140
2,229
(89 ) (4.0 )%
New England 145
160
(15 ) (9.4 )% 403
350
53
15.1 %
New York^(d)
296
194
102
52.6 % 678
592
86
14.5 %
ERCOT 118
93
25
26.9 % 258
231
27
11.7 %
Other Power Regions 68
77
(9 ) (11.7 )% 220
253
(33 ) (13.0 )%
Total electric revenue net of purchased power and fuel expense 2,179
2,192
(13 ) (0.6 )% 6,110
6,211
(101 ) (1.6 )%
Proprietary Trading 4
3
1
33.3 % 11
9
2
22.2 %
Mark-to-market (losses) gains 73
88
(15 ) (17.0 )% (161 ) (113 ) (48 ) 42.5 %
Other^(c)
164
163
1
0.6 % 566
647
(81 ) (12.5 )%
Total revenue net of purchased power and fuel expense $ 2,420
$ 2,446
$ (26 ) (1.1 )% $ 6,526
$ 6,754
$ (228 ) (3.4 )%
__________

~~_________~~(a)% Change in mark-to-market is not a meaningful measure.


~~(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 beginning on March 24, 2016, the day after the PHI merger was completed.


~~(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 $19 million and $22 million decrease to revenue net of purchased power and fuel expense for the three months ended September 30, 2017 and 2016, respectively, and accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 7 - Early Nuclear Plant Retirements of the Combined Notes to the Consolidated Financial Statements of $6 million and $28 million decrease to revenue net of purchased power and fuel expense for the three months ended September 30, 2017 and 2016, respectively. Also includes amortization of intangible assets related to commodity contracts recorded at fair value of a $41 million and $15 million decrease to revenue net of purchased power and fuel expense for the nine months ended September 30, 2017 and 2016, respectively, and accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 7 - Early Nuclear Plant Retirements of the Combined Notes to the Consolidated Financial Statements of $8 million and $38 million decrease to revenue net of purchased power and fuel expense for the nine months ended September 30, 2017 and 2016, respectively.


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

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

(c)Includes results of transactions with ComEd.

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Supply Sources. Generation’s supply sources by region are summarized below:


	Three Months Ended September 30,		Variance	% Change		Nine Months Ended September 30,		Variance	% Change
Supply Source (GWhs)	2021	2020				2021	2020
Nuclear Generation(a)
Mid-Atlantic	13,753	13,679	74	0.5	%	40,203	39,630	573	1.4	%
Midwest	23,909	24,471	(562)	(2.3)	%	70,363	71,929	(1,566)	(2.2)	%
New York	7,188	6,734	454	6.7	%	21,323	19,296	2,027	10.5	%
Total Nuclear Generation	44,850	44,884	(34)	(0.1)	%	131,889	130,855	1,034	0.8	%
Fossil and Renewables
Mid-Atlantic	491	304	187	61.5	%	1,675	1,864	(189)	(10.1)	%
Midwest	177	196	(19)	(9.7)	%	763	852	(89)	(10.4)	%
New York	—	1	(1)	(100.0)	%	1	3	(2)	(66.7)	%
ERCOT	4,670	4,394	276	6.3	%	10,250	10,658	(408)	(3.8)	%
Other Power Regions	2,409	2,794	(385)	(13.8)	%	7,641	8,905	(1,264)	(14.2)	%
Total Fossil and Renewables	7,747	7,689	58	0.8	%	20,330	22,282	(1,952)	(8.8)	%
Purchased Power
Mid-Atlantic	4,565	8,252	(3,687)	(44.7)	%	12,123	17,924	(5,801)	(32.4)	%
Midwest	77	71	6	8.5	%	386	595	(209)	(35.1)	%

ERCOT	595	1,104	(509)	(46.1)	%	2,626	3,351	(725)	(21.6)	%
Other Power Regions	13,585	14,512	(927)	(6.4)	%	38,778	37,981	797	2.1	%
Total Purchased Power	18,822	23,939	(5,117)	(21.4)	%	53,913	59,851	(5,938)	(9.9)	%
Total Supply/Sales by Region
Mid-Atlantic(b)	18,809	22,235	(3,426)	(15.4)	%	54,001	59,418	(5,417)	(9.1)	%
Midwest(b)	24,163	24,738	(575)	(2.3)	%	71,512	73,376	(1,864)	(2.5)	%
New York	7,188	6,735	453	6.7	%	21,324	19,299	2,025	10.5	%
ERCOT	5,265	5,498	(233)	(4.2)	%	12,876	14,009	(1,133)	(8.1)	%
Other Power Regions	15,994	17,306	(1,312)	(7.6)	%	46,419	46,886	(467)	(1.0)	%
Total Supply/Sales by Region	71,419	76,512	(5,093)	(6.7)	%	206,132	212,988	(6,856)	(3.2)	%

Three Months Ended
September 30, Variance % Change Nine Months Ended
September 30, Variance % Change
Supply source (GWhs) 2017 2016 2017 2016
Nuclear generation
Mid-Atlantic^(a)
16,480
15,604
876
5.6 % 48,271
47,035
1,236
2.6 %
Midwest 24,362
24,262
100
0.4 % 69,422
70,925
(1,503 ) (2.1 )%
New York^(a)(d)
6,905
4,843
2,062
42.6 % 17,623
14,002
3,621
25.9 %
Total Nuclear Generation 47,747
44,709
3,038
6.8 % 135,316

131,962
3,354
2.5 %
Fossil and Renewables

Mid-Atlantic 596
706
(110 ) (15.6 )% 2,330
2,290
40
1.7 %
Midwest 218
273
(55 ) (20.1 )% 1,053
1,046
7
0.7 %
New England 1,919
1,886
33
1.7 % 5,921
5,826
95
1.6 %
New York 1
1
—
— % 3
3
—
— %
ERCOT 5,703
2,472
3,231
130.7 % 9,388
5,726
3,662
64.0 %
Other Power Regions 2,149
2,103
46
2.2 % 5,656
6,245
(589 ) (9.4 )%
Total Fossil and Renewables 10,586
7,441
3,145
42.3 % 24,351

21,136
3,215
15.2 %
Purchased Power

Mid-Atlantic 2,541
7,139
(4,598 ) (64.4 )% 8,840
14,024
(5,184 ) (37.0 )%
Midwest 217
461
(244 ) (52.9 )% 1,018
1,855
(837 ) (45.1 )%
New England 4,513
3,927
586
14.9 % 13,920
11,863
2,057
17.3 %
New York —
—
—
— % 28
—
28
— %
ERCOT 1,199
2,895
(1,696 ) (58.6 )% 5,724
7,448
(1,724 ) (23.1 )%
Other Power Regions 3,982
3,803
179
4.7 % 10,357
10,281
76
0.7 %
Total Purchased Power 12,452
18,225
(5,773 ) (31.7 )% 39,887

45,471
(5,584 ) (12.3 )%
Total Supply/Sales by Region^(b)

Mid-Atlantic^(c)
19,617
23,449
(3,832 ) (16.3 )% 59,441
63,349
(3,908 ) (6.2 )%
Midwest^(c)
24,797
24,996
(199 ) (0.8 )% 71,493
73,826
(2,333 ) (3.2 )%
New England 6,432
5,813
619
10.6 % 19,841
17,689
2,152
12.2 %
New York 6,906
4,844
2,062
42.6 % 17,654
14,005
3,649
26.1 %
ERCOT 6,902
5,367
1,535
28.6 % 15,112
13,174
1,938
14.7 %
Other Power Regions 6,131
5,906
225
3.8 % 16,013
16,526
(513 ) (3.1 )%
Total Supply/Sales by Region 70,785
70,375
410
0.6 % 199,554

198,569
985
0.5 %
__________

~~_________~~


~~(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)~~	Excludes physical proprietary trading volumes of 2,601 GWhs and 1,506 GWhs for the three months ended September 30, 2017 and 2016, respectively, and 6,763 GWhs and 4,015 GWhs for the nine months ended September 30, 2017 and 2016.

~~(c)~~

~~Includes affiliate sales~~(a)Includes the proportionate share of output where Generation has an undivided ownership interest in jointly-owned generating plants. Includes the total output for fully owned plants and the total output for CENG prior to PECO and BGE in the Mid-Atlantic region and affiliate sales to ComEd in the Midwest region. As a result of the PHI Merger, includes affiliate sales to Pepco, DPL and ACE in the Mid-Atlantic region beginning on March 24, 2016.


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

~~Mid-Atlantic~~

~~Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016.~~ The $32 million decrease in Revenue net of purchased power and fuel expense in the Mid-Atlantic primarily reflects lower load volumes and lower realized energy prices, partially offset by decreased nuclear outage days and increased capacity prices.

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~~Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016.~~ The $145 million decrease in Revenue net of purchased power and fuel expense in the Mid-Atlantic primarily reflects lower load volumes, lower realized energy prices and decreased capacity prices, partially offset by the absence of oil inventory write-downs in 2017 and decreased nuclear outage days.

~~Midwest~~

~~Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016.~~ The $84 million decrease in Revenue net of purchased power and fuel expense in the Midwest primarily reflects lower realized energy prices, partially offset by increased capacity prices and decreased nuclear fuel prices.

~~Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016.~~ The $89 million decrease in Revenue net of purchased power and fuel expense in the Midwest primarily reflects lower realized energy prices and increased nuclear outage days, partially offset by decreased fuel prices.

~~New England~~

~~Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016.~~ ~~The $15 million decrease in Revenue net of purchased power and fuel expense in New England primarily reflects lower realized energy prices, partially offset by increased capacity prices.~~

~~Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016.~~ ~~The $53 million increase in Revenue net of purchased power and fuel expense in New England was driven by increased capacity prices, partially offset by lower realized energy prices.~~

~~New York~~

~~Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016.~~ ~~The $102 million increase in Revenue net of purchased power and fuel expense in New York was primarily due to the impact of the New York CES and~~ the acquisition of ~~FitzPatrick, partially offset by the conclusion of the Ginna Reliability Support Service Agreement~~EDF’s interest on August 6, 2021 as CENG was fully consolidated. See Note 2 — Mergers, Acquisitions, and ~~lower realized energy prices.~~

~~Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016.~~ The $86 million increase in Revenue net of purchased power and fuel expense in New York was primarily due to impact of the New York CES and the acquisition of FitzPatrick, partially offset by the conclusion of the Ginna Reliability Support Service Agreement and lower realized energy prices.

~~ERCOT~~

~~Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016.~~ ~~The $25 million increase in Revenue net of purchased power and fuel expense in ERCOT was primarily due to the addition of two combined-cycle gas turbines in Texas.~~

~~Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016.~~ The $27 million increase in Revenue net of purchased power and fuel expense in ERCOT was primarily due to the addition of two combined-cycle gas turbines in Texas, partially offset by lower realized energy prices.

~~Other Power Regions~~

~~Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016.~~ ~~The $9 million decrease in Revenue net of purchased power and fuel expense in Other Power Regions was primarily due to lower realized energy prices.~~

~~Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016.~~ ~~The $33 million decrease in Revenue net of purchased power and fuel expense in Other Power Regions was primarily due to lower realized energy prices.~~

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~~Proprietary Trading~~

~~Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016.~~ ~~The $1 million increase in Revenue net of purchased power and fuel expense in Proprietary Trading was primarily due to congestion activity.~~

~~Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016.~~ ~~The $2 million increase in Revenue net of purchased power and fuel expense in Proprietary Trading was primarily due to congestion activity.~~

~~Mark-to-market~~

~~Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016.~~ Mark-to-market gains on economic hedging activities were $73 million for the three months ended September 30, 2017 compared to gains of $88 million for the three months ended September 30, 2016. See Notes 9 — Fair Value of Financial Assets and Liabilities and 10 — Derivative Financial InstrumentsDispositions of the Combined Notes to ~~the~~ Consolidated Financial Statements for additional information on ~~gains~~Generation’s acquisition of EDF’s interest in CENG.

(b)Includes affiliate sales to PECO, BGE, Pepco, DPL, and ~~losses associated with mark-to-market derivatives.~~ACE in the Mid-Atlantic region and affiliate sales to ComEd in the Midwest region.

~~Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016.~~ Mark-to-market losses on economic hedging activities were $161 million for the nine months ended September 30, 2017 compared to losses of $113 million for the nine months ended September 30, 2016. See Notes 9 — Fair Value of Financial Assets and Liabilities and 10 — Derivative Financial Instruments of the Combined Notes to the Consolidated Financial Statements for information on gains and losses associated with mark-to-market derivatives.

~~Other~~

~~Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016.~~ The $1 million increase in Revenue net of purchased power and fuel expense in Other was due to the decline in revenues related to the distributed generation business, offset by lower accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 7 - Early Nuclear Plant Retirements of the Combined Notes to the Consolidated Financial Statements.

~~Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016.~~ The $81 million decrease in other revenue net of purchased power and fuel was primarily due to the impacts of declining natural gas prices on Generation’s natural gas portfolio and amortization of energy contracts recorded at fair value associated with prior acquisitions, partially offset by revenue related to the inclusion of Pepco Energy Services results in 2017 and lower accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 7 - Early Nuclear Plant Retirements of the Combined Notes to the Consolidated Financial Statements.

Nuclear Fleet Capacity ~~Factor~~

Factor. The following table presents nuclear fleet operating data for the ~~three and nine months ended September 30, 2017 as compared to the same period in 2016, for the~~ Generation-operated ~~plants.~~plants, which reflects ownership percentage of stations operated by Exelon, excluding Salem, which is operated by PSEG. The nuclear fleet capacity factor presented in the table is defined as the ratio of the actual output of a plant over a period of time to its output if the plant had operated at full average annual mean capacity for that time period. Generation considers capacity factor to be a useful measure to analyze the nuclear fleet performance between periods. Generation has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, these measures are not a presentation defined under

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GAAP and may not be comparable to other companies’ presentations or be more useful than the GAAP information provided elsewhere in this report.


	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Nuclear fleet capacity factor	96.0	%	96.0	%	95.0	%	95.1	%
Refueling outage days	22		17		172		203
Non-refueling outage days	—		4		10		15

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Nuclear fleet capacity factor^(a)
96.1 % 96.3 % 93.7 % 94.8 %
Refueling outage days^(a)
13
17
233
174
Non-refueling outage days^(a)
15
—
35
31
ZEC Prices. Generation is compensated through state programs for the carbon-free attributes of its nuclear generation. ZEC prices have a significant impact on Operating revenues. The following table presents the average ZEC prices ($/MWh) for each of Generation's major regions in which state programs have been enacted. Prices reflect the weighted average price for the various delivery periods within each calendar year.

~~_________~~


	Three Months Ended September 30,				Variance		% Change		Nine Months Ended September 30,				Variance		% Change
State (Region)	2021		2020						2021		2020
New Jersey (Mid-Atlantic)	$	10.00	$	10.00	$	—	—	%	$	10.00	$	10.00	$	—	—	%
Illinois (Midwest)	16.50		16.50		—		—	%	16.50		16.50		—		—	%
New York (New York)	21.38		19.59		1.79		9.1	%	20.78		19.59		1.19		6.1	%


~~(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.~~

Capacity Prices. Generation participates in capacity auctions in each of its major regions, except ERCOT which does not have a capacity market. Generation also incurs capacity costs associated with load served, except in ERCOT. Capacity prices have a significant impact on Generation's operating revenues and purchased power and fuel. The following table presents the average capacity prices ($/MW Day) for each of Generation's major regions. Prices reflect the weighted average price for the various auction periods within each calendar year.


	Three Months Ended September 30,				Variance		% Change		Nine Months Ended September 30,				Variance		% Change
Location (Region)	2021		2020						2021		2020
Eastern Mid-Atlantic Area Council (Mid-Atlantic and Midwest)	$	165.73	$	187.87	$	(22.14)	(11.8)	%	$	178.03	$	159.50	$	18.53	11.6	%
ComEd (Midwest)	195.55		188.12		7.43		3.9	%	191.42		194.22		(2.80)		(1.4)	%
Rest of State (New York)	160.44		89.30		71.14		79.7	%	94.12		54.32		39.80		73.3	%
Southeast New England (Other)	154.37		176.67		(22.30)		(12.6)	%	166.76		200.69		(33.93)		(16.9)	%

Electricity Prices. The price of electricity has a significant impact on Generation's operating revenues and purchased power cost. The following table presents the average day-ahead around-the-clock price ($/MWh) for each of Generation's major regions.

~~209~~

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	Three Months Ended September 30,				Variance		% Change		Nine Months Ended September 30,				Variance		% Change
Location (Region)	2021		2020						2021		2020
PJM West (Mid-Atlantic)	$	41.77	$	22.75	$	19.02	83.6	%	$	33.70	$	20.24	$	13.46	66.5	%
ComEd (Midwest)	39.68		20.98		18.70		89.1	%	31.76		18.57		13.19		71.0	%
Central (New York)	36.27		19.53		16.74		85.7	%	26.58		16.33		10.25		62.8	%
North (ERCOT)	42.67		27.14		15.53		57.2	%	182.23		21.83		160.40		734.8	%
Southeast Massachusetts (Other)(a)	45.23		22.95		22.28		97.1	%	41.54		21.26		20.28		95.4	%

~~Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016.~~ ~~The nuclear fleet capacity factor decreased primarily due to more non-refueling outage days and was partially offset by fewer refueling outage days, excluding Salem outages, during~~__________

(a)Reflects New England, which comprises the majority of the activity in the Other region.

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For the three ~~months ended September 30, 2017 compared to the same period in 2016.~~

~~Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016.~~ ~~The nuclear fleet capacity factor decreased primarily due to more refueling~~ and ~~non-refueling outage days, excluding Salem outages, during the~~ nine months ended September 30, ~~2017~~2021 compared to 2020, changes in Operating revenues by region were approximately as follows:



	Variance		% Change(a)		Three Months Ended September 30, 2021	Variance		% Change(a)		Nine Months Ended September 30, 2021
Mid-Atlantic	$	(41)	(3.1)	%	• unfavorable wholesale load revenue of $(185) primarily due to lower volumes; partially offset by • favorable settled economic hedges of $120 due to settled prices relative to hedged prices • favorable retail load revenue of $20 primarily due to higher prices	$	(34)	(1.0)	%	• unfavorable wholesale load revenue of $(370) primarily due to lower volumes; partially offset by • favorable settled economic hedges of $305 due to settled prices relative to hedged prices • favorable retail load revenue of $35 primarily due to higher prices
Midwest	(58)		(5.6)	%	• unfavorable settled economic hedges of $(185) due to settled prices relative to hedged prices; partially offset by • favorable net wholesale load and generation revenue of $120 due to higher load volumes and higher prices, partially offset by decreased generation due to higher nuclear outage days	(62)		(2.1)	%	• unfavorable settled economic hedges of $(375) due to settled prices relative to hedged prices; partially offset by • favorable net wholesale load and generation revenue of $315 primarily due to higher prices, partially offset by decreased generation due to higher nuclear outage days
New York	49		12.1	%	• favorable nuclear generation revenue of $20 primarily due to lower outage days and higher prices • favorable ZEC revenue of $25 due to higher prices and higher nuclear generation	112		10.6	%	• favorable nuclear generation revenue of $40 primarily due to lower outage days and higher prices • favorable ZEC revenue of $65 due to higher prices and higher nuclear generation
ERCOT	28		8.5	%	• favorable settled economic hedges of $65 due to settled prices relative to hedged prices; partially offset by • unfavorable wholesale load revenue of $(15) primarily due to lower volumes	136		18.0	%	• favorable retail load revenue of $120 primarily due to higher prices in part due to the February 2021 extreme cold weather event
Other Power Regions	151		13.6	%	• favorable retail load revenue of $175 due to higher prices and higher volumes • favorable settled economic hedges of $110 due to settled prices relative to hedged prices; partially offset by • unfavorable wholesale load revenue of $(155) primarily due to lower volumes	745		25.0	%	• favorable settled economic hedges of $520 due to settled prices relative to hedged prices • favorable retail load revenue of $400 due to higher prices and higher volumes; partially offset by • unfavorable wholesale load revenue of $(205) primarily due to lower volumes
Other	290		68.9	%	• favorable gas revenue of $250 primarily due to higher prices	1,144		68.6	%	• favorable gas revenue of $1,060 primarily due to higher prices in part due to the February 2021 extreme cold weather event
Mark-to-market(b)	(672)				• losses on economic hedging activities of $(635) in 2021 compared to gains of $37 in 2020	(1,196)				• losses on economic hedging activities of $(958) in 2021 compared to gains of $238 in 2020
Total	$	(253)	(5.4)	%		$	845	6.4	%

__________

(a)% Change in mark-to-market is not a meaningful measure.

(b)See Note 12 — Derivative Financial Instruments of the ~~same period~~Combined Notes to Consolidated Financial Statements for additional information on mark-to-market gains and losses.

Purchased power and fuel. See Operating revenues above for discussion of Generation's reportable segments and hedging strategies and for supplemental statistical data, including supply sources by region, nuclear fleet capacity factor, capacity prices, and electricity prices.

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The following business activities are not allocated to a region and are reported under Other: natural gas, as well as other miscellaneous business activities that are not significant to overall purchased power and fuel expense or results of operations, and accelerated nuclear fuel amortization associated with nuclear decommissioning.

For the three and nine months ended September 30, 2021 compared to 2020, Purchased power and fuel by region were as follows:


	Three Months Ended September 30,				Variance		% Change(a)		Nine Months Ended September 30,				Variance		% Change(a)
	2021		2020						2021		2020
Mid-Atlantic(b)	$	702	$	722	$	20	2.8	%	$	1,815	$	1,878	$	63	3.4	%
Midwest(c)	330		293		(37)		(12.6)	%	930		829		(101)		(12.2)	%
New York	109		121		12		9.9	%	293		336		43		12.8	%
ERCOT	179		183		4		2.2	%	1,812		429		(1,383)		(322.4)	%
Other Power Regions	1,049		884		(165)		(18.7)	%	3,165		2,446		(719)		(29.4)	%
Total electric purchased power and fuel	2,369		2,203		(166)		(7.5)	%	8,015		5,918		(2,097)		(35.4)	%
Other	566		329		(237)		(72.0)	%	2,288		1,277		(1,011)		(79.2)	%
Mark-to-market gains	(1,389)		(218)		1,171				(2,200)		(234)		1,966
Total purchased power and fuel	$	1,546	$	2,314	$	768	33.2	%	$	8,103	$	6,961	$	(1,142)	(16.4)	%

__________

(a)% Change in ~~2016.~~mark-to-market is not a meaningful measure.

~~Operating~~(b)Includes results of transactions with PECO, BGE, Pepco, DPL, and ~~Maintenance~~ACE.

(c)Includes results of transactions with ComEd.

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For the three and nine months ended September 30, 2021 compared to 2020, changes in Purchased power and fuel by region were approximately as follows:



	Variance		% Change(a)		Three Months Ended September 30, 2021	Variance		% Change(a)		Nine Months Ended September 30, 2021
Mid-Atlantic	$	20	2.8	%	• no significant changes	$	63	3.4	%	• favorable purchased power and net capacity impact of $45 primarily due to lower load and higher capacity prices earned partially offset by lower cleared capacity volumes • favorable settlement of economic hedges of $40 due to settled prices relative to hedged prices
Midwest	(37)		(12.6)	%	• unfavorable purchased power of $(35) primarily due to lower nuclear generation due to higher nuclear outage days, higher energy prices, and higher load	(101)		(12.2)	%	• unfavorable purchased power and net capacity impact of $(140) primarily due to lower nuclear generation due to higher nuclear outage days, higher energy prices, lower cleared capacity volumes, and lower capacity prices
New York	12		9.9	%	• no significant changes	43		12.8	%	• favorable settlement of economic hedges of $70 due to settled prices relative to hedged prices; partially offset by • unfavorable purchased power and net capacity impact of $(35) primarily due to higher energy prices partially offset by higher capacity prices earned
ERCOT	4		2.2	%	• favorable purchased power of $85 primarily due to a favorable recovery related to the February 2021 extreme cold weather event and lower load; partially offset by • unfavorable settlement of economic hedges of $(75) due to settled prices relative to hedged prices	(1,383)		(322.4)	%	• unfavorable purchased power of $(750) primarily due to higher energy prices primarily during the February 2021 extreme cold weather event • unfavorable settlement of economic hedges of $(460) due to settled prices relative to hedged prices • unfavorable fuel cost of $(150) primarily due to higher gas prices
Other Power Regions	(165)		(18.7)	%	• unfavorable purchased power and net capacity impact of $(190) primarily due to lower generation, higher energy prices, and lower cleared capacity volumes; partially offset by • favorable settlement of economic hedges of $45 due to settled prices relative to hedged prices	(719)		(29.4)	%	• unfavorable purchased power and net capacity impact of $(680) primarily due to higher load, lower generation, higher energy prices, lower cleared capacity volumes, and lower capacity prices • unfavorable RPS expense of $(55) primarily due to higher prices and higher load • unfavorable fuel cost of $(40) primarily due to higher gas prices; partially offset by • favorable settlement of economic hedges of $80 due to settled prices relative to hedged prices
Other	(237)		(72.0)	%	• unfavorable net gas purchase costs and settlement of economic hedges of $(190) • unfavorable accelerated nuclear fuel amortization associated with announced early plant retirements of $(20)	(1,011)		(79.2)	%	• unfavorable net gas purchase costs and settlement of economic hedges of $(830) • unfavorable accelerated nuclear fuel amortization associated with announced early plant retirements of $(125)
Mark-to-market(b)	1,171				• gains on economic hedging activities of $1,389 in 2021 compared to gains of $218 in 2020	1,966				• gains on economic hedging activities of $2,200 in 2021 compared to gains of $234 in 2020
Total	$	768	33.2	%		$	(1,142)	(16.4)	%

__________

(a)% Change in mark-to-market is not a meaningful measure.

(b)See Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on mark-to-market gains and losses.

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The changes in Operating and maintenance expenseconsisted of the following:


	Three Months Ended September 30, 2021		Nine Months Ended September 30, 2021
	(Decrease) Increase		Increase (Decrease)
Asset impairments	$	(456)	$	23
Plant retirements and divestitures(a)	(314)		(706)
ARO update	(49)		(49)
Labor, other benefits, contracting, and materials	(25)		(29)
Change in environmental liabilities	(18)		(18)
Cost management program	(12)		(24)
Corporate allocations	(8)		(19)
Credit loss expense	3		46
Acquisition related costs	6		17
Separation costs	16		25
Nuclear refueling outage costs, including the co-owned Salem plants	17		(70)
Other	41		29
Total decrease	$	(799)	$	(775)

__________

(a)Primarily reflects contractual offset of accelerated depreciation and amortization associated with Generation's previous decision to early retire the Byron and Dresden nuclear facilities. See Note 8 — Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements for additional information.

Depreciation and amortization expense increased for the three and nine months ended September 30, ~~2017 as~~2021 compared to the same period in ~~2016, consisted of~~2020, primarily due to the ~~following:~~

Three Months Ended
September 30, Nine Months Ended
September 30,

Increase (Decrease)^(a)

Increase (Decrease)^(a)
Labor, other benefits, contracting, materials^(b)
$ (8 ) $ 74
Nuclear refueling outage costs, including the co-owned Salem plants^(c)
(12 ) 88
Corporate allocations 19
29
Merger and integration costs^(d)
(4 ) 36
Merger commitments —
(3 )
Plant retirements and divestitures^(e)
41
(15 )
Cost management program 5
(7 )
ARO update (3 ) (4 )
Long-lived asset impairments^(f)
25
288
Pension and non-pension postretirement benefits expense 3
4
Allowance for uncollectible accounts 12
35
Accretion expense^(g)
10
27
Other (50 ) (14 )
Increase in operating and maintenance expense $ 38
$ 538

~~_________~~


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


~~(b)~~	~~Reflects increased salaries, wages and contracting costs primarily related to the acquisition of the FitzPatrick nuclear facility beginning on March 31, 2017.~~


~~(c)~~	Primarily reflects a decrease in the number of nuclear outage days for the three months ended September 30, 2017 compared to 2016 and an increase in the number of nuclear outage days for the nine months ended September 30, 2017 compared to the same period in 2016.


~~(d)~~	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.


~~(e)~~	Represents the announcement of the early retirement of Generation's TMI nuclear facility in 2017 compared to the previous decision to early retire Generation's Clinton and Quad Cities nuclear facilities in 2016.


~~(f)~~	~~Primarily reflects charges to earnings related to impairments as a result of the EGTP assets held for sale in 2017 and impairment of Upstream assets and certain wind projects in 2016.~~


~~(g)~~	~~Reflects the impact of increased accretion expenses primarily due to the acquisition of FitzPatrick on March 31, 2017.~~

~~Depreciation and Amortization~~

~~Depreciation~~accelerated depreciation and amortization ~~expense~~associated with Generation's previous decision to early retire the Byron and Dresden nuclear facilities. This decision was reversed on September 15, 2021 and depreciation for Byron and Dresden was adjusted beginning September 15, 2021 to reflect the extended useful life estimates. A portion of this accelerated depreciation and amortization is offset in Operating and maintenance expense.

Gain on sales of assets and businessesincreased for the three and nine months ended September 30, ~~2017~~2021 compared to the ~~three~~same period in 2020, primarily due to gains on sales of equity investments that became publicly traded entities in the fourth quarter of 2020 and the first half of 2021, and additionally increased for the nine months ended September 30, ~~2016 decreased primarily due to lower accelerated depreciation and amortization as a result of the 2017 decision to early retire the TMI nuclear facility~~2021 compared to the ~~previous decision~~same period in ~~2016~~2020, due to ~~early retire the Clinton and Quad Cities nuclear facilities.~~a gain on sale of Generation's solar business.

~~Taxes Other Than Income~~

~~Taxes other than income taxes, which can vary period to period, include non-income municipal and state utility taxes, real estate taxes and payroll taxes. Taxes other than income~~Interest expense, net decreased for the ~~three and~~ nine months ended September 30, ~~2017~~2021 compared to the ~~three and nine months ended September 30, 2016 increased~~same period in 2020, primarily due to ~~increased property~~

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~~taxes as a result~~mark-to-market gains related to the EGR IV interest swaps entered into in December 2020 and decreases in interest rates. See Note 17 — Debt and Credit Agreements of the ~~addition of FitzPatrick, increased gross receipts tax expense, and increased sales and use tax expense.~~Exelon 2020 Form 10-K for additional information on the interest swaps.

~~(Loss) gain on Sales of Assets~~

~~Loss on sales of assets~~Other, net decreased for the three months ended September 30, ~~2017~~2021 compared to the ~~three months ended September 30, 2016 remained relatively stable. Gain on sales of assets~~same period in 2020 and increased for the nine months ended September 30, ~~2017~~2021 compared to the ~~nine months ended September 30, 2016 decreased primarily~~same period in 2020, due to ~~the gain associated with Generation's sale of the New Boston generating site in 2016.~~

~~Bargain Purchase Gain~~

Bargain purchase gain for the three and nine months ended September 30, 2017 compared to the three and nine months ended September 30, 2016 increased as a result of the gain associated with the FitzPatrick acquisition. Refer to Note 4 — Mergers, Acquisitions and Dispositions of the Combined Notes to the Consolidated Financial Statements for additional information.

~~Interest Expense, net~~

Interest expense, net for the three and nine months ended September 30, 2017 compared to the three and nine months ended September 30, 2016 increased primarily due to the impact of project in-service dates on the capitalization of interest and higher outstanding debt.

~~Other, Net~~

Other, net for the three and nine months ended September 30, 2017 compared to the three and nine months ended September 30, 2016 increased primarily due to the change in the realized and unrealized gains and losses related to NDT funds of Non-Regulatory Agreement Units asactivity described in the table ~~below. Other, net also reflects $37 million~~below:

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	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
Net unrealized (losses) gains on NDT funds(a)	$	(94)	$	254	$	33	$	1
Net realized gains on sale of NDT funds(a)	101		—		349		58
Interest and dividend income on NDT funds(a)	26		23		73		69
Contractual elimination of income tax expense(b)	11		89		150		46
Net unrealized losses from equity investments(c)	(179)		—		(83)		—
Other	20		1		39		25
Total other, net	$	(115)	$	367	$	561	$	199

__________

(a)Unrealized (losses) gains, realized gains, and ~~$39 million~~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.

(c)Net unrealized losses from equity investments that became publicly traded entities in the fourth quarter of 2020 and the first half of 2021.

Effective income tax rates were 21.7% and 45.7% for the three months ended September 30, ~~2017~~2021 and ~~2016,~~2020, respectively, and ~~$129 million~~(1,350.0)% and ~~$84 million~~7.7% for the nine months ended September 30, ~~2017~~2021 and ~~2016, respectively, related~~2020, respectively. See Note 10 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.

Net income attributable to noncontrolling interests decreased for the three months ended September 30, 2021 compared to the ~~contractual elimination~~same period in 2020, primarily due to lower net gains on NDT fund investments for CENG prior to Generation's acquisition of ~~income tax expense (benefit) associated with~~EDF's interest in CENG on August 6, 2021, and the noncontrolling portion of a wind project impairment, and increased for the nine months ended September 30, 2021 compared to the same period in 2020, primarily due to higher net gains on NDT ~~funds~~fund investments for CENG prior to Generation's acquisition of EDF's interest in CENG on August 6, 2021, partially offset by the ~~Regulatory Agreement Units. Refer~~noncontrolling portion of a wind project impairment.

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Results of Operations — ComEd


	Three Months Ended September 30,				Favorable (Unfavorable) Variance		Nine Months Ended September 30,				Favorable (Unfavorable) Variance
	2021		2020				2021		2020
Operating revenues	$	1,789	$	1,643	$	146	$	4,840	$	4,499	$	341
Operating expenses
Purchased power	703		606		(97)		1,728		1,557		(171)
Operating and maintenance	330		321		(9)		969		1,173		204
Depreciation and amortization	304		294		(10)		893		841		(52)
Taxes other than income taxes	91		81		(10)		243		227		(16)
Total operating expenses	1,428		1,302		(126)		3,833		3,798		(35)

Operating income	361		341		20		1,007		701		306
Other income and (deductions)
Interest expense, net	(98)		(95)		(3)		(292)		(287)		(5)
Other, net	13		10		3		35		32		3
Total other income and (deductions)	(85)		(85)		—		(257)		(255)		(2)
Income before income taxes	276		256		20		750		446		304
Income taxes	56		60		4		141		142		1
Net income	$	220	$	196	$	24	$	609	$	304	$	305

Three Months Ended September 30, 2021 Compared to Three Months Ended September 30, 2020. Net incomeincreased by $24 million as compared to the same period in 2020, primarily due to increased electric distribution formula rate earnings (reflecting the impacts of higher rate base and higher allowed electric distribution ROE due to an increase in treasury rates).

Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020. Net income increased by $305 million as compared to the same period in 2020, primarily due to increases in electric distribution formula rate earnings (reflecting the impacts of higher rate base and higher allowed electric distribution ROE due to an increase in treasury rates) and payments that ComEd made in 2020 under the Deferred Prosecution Agreement. See Note ~~13 — Nuclear Decommissioning~~15 - Commitments and Contingencies of the Combined Notes to the Consolidated Financial Statements for additional information ~~regarding NDT funds.~~

The following table provides unrealized and realized gains and losses on the NDT funds of the Non-Regulatory Agreement Units recognized in Other, net for the three and nine months ended September 30, 2017 and 2016:

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Net unrealized gains on decommissioning trust funds $ 111

$ 116
$ 347
$ 216
Net realized gains on sale of decommissioning trust funds 33
12
82
26

~~Equity in Losses of Unconsolidated Affiliates~~

~~Equity in losses of unconsolidated affiliates for the three and nine months ended September 30, 2017 compared to the three and nine ended September 30, 2016 remained relatively stable.~~

~~Effective Income Tax Rate~~

Generation's effective income tax rate was 40.3% and 38.4% for the three months ended September 30, 2017 and 2016, respectively. Generation's effective income tax rate was 28.8% and 33.9% for the nine months ended September 30, 2017 and 2016, respectively. See Note 12 — Income Taxes of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in the effective income tax rate.

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~~Results of Operations — ComEd~~

Three Months Ended
September 30,
Favorable
(Unfavorable)
Variance
Nine Months Ended
September 30,
Favorable
(Unfavorable)
Variance
2017 2016 2017 2016
Operating revenues $ 1,571
$ 1,497
$ 74
$ 4,227
$ 4,031
$ 196
Purchased power expense 529
454
(75 ) 1,241
1,141
(100 )
Revenues net of purchased power expense^(a)(b)
1,042
1,043
(1 ) 2,986
2,890
96
Other operating expenses
Operating and maintenance 346
377
31
1,096
1,113
17
Depreciation and amortization 212
196
(16 ) 631
574
(57 )
Taxes other than income 80
82
2
223
222
(1 )
Total other operating expenses 638
655
17
1,950
1,909
(41 )
Gain on sales of assets —
1
(1 ) —
6
(6 )
Operating income 404
389
15
1,036
987
49
Other income and (deductions)
Interest expense, net (89 ) (197 ) 108
(275 ) (374 ) 99
Other, net 5
(80 ) 85
14
(72 ) 86
Total other income and (deductions) (84 ) (277 ) 193
(261 ) (446 ) 185
Income before income taxes 320
112
208
775
541
234
Income taxes 131
75
(56 ) 328
244
(84 )
Net income $ 189
$ 37
$ 152
$ 447
$ 297
$ 150

~~_________~~

~~(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).

~~Net Income~~

~~Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016.~~ ComEd’s Net income for the three months ended September 30, 2017 was higher than the same period in 2016, primarily due to the recognition of the penalty and the after-tax interest due on the asserted penalty related to the ~~Tax Court's decision on Exelon's like-kind exchange tax position~~Deferred Prosecution Agreement.

The changes in the third quarter of 2016 and increased electric distribution and transmission formula rate earnings (reflecting the impacts of increased capital investment and higher allowed electric distribution ROE). The higher Net income was partially offset by the impact of weather conditions in the third quarter of 2016. See Revenue Decoupling discussion below for additional information on the impact of weather.

~~Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016.~~ ComEd’s Net income for the nine months ended September 30, 2017 was higher than the same period in 2016, primarily due to the recognition of the penalty and the after-tax interest due on the asserted penalty related to the Tax Court's decision on Exelon's like-kind exchange tax position in the third quarter of 2016 and increased electric distribution and transmission formula rate earnings (reflecting the impacts of increased capital investment and higher allowed electric distribution ROE). The higher Net income was partially offset by additional tax and interest recorded in the second quarter of 2017 relating to Exelon's like-kind exchange tax position and the impact of weather conditions in the second and third quarters of 2016. See Revenue Decoupling discussion below for additional information on the impact of weather.

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~~Revenues Net of Purchased Power Expense~~

~~There are certain drivers of~~ Operating revenues that are fully offset by their impact on Purchased power expense, such as commodity, REC, and ZEC procurement costs and participation in customer choice programs. ComEd is permitted to recover electricity, REC, and ZEC procurement costs from retail customers without mark-up. Therefore, these costs have no significant impact on Revenue net of purchased power expense. See Note 3 — Regulatory Matters of the Exelon 2016 Form 10-K for additional information on ComEd’s electricity procurement process.

All ComEd customers have the choice to purchase electricity from a competitive electric generation supplier. Customer choice programs do not impact ComEd’s volume of deliveries, but do affect ComEd’s Operating revenues related to supplied energy, which is fully offset in Purchased power expense. Therefore, customer choice programs have no impact on Revenue net of purchased power expense.

~~Retail deliveries purchased from competitive electric generation suppliers (as a percentage of kWh sales) for the three and nine months ended September 30, 2017 and 2016,~~ consisted of the following:


	Three Months Ended September 30, 2021		Nine Months Ended September 30, 2021
	Increase		Increase
Distribution	$	25	$	98
Transmission	10		14
Energy efficiency	10		34
Other	8		20




	53		166
Regulatory required programs	93		175
Total increase	$	146	$	341

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Electric 68 % 70 % 70 % 72 %

~~Retail customers purchasing electric generation from competitive electric generation suppliers at September 30, 2017 and 2016 consisted of the following:~~

September 30, 2017 September 30, 2016
Number of customers % of total retail customers Number of customers % of total retail customers
Electric 1,360,800
34 % 1,526,900
39 %

~~The changes in ComEd’s Revenue net of purchased power expense for the three and nine months ended September 30, 2017, compared to the same period in 2016 consisted of the following:~~

Three Months Ended
September 30, 2017 Nine Months Ended
September 30, 2017
Increase (Decrease) Increase (Decrease)
Weather^(a)
$ (34 ) $ (37 )
Volume^(a)
(5 ) (11 )
Electric distribution revenue 59
119
Transmission revenue 11
45
Energy efficiency revenue^(b)
5
6
Regulatory required programs^(b)
(39 ) (24 )
Uncollectible accounts recovery, net (3 ) (5 )
Pricing and customer mix^(a)
—
(1 )
Other 5
4
Total increase (decrease) $ (1 ) $ 96

~~_________~~

~~(a)~~

These changes only reflect the 2016 impacts of weather, volume, and pricing and customer mix. As further described below, pursuant to the revenue decoupling provision in FEJA, ComEd began recording an adjustment to revenue in the first quarter of 2017 to eliminate the favorable or unfavorable impacts associated with variations in delivery volumes associated with above or below normal weather, number of customers or usage per customer.


~~(b)~~	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.

Revenue Decoupling.The demand for electricity is affected by weather ~~conditions. Very warm weather in summer months~~conditions and ~~very cold weather in other months are referred to as "favorable weather conditions" because these weather conditions result in increased~~ customer usage. ~~Conversely, mild~~Operating revenues are not impacted by abnormal weather, ~~reduces demand.~~

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~~Table~~usage per customer or number of ~~Contents~~

~~Under EIMA, ComEd's electric distribution formula rate provided for an adjustment to future billings if its earned ROE fell outside~~customers as a 50 bps collar of its allowed ROE, which partially eliminated the impacts of weather and load on ComEd's revenue. As allowed under FEJA, ComEd will revise its electric distribution formula rate to eliminate the ROE collar beginning with the reconciliation filed in 2018 for the 2017 calendar year. Eliminationresult of the ROE collar effectively offsets the favorable or unfavorable impacts to Operating revenues associated with variations in delivery volumes associated with above or below normal weather, numbers of customers or usage per customer. ComEd began recognizing the impacts of this change beginning in the first quarter of 2017. During the threerevenue decoupling mechanisms as allowed by FEJA.

Distribution Revenue. EIMA and nine months ended September 30, 2017, ComEd recorded a decrease to Electric distribution revenues of approximately $15 million and an increase to Electric distribution revenues of approximately $21 million, respectively, to eliminate weather and load impacts.

Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 30-year period in ComEd's service territory with cooling degree days generally having a more significant impact to ComEd, particularly during the summer months. The changes in heating and cooling degree days in ComEd’s service territory for the three and nine months ended September 30, 2017 and 2016, consisted of the following:

Heating and Cooling Degree-Days % Change
Three Months Ended September 30, 2017 2016 Normal 2017 vs. 2016 2017 vs. Normal
Heating Degree-Days 42
23
97
82.6 % (56.7 )%
Cooling Degree-Days 699
840
641
(16.8 )% 9.0 %

Nine Months Ended September 30,
Heating Degree-Days 3,269
3,678
3,972
(11.1 )% (17.7 )%
Cooling Degree-Days 962
1,130
882
(14.9 )% 9.1 %

~~Electric Distribution Revenue.~~ ~~EIMA provides~~FEJA provide for a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs that the ICC determines are prudently and reasonably incurred in a given year. ~~Under EIMA, electric~~Electric distribution revenue varies from year to year based upon fluctuations in the underlying costs, (e.g., severe weather and storm restoration), investments being recovered, and allowed ROE. ComEd’s allowed ROE is the annual average rate on 30-year treasury notes plus 580 basis points. In addition, ComEd's allowed ROE is subject to reduction if ComEd does not deliver the reliability and customer service benefits to which it has committed over the ten-year life of the investment program. Electric distribution revenue increased ~~during~~for the three and nine months ended September 30, ~~2017, primarily~~2021 as

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compared to the same period in 2020, due to ~~increased capital investment, increased Depreciation expense, and~~ higher allowed ROE due to an increase in treasury rates ~~as compared to~~and the same period in 2016 and due to revenue decoupling impacts (as described above) during the nine months ended September 30, 2017. See Depreciation and amortization expense discussions below, and Note 5 — Regulatory Mattersimpact of ~~the Combined Notes to Consolidated Financial Statements for additional information.~~a higher rate base.

Transmission Revenue.Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered, and the highest daily peak load, which is updated annually in January based on the prior calendar year. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. ~~For~~Transmission revenue increased for the three and nine months ended September 30, ~~2017, ComEd recorded increased transmission revenue due to increased capital investment, higher Depreciation expense and increased highest daily peak load~~2021 as compared to the same ~~period~~periods in ~~2016. See Operating and maintenance expense below and Note 5 — Regulatory Matters~~2020 primarily due to the impact of ~~the Combined Notes to Consolidated Financial Statements for additional information.~~a higher rate base.

Energy Efficiency Revenue. ~~Beginning June 1, 2017,~~ FEJA provides for a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs that the ICC determines are prudently and reasonably incurred in a given year. ~~Under~~Under FEJA, energy efficiency revenue varies from year to year based upon ~~fluctuations~~fluctuations in the underlying costs, investments being recovered, and allowed ROE. ~~ComEd’s allowed ROE~~Energy efficiency revenue remained relatively consistent for the three months ended September 30, 2021 as compared to the same period in 2020. Energy efficiency revenue increased during the nine months ended September 30, 2021 as compared to the same period in 2020, primarily due to increased regulatory asset amortization, which is fully recoverable.

Other Revenue primarily includes assistance provided to other utilities through mutual assistance programs. Other revenue increased for the ~~annual average rate on 30-year treasury notes plus 580 basis points. Beginning January 1, 2018, ComEd’s allowed ROE is subject~~three and nine months ended September 30, 2021 as compared to ~~a maximum downward or upward adjustment of 200 basis points if ComEd’s cumulative persisting annual MWh savings falls short of or exceeds specified percentage benchmarks of its annual incremental~~the same period in 2020, which primarily reflects mutual assistance revenues associated with storm restoration efforts.

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~~savings goal. See Depreciation and amortization expense discussions below, and Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.~~

Regulatory Required ~~Programs.~~ ~~This~~ Programs represents ~~the change in Operating~~ revenues collected under approved ~~rate~~ riders to recover costs incurred for regulatory programs such as ~~ComEd’s purchased power administrative~~recoveries under the credit loss expense tariff, environmental costs associated with MGP sites, and ~~energy efficiency~~costs related to electricity, ZEC and ~~demand response through June 1, 2017 pursuant to FEJA.~~REC procurement. The riders are designed to provide full and current cost recovery. ~~An equal and offsetting amount has been~~The costs of these programs are included in ~~Operating and maintenance expense. See~~Purchased power expense, Operating and maintenance expense, ~~discussion below~~Depreciation and amortization expense and Taxes other than income. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries as ComEd remains the distribution service provider for ~~additional information on included programs.~~

~~Uncollectible Accounts Recovery, Net.~~ ~~Uncollectible accounts recovery, net represents recoveries under ComEd’s uncollectible accounts tariff. See~~all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, ComEd either acts as the billing agent or the competitive supplier separately bills its own customers, and ~~maintenance~~therefore ComEd does not record Operating revenues or Purchased power expense ~~discussion below for additional information on this tariff.~~

~~Other.~~ ~~Other revenue, which can vary period to period, includes rental revenue, revenue~~ related to ~~late payment charges, assistance provided~~the electricity. For customers that choose to ~~other utilities through mutual assistance programs, recoveries~~purchase electric generation from ComEd, ComEd is permitted to recover the electricity, ZEC, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power expense related to the electricity, ZECs, and RECs.

See Note 5 — Segment Information of ~~environmental costs associated with MGP sites, and recoveries~~the Combined Notes to Consolidated Financial Statements for the presentation of ~~energy procurement costs.~~ComEd's revenue disaggregation.

~~Operating and Maintenance Expense~~

Three Months Ended
September 30,
Increase
(Decrease)
Nine Months Ended
September 30, Increase (Decrease)
2017 2016 2017 2016
Operating and maintenance expense — baseline $ 344
$ 336
$ 8
$ 1,000
$ 993
$ 7
Operating and maintenance expense — regulatory required programs^(a)
2
41
$ (39 ) 96
120
(24 )
Total operating and maintenance expense $ 346

$ 377

$ (31 )
$ 1,096

$ 1,113

$ (17 )

~~_________~~


~~(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.

The increase ~~in Operating~~of $97 million and ~~maintenance expense~~of $171 million for the three and nine months ended September 30, ~~2017~~2021 compared to the same period in ~~2016,~~2020, respectively, in Purchased power expense is offset in Operating revenues as part of regulatory required programs.

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The changes in Operating and maintenance expense consisted of the following:


	Three Months Ended September 30, 2021		Nine Months Ended September 30, 2021
	Increase (Decrease)		(Decrease) Increase
Deferred Prosecution Agreement payments(a)	$	—	$	(200)
Storm-related costs	4		(10)
Pension and non-pension postretirement benefits expense	1		3
Labor, other benefits, contracting and materials	(4)		6

BSC costs	6		11

Other(b)	(3)		(25)
	4		(215)
Regulatory required programs(c)	5		11
Total increase (decrease)	$	9	$	(204)

Three Months Ended
September 30, 2017 Nine Months Ended
September 30, 2017
Increase (Decrease) Increase (Decrease)
Baseline
Labor, other benefits, contracting and materials $ (5 ) $ (11 )
Pension and non-pension postretirement benefits expense 1
2
Storm-related costs 1
1
Uncollectible accounts expense — provision^(a)
(4 ) (8 )
Uncollectible accounts expense — recovery, net^(a)
1
3
BSC costs^(b)
21
35
Other (7 ) (15 )
8
7
Regulatory required programs
Energy efficiency and demand response programs^(c)
(39 ) (24 )
Decrease in operating and maintenance expense $ (31 ) $ (17 )
__________

~~_________~~

~~(a)~~

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 and nine months ended September 30, 2017, ComEd recorded a net decrease 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.


~~(b)~~	For the three and nine months ended September 30, 2017, includes the $8 million write-off of a regulatory asset related to Constellation merger and integration costs for which recovery is no longer expected.


~~(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)See Note 15 - Commitments and Contingencies of the Combined Notes to the Consolidated Financial Statements for additional information.

~~215~~

~~Table~~(b)Primarily reflects the absence of ~~Contents~~an impairment charge related to the acquisition of transmission assets in 2020.

(c)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.

~~Depreciation and Amortization Expense~~

The ~~increase~~changes in Depreciation and amortization expense ~~during the three and nine months ended September 30, 2017, compared to the same period in 2016,~~ consisted of the following:


	Three Months Ended September 30, 2021		Nine Months Ended September 30, 2021
	Increase (Decrease)		Increase
Depreciation and amortization(a)	$	12	$	36
Regulatory asset amortization(b)	(2)		16

Total increase	$	10	$	52

Three Months Ended
September 30, 2017 Nine Months Ended
September 30, 2017
Increase (Decrease) Increase (Decrease)
Depreciation expense^(a)
$ 14
$ 47
Regulatory asset amortization^(b)
1
2
Other 1
8
Total increase $ 16
$ 57
__________

~~_________~~


~~(a)~~	~~Primarily reflects ongoing capital expenditures for the three and nine months ended September 30, 2017.~~


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

~~Taxes Other Than Income~~(a)Reflects ongoing capital expenditures.

~~Taxes other than income, which can vary year to year, include municipal~~(b)Includes amortization of ComEd's energy efficiency formula rate regulatory asset and state utility taxes, real estate taxes and payroll taxes. Taxes other than income taxes remained relatively consistent for the three and nine months ended September 30, 2017, compared to the same period in 2016.

~~Gain on Sales of Assets~~

~~The decrease in Gain on sales of assets during the nine months ended September 30, 2017, compared to the same period in 2016, is primarily due to the sale of land during March 2016.~~

~~Interest Expense, Net~~

~~The changes in interest expense, net, for the three and nine months ended September 30, 2017, compared to the same period in 2016, consisted of the following:~~

Three Months Ended
September 30, 2017 Nine Months Ended
September 30, 2017
Increase (Decrease) Increase (Decrease)
Interest expense related to uncertain tax positions^(a)
$ (110 ) $ (103 )
Interest expense on debt (including financing trusts) (1 ) 3
Other 3
1
Decrease in interest expense, net $ (108 ) $ (99 )

~~_________~~


~~(a)~~	Primarily reflects the recognition of the after-tax interest due on the asserted penalty related to the Tax Court's decision on Exelon's like-kind exchange tax position in the third quarter of 2016, partially offset by additional interest recorded in the second quarter of 2017 related to Exelon's like-kind exchange tax position.

~~Other, Net~~

~~Other, net, decreased during the three and nine months ended September 30, 2017, compared to the same period in 2016 primarily due to the recognition of the penalty~~amortization related to the ~~Tax Court's decision on Exelon's like-kind exchange tax position in the third quarter of 2016.~~August 2020 storm regulatory asset.

Effective ~~Income Tax Rate~~

~~ComEd's effective~~ income tax ~~rate was 40.9%~~rates were 20.3% and ~~67.0%~~23.4% for the three months ended September 30, ~~2017~~2021 and ~~2016, respectively. ComEd's effective income tax rate was 42.3%~~2020, respectively, and ~~45.1%~~18.8% and 31.8% for the nine months ended September 30, ~~2017~~2021 and ~~2016,~~2020, respectively. The decreases in the effective income tax rates for the three and nine months ended September 30, 2017 as compared to the same period in 2016 are primarily due to a non-deductible penalty incurred in 2016. See Note 1210 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

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~~ComEd Electric Operating Statistics and Revenue Detail~~

Three Months Ended
September 30, % Change
Weather-
Normal
% Change
Nine Months Ended
September 30, % Change
Weather-
Normal
% Change
Retail Deliveries to Customers (in GWhs) 2017 2016 2017 2016
Retail Deliveries^(a)

Residential 8,004
9,014
(11.2 )% (0.6 )% 20,164
21,738
(7.2 )% (1.3 )%
Small commercial & industrial 8,488
8,833
(3.9 )% (1.0 )% 23,634
24,447
(3.3 )% (1.6 )%
Large commercial & industrial 7,232
7,565
(4.4 )% (2.5 )% 20,712
21,057
(1.6 )% (0.5 )%
Public authorities & electric railroads 302
308
(1.9 )% (1.7 )% 928
947
(2.0 )% (1.4 )%
Total retail deliveries 24,026

25,720
(6.6 )% (1.3 )% 65,438

68,189
(4.0 )% (1.1 )%

As of September 30,
Number of Electric Customers 2017 2016
Residential 3,610,091
3,578,846
Small commercial & industrial 376,309
372,603
Large commercial & industrial 1,954
2,010
Public authorities & electric railroads 4,763
4,738
Total 3,993,117

3,958,197

Three Months Ended
September 30, Nine Months Ended
September 30,
Electric Revenue 2017 2016
%
Change
2017 2016
%
Change
Retail Sales^(a)

Residential $ 825
$ 786
5.0 % $ 2,108
$ 2,018
4.5 %
Small commercial & industrial 369
356
3.7 % 1,051
1,007
4.4 %
Large commercial & industrial 121
126
(4.0 )% 352
350
0.6 %
Public authorities & electric railroads 11
10
10.0 % 34
33
3.0 %
Total retail 1,326
1,278
3.8 % 3,545
3,408
4.0 %
Other revenue^(b)
245
219
11.9 % 682
623
9.5 %
Total electric revenue^(c)
$ 1,571
$ 1,497
4.9 % $ 4,227
$ 4,031
4.9 %

~~_________~~


~~(a)~~	Reflects delivery revenue and 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. For customers purchasing electricity from ComEd, revenue also reflects the cost of energy and transmission.


~~(b)~~	Other revenue primarily includes transmission revenue from PJM. Other revenue also includes rental revenue, revenue related to late payment charges, revenue from other utilities for mutual assistance programs and recoveries of remediation costs associated with MGP sites.


~~(c)~~	Includes operating revenues from affiliates totaling $3 million and $4 million for the three and nine months ended September 30, 2017 and 2016, and $12 million and $12 million for the nine months ended September 30, 2017 and 2016, respectively.

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Results of Operations — PECO


	Three Months Ended September 30,				Favorable (Unfavorable) Variance		Nine Months Ended September 30,				Favorable (Unfavorable) Variance
	2021		2020				2021		2020
Operating revenues	$	818	$	813	$	5	$	2,399	$	2,306	$	93
Operating expenses
Purchased power and fuel	277		269		(8)		800		768		(32)
Operating and maintenance	263		251		(12)		706		742		36
Depreciation and amortization	86		85		(1)		259		259		—
Taxes other than income taxes	51		53		2		143		131		(12)
Total operating expenses	677		658		(19)		1,908		1,900		(8)

Operating income	141		155		(14)		491		406		85
Other income and (deductions)
Interest expense, net	(40)		(39)		(1)		(119)		(108)		(11)
Other, net	7		6		1		20		12		8
Total other income and (deductions)	(33)		(33)		—		(99)		(96)		(3)
Income before income taxes	108		122		(14)		392		310		82
Income taxes	(3)		(16)		(13)		9		(7)		(16)


Net income	$	111	$	138	$	(27)	$	383	$	317	$	66

Three Months Ended
September 30,
Favorable
(Unfavorable)
Variance
Nine Months Ended
September 30, Favorable
(Unfavorable)
Variance
2017 2016 2017 2016
Operating revenues $ 715
$ 788
$ (73 ) $ 2,141
$ 2,293
$ (152 )
Purchased power and fuel expense 235
272
37
719
809
90
Revenues net of purchased power and fuel expense^(a)
480
516
(36 ) 1,422
1,484
(62 )
Other operating expenses
Operating and maintenance 197
199
2
595
604
9
Depreciation and amortization 72
67
(5 ) 213
201
(12 )
Taxes other than income 42
46
4
116
126
10
Total other operating expenses 311
312
1
924
931
7
Operating income 169
204
(35 ) 498
553
(55 )
Other income and (deductions)
Interest expense, net (31 ) (30 ) (1 ) (93 ) (92 ) (1 )
Other, net 2
2
—
6
6
—
Total other income and (deductions) (29 ) (28 ) (1 ) (87 ) (86 ) (1 )
Income before income taxes 140
176
(36 ) 411
467
(56 )
Income taxes 28
54
26
84
121
37
Net income $ 112
$ 122
$ (10 ) $ 327
$ 346
$ (19 )

~~_________~~

~~(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.

~~Net Income~~

Three Months Ended September 30, ~~2017~~2021 Compared to Three Months Ended September 30, ~~2016.~~ ~~PECO's~~ 2020. Net income decreased ~~from the same period in 2016,~~by $27 million primarily due to ~~lower Revenues~~an increase in storm cost activity, net of ~~purchased power and fuel from unfavorable weather conditions in PECO's service territory.~~tax repair deductions.

Nine Months Ended September 30, ~~2017~~2021 Compared to Nine Months Ended September 30, ~~2016.~~ ~~PECO's~~ 2020. Net income ~~decreased from the same period in 2016,~~ increased by $66 million primarily due to ~~lower Revenues~~favorable weather, an increase in primarily electric volume, and a decrease in storm cost activity, net of ~~purchased power and fuel from unfavorable weather conditions~~tax repair deductions.

The changes in ~~PECO's service territory.~~

~~Revenues Net of Purchased Power and Fuel Expense~~

Electric and natural gas revenue and purchased power and fuel expense are affected by fluctuations in commodity procurement costs. PECO's electric supply and natural gas cost rates charged to customers are subject to adjustments at least quarterly that are designed to recover or refund the difference between the actual cost of electric supply and natural gas and the amount included in rates in accordance with the PAPUC's GSA and PGC, respectively. Therefore, fluctuations in electric supply and natural gas procurement costs have no impact on electric and natural gas revenue net of purchased power and fuel expense.

Electric and natural gas revenue and purchased power and fuel expense are also affected by fluctuations in participation in the Customer Choice Program. All PECO customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers, respectively. The customers' choice of suppliers does not impact the volume of deliveries, but affects revenue collected from customers related to supplied energy and natural gas service. Customer choice program activity has no impact on electric and natural gas revenue net of purchased power and fuel expense.

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Retail deliveries purchased from competitive electric generation and natural gas suppliers (as a percentage of kWh and mmcf sales, respectively) for the three and nine months ended September 30, 2017 and 2016,Operating revenues consisted of the following:


	Three Months Ended September 30, 2021						Nine Months Ended September 30, 2021
	Increase (Decrease)						Increase (Decrease)
	Electric		Gas		Total		Electric		Gas		Total
Weather	$	(7)	$	(7)	$	(14)	$	17	$	17	$	34
Volume	2		7		9		19		—		19
Pricing	2		4		6		(1)		(1)		(2)
Transmission	4		—		4		7		—		7
Other	—		—		—		(1)		—		(1)
	1		4		5		41		16		57
Regulatory required programs	3		(3)		—		46		(10)		36
Total increase	$	4	$	1	$	5	$	87	$	6	$	93

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Electric 70 % 69 % 71 % 70 %
Natural Gas 29 % 31 % 26 % 26 %

~~Retail customers purchasing electric generation and natural gas from competitive electric generation and natural gas suppliers at September 30, 2017 and 2016 consisted of the following:~~

September 30, 2017 September 30, 2016
Number of customers % of total retail customers Number of customers % of total retail customers
Electric 570,500
35 % 581,600
36 %
Natural Gas 82,600
16 % 81,300
16 %

The changes in PECO’s Operating revenues net of purchased power and fuel expense for the three and nine months ended September 30, 2017 compared to the same period in 2016 consisted of the following:

Three Months Ended
September 30, 2017 Nine Months Ended
September 30, 2017
Increase (Decrease) Increase (Decrease)
Electric Natural Gas Total Electric Natural Gas Total
Weather $ (48 ) $ —
$ (48 ) $ (45 ) $ (3 ) $ (48 )
Volume —
1
1
(12 ) 4
(8 )
Pricing 9
—
9
13
—
13
Regulatory required programs (6 ) —
(6 ) (29 ) —
(29 )
Other 7
1
8
10
—
10
Total decrease $ (38 ) $ 2
$ (36 ) $ (63 ) $ 1
$ (62 )

Weather. The demand for electricity and natural gas is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the three months ended September 30, ~~2017~~2021 compared to the same period in ~~2016,~~2020, Operating ~~revenue net of purchased power decreased~~revenues related to weather fell due to unfavorable ~~summer weather conditions. Operating revenue net of fuel expense was relatively consistent.~~ weather. During the nine months ended September 30, ~~2017~~2021 compared to the same period in ~~2016, Operating revenue net~~2020, revenues related to weather increased by the impact of ~~purchased power and fuel expense decreased due to unfavorable~~favorable weather ~~conditions.~~

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conditions in PECO's service territory.

Heating and cooling ~~degree days~~degree-days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling ~~degree days~~degree-days for a 30-year period in PECO's service territory. The changes in heating and cooling ~~degree days~~degree-days in

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PECO

PECO’s service territory for the three and nine months ended September 30, ~~2017~~2021 compared to the same ~~periods~~period in ~~2016~~2020 and normal weather consisted of the following:


Heating and Cooling Degree-Days			Normal	% Change
Three Months Ended September 30,	2021	2020		From 2020		2021 vs. Normal
Heating Degree-Days	4	37	25	(89.2)	%	(84.0)	%
Cooling Degree-Days	1,094	1,128	1,013	(3.0)	%	8.0	%
			Normal	% Change
Nine Months Ended September 30,	2021	2020		From 2020		2021 vs. Normal
Heating Degree-Days	2,710	2,594	2,865	4.5	%	(5.4)	%
Cooling Degree-Days	1,517	1,504	1,402	0.9	%	8.2	%

Heating and Cooling Degree-Days Normal % Change
Three Months Ended September 30, 2017 2016 2017 vs. 2016 2017 vs. Normal
Heating Degree-Days 14
10
35
40.0 % (60.0 )%
Cooling Degree-Days 989
1,288
923
(23.2 )% 7.2 %

Nine Months Ended September 30,
Heating Degree-Days 2,437
2,616
2,974
(6.8 )% (18.1 )%
Cooling Degree-Days 1,404
1,684
1,271
(16.6 )% 10.5 %

Volume. Operating revenue net of purchased power and fuel related to delivery volume, exclusive of the effects of weather, remained relatively consistent for the three months ended September 30, 2017 compared to the same period in 2016. The decrease in Operating revenue net of purchased power related to deliveryElectric volume, exclusive of the effects of weather, for the three and nine months ended September 30, ~~2017~~2021, compared to the same period in ~~2016, primarily reflects the impacts of energy efficiency initiatives~~2020, increased on ~~customer usage partially offset by moderate economic and customer growth, as well as~~ a ~~shift in the volume profile across classes from residential and small commercial and industrial to large commercial and industrial. Operating revenue~~ net ~~of fuel expense for the nine months ended September 30, 2017 compared to the same period in 2016 increased~~basis due to ~~strong~~an increase in overall usage for customers further increased by customer ~~growth and moderate economic~~ growth.

~~Pricing.~~ ~~Operating revenues net of purchased power as a result of pricing~~ Natural gas volume for the three and nine months ended September 30, ~~2017~~2021 compared to the same period in ~~2016~~2020, increased ~~primarily~~ due to ~~higher overall effective rates due to decreased usage across~~retail load growth.


Electric Retail Deliveries to Customers (in GWhs)	Three Months Ended September 30,		% Change		Weather - Normal % Change(b)		Nine Months Ended September 30,		% Change		Weather - Normal % Change(b)
	2021	2020					2021	2020
Residential	4,318	4,477	(3.6)	%	(1.4)	%	11,201	10,874	3.0	%	1.0	%
Small commercial & industrial	2,157	2,017	6.9	%	7.7	%	5,796	5,493	5.5	%	3.9	%
Large commercial & industrial	3,880	3,791	2.3	%	2.7	%	10,627	10,393	2.3	%	1.8	%
Public authorities & electric railroads	155	145	6.9	%	7.2	%	425	407	4.4	%	4.3	%
Total electric retail deliveries(a)	10,510	10,430	0.8	%	2.0	%	28,049	27,167	3.2	%	2.0	%


	As of September 30,
Number of Electric Customers	2021	2020
Residential	1,514,836	1,505,080
Small commercial & industrial	155,006	154,183
Large commercial & industrial	3,108	3,105
Public authorities & electric railroads	10,271	10,149
Total	1,683,221	1,672,517

__________

(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 ~~major customer classes. Operating revenues net~~change in delivery volumes assuming normalized weather based on the historical 30-year average.


Natural Gas Deliveries to Customers (in mmcf)	Three Months Ended September 30,		% Change		Weather - Normal % Change(b)		Nine Months Ended September 30,		% Change		Weather - Normal % Change(b)
	2021	2020					2021	2020
Residential	2,244	2,121	5.8	%	8.2	%	27,945	25,867	8.0	%	0.8	%
Small commercial & industrial	1,926	2,157	(10.7)	%	(11.7)	%	15,217	13,020	16.9	%	7.5	%
Large commercial & industrial	4	9	(55.6)	%	1.3	%	13	20	(35.0)	%	7.7	%
Transportation	5,356	5,269	1.7	%	5.0	%	18,474	17,553	5.2	%	4.0	%
Total natural gas retail deliveries(a)	9,530	9,556	(0.3)	%	2.0	%	61,649	56,460	9.2	%	3.3	%

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PECO


	As of September 30,
Number of Natural Gas Customers	2021	2020
Residential	495,752	490,158
Small commercial & industrial	44,435	44,138
Large commercial & industrial	6	5
Transportation	670	715
Total	540,863	535,016

__________

(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.

Pricing for the three and nine months ended September 30, ~~2017~~2021 compared to the same period in ~~2016~~2020 remained relatively consistent.

Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered.

Regulatory Required ~~Programs.~~ ~~This~~ Programs represents ~~the change in Operating revenue~~revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency, PGC, and the GSA. The riders are designed to provide full and current cost recovery as well as a return. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Income taxes. ~~Refer to the Operating and maintenance expense discussion below for additional information on included programs.~~

~~Other.~~ Other revenue, which can vary period to period, primarily includes wholesale transmission revenue, rental revenue, revenue related to late payment charges and assistance provided to other utilities through mutual assistance programs.

~~Operating and Maintenance Expense~~

Three Months Ended
September 30,
Increase
(Decrease)
Nine Months Ended
September 30, Increase
(Decrease)
2017 2016 2017 2016
Operating and maintenance expense — baseline $ 183
$ 185
$ (2 ) $ 552
$ 545
$ 7
Operating and maintenance expense — regulatory required programs^(a)
14
14
—
43
59
(16 )
Total operating and maintenance expense $ 197
$ 199
$ (2 ) $ 595
$ 604
$ (9 )

~~_________~~


~~(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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~~The changes in Operating and maintenance expense for the three and nine months ended September 30, 2017 compared to the same period in 2016, consisted of the following:~~

Three Months Ended
September 30, 2017 Nine Months Ended
September 30, 2017
Increase (Decrease) Increase (Decrease)
Baseline
Labor, other benefits, contracting and materials $ 7
$ 14
Storm-related costs (3 ) (7 )
Pension and non-pension postretirement benefits expense (1 ) (2 )
PHI merger and integration costs 1
1
BSC costs 5
6
Uncollectible accounts expense (6 ) (6 )
Other (5 ) 1
(2 ) 7
Regulatory Required Programs
Energy efficiency 1
(15 )
Other (1 ) (1 )
—
(16 )
Total decrease $ (2 ) $ (9 )

~~Depreciation and Amortization Expense~~

~~The changes in Depreciation and amortization expense for the three and nine months ended September 30, 2017 compared to the same period in 2016, consisted of the following:~~

Three Months Ended
September 30, 2017 Nine Months Ended
September 30, 2017
Increase (Decrease) Increase (Decrease)
Depreciation and amortization expense $ 5
$ 13
Regulatory asset amortization —
(1 )
Total increase $ 5
$ 12

~~Taxes Other Than Income~~

Taxes other than income, which can vary period to period, include municipal and state utility taxes, real estate taxes and payroll taxes. Taxes other than income decreased for the three and nine months ended September 30, 2017 compared to the same period in 2016 due to a decrease in gross receipts tax driven by a decrease in electric revenue.

~~Interest Expense, Net~~

~~Interest expense, net for the three and nine months ended September 30, 2017 remained consistent compared to the same period in 2016.~~

~~Other, Net~~

~~Other, net for the three and nine months ended September 30, 2017 remained consistent compared to the same period in 2016.~~

~~Effective Income Tax Rate~~

PECO's effective income tax rate was 20.0% and 30.7% for the three months ended September 30, 2017 and 2016, respectively, and 20.4% and 25.9% for the nine months ended September 30, 2017 and 2016, respectively. See

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~~Table of Contents~~

~~Note 12 — Income Taxes of the Combined Notes to the Consolidated Financial Statements for further discussion of the change in effective income tax rate.~~

~~PECO Electric Operating Statistics and Revenue Detail~~

Three Months Ended
September 30, % Change
Weather -
Normal
% Change
Nine Months Ended
September 30, % Change Weather -
Normal
% Change
Retail Deliveries to Customers (in GWhs) 2017 2016 2017 2016
Retail Deliveries^(a)

Residential 3,752
4,358
(13.9 )% 0.2 % 9,939
10,682
(7.0 )% (1.4 )%
Small commercial & industrial 2,158
2,324
(7.1 )% (1.0 )% 6,048
6,236
(3.0 )% (1.1 )%
Large commercial & industrial 4,137
4,234
(2.3 )% 1.4 % 11,593
11,598
— % 0.8 %
Public authorities & electric railroads 198
240
(17.5 )% (17.5 )% 618
672
(8.0 )% (8.0 )%
Total retail deliveries 10,245

11,156
(8.2 )% — % 28,198

29,188
(3.4 )% (0.6 )%

As of September 30,
Number of Electric Customers 2017 2016
Residential 1,463,906
1,451,533
Small commercial & industrial 150,964
149,646
Large commercial & industrial 3,112
3,094
Public authorities & electric railroads 9,665
9,820
Total 1,627,647
1,614,093

Three Months Ended
September 30, % Change Nine Months Ended
September 30, % Change
Electric Revenue 2017 2016 2017 2016
Retail Sales^(a)

Residential $ 434
$ 513
(15.4 )% $ 1,147
$ 1,278
(10.3 )%
Small commercial & industrial 106
109
(2.8 )% 303
334
(9.3 )%
Large commercial & industrial 59
59
— % 168
182
(7.7 )%
Public authorities & electric railroads 7
8
(12.5 )% 23
25
(8.0 )%
Total retail 606
689
(12.0 )% 1,641
1,819
(9.8 )%
Other revenue^(b)
56
51
9.8 % 161
152
5.9 %
Total electric revenue^(c)
$ 662
$ 740
(10.5 )% $ 1,802
$ 1,971
(8.6 )%

~~_________~~


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


~~(b)~~	~~Other revenue primarily includes transmission revenue from PJM and wholesale electric revenue, in addition to rental income.~~


~~(c)~~	Includes operating revenues from affiliates totaling $1 million and $2 million for the three months ended September 30, 2017 and 2016, respectively, and $4 million and $5 million for the nine months ended September 30, 2017 and 2016, respectively.

~~PECO Natural Gas Operating Statistics and Revenue Detail~~

Three Months Ended
September 30, % Change
Weather -
Normal
% Change
Nine Months Ended
September 30, % Change
Weather -
Normal
% Change
Deliveries to Customers (in mmcf) 2017 2016 2017 2016
Retail Delivery
Retail sales^(a)
3,993
3,494
14.3 % 9.4 % 38,825
38,488
0.9 % 2.7 %
Transportation and other 5,674
7,315
(22.4 )% (14.5 )% 19,122
20,917
(8.6 )% (5.9 )%
Total natural gas deliveries 9,667
10,809
(10.6 )% (6.0 )% 57,947
59,405
(2.5 )% (0.1 )%

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~~Table of Contents~~

As of September 30,
Number of Natural Gas Customers 2017 2016
Residential 474,766
470,024
Commercial & industrial 43,358
42,997
Total retail 518,124

513,021
Transportation 771
802
Total 518,895

513,823

Three Months Ended
September 30, % Change Nine Months Ended
September 30, % Change
Natural Gas Revenue 2017 2016 2017 2016
Retail Sales
Retail sales^(a)
$ 46
$ 41
12.2 % $ 315
$ 298
5.7 %
Transportation and other 7
7
— % 24
24
— %
Total natural gas revenues^(b)
$ 53

$ 48
10.4 % $ 339

$ 322
5.3 %

~~_________~~


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


~~(b)~~	~~Includes operating revenues from affiliates totaling less than $1 million for the three and nine months ended September 30, 2017 and 2016.~~

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~~Results of Operations — BGE~~

Three Months Ended
September 30,
Favorable
(Unfavorable)
Variance
Nine Months Ended
September 30,
Favorable
(Unfavorable)
Variance
2017 2016 2017 2016
Operating revenues $ 738
$ 812
$ (74 ) $ 2,363
$ 2,421
$ (58 )
Purchased power and fuel expense 269
360
91
853
994
141
Revenues net of purchased power and fuel expense^(a)
469
452
17
1,510
1,427
83
Other operating expenses
Operating and maintenance 175
178
3
532
588
56
Depreciation and amortization 109
101
(8 ) 348
307
(41 )
Taxes other than income 61
58
(3 ) 180
172
(8 )
Total other operating expenses 345
337
(8 ) 1,060
1,067
7
Operating income 124
115
9
450
360
90
Other income and (deductions)
Interest expense, net (26 ) (28 ) 2
(80 ) (76 ) (4 )
Other, net 4
5
(1 ) 12
16
(4 )
Total other income and (deductions) (22 ) (23 ) 1
(68 ) (60 ) (8 )
Income before income taxes 102
92
10
382
300
82
Income taxes 40
36
(4 ) 151
109
(42 )
Net income 62
56
6
231
191
40
Preference stock dividends —
2
2
—
8
8
Net income attributable to common shareholder $ 62
$ 54
$ 8
$ 231
$ 183
$ 48

~~_________~~

~~(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.

~~Net Income Attributable to Common Shareholder~~

~~Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016~~. BGE’s Net income attributable to common shareholder for the three months ended September 30, 2017 was higher than the same period in 2016, primarily due to an increase in Revenues net of purchased power and fuel expense, predominantly as a result of an increase in transmission formula rate revenues. This item was partially offset by an increase in Depreciation and amortization expense primarily related to the impacts of increased capital investment.

~~Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016~~. BGE’s Net income attributable to common shareholder for the nine months ended September 30, 2017 was higher than the same period in 2016, primarily due to an increase in Revenues net of purchased power and fuel expense and lower Operating and maintenance expense. The increase in Revenues net of purchased power and fuel expense was primarily due to the impacts of the electric and natural gas distribution rate orders issued by the MDPSC in June 2016 and July 2016 and an increase in transmission formula rate revenues. The lower Operating and maintenance expense was primarily due to the absence of cost disallowances resulting from the 2016 distribution rate orders issued by the MDPSC and decreased storm costs in 2017. These items were partially offset by higher income tax expense primarily resulting from a cumulative adjustment to reduce tax expense in 2016 for transmission-related regulatory assets and an increase in Depreciation and amortization expense primarily related to the initiation of cost recovery of the AMI programs under the distribution rate orders and the impacts of increased capital investment.

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~~Revenues Net of Purchased Power and Fuel Expense~~

There are certain drivers to Operating revenues that are offset by their impact on Purchased power and fuel expense, such as commodity procurement costs and programs allowing customers to select a competitive electric or natural gas supplier. Operating revenues and Purchased power and fuel expense are affected by fluctuations in commodity procurement costs. BGE’s electric and natural gas rates charged to customers are subject to periodic adjustments that are designed to recover or refund the difference between the actual cost of purchased electric power and purchased natural gas and the amount included in rates in accordance with the MDPSC’s market-based SOS and gas commodity programs, respectively.

Electric and natural gas revenue and purchased power and fuel expense are also affected by fluctuations in the number of customers electing to use a competitive electric generation or natural gas supplier. All BGE customersCustomers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas ~~suppliers, respectively. The customers'~~suppliers. Customer choice ~~of suppliers does~~programs do not impact the volume of deliveries ~~but~~as PECO remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation or natural gas from competitive suppliers, PECO either acts as the billing agent or the competitive supplier separately bills its own customers and therefore PECO does ~~affect revenue collected from customers~~not record Operating revenues or Purchased power and fuel expense related to ~~supplied energy and~~the electricity and/or natural gas.

~~Retail deliveries purchased from competitive~~ For customers that choose to purchase electric generation ~~and~~or natural gas ~~suppliers (as a percentage of kWh~~from PECO, PECO is permitted to recover the electricity, natural gas, and ~~mmcf sales, respectively)~~REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power and fuel expense related to the electricity, natural gas, and RECs.

Other revenue which primarily includes revenue related to late payment charges. Other revenues for the three and nine months ended September 30, ~~2017 and 2016 consisted~~2021 compared to the same period in 2020, remained relatively consistent.

See Note 5 — Segment Information of the ~~following:~~Combined Notes to Consolidated Financial Statements for the presentation of PECO's revenue disaggregation.

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Electric 60 % 58 % 60 % 59 %
Natural Gas 74 % 80 % 57 % 59 %

The ~~number~~increase of ~~retail customers purchasing electric generation~~$8 million and ~~natural gas from competitive electric generation and natural gas suppliers at September 30, 2017 and 2016 consisted~~the increase of ~~the following:~~

September 30, 2017 September 30, 2016
Number of Customers % of total retail customers Number of customers % of total retail customers
Electric 339,300
27 % 334,100
26 %
Natural Gas 148,600
22 % 150,000
23 %

~~The changes in BGE’s Operating revenues net of purchased power and fuel expense~~$32 million for the three and nine months ended September 30, ~~2017,~~2021 compared to the same period in ~~2016,~~2020, respectively, in Purchased power and fuel expenseispartially offset in Operating revenues as part of regulatory required programs.

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PECO

The changes in Operating and maintenance expense consisted of the following:


	Three Months Ended September 30, 2021		Nine Months Ended September 30, 2021
	Increase (Decrease)		Increase (Decrease)
Storm-related costs(a)	$	5	(54)
Credit loss expense	10		(2)
Regulatory Required Programs	(6)		(7)
BSC costs	5		12
Labor, other benefits, contracting and materials	(4)		19
Pension and non-pension post retirement benefit expense	—		1
Other	2		(5)









Total increase (decrease)	$	12	$	(36)

Three Months Ended
September 30, 2017 Nine Months Ended
September 30, 2017
Increase (Decrease) Increase (Decrease)
Electric Gas Total Electric Gas Total
Distribution rate increase $ —
$ —
$ —
$ 21
$ 29
$ 50
Regulatory required programs 2
—
2
11
1
12
Transmission revenue 7
—
7
10
—
10
Other, net 4
4
8
5
6
11
Total increase $ 13
$ 4
$ 17
$ 47
$ 36
$ 83
__________

~~Distribution Rate Increase.~~ ~~The increase~~(a) YTD primarily reflects the absence of costs in ~~distribution revenues for the nine months ended September 30, 2017, compared~~2021 due to the ~~same period~~June and August 2020 storms.

The changes in ~~2016, was~~Depreciation and amortization expense consisted of the following:


	Three Months Ended September 30, 2021		Nine Months Ended September 30, 2021
	Increase (Decrease)		Increase (Decrease)
Depreciation and amortization(a)	$	6	$	11
Regulatory asset amortization	(5)		(11)

Total increase	$	1	$	—

__________

(a)Depreciation and amortization increased primarily due to ~~the impact of the electric~~ongoing capital expenditures.

Interest expense, net increased $1 million and natural gas distribution rates charged to customers that became effective in June 2016 in accordance with the electric and natural gas distribution rate orders issued by the MDPSC in June 2016 and July 2016. See Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

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~~Table of Contents~~

~~Revenue Decoupling.~~ The demand for electricity and natural gas is affected by weather and usage conditions. The MDPSC allows BGE to record a monthly adjustment to its electric and natural gas distribution revenue from all residential customers, commercial electric customers, the majority of large industrial electric customers, and all firm service natural gas customers to eliminate the effect of abnormal weather and usage patterns per customer on BGE's electric and natural gas distribution volumes, thereby recovering a specified dollar amount of distribution revenue per customer, by customer class, regardless of fluctuations in actual consumption levels. This allows BGE to recognize revenue at MDPSC-approved distribution charges per customer, regardless of what BGE's actual distribution volumes were for a billing period. Therefore, while this revenue is affected by customer growth (i.e., increase in the number of customers), it will not be affected by actual weather or usage conditions (i.e., changes in consumption per customer). BGE bills or credits customers in subsequent months for the difference between approved revenue levels under revenue decoupling and actual customer billings.

Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 30-year period in BGE's service territory. The changes in heating and cooling degree days in BGE's service territory$11 million for the three and nine months ended September 30, ~~2017~~2021 compared to the same period in ~~2016 consisted of the following:~~

Heating and Cooling Degree-Days % Change
Three Months Ended September 30, 2017 2016 Normal 2017 vs. 2016 2017 vs. Normal
Heating Degree-Days 64
24
78
166.7 % (17.9 )%
Cooling Degree-Days 595
747
596
(20.3 )% (0.2 )%

Nine Months Ended September 30,
Heating Degree-Days 2,524
2,878
2,992
(12.3 )% (15.6 )%
Cooling Degree-Days 877
966
850
(9.2 )% 3.2 %

~~Regulatory Required Programs.~~ Revenue from regulatory required programs are billings for the costs of various legislative and/or regulatory programs that are recoverable from customers on a full and current basis. These programs are designed to provide full cost recovery, as well as a return in certain instances. The costs of these programs are included in Operating and maintenance expense, Depreciation and amortization expense and Taxes other than income in BGE's Consolidated Statements of Operations and Comprehensive Income.

~~Transmission Revenue.~~ Under a FERC approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered and other billing determinants. The increase in transmission revenue for the three and nine months ended September 30, 2017, compared to the same period in 2016, was2020, respectively, primarily due to ~~increases~~the issuance of debt in ~~capital investment~~March 2021 and operating and maintenance expense recoveries. See Operating and Maintenance Expense below and Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.June 2020.

~~Other, Net.~~ Other net revenue, which can vary from period to period, primarily includes late payment fees and other miscellaneous revenue such as service application fees and assistance provided to other utilities through BGE's mutual assistance program.

~~Operating and Maintenance Expense~~

Three Months Ended
September 30,
Increase
(Decrease)
Nine Months Ended
September 30, Increase
(Decrease)
2017 2016 2017 2016
Operating and maintenance expense — baseline $ 167
$ 170
$ (3 ) $ 499
$ 561
$ (62 )
Operating and maintenance expense — regulatory required programs^(a)
8
8
—
33
27
6
Total operating and maintenance expense $ 175
$ 178
$ (3 ) $ 532
$ 588
$ (56 )

~~_________~~


~~(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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~~The changes in Operating and maintenance expense for the three and nine months ended September 30, 2017 compared to the same period in 2016, consisted of the following:~~

Three Months Ended
September 30, 2017 Nine Months Ended
September 30, 2017
Increase (Decrease) Increase (Decrease)
Baseline
Impairment on long-lived assets and losses on regulatory assets^(a)
$ 1
$ (50 )
City of Baltimore conduit fees (4 ) (12 )
Storm-related costs 3
(11 )
Uncollectible accounts expense (8 ) (8 )
BSC costs 8
10
Other (3 ) 9
(3 ) (62 )
Regulatory Required Programs
Other $ —
$ 6
—
6
Total decrease $ (3 ) $ (56 )

~~__________~~


~~(a)~~	~~See Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.~~

~~Depreciation and Amortization~~

~~The changes in Depreciation and amortization expense for the three and nine months ended September 30, 2017 compared to the same period in 2016 consisted of the following:~~

Three Months Ended
September 30, 2017 Nine Months Ended
September 30, 2017
Increase (Decrease) Increase (Decrease)
Depreciation expense^(a)
$ 5
$ 10
Regulatory asset amortization^(b)
1
25
Regulatory required programs^(c)
2
6
Total increase $ 8
$ 41

~~_________~~


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

~~(b)~~

Regulatory asset amortization increased for the three and nine months ended September 30, 2017 compared to the same period in 2016 primarily due to an increase in regulatory asset amortization related to energy efficiency programs and the initiation of cost recovery of the AMI programs under the final electric and natural gas distribution rate case order issued by the MDPSC in June 2016 and increased depreciation from AMI program capital expenditures. See Note 5 — 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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~~Taxes Other Than Income~~

Taxes other than income, which can vary period to period, include municipal and state utility taxes, real estate taxes and payroll taxes. Taxes other than income for the three and nine months ended September 30, 2017 compared to the same period in 2016 remained relatively consistent.

~~Interest Expense, Net~~

~~Interest expense, net for the three and nine months ended September 30, 2017, compared to the same period in 2016 remained relatively consistent.~~

Effective ~~Income Tax Rate~~

~~BGE’s effective~~ income tax ~~rate was 39.2%~~rates were (2.8)% and ~~39.1%~~(13.1)% for the three months ended September 30, ~~2017~~2021 and ~~2016, respectively. BGE’s effective income tax rate was 39.5%~~2020 respectively, and ~~36.3%~~2.3% and (2.3)% for the nine months ended September 30, ~~2017~~2021 and ~~2016,~~2020, respectively. See Note 1210 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

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Table of Contents

BGE

~~BGE Electric Operating Statistics and Revenue Detail~~

Three Months Ended
September 30, % Change Weather -
Normal
% Change Nine Months Ended
September 30, % Change Weather -
Normal
% Change
Retail Deliveries to Customers (in GWhs) 2017
2016 2017 2016
Retail Deliveries^(a)

Residential 3,370
3,900
(13.6 )% (2.9 )% 9,126
9,996
(8.7 )% (4.3 )%
Small commercial & industrial 785
877
(10.5 )% (9.0 )% 2,210
2,343
(5.7 )% (5.8 )%
Large commercial & industrial 3,781
3,992
(5.3 )% (3.9 )% 10,422
10,627
(1.9 )% (2.6 )%
Public authorities & electric railroads 64
72
(11.1 )% (2.5 )% 204
215
(5.1 )% (2.5 )%
Total electric deliveries 8,000
8,841
(9.5 )% (4.0 )% 21,962
23,181
(5.3 )% (3.7 )%

As of September 30,
Number of Electric Customers 2017 2016
Residential 1,156,659
1,145,020
Small commercial & industrial 113,224
112,609
Large commercial & industrial 12,144
12,030
Public authorities & electric railroads 274
282
Total 1,282,301
1,269,941

Three Months Ended
September 30, % Change Nine Months Ended
September 30, % Change
Electric Revenue 2017
2016 2017 2016
Retail Sales^(a)

Residential $ 376
$ 451
(16.6 )% $ 1,096
$ 1,203
(8.9 )%
Small commercial & industrial 67
74
(9.5 )% 202
212
(4.7 )%
Large commercial & industrial 120
123
(2.4 )% 343
337
1.8 %
Public authorities & electric railroads 8
9
(11.1 )% 23
27
(14.8 )%
Total retail 571

657
(13.1 )% 1,664

1,779
(6.5 )%
Other revenue^(b)(c)
87
78
11.5 % 231
219
5.5 %
Total electric revenue $ 658

$ 735
(10.5 )% $ 1,895

$ 1,998
(5.2 )%

~~_________~~


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


~~(b)~~	~~Other revenue primarily includes wholesale transmission revenue and late payment charges.~~


~~(c)~~	~~Includes operating revenues from affiliates totaling $1 million for both the three months ended September 30, 2017 and 2016 and $5 million for both the nine months ended September 30, 2017 and 2016.~~

~~BGE Natural Gas Operating Statistics and Revenue Detail~~

Three Months Ended
September 30, % Change Weather -
Normal
% Change Nine Months Ended
September 30, % Change Weather -
Normal
% Change
Deliveries to Customers (in mmcf) 2017 2016 2017 2016
Retail Deliveries^(a)

Retail sales 11,221
13,159
(14.7 )% (14.3 )% 60,620
69,415
(12.7 )% (5.3 )%
Transportation and other^(b)
68
1,311
(94.8 )% n/a
2,463
4,078
(39.6 )% n/a
Total natural gas deliveries 11,289
14,470
(22.0 )% (14.3 )% 63,083
73,493
(14.2 )% (5.3 )%

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~~Table of Contents~~

As of September 30,
Number of Gas Customers 2017
2016
Residential 626,039
619,837
Commercial & industrial 43,973
43,957
Total 670,012

663,794

Three Months Ended
September 30, % Change Nine Months Ended
September 30, % Change
Natural Gas Revenue 2017 2016 2017 2016
Retail Sales^(a)

Retail sales $ 77
$ 71
8.5 % $ 445
$ 403
10.4 %
Transportation and other^(b)
3
6
(50.0 )% 23
20
15.0 %
Total natural gas revenues^(c)
$ 80
$ 77
3.9 % $ 468
$ 423
10.6 %

~~_________~~


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


~~(b)~~	Transportation and other natural gas revenue includes off-system revenue of 68 mmcfs ($1 million) and 1,311 mmcfs ($4 million) for the three months ended September 30, 2017 and 2016, respectively, and 2,463 mmcfs ($15 million) and 4,078 mmcfs ($14 million) for the nine months ended September 30, 2017 and 2016, respectively.


~~(c)~~	Includes operating revenues from affiliates totaling $2 million and $6 million for the three months ended September 30, 2017 and 2016, respectively, and $7 million and $11 million for the nine months ended September 30, 2017 and 2016, respectively.

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Results of Operations — ~~PHI~~BGE

~~PHI’s results~~


	Three Months Ended September 30,				Favorable (Unfavorable) Variance		Nine Months Ended September 30,				Favorable (Unfavorable) Variance
	2021		2020				2021		2020
Operating revenues	$	770	$	731	$	39	$	2,426	$	2,284	$	142
Operating expenses
Purchased power and fuel	290		250		(40)		840		731		(109)
Operating and maintenance	205		191		(14)		595		567		(28)
Depreciation and amortization	142		133		(9)		434		405		(29)
Taxes other than income taxes	72		68		(4)		211		200		(11)
Total operating expenses	709		642		(67)		2,080		1,903		(177)

Operating income	61		89		(28)		346		381		(35)
Other income and (deductions)
Interest expense, net	(36)		(34)		(2)		(103)		(99)		(4)
Other, net	7		6		1		23		17		6
Total other income and (deductions)	(29)		(28)		(1)		(80)		(82)		2
Income before income taxes	32		61		(29)		266		299		(33)
Income taxes	(4)		8		12		(24)		26		50
Net income	$	36	$	53	$	(17)	$	290	$	273	$	17

Three Months Ended September 30, 2021 Compared to Three Months Ended September 30, 2020. Net incomedecreased by $17 million primarily related to an increase in depreciation and amortization expense and an increase in various expenses, partially offset by favorable impacts of ~~operations include~~ the ~~results~~multi-year plan.

Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020.Net income increased by $17 million primarily due to favorable impacts of ~~its~~the multi-year plan, partially offset by an increase in depreciation and amortization expense and an increase in storm costs. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the three-year electric and natural gas distribution multi-year plan.

The changes in Operating revenues consisted of the following:


	Three Months Ended September 30, 2021						Nine Months Ended September 30, 2021
	Increase (Decrease)						Increase (Decrease)
	Electric		Gas		Total		Electric		Gas		Total
Distribution	$	1	$	1	$	2	$	7	$	2	$	9
Transmission	(6)		—		(6)		23		—		23
Other	7		—		7		5		1		6
	2		1		3		35		3		38
Regulatory required programs	29		7		36		70		34		104
Total increase	$	31	$	8	$	39	$	105	$	37	$	142

Revenue Decoupling.The demand for electricity and natural gas is affected by weather and customer usage. However, Operating revenues are not impacted by abnormal weather or usage per customer as a result of a bill stabilization adjustment (BSA) that provides for a fixed distribution charge per customer by customer class. While Operating revenues are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.

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Table of Contents

BGE


	As of September 30,
Number of Electric Customers	2021	2020
Residential	1,194,254	1,187,498
Small commercial & industrial	114,814	114,038
Large commercial & industrial	12,584	12,428
Public authorities & electric railroads	268	267
Total	1,321,920	1,314,231


	As of September 30,
Number of Natural Gas Customers	2021	2020
Residential	649,745	644,872
Small commercial & industrial	38,216	38,173
Large commercial & industrial	6,167	6,083
Total	694,128	689,128

Distribution Revenue increased for the three ~~reportable segments, Pepco, DPL~~ and ~~ACE~~nine months ended September 30, 2021,compared to the same period in 2020, due to customer growth.

Transmission Revenue.Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue decreased for the three months ended September 30, 2021, compared to the same period in 2020, primarily due to decreases in Operating and maintenance expense recoveries in 2021. Transmission revenue increased for the nine months ended September 30, 2021, compared to the same period in 2020, primarily due to the reduction in revenue in 2020 due to the settlement agreement of ongoing transmission related income tax regulatory liabilities.

Other Revenueincludes revenue related to late payment charges, mutual assistance, off-system sales, and service application fees. Other revenue increased for both the three and nine months ended September 30, 2021, compared to the same period in 2020, as BGE had temporarily suspended customer disconnections for non-payment and temporarily ceased new late fees for customers in 2020 which has resumed in 2021.

Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as conservation, demand response, STRIDE, and the POLR mechanism. The riders are designed to provide full and current cost recovery, as well as a return in certain instances. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers. Customer choice programs do not impact the volume of deliveries as BGE remains the distribution service provider for all ~~periods presented below.~~customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For ~~"Predecessor" reporting periods, PHI's results of operations also include~~customers that choose to purchase electric generation or natural gas from competitive suppliers, BGE either acts as the ~~results of PES~~billing agent or the competitive supplier separately bills its own customers, and ~~PCI.~~ therefore BGE does not record Operating revenues or Purchased power and fuel expense related to the electricity and/or natural gas. For customers that choose to purchase electric generation or natural gas from BGE, BGE is permitted to recover the electricity and natural gas procurement costs from customers and therefore records the amounts related to the electricity and/or natural gas in Operating revenues and Purchased power and fuel expense. BGE recovers electricity and natural gas procurement costs from customers with a slight mark-up.

See Note ~~20 -~~5 — Segment Information of the Combined Notes to Consolidated Financial Statements for ~~additional information regarding PHI's reportable segments. All material intercompany accounts~~the presentation of BGE's revenue disaggregation.

The increase of $40 million and ~~transactions have been eliminated~~$109 million for the three and nine months ended September 30, 2021 compared to the same period in ~~consolidation. A separate specific discussion~~2020, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.

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BGE

The changes in Operating and maintenance expense consisted of the ~~results of operations for Pepco, DPL~~following:


	Three Months Ended September 30, 2021		Nine Months Ended September 30, 2021
	Increase (Decrease)		Increase (Decrease)
Labor, other benefits, contracting, and materials	$	3	$	5
Storm-related costs	3		10
Pension and non-pension postretirement benefits expense	—		1
BSC costs	7		13
Credit loss expense	1		(5)
Other	(2)		(1)
	12		23
Regulatory required programs	2		5

Total increase	$	14	$	28

The changes in Depreciation and ~~ACE is presented elsewhere in this report.~~

~~As a result~~amortization expense consisted of the PHI Merger, the following consolidated financial results present two separate reporting periods for 2016. The "Predecessor" reporting period represents PHI's results of operations for the period from January 1, 2016following:


	Three Months Ended September 30, 2021		Nine Months Ended September 30, 2021
	Increase (Decrease)		Increase (Decrease)
Depreciation and amortization(a)	$	12	$	31
Regulatory asset amortization	1		1
Regulatory required programs	(4)		(3)

Total increase	$	9	$	29

__________

(a)Depreciation and amortization increased primarily due to ~~March 23, 2016. The "Successor" reporting periods represent PHI's results of operations~~ongoing capital expenditures.

Taxes other than income taxes increased for the three and nine months ended September 30, ~~2017, the three months ended September 30, 2016 and for the period from March 24, 2016 to September 30, 2016. All amounts presented below are before the impact of income taxes, except as noted.~~

Successor Successor Predecessor
Three Months Ended September 30, Favorable (Unfavorable) Variance Nine Months Ended September 30, March 24 to September 30, January 1 to March 23,
2017 2016 2017 2016 2016
Operating revenues $ 1,310
$ 1,394
$ (84 ) $ 3,557
$ 2,565
$ 1,153
Purchased power and fuel expense 473
583
110
1,318
1,037
497
Revenue net of purchased power and fuel expense^(a)
837
811
26
2,239
1,528
656
Other operating expenses
Operating and maintenance 251
226
(25 ) 774
921
294
Depreciation and amortization 179
182
3
511
355
152
Taxes other than income 122
124
2
344
248
105
Total other operating
expenses 552
532
(20 ) 1,629
1,524
551
Gain on sales of assets —
—
—
1
—
—
Operating income 285
279
6
611
4
105
Other income and (deductions)
Interest expense, net (62 ) (64 ) 2
(183 ) (135 ) (65 )
Other, net 13
19
(6 ) 40
31
(4 )
Total other income and
(deductions) (49 ) (45 ) (4 ) (143 ) (104 ) (69 )
Income (loss) before income taxes 236
234
2
468
(100 ) 36
Income taxes 83
68
(15 ) 109
(9 ) 17
Net income (loss) $ 153
$ 166
$ (13 ) $ 359
$ (91 ) $ 19

~~_________~~

~~(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.

~~Successor Period Three Months Ended September 30, 2017 Compared to Successor Period Three Months Ended September 30, 2016~~

~~Net Income~~

~~PHI's Net income for the Successor period of three months ended September 30, 2017 was $153 million~~2021 compared to ~~$166 million for~~ the ~~Successor~~same period ~~of three months ended September 30, 2016. The decrease~~ in ~~Net~~2020, primarily due to higher property taxes.

Effective income ~~reflects the September 2016 pre-tax recording of a $50 million reallocation of merger-related commitments from Pepco, DPL~~tax rateswere (12.5)% and ~~ACE to Exelon, which resulted in more commitments becoming obligations of Exelon. The increase in Operating~~

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and maintenance expense is partially offset by the impact of increases in electric distribution and natural gas rates within Revenue net of purchased power expense (Pepco electric distribution rates effective November 2016 in Maryland, Pepco electric distribution rates effective August 2017 in the District of Columbia, DPL electric distribution rates effective February 2017 in Maryland, DPL electric distribution and natural gas rates effective July 2016 and December 2016 in Delaware, and ACE electric distribution rates effective August 2016 in New Jersey).

~~Operating Revenue Net of Purchased Power and Fuel Expense~~

~~Operating revenue net of purchased power and fuel expense, which is a non-GAAP measure discussed above, increased by $26 million~~13.1% for the three months ended September 30, ~~2017 as compared to~~2021 and 2020, respectively, and (9.0)% and 8.7% for the ~~three~~nine months ended September 30, ~~2016.~~2021 and 2020, respectively. The ~~increase~~change is ~~primarily attributable to the following factors:~~

Increase of $17 million at DPL primarily related to the impact of the new electric distribution and natural gas rates charged to Delaware customers that became effective in July 2016 and December 2016 and the impact of new electric distribution rates charged to Maryland customers that became effective in February 2017;

Increase of $14 million at Pepco primarily related to the impact of the new electric distribution rates charged to customers in Maryland that became effective in November 2016 and and the impact of new electric distribution rates charged to customers in the District of Columbia effective August 2017; and

Decrease of $6 million at ACE primarily related to lower average customer usage and unfavorable weather related sales, partially offset by the impact of the new electric distribution base rate charged to customers that became effective in August 2016.

~~Operating and Maintenance Expense~~

Operating and maintenance expense increased by $25 million for the three months ended September 30, 2017 as compared to the three months ended September 30, 2016. The increase is attributable to the following factors:

~~Increase of $24 million at DPL due primarily to a merger commitment reallocation from DPL to Exelon that decreased Operating and maintenance expense in 2016;~~

Increase of $5 million at ACE primarily due to a merger commitment reallocation from ACE to Exelon that decreased Operating and maintenance expense in 2016, partially offset by the deferral of merger-related costs to a regulatory asset; and

~~Decrease of $6 million at Pepco~~ primarily due to the ~~deferral~~multi-year plan which resulted in the acceleration of merger-related, rate case, and customer billing system costs to a regulatory asset, partially offset by a merger commitment reallocation from Pepco to Exelon that decreased Operating and maintenance expense in 2016.

~~Depreciation and Amortization Expense~~

Depreciation and amortization expense decreased by $3 million primarily due to lower amortization expense at ACE resulting from lower revenue due to rate decreases effective October 2016 for the ACE Transition Bond Charge and ACE Market Transition Charge Tax, partially offset by higher depreciation as a result of higher Maryland depreciation rates at Pepco effective November 2016 and at DPL effective February 2017 and due to ongoing capital expenditures at Pepco, DPL, and ACE.

~~Taxes Other Than Income~~

~~Taxes other than income decreased by $2 million primarily due to lower utility taxes that are collected and passed through by Pepco, partially offset by higher property taxes at Pepco.~~

~~Interest Expense, Net~~

~~Interest expense decreased by $2 million primarily due to the redemption of long-term debt in December 2016 and lower short-term debt interest rates.~~

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~~Other, Net~~

Other, net decreased by $6 million primarily due to the September 2016 reversal of contributions in aid of construction tax gross-up reserves due to the determination that there is no legal obligation to refund customers per contract terms.

~~Effective Income Tax Rate~~

~~PHI's effective~~certain income tax ~~rate was 35.2%~~benefits and ~~29.1% for~~ the ~~three months ended September 30, 2017 and 2016, respectively.~~April 24, 2020 settlement agreement of ongoing transmission related income tax regulatory liabilities. See Note ~~12 -~~3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the three-year electric and natural gas distribution multi-year plan, Note 3 — Regulatory Matters of the 2020 Exelon Form 10-K for additional information on the April 24, 2020 settlement agreement, and Note 10 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

~~Successor Period~~

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Results of Operations — PHI

PHI’s Results of Operations include the results of its three reportable segments, Pepco, DPL, and ACE. PHI also has a business services subsidiary, PHISCO, which provides a variety of support services and the costs are directly charged or allocated to the applicable subsidiaries. Additionally, the results of PHI’s corporate operations include interest costs from various financing activities. All material intercompany accounts and transactions have been eliminated in consolidation. The following table sets forth PHI's GAAP consolidated Net income, by Registrant, for the three and nine months ended September 30, 2021 compared to the same period in 2020. See the Results of Operations for Pepco, DPL, and ACE for additional information.


	Three Months Ended September 30,				Favorable Variance		Nine Months Ended September 30,				Favorable Variance
	2021		2020				2021		2020
PHI	$	266	$	216	$	50	$	535	$	418	$	117
Pepco	130		118		12		264		227		37
DPL	50		27		23		135		91		44
ACE	90		75		15		141		106		35
Other(a)	(4)		(4)		—		(5)		(6)		1

_________

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

Three Months Ended September 30, 2021 Compared to Three Months Ended September 30, 2020. Net income increased by $50 million primarily due to higher distribution rates, customer growth at Pepco, higher transmission revenues due to an increase in capital investments in ACE's service territories, and a decrease in storm costs due to the August 2020 storms in Delaware at DPL, partially offset by an increase in depreciation and amortization expense at Pepco.

Nine Months Ended September 30, ~~2017~~2021 Compared to Nine Months Ended September 30, 2020. Net income increased by $117 million primarily due to higher distribution rates, higher transmission revenues due to an increase in capital investments in DPL's and ACE's service territories, higher distribution revenues due to an increase in volume in ACE's service territory, favorable weather conditions in DPL's Delaware service territory, customer growth at Pepco, a decrease in credit loss expense at Pepco and DPL, and a decrease in storm costs due to the August 2020 storms in Delaware at DPL, partially offset by an increase in depreciation and amortization expense at Pepco.

~~PHI's~~

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Pepco

Results of Operations — Pepco


	Three Months Ended September 30,				Favorable (Unfavorable) Variance		Nine Months Ended September 30,				Favorable (Unfavorable) Variance
	2021		2020				2021		2020
Operating revenues	$	660	$	611	$	49	$	1,736	$	1,650	$	86
Operating expenses
Purchased power	172		163		(9)		471		467		(4)
Operating and maintenance	120		106		(14)		341		336		(5)
Depreciation and amortization	104		96		(8)		302		282		(20)
Taxes other than income taxes	105		100		(5)		282		279		(3)
Total operating expenses	501		465		(36)		1,396		1,364		(32)

Operating income	159		146		13		340		286		54
Other income and (deductions)
Interest expense, net	(35)		(35)		—		(104)		(103)		(1)
Other, net	12		10		2		37		28		9
Total other income and (deductions)	(23)		(25)		2		(67)		(75)		8
Income before income taxes	136		121		15		273		211		62
Income taxes	6		3		(3)		9		(16)		(25)
Net income	$	130	$	118	$	12	$	264	$	227	$	37

Three Months Ended September 30, 2021 Compared to Three Months Ended September 30, 2020.Net income increased by $12 million primarily due to higher distribution rates and customer growth, partially offset by an increase in depreciation and amortization expense.

Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020.Net income increased by $37 million primarily due to higher distribution rates, customer growth, a decrease in credit loss expense, and decreases in various operating expenses, partially offset by an increase in depreciation and amortization expense.

The changes in Operating revenues consisted of the following:


	Three Months Ended September 30, 2021		Nine Months Ended September 30, 2021
	Increase		Increase
Distribution	$	18	$	23
Transmission	6		28
Other	4		3
	28		54
Regulatory required programs	21		32
Total increase	$	49	$	86

Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in both Maryland and the ~~Successor period~~District of Columbia are not impacted by abnormal weather or usage per customer as a result of a bill stabilization adjustment (BSA) that provides for a fixed distribution charge per customer by customer class. While Operating revenues are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.

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	As of September 30,
Number of Electric Customers	2021	2020
Residential	839,574	828,578
Small commercial & industrial	53,849	53,813
Large commercial & industrial	22,586	22,485
Public authorities & electric railroads	179	167
Total	916,188	905,043

Distribution Revenue increased for both the three and nine months ended September 30, ~~2017 was $359 million. Therewere no significant changes~~2021 compared to the same period in 2020 due to higher distribution rates that became effective in Maryland and District of Columbia in Q3 2021 and customer growth.

Transmission Revenues. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying ~~trends affecting PHI's operations during~~costs and capital investments being recovered. Transmission revenue increased for the ~~Successor~~three months ended September 30, 2021 compared to the same period ofin 2020, primarily due to increases in underlying costs. Transmission revenue increased for the nine months ended September 30, ~~2017 except for~~2021, compared to the ~~impact~~same period in 2020, primarily due to the reduction in revenue in 2020 due to the settlement agreement of ongoing transmission related income tax regulatory liabilities and increases in ~~electric distribution~~underlying costs.

Other Revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues, and ~~natural gas rates within Revenue net~~recoveries of ~~purchased~~other taxes.

Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, DC PLUG, and SOS procurement and administrative costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Purchased power expense, (Pepco electric distribution rates effective November 2016 in Maryland, Pepco electric distribution rates effective August 2017 in the District of Columbia, DPL electric distribution rates effective February 2017 in Maryland, DPL electric distribution and natural gas rates effective July 2016 and December 2016 in Delaware, and ACE electric distribution rates effective August 2016 in New Jersey). The deferral of merger-related, rate case, and customer billing system costs to a regulatory asset and lower uncollectible accounts expense contributed to lower Operating and maintenance ~~expense. Income taxes were lower due~~expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to ~~unrecognized tax benefits~~purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of ~~$59 million~~deliveries, as Pepco remains the distribution service provider for ~~uncertain tax positions~~all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, Pepco either acts as the billing agent or the competitive supplier separately bills its own customers, and therefore Pepco does not record Operating revenues or Purchased power expense related to the ~~deductibility~~electricity. For customers that choose to purchase electric generation from Pepco, Pepco is permitted to recover the electricity and REC procurement costs from customers and therefore records the amounts related to the electricity and RECs in Operating revenues and Purchased power expense. Pepco recovers electricity and REC procurement costs from customers with a slight mark-up.

See Note 5 - Segment Information of ~~certain merger commitments in~~ the ~~first quarter of 2017.~~

~~PHI's effective income tax rate~~ Combined Notes to Consolidated Financial Statements for the ~~Successor period~~presentation of Pepco's revenue disaggregation.

The increase of $9 million and $4 million for the three and nine months ended September 30, ~~2017 was 23.3%.~~2021, respectively compared to the same period in 2020, respectively, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.

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The changes in Operating and maintenance expense consisted of the following:


	Three Months Ended September 30, 2021		Nine Months Ended September 30, 2021
	Increase (Decrease)		Increase (Decrease)
Storm-related costs	$	5	$	5
BSC and PHISCO costs	2		1
Credit loss expense	—		(4)
Pension and non-pension postretirement benefits expense	(1)		(3)
Labor, other benefits, contracting and materials	(2)		(13)


Other	6		14
	10		—

Regulatory required programs	4		5
Total increase	$	14	$	5

The changes in Depreciation and amortization expense consisted of the following:


	Three Months Ended September 30, 2021		Nine Months Ended September 30, 2021
	Increase (Decrease)		Increase (Decrease)
Depreciation and amortization(a)	$	5	$	13
Regulatory asset amortization	(3)		(10)
Regulatory required programs	6		17
Total increase	$	8	$	20

_________

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

Effective income tax rates were 4.4% and 2.5% for the three months ended September 30, 2021 and 2020, respectively, and 3.3% and (7.6)% for the nine months ended September 30, 2021 and 2020, respectively. For the nine months ended September 30, 2021, the change is primarily due to the April 24, 2020 settlement agreement of ongoing transmission related income tax regulatory liabilities, partially offset by the multi-year plan which resulted in the acceleration of certain income tax benefits. See Note ~~12 -~~3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the three-year electric distribution multi-year plan, Note 3 — Regulatory Matters of the 2020 Exelon Form 10-K for additional information on the April 24, 2020 settlement agreement, and Note 10 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

~~Successor Period March 24, 2016 to September 30, 2016~~

~~PHI's Net loss for the Successor period from March 24, 2016 to September 30, 2016was $91 million~~. ~~There~~were no significant changes in the underlying trends affecting PHI's results of operations during the Successor period of March 24, 2016 to September 30, 2016 except for the pre-tax recording of $375 million of non-recurring merger-related costs within Operating and maintenance expense.

PHI's effective income tax rate for the Successor period of March 24, 2016 to September 30, 2016 was 9.0%. See Note 12 - Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

~~Predecessor Period January 1, 2016 to March 23, 2016~~

~~PHI's Net income for the Predecessor period of January 1, 2016 to March 23, 2016was $19 million~~. ~~There~~were no significant changes in the underlying trends affecting PHI's results of operations during the Predecessor period of January 1, 2016 to March 23, 2016 except for the pre-tax recording of $29 million of non-recurring merger-related costs within Operating and maintenance expense and $18 million of preferred stock derivative expense within Other, net.

PHI's effective income tax rate for the Predecessor period of January 1, 2016 to March 23, 2016 was 47.2%. See Note 12 - Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

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DPL

Results of Operations ~~- Pepco~~— DPL


	Three Months Ended September 30,				Favorable (Unfavorable) Variance		Nine Months Ended September 30,				Favorable (Unfavorable) Variance
	2021		2020				2021		2020
Operating revenues	$	360	$	337	$	23	$	1,040	$	954	$	86
Operating expenses
Purchased power and fuel	138		131		(7)		402		379		(23)
Operating and maintenance	87		101		14		249		272		23
Depreciation and amortization	53		48		(5)		157		143		(14)
Taxes other than income taxes	17		16		(1)		50		49		(1)
Total operating expenses	295		296		1		858		843		(15)

Operating income	65		41		24		182		111		71
Other income and (deductions)
Interest expense, net	(15)		(15)		—		(47)		(47)		—
Other, net	3		2		1		9		7		2
Total other income and (deductions)	(12)		(13)		1		(38)		(40)		2
Income before income taxes	53		28		25		144		71		73
Income taxes	3		1		(2)		9		(20)		(29)
Net income	$	50	$	27	$	23	$	135	$	91	$	44

Three Months Ended September 30, Favorable (Unfavorable) Variance Nine Months Ended September 30, Favorable (Unfavorable) Variance
2017 2016 2017 2016
Operating revenues $ 604
$ 635
$ (31 ) $ 1,649
$ 1,695
$ (46 )
Purchased power expense 168
213
45
478
563
85
Revenue net of purchased power expense^(a)
436
422
14
1,171
1,132
39
Other operating expenses
Operating and maintenance 103
109
6
336
508
172
Depreciation and amortization 82
76
(6 ) 242
221
(21 )
Taxes other than income 102
105
3
282
287
5
Total other operating expenses 287
290
3
860
1,016
156
Gain on sales of assets —
—
—
1
8
(7 )
Operating income 149
132
17
312
124
188
Other income and (deductions)

Interest expense, net (31 ) (30 ) (1 ) (89 ) (98 ) 9
Other, net 7
12
(5 ) 22
28
(6 )
Total other income and (deductions) (24 ) (18 ) (6 ) (67 ) (70 ) 3
Income before income taxes 125
114
11
245
54
191
Income taxes 38
35
(3 ) 57
34
(23 )
Net income $ 87
$ 79
$ 8
$ 188
$ 20
$ 168

~~_________~~

~~(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.

~~Net Income~~

Three Months Ended September 30, ~~2017~~2021 Compared to Three Months Ended September 30, ~~2016.~~ ~~Pepco's~~ 2020. Net income ~~for the three months ended September 30, 2017, was higher than the same period in 2016,~~ increased by $23 million primarily due to ~~an increase in Revenue net of purchased power expense resulting from~~ higher electric distribution ~~revenues as~~rates and a ~~result of~~decrease in storm costs due to the ~~distribution rate increase approved by the MDPSC effective November 2016 and the distribution rate increase approved by the DCPSC effective~~ August ~~2017.~~2020 storms in Delaware.

Nine Months Ended September 30, ~~2017~~2021 Compared to Nine Months Ended September 30, ~~2016.~~ ~~Pepco's~~ 2020. Net income ~~for~~ increased by $44 million primarily due to higher electric distribution rates, a decrease in storm costs due to the ~~nine months ended September 30, 2017, was~~August 2020 storms in Delaware, higher ~~than the same period in 2016, primarily~~transmission revenues due to an increase in capital investments, a decrease in credit loss expense, and favorable weather conditions at DPL's Delaware electric service territories.

The changes in Operating revenues consisted of the following:


	Three Months Ended September 30, 2021						Nine Months Ended September 30, 2021
	(Decrease) Increase						Increase (Decrease)
	Electric		Gas		Total		Electric		Gas		Total
Weather	$	—	$	(2)	$	(2)	$	4	$	—	$	4
Volume	(2)		1		(1)		—		(1)		(1)
Distribution	11		(1)		10		20		1		21
Transmission	5		—		5		33		—		33
Other	—		1		1		1		—		1
	14		(1)		13		58		—		58
Regulatory required programs	9		1		10		27		1		28
Total increase	$	23	$	—	$	23	$	85	$	1	$	86

~~Operating Revenue Net of Purchased Power Expense~~

Operating revenues include revenue from the distribution and supply of electricity to Pepco’s customers within its service territories at regulated rates. Operating revenues also include transmission service revenue that Pepco receives as a transmission owner from PJM at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.

Electric revenues and purchased power expense are also affected by fluctuations in participation in the Customer Choice Program. All Pepco customers have the choice to purchase electricity from competitive electric generation

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~~suppliers. The customers' choice of supplier does not impact the volume of deliveries, but affects revenue collected from customers related to supplied energy service.~~

Retail deliveries purchased from competitive electric generation suppliers (as a percentage of kWh sales) for the three and nine months ended September 30, 2017, compared to the same periods in 2016, consisted of the following:

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Electric 65 % 63 % 66 % 65 %

~~Retail customers purchasing electric generation from competitive electric generation suppliers at September 30, 2017 and 2016 consisted of the following:~~

September 30, 2017 September 30, 2016
Number of customers % of total retail customers Number of customers % of total retail customers
Electric 179,106
21 % 175,960
21 %

Retail deliveries purchased from competitive electric generation suppliers represented 72% and 73% of Pepco’s retail kWh sales to the District of Columbia customers and 60% and 60% of Pepco’s retail kWh sales to Maryland customers for the three and nine months ended September 30, 2017, respectively and 71% and 72% of Pepco’s retail kWh sales to the District of Columbia customers and 58% and 59% of Pepco’s retail kWh sales to Maryland customers for the three and nine months ended September 30, 2016, respectively.

~~Operating revenues include transmission enhancement credits that Pepco receives as a transmission owner from PJM in consideration for approved regional transmission expansion plan expenditures.~~

Operating revenues also include work and services performed on behalf of customers, including other utilities, which is generally not subject to price regulation. Work and services includes mutual assistance to other utilities, highway relocation, rentals of pole attachments, late payment fees and collection fees.

Purchased power expense consists of the cost of electricity purchased by Pepco to fulfill its default electricity supply obligation and, as such, is recoverable from customers in accordance with the terms of public service commission orders.

~~The changes in Pepco’s operating revenues net of purchased power expense for the three and nine months ended September 30, 2017 compared to the same periods in 2016 consisted of the following:~~

Three Months Ended September 30, 2017 Nine Months Ended September 30, 2017
Increase (Decrease) Increase (Decrease)
Volume $ 5
$ 13
Distribution rate increase 17
45
Regulatory required programs (6 ) (11 )
Transmission revenues 3
9
Other (5 ) (17 )
Total increase $ 14
$ 39

~~Volume.~~ The increase in operating revenue net of purchased power and fuel expense related to delivery volume, exclusive of the effects of weather, for the three and nine months ended September 30, 2017 compared to the same periods in 2016, primarily reflects the impact of customer growth.

~~Distribution Rate Increase.~~ ~~The increase in electric operating revenues net of purchased power expense for the three and nine months ended September 30, 2017 compared to the same periods in 2016 was primarily due to the~~

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impact of higher electric distribution rates charged to customers in Maryland that became effective in November 2016 and higher electric distribution rates charged to customers in the District of Columbia that became effective August 2017. See Note 5—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

~~Revenue Decoupling.~~ Pepco’s results historically have been seasonal, generally producing higher revenue and income in the warmest and coldest periods of the year. For retail customers of Pepco in Maryland and in the District of Columbia, revenues are not affected by unseasonably warmer or colder weather because a bill stabilization adjustment (BSA) ~~for retail customers was implemented~~ that provides for a fixed distribution charge per ~~customer. The BSA has the effect of decoupling the~~customer by customer class. While Operating revenues from electric distribution ~~revenue recognized in a reporting period from the amount of power delivered during the period. As a result, the only factors that will cause distribution revenue from~~ customers in Maryland ~~and the District of Columbia to fluctuate from period to period~~ are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers and changes in the approved distribution charge per customer. Changes in customer usage (due to weather conditions, energy prices, energy efficiency programs or other reasons) from period to period have no impact on reported distribution revenue for customers to whom the BSA applies.

In accounting for the BSA in Maryland and the District of Columbia, a Revenue Decoupling Adjustment is recorded representing either (i) a positive adjustment equal to the amount by which revenue from Maryland and the District of Columbia retail distribution sales falls short of the revenue that Pepco is entitled to earn based on the approved distribution charge per customer or (ii) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that Pepco is entitled to earn based on the approved distribution charge per customer.

Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 20-year period in Pepco's service territory. The changes in heating and cooling degree days in Pepco’s service territory for the three and nine months ended September 30, 2017 compared to the same periods in 2016 and normal weather consisted of the following:customers.

188

% Change
2017 2016 Normal 2017 vs. 2016 2017 vs. Normal
Three Months Ended September 30,
Heating Degree-Days 8
1
19
700.0 % (57.9 )%
Cooling Degree-Days 1,130
1,418
1,133
(20.3 )% (0.3 )%

Nine Months Ended September 30,

Heating Degree-Days 1,963
2,408
2,477
(18.5 )% (20.8 )%
Cooling Degree-Days 1,679
1,872
1,611
(10.3 )% 4.2 %

~~Regulatory Required Programs.~~This represents the change in operating revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs. The riders are designed to provide full and current cost recovery as well as a return. The costs of these programs are included in Operating and maintenance expense, Depreciation and amortization expense and Taxes other than income in Pepco's Consolidated Statements of Operations and Comprehensive Income. Refer to the Operating and maintenance expense and Depreciation and amortization expense discussion below for additional information on included programs.

~~Transmission Revenues~~. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered and other billing adjustments. The increase in revenue net of purchased power expense for the three months ended September 30, 2017 compared to the same period in 2016 is a result of higher rates effective June 1, 2017 related to increases in transmission plant investment and operating expenses. The increase in revenue net of purchased power expense for the nine months ended September 30, 2017 compared to the same period in 2016 is a result of higher rates effective June 1, 2017 and June 1, 2016 related to increases in transmission plant investment and operating expenses, partially offset by lower revenue related to the MAPP abandonment recovery period that ended in March 2016.

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~~Other.~~ The decrease in other operating revenue net of purchased power and fuel expense for the three and nine months ended September 30, 2017 compared to the same periods in 2016 is primarily due to lower pass-through revenue (which is substantially offset in Taxes other than income) primarily the result of lower sales that resulted in a decrease in utility taxes that are collected by Pepco on behalf of the jurisdiction.

~~Operating and Maintenance Expense~~

Three Months Ended
September 30, Increase (Decrease) Nine Months Ended
September 30,
Increase
(Decrease)
2017 2016 2017 2016
Operating and maintenance expense - baseline $ 100
$ 106
$ (6 ) $ 331
$ 500
$ (169 )
Operating and maintenance expense - regulatory required programs^(a)
3
3
—
5
8
(3 )
Total operating and maintenance expense $ 103
$ 109
$ (6 ) $ 336
$ 508
$ (172 )

~~_________~~


~~(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.

~~The changes in Operating and maintenance expense for the three and nine months ended September 30, 2017 compared to the same periods in 2016, consisted of the following:~~

Three Months Ended September 30, 2017 Nine Months Ended September 30, 2017
Increase (Decrease) Increase (Decrease)
Baseline
Labor, other benefits, contracting and materials $ 2
$ 14
Storm-related costs (1 ) —
Remeasurement of AMI-related regulatory asset^(a)
(4 ) (11 )
Uncollectible accounts expense 1
(1 )
Deferral of merger-related costs to regulatory asset (8 ) (1 )
Deferral of rate case and customer billing system costs (6 ) (6 )
BSC and PHISCO allocations^(b)
1
(22 )
Merger commitments^(c)
13
(132 )
Other (4 ) (10 )
(6 ) (169 )
Regulatory required programs
Purchased power administrative costs —
(3 )
Total decrease $ (6 ) $ (172 )

~~_________~~


~~(a)~~	~~Related to a remeasurement of a regulatory asset for legacy meters recognized in 2016.~~


~~(b)~~	~~Primarily related to merger severance and compensation costs recognized in 2016.~~


~~(c)~~	~~Primarily related to merger-related commitments for customer rate credits and charitable contributions recognized in 2016.~~

~~Depreciation and Amortization Expense~~

~~The changes in Depreciation and amortization expense for the three and nine months ended September 30, 2017 compared to the same periods in 2016, consisted of the following:~~

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Three Months Ended September 30, 2017 Nine Months Ended September 30, 2017
Increase (Decrease) Increase (Decrease)
Depreciation expense^(a)
$ 9
$ 25
Regulatory asset amortization 3
4
Regulatory required programs^(b)
(6 ) (8 )
Total increase $ 6
$ 21

~~_________~~


~~(a)~~	~~Depreciation expense increased due to higher depreciation rates in Maryland effective November 2016 and due to ongoing capital expenditures.~~


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

~~Taxes Other Than Income~~

Taxes other than income for the three and nine months ended September 30, 2017 compared to the same periods in 2016, decreased due to a decrease in the utility taxes that are collected and passed through by Pepco (which is substantially offset in Operating revenues), partially offset by higher property taxes.

~~Gain on sales of assets~~

~~Gain on sales of assets for the nine months ended September 30, 2017 compared to the same period in 2016 decreased due to a second quarter 2016 gain recorded from the sale of land.~~

~~Interest Expense, Net~~

~~Interest expense, net for the three months ended September 30, 2017 compared to the same period in 2016, remained relatively constant.~~

Interest expense, net for the nine months ended September 30, 2017 compared to the same period in 2016 decreased primarily due to the recording of interest expense for an uncertain tax position in the first quarter of 2016 and an increase in capitalized AFUDC interest.

~~Other, Net~~

Other, net for the three and nine months ended September 30, 2017 compared to the same periods in 2016 decreased primarily due to the September 2016 reversal of contributions in aid of construction tax gross-up reserves due to the determination that there is no legal obligation to refund customers per contract terms.

~~Effective Income Tax Rate~~

Pepco's effective income tax rate was 30.4% and 30.7% for the three months ended September 30, 2017 and 2016, respectively. Pepco's effective income tax rate was 23.3% and 63.0% for the nine months ended September 30, 2017 and 2016, respectively. In the first quarter of 2017, Pepco decreased its liability for unrecognized tax benefits by $21 million resulting in a benefit to Income taxes and a corresponding decrease in its effective tax rate. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates.

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~~Pepco Electric Operating Statistics and Revenue Detail~~

Three Months Ended
September 30, Nine Months Ended
September 30,
Retail Deliveries to Customers (in GWhs) 2017 2016 % Change Weather - Normal % Change 2017 2016 % Change Weather - Normal % Change
Retail Deliveries^(a)

Residential 2,281
2,675
(14.7 )% (5.2 )% 6,038
6,652
(9.2 )% (2.7 )%
Small commercial & industrial 347
394
(11.9 )% (7.2 )% 999
1,124
(11.1 )% (8.4 )%
Large commercial & industrial 4,146

4,314
(3.9 )% 0.8 % 11,306
11,890
(4.9 )% (3.0 )%
Public authorities & electric railroads 180
180
— % 1.1 % 542
544
(0.4 )% (0.2 )%
Total retail deliveries 6,954
7,563
(8.1 )% (1.7 )% 18,885
20,210
(6.6 )% (3.1 )%

As of September 30,
Number of Electric Customers 2017 2016
Residential 790,032
775,911
Small commercial & industrial

53,543
53,425
Large commercial & industrial 21,733
21,315
Public authorities & electric railroads 143
129
Total 865,451
850,780

Three Months Ended
September 30, Nine Months Ended
September 30,
Electric Revenue 2017 2016 % Change 2017 2016 % Change
Retail Sales^(a)

Residential $ 283
$ 315
(10.2 )% $ 744
$ 791
(5.9 )%
Small commercial & industrial 38
43
(11.6 )% 113
116
(2.6 )%
Large commercial & industrial 221
219
0.9 % 608
613
(0.8 )%
Public authorities & electric railroads 8
7
14.3 % 24
23
4.3 %
Total retail 550
584
(5.8 )% 1,489
1,543
(3.5 )%
Other revenue^(b)
54
51
5.9 % 160
152
5.3 %
Total electric revenue^(c)
$ 604
$ 635
(4.9 )% $ 1,649
$ 1,695
(2.7 )%

~~_________~~


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


~~(b)~~	~~Other revenue includes transmission revenue from PJM and wholesale electric revenues.~~


~~(c)~~	Includes operating revenues from affiliates totaling $1 million for the three months ended September 30, 2017 and 2016 and $4 million and $3 million for the nine months ended September 30, 2017 and 2016, respectively.

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~~Results of Operations - DPL~~

Three Months Ended September 30, Favorable (Unfavorable) Variance Nine Months Ended September 30, Favorable (Unfavorable) Variance
2017 2016 2017 2016
Operating revenues $ 327
$ 331
$ (4 ) $ 971
$ 974
$ (3 )
Purchased power and fuel expense 129
150
21
399
448
49
Revenues net of purchased power and fuel expense^(a)
198
181
17
572
526
46
Other operating expenses

Operating and maintenance 79
55
(24 ) 227
338
111
Depreciation and amortization 45
44
(1 ) 124
120
(4 )
Taxes other than income 15
14
(1 ) 43
42
(1 )
Total other operating expenses 139
113
(26 ) 394
500
106
Gain on sales of asset —
4
(4 ) —
4
(4 )
Operating income 59
72
(13 ) 178
30
148
Other income and (deductions)

Interest expense, net (13 ) (12 ) (1 ) (38 ) (37 ) (1 )
Other, net 4
3
1
10
9
1
Total other income and (deductions) (9 ) (9 ) —
(28 ) (28 ) —
Income before income taxes 50

63
(13 ) 150

2
148
Income taxes 19
19
—
43
18
(25 )
Net income (loss) $ 31
$ 44
$ (13 ) $ 107
$ (16 ) $ 123

~~_________~~

~~(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.

~~Net Income (Loss)~~

~~Three Months Ended September 30, 2017 Compared to~~ Three Months Ended September 30, 2016. DPL's Net income for the three months ended September 30, 2017, was lower than the same period in 2016 as a result of the merger commitment reallocation from DPL to Exelon that decreased Operating and maintenance expense in 2016, partially offset by an increase in Revenue net of purchased power and fuel expense primarily resulting from higher electric distribution and natural gas revenues as a result of the distribution rate increases approved by the DPSC effective July 2016 and December 2016 and by the MDPSC effective February 2017.

~~Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016.~~ DPL's Net income (loss) for the nine months ended September 30, 2017, was higher than the same period in 2016 as a result of an increase in Revenue net of purchased power and fuel expense primarily resulting from higher electric distribution and natural gas revenues as a result of the distribution rate increases approved by the DPSC effective July 2016 and December 2016 and by the MDPSC effective February 2017, lower Operating and maintenance expense due to merger-related costs recognized in March 2016, lower uncollectible accounts expense, and the deferral of merger-related costs to a regulatory asset in 2017, and a decrease in income tax reserves in the first quarter of 2017 for uncertain tax positions related to the deductibility of certain merger commitments.

~~Revenues Net of Purchased Power and Fuel Expense~~

Operating revenues include revenue from the distribution and supply of electricity to DPL’s customers within its service territories at regulated rates. Operating revenues also include transmission service revenue that DPL receives as a transmission owner from PJM at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.

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Electric and natural gas revenues and purchased power and fuel expense are also affected by fluctuations in participation in the Customer Choice Program. All DPL customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers, respectively. The customers' choice of suppliers does not impact the volume of deliveries, but affects revenue collected from customers related to supplied energy and natural gas service.

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Electric 51 % 49 % 52 % 51 %
Natural Gas 53 % 51 % 35 % 32 %

~~Retail customers purchasing electric generation and natural gas from competitive electric generation and natural gas suppliers at September 30, 2017 and 2016 consisted of the following:~~

September 30, 2017 September 30, 2016
Number of customers % of total retail customers Number of customers % of total retail customers
Electric 78,426
15.0 % 79,501
15.4 %
Natural Gas 155
0.1 % 157
0.1 %

Retail deliveries purchased from competitive electric generation suppliers represented 53% and 54% of DPL’s retail kWh sales to Delaware customers and 48% and 48% of DPL's retail kWh sales to Maryland customers for the three and nine months ended September 30, 2017, respectively and 51% and 53% of DPL's retail kWh sales to Delaware customers and 47% and 47% of DPL's retail kWh sales to Maryland customers for the three and nine months ended September 30, 2016, respectively.

~~Operating revenues include transmission enhancement credits that DPL receives as a transmission owner from PJM in consideration for approved regional transmission expansion plan expenditures.~~

Natural gas operating revenue includes sources that are subject to price regulation (Regulated Gas Revenue) and those that generally are not subject to price regulation (Other Gas Revenue). Regulated gas revenue includes the revenue DPL receives from on-system natural gas delivered sales and the transportation of natural gas for customers within its service territory at regulated rates. Other gas revenue consists of off-system natural gas sales and the short-term release of interstate pipeline transportation and storage capacity not needed to serve customers. Off-system sales are made possible when low demand for natural gas by regulated customers creates excess pipeline capacity.

Purchased power expense consists of the cost of electricity purchased by DPL to fulfill its default electricity supply obligation and, as such, is recoverable from customers in accordance with the terms of public service commission orders. Purchased fuel expense consists of the cost of gas purchased by DPL to fulfill its obligation to regulated gas customers and, as such, is recoverable from customers in accordance with the terms of public service commission orders. It also includes the cost of gas purchased for off-system sales.

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The changes in DPL’s operating revenues net of purchased power and fuel expense for the three and nine months ended September 30, 2017 compared to the same periods in 2016 consisted of the following:

Three Months Ended
September 30, 2017 Nine Months Ended
September 30, 2017
Increase (Decrease)
Increase (Decrease)
Electric Gas Total Electric Gas Total
Weather $ (6 ) $ 1
$ (5 ) $ (9 ) $ (13 ) $ (22 )
Volume 2
(1 ) 1
3
10
13
Pricing - distribution revenues 17
—
17
49
2
51
Regulatory required programs (3 ) —
(3 ) (2 ) —
(2 )
Transmission revenues 5
—
5
4
—
4
Other 3
(1 ) 2
5
(3 ) 2
Total increase (decrease) $ 18
$ (1 ) $ 17
$ 50
$ (4 ) $ 46

~~Revenue Decoupling.~~ DPL’s results historically have been seasonal, generally producing higher revenue and income in the warmest and coldest periods of the year. For retail customers of DPL in Maryland, revenues are not affected by unseasonably warmer or colder weather because a bill stabilization adjustment (BSA) for retail customers was implemented that provides for a fixed distribution charge per customer. The BSA has the effect of decoupling the distribution revenue recognized in a reporting period from the amount of power delivered during the period. As a result, the only factors that will cause distribution revenue from customers in Maryland to fluctuate from period to period are changes in the number of customers and changes in the approved distribution charge per customer. A modified fixed variable rate design, which would provide for a charge not tied to a customer’s volumetric consumption of electricity or natural gas, has been proposed for DPL electricity and natural gas customers in Delaware. Changes in customer usage (due to weather conditions, energy prices, energy efficiency programs or other reasons) from period to period have no impact on reported distribution revenue for customers to whom the BSA applies.

In accounting for the BSA in Maryland, a Revenue Decoupling Adjustment is recorded representing either (i) a positive adjustment equal to the amount by which revenue from Maryland retail distribution sales falls short of the revenue that DPL is entitled to earn based on the approved distribution charge per customer or (ii) a negative adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that DPL is entitled to earn based on the approved distribution charge per customer.

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Weather. The demand for electricity and natural gas in ~~areas not subject to the BSA~~Delaware is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as ~~“favorable~~"favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the three ~~and nine~~ months ended September 30, ~~2017~~2021 compared to the same ~~periods~~period in ~~2016, operating revenue net of purchased power and fuel expense was lower~~2020, Operating revenues related to weather decreased due to the impact of unfavorable weather conditions in DPL's Delaware natural gas service territory. During the nine months ended September 30, 2021 compared to the same period in 2020, Operating revenues related to weather increased due to the impact of favorable weather conditions in DPL's Delaware electric service territory.

Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 20-year period in DPL's Delaware electric service territory and a 30-year period in DPL's Delaware natural gas service territory. The changes in heating and cooling degree days in DPL’s Delaware service territory for the three and nine months ended September 30, ~~2017~~2021 compared to ~~the~~ same ~~periods~~period in ~~2016~~2020 and normal weather consisted of the following:


Delaware Electric Service Territory				% Change
Three Months Ended September 30,	2021	2020	Normal	2021 vs. 2020		2021 vs. Normal
Heating Degree-Days	11	55	29	(80.0)	%	(62.1)	%
Cooling Degree-Days	969	961	894	0.8	%	8.4	%

				% Change
Nine Months Ended September 30,	2021	2020	Normal	2021 vs. 2020		2021 vs. Normal
Heating Degree-Days	2,848	2,664	2,993	6.9	%	(4.8)	%
Cooling Degree-Days	1,333	1,260	1,228	5.8	%	8.6	%


Electric Service Territory				% Change
Delaware Natural Gas Service Territory								Delaware Natural Gas Service Territory				% Change
Three Months Ended September 30,	2017	2016	Normal	2017 vs. 2016		2017 vs. Normal		Three Months Ended September 30,	2021	2020	Normal	2021 vs. 2020		2021 vs. Normal
Heating Degree-Days	24	14	33	71.4	%	(27.3	)%	Heating Degree-Days	11	55	38	(80.0)	%	(71.1)	%
Cooling Degree-Days	867	1,103	856	(21.4	)%	1.3	%

												% Change
Nine Months Ended September 30,								Nine Months Ended September 30,	2021	2020	Normal	2021 vs. 2020		2021 vs. Normal
Heating Degree-Days	2,384	2,812	2,933	(15.2	)%	(18.7	)%	Heating Degree-Days	2,848	2,664	3,025	6.9	%	(5.9)	%
Cooling Degree-Days	1,228	1,410	1,184	(12.9	)%	3.7	%

Natural Gas Service Territory % Change
Three Months Ended September 30, 2017 2016 Normal 2017 vs. 2016 2017 vs. Normal
Heating Degree-Days 28
20
42
40.0 % (33.3 )%

Nine Months Ended September 30,
Heating Degree-Days 2,431
2,913
3,062
(16.5 )% (20.6 )%

~~Volume.~~ ~~The increase in operating revenue net of purchased power and fuel expense related to delivery volume,~~ Volume, exclusive of the effects of weather, remained relatively consistent for the three and nine months ended September 30, ~~2017~~2021 compared to the same ~~periods~~period in ~~2016, primarily reflects~~2020.


Electric Retail Deliveries to Delaware Customers (in GWhs)	Three Months Ended September 30,		% Change		Weather - Normal % Change(b)		Nine Months Ended September 30,		% Change		Weather - Normal % Change(b)
	2021	2020					2021	2020
Residential	973	1,028	(5.4)	%	(5.1)	%	2,530	2,474	2.3	%	(0.3)	%
Small commercial & industrial	412	373	10.5	%	10.8	%	1,111	943	17.8	%	16.3	%
Large commercial & industrial	860	775	11.0	%	11.2	%	2,359	2,408	(2.0)	%	(2.5)	%
Public authorities & electric railroads	7	6	16.7	%	21.6	%	26	23	13.0	%	11.0	%
Total electric retail deliveries(a)	2,252	2,182	3.2	%	3.6	%	6,026	5,848	3.0	%	1.5	%

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DPL


	As of September 30,
Number of Total Electric Customers (Maryland and Delaware)	2021	2020
Residential	476,008	471,875
Small commercial & industrial	62,990	62,291
Large commercial & industrial	1,215	1,234
Public authorities & electric railroads	605	610
Total	540,818	536,010

_________

(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 ~~impact of increased~~change in delivery volumes assuming normalized weather based on the historical 20-year average.


Natural Gas Retail Deliveries to Delaware Customers (in mmcf)	Three Months Ended September 30,		% Change		Weather - Normal % Change(b)		Nine Months Ended September 30,		% Change		Weather - Normal % Change(b)
	2021	2020					2021	2020
Residential	399	441	(9.5)	%	8.8	%	5,507	5,256	4.8	%	(1.2)	%
Small commercial & industrial	352	339	3.8	%	13.9	%	2,647	2,567	3.1	%	(2.2)	%
Large commercial & industrial	395	402	(1.7)	%	(1.8)	%	1,247	1,265	(1.4)	%	(1.6)	%
Transportation	1,303	1,231	5.8	%	7.2	%	4,997	4,811	3.9	%	2.3	%
Total natural gas deliveries(a)	2,449	2,413	1.5	%	6.9	%	14,398	13,899	3.6	%	0.3	%


	As of September 30,
Number of Delaware Natural Gas Customers	2021	2020
Residential	127,740	126,659
Small commercial & industrial	9,935	9,885
Large commercial & industrial	21	17
Transportation	158	160
Total	137,854	136,721

__________

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

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

Distribution ~~Revenues.~~ ~~The increase in electric operating revenues net of purchased power expense as a result of pricing~~Revenue increased for the three ~~and~~months ended September 30, 2021 compared to the same period in 2020 primarily due to higher electric distribution rates in Delaware that became effective in October 2020. Distribution revenue increased for the nine months ended September 30, ~~2017~~2021 compared to the same ~~periods~~period in ~~2016 was~~2020 primarily due to ~~the impact of~~ higher electric distribution ~~and natural gas~~ rates ~~charged to Delaware customers~~in Maryland that became effective in July 2020 and ~~December 2016 and the impact of~~ higher electric distribution rates ~~charged to Maryland customers~~in Delaware that became effective in ~~February 2017. See Note 5—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.~~October 2020.

~~Regulatory Required Programs.~~ This represents the change in operating revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs. The riders are designed to provide full and current cost recovery as well as a return. The costs of these programs are included in Operating and maintenance expense, Depreciation and amortization expense and Taxes other than income in DPL's Consolidated Statements of Operations and Comprehensive Income. Refer to the Operating and maintenance expense and Depreciation and amortization expense discussion below for additional information on included programs.

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ended September 30, ~~2017~~2021, compared to the same period in ~~2016 is a result~~2020, primarily due to the reduction in revenue in 2020 due to the settlement agreement of ~~higher rates effective June 1, 2017~~ongoing transmission related income tax regulatory liabilities and ~~June 1, 2016 related to~~ increases in ~~transmission plant investment~~underlying costs and ~~operating expenses, partially offset by lower revenue related to the MAPP abandonment recovery period that ended in March 2016.~~capital investments.

~~Other.~~ Other ~~revenue, which can vary period to period,~~Revenue includes rental revenue, revenue related to late payment charges, ~~assistance provided to other utilities through~~ mutual assistance ~~programs,~~revenues, and recoveries of other taxes.

~~Operating~~Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, DE Renewable Portfolio Standards, SOS procurement and ~~Maintenance Expense~~administrative costs, and GCR costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Purchased power

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DPL

Three Months Ended
September 30, Increase (Decrease) Nine Months Ended
September 30, Increase (Decrease)
2017 2016 2017 2016
Operating and maintenance expense - baseline $ 76
$ 50
$ 26
$ 221
$ 328
$ (107 )
Operating and maintenance expense - regulatory required programs^(a)
3
5
(2 ) 6
10
(4 )
Total operating and maintenance expense $ 79
$ 55
$ 24
$ 227
$ 338
$ (111 )

~~_________~~


~~(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.

~~The changes in~~and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries as DPL remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, DPL either acts as the billing agent or the competitive supplier separately bills its own customers, and therefore DPL does not record Operating revenues or Purchased power and fuel expense related to the electricity. For customers that choose to purchase electric generation from DPL, DPL is permitted to recover the electricity and REC procurement costs from customers with a slight mark-up and therefore records the amounts related to the electricity and RECs in Operating revenues and Purchased power and fuel expense. DPL recovers natural gas costs without mark-up and records the amount in Operating revenues and Purchased power and fuel expense.

See Note 5 - Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of DPL's revenue disaggregation.

The increase of $7 million and $23 million for the three and nine months ended September 30, ~~2017~~2021, compared to the same ~~periods~~period in ~~2016,~~2020, respectively, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.

The changes in Operating and maintenance expense consisted of the following:


	Three Months Ended September 30, 2021		Nine Months Ended September 30, 2021
	(Decrease) Increase		(Decrease) Increase
Storm-related costs	$	(16)	$	(20)
Pension and non-pension postretirement benefits expense	(1)		(2)
Credit loss expense	(1)		(7)
Labor, other benefits, contracting and materials	2		(1)
BSC and PHISCO costs	3		5
Other	(1)		3
	(14)		(22)
Regulatory required programs	—		(1)
Total decrease	$	(14)	$	(23)

Three Months Ended September 30, 2017 Nine Months Ended September 30, 2017
Increase (Decrease)
Increase (Decrease)
Baseline
Labor, other benefits, contracting and materials $ 3
$ 3
Storm-related costs (2 ) 4
Uncollectible accounts expense (2 ) (7 )
Remeasurement of AMI-related regulatory asset^(a)
(1 ) (2 )
Deferral of merger-related costs to regulatory asset —
(6 )
BSC and PHISCO allocations^(b)
(1 ) (15 )
Merger commitments^(c)
27
(79 )
Other 2
(5 )
26
(107 )
Regulatory required programs
Purchased power administrative costs (2 ) (4 )
Total increase (decrease) $ 24
$ (111 )

~~_________~~


~~(a)~~	~~Related to a remeasurement of a regulatory asset for legacy meters recognized in 2016.~~


~~(b)~~	~~Primarily related to merger severance and compensation costs recognized in 2016.~~


~~(c)~~	~~Primarily related to merger-related commitments for customer rate credits and charitable contributions recognized in 2016.~~

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~~Depreciation and Amortization Expense~~

The changes in Depreciation and amortization expense ~~for the three and nine months ended September 30, 2017 compared to the same periods in 2016~~ consisted of the following:


								Three Months Ended September 30, 2021		Nine Months Ended September 30, 2021
	Three Months Ended September 30, 2017			Nine Months Ended September 30, 2017				Increase		Increase (Decrease)
	Increase (Decrease)			Increase (Decrease)
Depreciation expense^(a)	$	3		$	9
Depreciation and amortization(a)							Depreciation and amortization(a)	$	3	$	10
Regulatory asset amortization	—			(2		)	Regulatory asset amortization	—		(1)
Regulatory required programs^(b)	(2		)	(3		)
Regulatory required programs							Regulatory required programs	2		5
Total increase	$	1		$	4		Total increase	$	5	$	14

_________


~~(a)~~	~~Depreciation expense increased due to higher depreciation rates in Maryland effective February 2017 and due to ongoing capital expenditures.~~


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

~~Taxes Other Than Income~~(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.

~~Taxes other than income for the three and nine months ended September 30, 2017 compared to the same periods in 2016 remained relatively constant.~~

~~Interest Expense, Net~~

~~Interest expense, net for the three and nine months ended September 30, 2017 compared to the same periods in 2016 remained relatively constant.~~

~~Other, Net~~

~~Other, net for the three and nine months ended September 30, 2017 compared to the same periods in 2016 remained relatively constant.~~

Effective ~~Income Tax Rate~~

~~DPL's effective~~ income tax ~~rate was 38.0%~~rates were 5.7% and ~~30.2%~~3.6% for the three months ended September 30, ~~2017~~2021 and ~~2016, respectively. DPL's effective income tax rate was 28.7%~~2020, respectively, and ~~900.0%~~6.3% and (28.2)% for the nine months ended September 30, ~~2017~~2021 and ~~2016,~~2020, respectively. InFor the ~~first quarter~~nine months ended September 30, 2021, compared to the same period in 2020, the change is primarily due to the April 24, 2020 settlement agreement of ~~2017, DPL decreased its liability for unrecognized~~ongoing transmission related income tax ~~benefits by $16 million resulting in a benefit to Income taxes and a corresponding decrease in its effective tax rate.~~regulatory liabilities. See Note ~~12 -~~3 — Regulatory Matters of the 2020 Exelon Form 10-K for additional information on the April 24, 2020 settlement agreement, and Note 10 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

~~DPL Electric Operating Statistics and Revenue Detail~~

191

Three Months Ended
September 30, % Change Weather - Normal % Change Nine Months Ended
September 30, % Change Weather - Normal % Change
Retail Deliveries to Customers (in GWhs) 2017 2016 2017 2016
Retail Deliveries^(a)

Residential 1,439
1,601
(10.1 )% (2.2 )% 3,843
4,066
(5.5 )% 0.4 %
Small commercial & industrial 636
642
(0.9 )% 3.2 % 1,693
1,746
(3.0 )% (0.9 )%
Large commercial & industrial 1,245
1,250
(0.4 )% 4.1 % 3,440
3,492
(1.5 )% 0.3 %
Public authorities & electric railroads 10
9
11.1 % 11.1 % 35
35
— % — %
Total retail deliveries 3,330
3,502
(4.9 )% 1.2 % 9,011
9,339
(3.5 )% 0.1 %

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As of September 30,
Number of Electric Customers 2017 2016
Residential 458,790
455,640
Small commercial & industrial 60,542
60,034
Large commercial & industrial

1,406
1,414
Public authorities & electric railroads 633
643
Total 521,371
517,731

Three Months Ended
September 30, % Change Nine Months Ended
September 30, % Change
Electric Revenue 2017 2016 2017 2016
Retail Sales^(a)

Residential $ 183
$ 200
(8.5 )% $ 508
$ 522
(2.7 )%
Small commercial & industrial 49
48
2.1 % 138
143
(3.5 )%
Large commercial & industrial 26
24
8.3 % 77
74
4.1 %
Public authorities & electric railroads 3
2
50.0 % 11
9
22.2 %
Total retail 261
274
(4.7 )% 734
748
(1.9 )%
Other revenue^(b)
48
40
20.0 % 132
124
6.5 %
Total electric revenue^(c)
$ 309
$ 314
(1.6 )% $ 866
$ 872
(0.7 )%

~~_________~~


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


~~(b)~~	~~Other revenue includes transmission revenue from PJM and wholesale electric revenues.~~


~~(c)~~	~~Includes operating revenues from affiliates totaling $2 million for the three months ended September 30, 2017 and 2016 and $6 million for the nine months ended September 30, 2017 and 2016.~~

~~DPL Natural Gas Operating Statistics and Revenue Detail~~

Three Months Ended
September 30, % Change Weather - Normal % Change Nine Months Ended
September 30, % Change Weather - Normal % Change
Retail Deliveries to Customers (in mmcf) 2017 2016 2017 2016
Retail Deliveries
Retail sales 1,069
1,121
(4.6 )% (6.4 )% 8,679
9,253
(6.2 )% 6.5 %
Transportation & other 1,197
1,166
2.7 % 2.4 % 4,690
4,455
5.3 % 7.9 %
Total natural gas deliveries 2,266
2,287
(0.9 )% (2.0 )% 13,369
13,708
(2.5 )% 7.0 %

As of September 30,
Number of Gas Customers 2017 2016
Residential 121,238
120,075
Commercial & industrial 9,700
9,656
Transportation & other 155
157
Total 131,093
129,888

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Three Months Ended
September 30, % Change Nine Months Ended
September 30, % Change
Natural Gas Revenue 2017 2016 2017 2016
Retail Sales^(a)

Retail sales $ 12
$ 13
(7.7 )% $ 87
$ 87
— %
Transportation & other^(b)
6
4
50.0 % 18
15
20.0 %
Total natural gas revenues $ 18
$ 17
5.9 % $ 105
$ 102
2.9 %

~~__________~~


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


~~(b)~~	~~Transportation and other revenue includes off-system natural gas sales and the short-term release of interstate pipeline transportation and storage capacity not needed to serve customers.~~

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Results of Operations -— ACE


	Three Months Ended September 30,				Favorable (Unfavorable) Variance		Nine Months Ended September 30,				Favorable (Unfavorable) Variance
	2021		2020				2021		2020
Operating revenues	$	451	$	420	$	31	$	1,080	$	952	$	128
Operating expenses
Purchased power	230		211		(19)		541		469		(72)
Operating and maintenance	81		77		(4)		231		238		7
Depreciation and amortization	46		48		2		133		134		1
Taxes other than income taxes	2		2		—		6		6		—
Total operating expenses	359		338		(21)		911		847		(64)
Gain on sales of assets	—		—		—		—		2		(2)
Operating income	92		82		10		169		107		62
Other income and (deductions)
Interest expense, net	(14)		(15)		1		(43)		(45)		2
Other, net	1		1		—		3		5		(2)
Total other income and (deductions)	(13)		(14)		1		(40)		(40)		—
Income before income taxes	79		68		11		129		67		62
Income taxes	(11)		(7)		4		(12)		(39)		(27)
Net income	$	90	$	75	$	15	$	141	$	106	$	35

Three Months Ended September 30, Favorable (Unfavorable) Variance Nine Months Ended September 30, Favorable (Unfavorable) Variance
2017 2016 2017 2016
Operating revenues $ 370
$ 421
$ (51 ) $ 915
$ 982
$ (67 )
Purchased power expense 176
221
45
442
520
78
Revenues net of purchased power expense^(a)
194
200
(6 ) 473
462
11
Other operating expenses

Operating and maintenance 72
67
(5 ) 225
346
121
Depreciation and amortization 41
49
8
113
130
17
Taxes other than income 2
1
(1 ) 6
6
—
Total other operating expenses 115
117
2
344
482
138
Gain on sales of assets —
—
—
—
1
(1 )
Operating income (loss) 79
83
(4 ) 129
(19 ) 148
Other income and (deductions)

Interest expense, net (15 ) (15 ) —
(46 ) (47 ) 1
Other, net 1
2
(1 ) 6
8
(2 )
Total other income and (deductions) (14 )
(13 ) (1 ) (40 )
(39 ) (1 )
Income (loss) before income taxes 65

70
(5 ) 89

(58 ) 147
Income taxes 24
23
(1 ) 12
(8 ) (20 )
Net income (loss) $ 41
$ 47
$ (6 ) $ 77
$ (50 ) $ 127

~~_________~~

~~(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.

~~Net Income (Loss)~~

Three Months Ended September 30, ~~2017~~2021 Compared to Three Months Ended September 30, ~~2016.~~ ~~ACE's~~ 2020. Net income ~~for the three months ended September 30, 2017, was lower than the same period in 2016,~~increased by $15 million primarily due to ~~a decrease in Revenue net of purchased power expense resulting from lower~~higher distribution rates and higher transmission revenues due to ~~lower average customer usage and unfavorable weather related sales, partially offset by the impact of distribution rate increases approved by the NJBPU effective August 2016.~~an increase in capital investments.

Nine Months Ended September 30, ~~2017~~2021 Compared to Nine Months Ended September 30, ~~2016.~~ ~~ACE's~~ 2020. Net income ~~(loss) for the nine months ended September 30, 2017, was~~increased by $35 million primarily due to higher ~~than the same period in 2016, primarily~~distribution rates, higher distribution revenues due to an increase in volume in ACE's service territory, and higher transmission revenues due to an increase in capital investments.

The changes in Operating revenues consisted of the following:


	Three Months Ended September 30, 2021		Nine Months Ended September 30, 2021
	(Decrease) Increase		Increase (Decrease)
Weather	$	(3)	$	—
Volume	3		19
Distribution	4		3
Transmission	10		46
Other	(1)		(1)
	13		67




Regulatory required programs	18		61
Total increase	$	31	$	128

Revenue ~~net of purchased power expense resulting~~Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from ~~higher~~ electric distribution ~~revenues~~in New Jersey are not impacted by abnormal weather or usage per customer as a result of ~~a distribution rate increase approved by~~ the ~~NJBPU~~Conservation Incentive Program (CIP) which became effective, ~~August 2016, lower Operating and maintenance expense mostly due to merger-related costs recognized in March 2016 and a decrease in income tax reserves~~prospectively, in the ~~first~~third quarter ~~2017 for uncertain tax positions related~~of 2021. The CIP compares current distribution revenues by customer class to approved target revenues established in ACE’s most recent distribution base rate case. The CIP is calculated annually, and recovery is subject to certain conditions, including an earnings test and ceilings on customer rate increases. While Operating revenues are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers. See Note 3 — Regulatory Matters of the Combined Notes to the ~~deductibility of certain merger commitments.~~

~~Revenues Net of Purchased Power Expense~~

Operating revenues include revenue from the distribution and supply of electricity to ACE’s customers within its service territories at regulated rates. Operating revenues also include transmission service revenue that ACE receives as a transmission owner from PJM at rates regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.

Electric revenues and purchased power expense are also affected by fluctuations in participation in the Customer Choice Program. All ACE customers have the choice to purchase electricity from competitive electric generation suppliers. The customer's choice of supplier does not impact the volume of deliveries, but affects revenue collected from customers related to supplied energy service.

Consolidated Financial Statements for additional information.

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~~Retail deliveries purchased from competitive electric generation suppliers (as a percentage of kWh sales) for the three and nine months ended September 30, 2017, compared~~Weather. Prior to the ~~same periods in 2016, consisted~~third quarter of 2021, the ~~following:~~

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Electric 44 % 44 % 48 % 46 %

~~Retail customers purchasing electric generation from competitive electric generation suppliers at September 30, 2017 and 2016 consisted of the following:~~

September 30, 2017 September 30, 2016
Number of customers % of total retail customers Number of customers % of total retail customers
Electric 91,219
17 % 96,837
18 %

Operating revenues include revenue from Transition Bond Charges that ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds, revenue from the resale in the PJM wholesale markets for energy and capacity purchased under contacts with unaffiliated NUGs, and revenue from transmission enhancement credits.

Purchased power expense consists of the cost of electricity purchased by ACE to fulfill its default electricity supply obligation and, as such, is recoverable from customers in accordance with the terms of public service commission orders.

~~The changes in ACE’s operating revenue net of purchased power expense for the three and nine months ended September 30, 2017 compared to the same periods in 2016 consisted of the following:~~

Three Months Ended
September 30, 2017 Nine Months Ended
September 30, 2017
Increase (Decrease) Increase (Decrease)
Weather $ (5 ) $ (7 )
Volume (12 ) (15 )
Pricing - distribution revenues 16
36
Regulatory required programs (9 ) (19 )
Transmission revenues 4
17
Other —
(1 )
Total (decrease) increase $ (6 ) $ 11

~~Weather.~~ ~~The~~ demand for electricity iswas affected by weather conditions. With respect to the electric business, very warm weather in summer months and very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity. Conversely, mild weather reduces demand. During the three ~~and~~months ended September 30, 2021 compared to the same period in 2020, Operating revenues related to weather decreased due to the absence of impacts in the third quarter of 2021 as a result of the CIP. During the nine months ended September 30, ~~2017~~2021 compared to the same ~~periods~~period in ~~2016, operating revenue net of purchased power and fuel expense was lower due to the impact of unfavorable weather conditions in ACE's service territory.~~

~~For retail customers of ACE, distribution~~2020, Operating revenues ~~are not decoupled from the distribution of electricity by ACE, and thus are subject to variability due to changes in customer consumption. Therefore, changes in customer usage (due~~related to weather ~~conditions, energy prices, energy savings programs or other reasons) from period to period have a direct impact on reported distribution revenue for customers in ACE's service territory.~~remained relatively consistent.

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Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 20-year period in ACE’s service territory. The changes in heating and cooling degree days in ACE’s service territory for the ~~three and~~ nine months ended September 30, ~~2017~~2021 compared to ~~the~~ same ~~periods~~period in ~~2016~~2020 and normal weather consisted of the following:


Heating and Cooling Degree-Days				% Change





Nine Months Ended September 30,	2021	2020	Normal	2021 vs. 2020		2021 vs. Normal
Heating Degree-Days	2,884	2,618	3,042	10.2	%	(5.2)	%
Cooling Degree-Days	1,246	1,300	1,165	(4.2)	%	7.0	%

Normal % Change
2017 2016 2017 vs. 2016 2017 vs. Normal
Three Months Ended September 30,
Heating Degree-Days 23
17
42
35.3 % (45.2 )%
Cooling Degree-Days 830
1,006
806
(17.5 )% 3.0 %

Nine Months Ended September 30,

Heating Degree-Days 2,608
2,938
3,103
(11.2 )% (16.0 )%
Cooling Degree-Days 1,153
1,267
1,092
(9.0 )% 5.6 %

~~Volume.~~ ~~During~~Volume,exclusive of the ~~three~~effects of weather, increased for the nine months ended September 30, ~~2017,~~2021 compared to the same period in ~~2016, the decrease in operating revenue net of purchased power expense related to delivery volume, exclusive of the effects of weather, is~~2020, primarily due to ~~lower average~~ customer growth and usage. ~~During~~


Electric Retail Deliveries to Customers (in GWhs)	Nine Months Ended September 30,		% Change	Weather - Normal % Change(b)
	2021	2020
Residential		3,443	3,193	7.8	%	7.1	%
Small commercial & industrial		1,073	967	11.0	%	11.1	%
Large commercial & industrial		2,351	2,287	2.8	%	3.1	%
Public authorities & electric railroads		33	33	—	%	0.7	%
Total electric retail deliveries(a)		6,900	6,480	6.5	%	6.3	%


	As of September 30,
Number of Electric Customers	2021	2020
Residential	499,775	497,222
Small commercial & industrial	61,838	61,521
Large commercial & industrial	3,209	3,305
Public authorities & electric railroads	707	694
Total	565,529	562,742

_________

(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 ~~nine months ended September 30, 2017 compared to~~change in delivery volumes assuming normalized weather based on the ~~same period in 2016, primarily reflects lower average customer usage, partially offset by the impact of customer growth.~~historical 20-year average.

~~Pricing—~~Distribution ~~Revenues.~~ ~~The increase in operating revenue net of purchased power expense~~Revenue increased for the three and nine months ended September 30, ~~2017,~~2021 compared to the same ~~periods~~period in ~~2016, was primarily~~2020 due to ~~the impact of~~ higher ~~electric~~ distribution ~~base rates charged to customers that became effective in August 2016. See Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.~~rates.

~~Regulatory Required Programs.~~ This represents the change in operating revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs. The riders are designed to provide full and current cost recovery as well as a return. The costs of these programs are included in Operating and maintenance expense, Depreciation and amortization expense and Taxes other than income in ACE's Consolidated Statements of Operations and Comprehensive Income. Refer to the Operating and maintenance expense and Depreciation and amortization expense discussion below for additional information on included programs.

Transmission Revenues.Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being ~~recovered and other billing adjustments. The increase in~~recovered. Transmission revenue ~~net of purchased power expense~~increased for the three months ended September 30, ~~2017~~2021 compared to the same period in ~~2016 is a result of higher rates effective June 1, 2017 and related~~2020, primarily due to increases in ~~transmission plant investment and operating expenses. The increase in~~capital investment. Transmission revenue ~~net of purchased power expense~~increased for the nine months ended September 30, ~~2017~~2021 compared to the same period in ~~2016 is a result~~2020, primarily due to the reduction in revenue in 2020 due to the settlement agreement of ~~higher rates effective June 1, 2017~~ongoing transmission related income tax regulatory liabilities and ~~June 1, 2016 related to~~ increases in ~~transmission plant investment~~capital investment.

Other Revenue includes rental revenue, service connection fees, and ~~operating expenses.~~

~~Operating and Maintenance Expense~~mutual assistance revenues.

193

Three Months Ended September 30, Increase (Decrease) Nine Months Ended September 30,
Increase
(Decrease)
2017 2016 2017 2016
Operating and maintenance expense - baseline $ 71
$ 66
$ 5
$ 222
$ 343
$ (121 )
Operating and maintenance expense - regulatory required programs^(a)
1
1
—
3
3
—
Total operating and maintenance expense $ 72
$ 67
$ 5
$ 225
$ 346
$ (121 )

~~_________~~


~~(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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Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, Societal Benefits Charge, Transition Bonds, and BGS procurement and administrative costs. The ~~changes~~riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Purchased power expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries, as ACE remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, ACE either acts as the billing agent or the competitive supplier separately bills its own customers, and therefore ACE does not record Operating revenues or Purchased power expense related to the electricity. For customers that choose to purchase electric generation from ACE, ACE is permitted to recover the electricity, ZEC, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power expense related to the electricity, ZECs, and RECs.

See Note 5 - Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ACE's revenue disaggregation.

The increase of $19 million and $72 million for the three and nine months ended September 30, ~~2017~~2021 compared to the same ~~periods~~period in ~~2016~~2020, respectively, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.

The changes in Operating and maintenance expense consisted of the following:


								Three Months Ended September 30, 2021		Nine Months Ended September 30, 2021
	Three Months Ended September 30, 2017			Nine Months Ended September 30, 2017				Increase (Decrease)		Increase (Decrease)
BSC and PHISCO costs							BSC and PHISCO costs	$	2	$	4
Labor, other benefits, contracting and materials							Labor, other benefits, contracting and materials	2		(2)
Pension and non-pension postretirement benefits expense							Pension and non-pension postretirement benefits expense	—		(1)
	Increase (Decrease)			Increase (Decrease)
Baseline
Labor, other benefits, contracting and materials	$	3		$	6
Storm-related costs	(3		)	(2		)	Storm-related costs	(2)		(5)
BSC and PHISCO allocations^(a)	—			(11		)
Deferral of merger-related costs to regulatory asset	(9		)	(9		)
Merger commitments^(b)	10			(111		)
Other	4			6			Other	(3)		(2)
								(1)		(6)

Regulatory required programs(a)							Regulatory required programs(a)	5		(1)
Total increase (decrease)	$	5		$	(121	)	Total increase (decrease)	$	4	$	(7)

_________


~~(a)~~	~~Primarily related to merger severance and compensation costs recognized in 2016.~~


~~(b)~~	~~Primarily related to merger-related commitments for customer rate credits and charitable contributions recognized in 2016.~~

~~Depreciation~~(a)ACE is allowed to recover from or refund to customers the difference between its annual credit loss expense and ~~Amortization Expense~~the amounts collected in rates annually through the Societal Benefits Charge.

The changes in Depreciation and amortizationexpense ~~for the three and nine months ended September 30, 2017 compared to the same periods in 2016~~ consisted of the following:


								Three Months Ended September 30, 2021		Nine Months Ended September 30, 2021
	Three Months Ended September 30, 2017			Nine Months Ended September 30, 2017				Increase (Decrease)		Increase (Decrease)
	Increase (Decrease)			Increase (Decrease)
Depreciation expense^(a)	$	1		$	4
Depreciation and amortization(a)							Depreciation and amortization(a)	$	4	$	11
Regulatory asset amortization	—			(2		)	Regulatory asset amortization	—		(1)
Regulatory required programs^(b)	(9		)	(19		)
Regulatory required programs							Regulatory required programs	(6)		(11)
Total decrease	$	(8	)	$	(17	)	Total decrease	$	(2)	$	(1)

_________


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

~~(b)~~

Regulatory required programs decreased for the three and nine months ended September 30, 2017 compared to the same periods in 2016 as a result of lower revenue due to rate decreases effective October 2016 for the ACE Transition Bond Charge and Market Transition Charge Tax. 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.

~~Taxes Other Than Income~~(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.

~~Taxes other than income for the three and nine months ended September 30, 2017 compared to the same periods in 2016, remained relatively constant.~~

~~Gain on sales of assets~~

~~Gain on sales of assets for the three and nine months ended September 30, 2017 compared to the same periods in 2016 remained relatively constant.~~

~~Interest Expense, Net~~

~~Interest expense, net for the three and nine months ended September 30, 2017 compared to the same periods in 2016 remained relatively constant.~~

~~Other, Net~~

~~Other, net for the three and nine months ended September 30, 2017 compared to the same periods in 2016, remained relatively constant.~~

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Effective ~~Income Tax Rate~~

~~ACE's effective~~ income tax ~~rate was 36.9%~~rates were (13.9)% and ~~32.9%~~(10.3)% for the three months ended September 30, ~~2017~~2021 and ~~2016, respectively. ACE's effective income tax rate was 13.5%~~2020, respectively, and ~~13.8%~~(9.3)% and (58.2)% for the nine months ended September 30, ~~2017~~2021 and ~~2016,~~2020, respectively. InFor the ~~first quarter~~nine months ended September 30, 2021, compared to the same period in 2020, the change is primarily due to the April 24, 2020 settlement agreement of ~~2017,~~ongoing transmission related income tax regulatory liabilities, partially offset by the July 14, 2021 settlement which allowed ACE ~~decreased its liability for unrecognized~~to retain certain tax ~~benefits by $22 million resulting in a benefit to Income taxes and a corresponding decrease in its effective tax rate.~~benefits. See Note ~~12 -~~3 — Regulatory Matters of the 2020 Exelon Form 10-K for additional information on the April 24, 2020

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settlement. See Note 3 — Regulatory Matters and Note 10 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information on the July 14, 2021 settlement agreement and regarding the components of the effective income tax ~~rates.~~

~~ACE Electric Operating Statistics and Revenue Detail~~rates, respectively.

195

Three Months Ended
September 30, % Change Weather - Normal % Change Nine Months Ended
September 30, % Change Weather - Normal % Change
Retail Deliveries to Customers (in GWhs) 2017 2016 2017 2016
Retail Deliveries^(a)

Residential 1,349
1,575
(14.3 )% (10.4 )% 3,042
3,327
(8.6 )% (6.0 )%
Small commercial & industrial 407
426
(4.5 )% (1.9 )% 992
998
(0.6 )% 0.8 %
Large commercial & industrial 939
1,032
(9.0 )% (6.3 )% 2,557
2,705
(5.5 )% (4.6 )%
Public authorities & electric railroads 9
11
(18.2 )% (18.2 )% 33
35
(5.7 )% (5.7 )%
Total retail deliveries 2,704
3,044
(11.2 )% (7.8 )% 6,624
7,065
(6.2 )% (4.5 )%

As of September 30,
Number of Electric Customers 2017 2016
Residential 486,212
483,542
Small commercial & industrial 60,982
60,875
Large commercial & industrial 3,726
3,796
Public authorities & electric railroads 633
593
Total 551,553
548,806

Three Months Ended
September 30, % Change Nine Months Ended
September 30, % Change
Electric Revenue 2017 2016 2017 2016
Retail Sales^(a)

Residential $ 211
$ 249
(15.3 )% $ 484
$ 530
(8.7 )%
Small commercial & industrial 53
55
(3.6 )% 129
133
(3.0 )%
Large commercial & industrial 49
57
(14.0 )% 143
158
(9.5 )%
Public authorities & electric railroads 3
4
(25.0 )% 10
10
— %
Total retail 316
365
(13.4 )% 766
831
(7.8 )%
Other revenue^(b)
54
56
(3.6 )% 149
151
(1.3 )%
Total electric revenue^(c)
$ 370
$ 421
(12.1 )% $ 915
$ 982
(6.8 )%

~~_________~~


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


~~(b)~~	~~Other revenue includes transmission revenue from PJM and wholesale electric revenues.~~


~~(c)~~	Includes operating revenues from affiliates totaling $0 million and $1 million for the three months ended September 30, 2017 and 2016, respectively, and $2 million and $3 million for the nine months ended September 30, 2017 and 2016, respectively.

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Liquidity and Capital Resources

Exelon activity presented below includes the activity of PHI, Pepco, DPL and ACE, from the PHI Merger effective date of March 24, 2016 through September 30, 2017. Exelon prior year activity is unadjusted for the effects of the PHI Merger. Due to the application of push-down accounting to the PHI entity, PHI's activity is presented in two separate reporting periods, the legacy PHI activity through March 23, 2016 (Predecessor), and PHI activity for the remainder of the period after the PHI merger date (Successor). For each of Pepco, DPL and ACE the activity presented below include its activity for the nine months ended September 30, 2017 and 2016. All results included throughout the liquidity and capital resources section are presented on a GAAP basis.

The Registrants’ operating and capital expenditures requirements are provided by internally generated cash flows from operations, the sale of certain receivables, as well as funds from external sources in the capital markets and through bank borrowings. The Registrants’ businesses are capital intensive and require considerable capital resources. Each of the Registrants annually evaluates its financing plan, dividend practices, and credit line sizing, focusing on maintaining its investment grade ratings while meeting its cash needs to fund capital requirements, retire debt, pay dividends, fund pension and OPEB obligations, and invest in new and existing ventures. A broad spectrum of financing alternatives beyond the core financing options can be used to meet its needs and fund growth including monetizing assets in the portfolio via project financing, asset sales, and the use of other financing structures (e.g., joint ventures, minority partners, etc.). Each Registrant’s access to external financing on reasonable terms depends on its credit ratings and current overall capital market business conditions, including that of the utility industry in general. If these conditions deteriorate to the extent that the Registrants no longer have access to the capital markets at reasonable terms, the Registrants have access to ~~unsecured revolving~~ credit facilities with aggregate bank commitments of $9$10.3 billion. ~~In addition, Generation has $525 millionin bilateral facilities with banks which have various expirations between December 2017 and January 2019.~~ The Registrants utilize their credit facilities to support their commercial paper programs, provide for other short-term borrowings and to issue letters of credit. See the “Credit Matters” section below for ~~further discussion.~~additional information. The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs, and capital expenditure requirements.

The Registrants primarily use their capital resources, including cash, to fund capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and ~~other postretirement benefit~~OPEB obligations, and invest in new and existing ventures. The Registrants spend a significant amount of cash on capital improvements and construction projects that have a long-term return on investment. Additionally, ~~ComEd, PECO, BGE, Pepco, DPL and ACE~~the Utility Registrants operate in rate-regulated environments in which the amount of new investment recovery may be delayed or limited and where such recovery takes place over an extended period of time. See Note 1113 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for ~~further discussion of~~additional information on the Registrants’ debt and credit agreements.

NRC Minimum Funding Requirements (Exelon and Generation)

NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that sufficient funds will be available in certain minimum amounts to decommission the facility. These NRC minimum funding levels are typically based upon the assumption that decommissioning activities will commence after the end of the current licensed life of each unit. If a unit fails the NRC minimum funding test, then the plant’s owners or parent companies would be required to take steps, such as providing financial guarantees through letters of credit or parent company guarantees or making additional cash contributions to the NDT fund to ensure sufficient funds are available. See Note ~~13 -~~8 — Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements for additional ~~information on the NRC minimum funding requirements.~~information.

If a nuclear plant were to early retire there is a risk that it will no longer meet the NRC minimum funding requirements due to the earlier commencement of decommissioning activities and a shorter time period over which the NDT ~~fund investments~~funds could appreciate in value. A shortfall could require ~~Exelon to post parental~~that Generation address the shortfall by providing additional financial assurances such as surety bonds, letters of credit, or parent company guarantees for Generation’s share of the ~~obligations.~~funding assurance. However, the amount of any ~~required guarantees~~assurance will ultimately depend on the decommissioning approach, ~~adopted at each site,~~ the associated level of costs, and the ~~decommissioning trust~~NDT fund investment performance going forward. ~~Within~~No later than two years after shutting down a plant, Generation must submit a ~~post-shutdown decommissioning activities report (PSDAR)~~PSDAR to the NRC that includes the planned option for decommissioning the site. As ~~discussed in Note 13 — Nuclear Decommissioning~~a result of the ~~Combined Notes to Consolidated Financial Statements, Generation filed its biennial decommissioning funding status report with the NRC on March 31, 2017 and demonstrated adequate funding~~early retirement reversal, additional financial assurance for all nuclear units currently operating. As of September 30, 2017, across the four alternative decommissioning approaches available, Generation estimates a parental guarantee of up to $115 million from Exelon could beis no longer required for TMI, dependent upon the ultimate decommissioning approach selected. TMI passes the NRC minimum funding test based on the unit's 2019 retirement date under the decommissioning approach currently considered to be the most likely. For Oyster Creek, none of the alternative decommissioning approaches available would require Exelon to post a parental guarantee.Byron.

Upon issuance of any required financial ~~guarantees,~~assurance, subject to satisfying various regulatory preconditions, each site would be able to utilize the respective NDT funds for radiological decommissioning costs, which represent the majority of the total expected decommissioning costs.

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However, under the regulations, the NRC must approve an ~~additional~~ exemption in order for ~~the plant’s owner(s)~~Generation to utilize the NDT ~~fund~~funds to pay for non-radiological decommissioning costs (i.e., spent fuel management and site restoration ~~costs)~~costs, if applicable). If a unit does not receive this exemption, ~~the~~those costs would be borne by Generation without reimbursement from or access to the ~~owner(s). While the ultimate amounts may vary greatly and could be reduced by alternate decommissioning scenarios and/or reimbursement~~NDT funds.

196

Table of ~~certain costs~~Contents

As of September 30, 2021, Generation is not required to provide any additional financial assurances for TMI Unit 1 under the ~~United States Department of Energy reimbursement agreements or future litigation, across~~SAFSTOR scenario which is the ~~four alternative~~planned decommissioning ~~approaches available, if~~option as described in the TMI ~~or Oyster Creek were~~Unit 1 PSDAR filed by Generation with the NRC on April 5, 2019. On October 16, 2019, the NRC granted Generation's exemption request to ~~fail to obtain~~use the ~~exemption, Generation estimates it could incur~~TMI Unit 1 NDT funds for spent fuel management ~~and~~costs. An additional exemption request to allow the TMI Unit 1 NDT funds to be used for site restoration costs ~~over~~was submitted to the ~~next ten years of up to $190 million~~NRC on May 20, 2021 and $150 million net of taxes, respectively, dependent upon the ultimate decommissioning approach selected. Under the decommissioning approach currently considered the most likely for each unit, Generation estimates it could incur spent fuel management and site restoration costs over the next ten years of up to $170 million and $130 million net of taxes, respectively, if TMI or Oyster Creek were to fail to obtain the exemption.is pending NRC review.

~~Junior Subordinated Notes~~

In June 2014, Exelon issued $1.15 billion of junior subordinated notes in the form of 23 million equity units at a stated amount of $50.00 per unit. Each equity unit represented an undivided beneficial ownership interest in Exelon’s $1.15 billion of 2.50% junior subordinated notes due in 2024 (“2024 notes”) and a forward equity purchase contract. As contemplated in the June 2014 equity unit structure, in April 2017, Exelon completed the remarketing of the 2024 notes into $1.15 billion of 3.497% junior subordinated notes due in 2022 (“Remarketing”). Exelon conducted the Remarketing on behalf of the holders of equity units and did not directly receive any proceeds therefrom. Instead, the former holders of the 2024 notes used debt remarketing proceeds towards settling the forward equity purchase contract with Exelon on June 1, 2017. Exelon issued approximately 33 million shares of common stock from treasury stock and received $1.15 billion upon settlement of the forward equity purchase contract. When reissuing treasury stock Exelon uses the average price paid to repurchase shares to calculate a gain or loss on issuance and records gains or losses directly to retained earnings. A loss on reissuance of treasury shares of $1.05 billion was recorded to retained earnings as of September 30, 2017. See Note 17 - Earnings Per Share and Equity of the Combined Notes to Consolidated Financial Statements for further information on the issuance of common stock.

Cash Flows from Operating Activities

~~General~~(All Registrants)

Generation’s cash flows from operating activities primarily result from the sale of electric energy and energy-related products and services to customers. Generation’s future cash flows from operating activities may be affected by future demand for, and market prices of, energy and its ability to continue to produce and supply power at competitive costs, as well as to obtain collections from ~~customers.~~customers and the sale of certain receivables.

The Utility Registrants' cash flows from operating activities primarily result from the transmission and distribution of electricity and, in the case of PECO, BGE, and DPL, gas distribution services. The Utility Registrants' distribution services are provided to an established and diverse base of retail customers. The Utility Registrants' future cash flows may be affected by the economy, weather conditions, future legislative initiatives, future regulatory proceedings with respect to their rates or operations, ~~competitive suppliers,~~ and their ability to achieve operating cost reductions.

See ~~Notes~~Note 3 — Regulatory Matters and 24Note 19 — Commitments and Contingenciesof the Combined Notes to Consolidated Financial Statements of the Exelon ~~2016~~2020 Form 10-K for ~~further discussion of~~additional information on regulatory and legal proceedings and proposed legislation.

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The following table provides a summary of the ~~major items affecting Exelon’s~~change in cash flows from ~~operations~~operating activities for the nine months ended September 30, ~~2017~~2021 and ~~2016:~~2020 by Registrant:

Nine Months Ended
September 30,
2017
2016^(c)
Variance
Net income $ 1,911
$ 956
$ 955
Add (subtract):
Non-cash operating activities^(a)
5,011
5,946
(935 )
Pension and non-pension postretirement benefit contributions (344 ) (283 ) (61 )
Income taxes 167
527
(360 )
Changes in working capital and other noncurrent assets and liabilities^(b)
(1,003 ) (516 ) (487 )
Option premiums received (paid), net 35
(24 ) 59
Collateral (posted) received, net (100 ) 757
(857 )
Net cash flows provided by operations $ 5,677
$ 7,363
$ (1,686 )

~~_________~~

~~(a)~~

Represents, when applicable, 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, PHI merger commitment and severance charges, and other non-cash charges. See Note 19 - 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.~~


~~(c)~~	~~Includes PHI Consolidated activity from March 24, 2016 to September 30, 2016.~~

~~Pension and Other Postretirement Benefits~~


(Decrease) increase in cash flows from operating activities	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Net income	$	(78)	$	(607)	$	305	$	66	$	17	$	117	$	37	$	44	$	35
Adjustments to reconcile net income to cash:
Non-cash operating activities	(899)		(527)		(216)		1		(4)		(22)		8		(10)		(23)
Pension and non-pension postretirement benefit contributions	(22)		12		(31)		3		(2)		(8)		(1)		—		—
Income taxes	281		65		13		7		(43)		31		1		31		6
Changes in working capital and other noncurrent assets and liabilities	(775)		(611)		(28)		(75)		(25)		(92)		(134)		28		27
Option premiums paid, net	(55)		(55)		—		—		—		—		—		—		—
Collateral received, net	1,467		1,334		65		—		—		—		—		—		—
(Decrease) increase in cash flows from operating activities	$	(81)	$	(389)	$	108	$	2	$	(57)	$	26	$	(89)	$	93	$	45

Management considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006, management of the pension obligation and regulatory implications.

On October 3, 2017, the US Department of Treasury and IRS released final regulations updating the mortality tables to be used for defined benefit pension plan funding, as well as the valuation of lump sum and other accelerated distribution options, effective for plan years beginning in 2018. The new mortality tables reflect improved projected life expectancy as compared to the existing table, which is generally expected to increase minimum pension funding requirements, Pension Benefit Guaranty Corporation premiums and the value of lump sum distributions. The IRS will permit plan sponsors the option of using existing mortality tables for determining minimum funding requirements for 2018. The one-year delay does not apply for use of the mortality tables to determine the present value of lump sum distributions. Exelon is still evaluating any potential impacts of the new mortality tables.

OPEB funding generally follows accounting cost; however, Exelon’s management has historically considered several factors in determining the level of contributions to its funded other postretirement benefit plans, including liabilities management, levels of benefit claims paid and regulatory implications (amounts deemed prudent to meet regulator expectations and best assure continued recovery).

To the extent interest rates decline significantly or the pension plans do not earn the expected asset return rates, annual pension contribution requirements in future years could increase. Additionally, expected contributions could change if Exelon changes its pension or OPEB funding strategy.

~~Tax Matters~~

~~The Registrants’ future cash flows from operating activities may be affected by the following tax matters:~~

Exelon appealed the Tax Court’s like-kind exchange decision in the third quarter of 2017 and expects that a payment of approximately $1.3 billion related to the like-kind exchange will be due, including $300 million attributable to ComEd, in the fourth quarter of 2017. While Exelon will receive a tax benefit of approximately $350 million associated with the deduction for the interest, Exelon currently has a net operating loss carryforward and thus does not expect to realize the cash benefit until 2018. After taking into account these interest deduction tax benefits, the total estimated net cash outflow for the like-kind exchange is

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approximately $950 million, of which approximately $300 million is attributable to ComEd after giving consideration to Exelon’s agreement to hold ComEd harmless from any unfavorable impacts on ComEd’s equity from the like-kind exchange position.

Of the above amounts payable, Exelon deposited with the IRS $1.25 billion in October of 2016. In the third quarter of 2017, the $300 million payable discussed above attributable to ComEd, net of ComEd’s receivable pursuant to the hold harmless agreement, was settled with Exelon. Any remaining amounts due to the IRS will be paid by Exelon in the fourth quarter of 2017. Exelon funded the $1.25 billion deposit with a combination of cash on hand and short-term borrowings. See Note 12 - Income Taxes for further discussion of the like-kind exchange tax position.

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. On July 6, 2017, Illinois enacted Senate Bill 9, which permanently increased Illinois’ total corporate income tax rate from 7.75% to 9.50% effective July 1, 2017. The rate increase is not expected to have a material ongoing impact to Exelon’s, Generation’s or ComEd’s future cash taxes. See Note 12 - ~~Income Taxes~~ ~~for further discussion of the Illinois tax rate change.~~

~~Cash flows from operations for the nine months ended September 30, 2017 and 2016 by Registrant were as follows:~~

Nine Months Ended
September 30,
2017 2016
Exelon $ 5,677
$ 7,363
Generation 2,270
3,723
ComEd 1,120
1,749
PECO 603
582
BGE 704
660
Pepco 348
504
DPL 292
267
ACE 158
315

Successor Predecessor
Nine Months Ended September 30, 2017
March 24, 2016 to September 30, 2016
January 1, 2016 to March 23, 2016
PHI $ 797
$ 546
$ 264

Changes in the Registrants'cash flows from operations were generally consistent with changes in each Registrant’s respective results of operations, as adjusted by changes in working capital in the normal course of business, except as discussed below. In addition, significant operating cash flow impacts for the Registrants for the nine months ended September 30, ~~2017~~2021 and ~~2016~~2020 were as follows:

~~Generation~~•See Note 18 — Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements and the Registrants’ Consolidated Statements of Cash Flows for additional information on non-cash operating activities.

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•See Note 10 — Income Taxes of the Combined Notes to Consolidated Financial Statements and the Registrants' Consolidated Statements of Cash Flows for additional information on income taxes.

•Changes in working capital and other noncurrent assets and liabilities include a decrease in Accounts receivable resulting from the impact of cash received at Exelon and Generation in 2020 related to the revolving accounts receivable financing arrangement entered into on April 8, 2020 and an increase in Accounts payable and accrued expenses resulting from the impact of certain penalties for natural gas delivery associated with the February 2021 extreme cold weather event at Exelon and Generation. See Note 6 – Accounts Receivable and Note 3 – Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the sales of customer accounts receivable and on the February 2021 extreme cold weather event, respectively.

•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~~over-the-counter markets. During the nine months ended September 30, 2017 and 2016, Generation had net (payments)/collections of counterparty cash collateral of $(77) million and $759 million, respectively, primarily due to market conditions that resulted in changes to Generation’s net mark-to-market position.

During the nine months ended September 30, 2017 and 2016, Generation had net (payments) collections of approximately $(35) million and $24 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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~~Table of Contents~~

~~ComEd~~

During nine months ended September 30, 2017 and 2016, ComEd posted approximately $24 million and $2 million of cash collateral with PJM, respectively. ComEd’s 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. As of September 30, 2017 and 2016, ComEd had approximately $47 million and $33 million cash collateral posted with PJM, respectively.

~~For further discussion regarding changes in non-cash operating activities, please refer to~~See Note ~~19 - Supplemental~~12 — Derivative Financial ~~Information~~Instruments of the Combined Notes to Consolidated Financial Statements for additional information on the ~~Financial Statements.~~Registrants’ collateral.

Cash Flows from Investing Activities (All Registrants)

~~Cash~~The following table provides a summary of the change in cash flows ~~used in~~from investing activities for the nine months ended September 30, ~~2017~~2021 and ~~2016~~2020 by ~~Registrant were as follows:~~ Registrant:

Nine Months Ended
September 30,
2017
2016
Exelon $ (5,810 ) $ (13,219 )
Generation (1,903 ) (3,278 )
ComEd (1,731 ) (1,919 )
PECO (457 ) (438 )
BGE (586 ) (614 )
Pepco (439 ) (435 )
DPL (293 ) (254 )
ACE (241 ) (227 )

Successor Predecessor

Nine Months Ended September 30, 2017
March 24, 2016 to September 30, 2016
January 1, 2016 to March 23, 2016
PHI $ (991 )
$ (631 ) $ (343 )


Increase (decrease) in cash flows from investing activities	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Capital expenditures	$	(364)	$	126	$	(140)	$	(54)	$	(69)	$	(227)	$	(129)	$	(42)	$	(55)
Proceeds from NDT fund sales, net	(66)		(66)		—		—		—		—		—		—		—

Proceeds from sales of assets and businesses	755		756		—		—		—		—		—		—		—
Changes in intercompany money pool	—		—		—		(68)		—		—		117		—		—
Collection of DPP	534		534		—		—		—		—		—		—		—

Other investing activities	42		—		20		1		13		(4)		1		4		(4)
Increase (decrease) in cash flows from investing activities	$	901	$	1,350	$	(120)	$	(121)	$	(56)	$	(231)	$	(11)	$	(38)	$	(59)

Significant investing cash flow impacts for the Registrants for nine months ended September 30, ~~2017~~2021 and ~~2016~~2020 were as follows:

~~Exelon~~

~~During the nine months ended September 30, 2017, Exelon had~~•Variances in capital expenditures ~~of $23 million and $178 million relating~~ are primarily due to the ~~acquisitions~~timing of ~~ConEdison Solutions~~cash expenditures for capital projects. Refer below for additional information on projected capital expenditure spending.

•Proceeds from sales of assets and ~~the FitzPatrick facility, respectively. During the nine months ended September 30, 2016, Exelon had expenditures of $6.6 billion relating~~businesses increased primarily due to the ~~acquisition~~sale of ~~PHI.~~a significant portion of Generation's solar business and a biomass facility and proceeds received on sales of equity investments. See Note 2 – Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information on the sale of Generation's solar business and biomass facility.

~~During~~•Changes in intercompany money pool are driven by short-term borrowing needs. Refer below for more information regarding the ~~nine months ended September 30, 2016, Exelon had proceeds~~intercompany money pool.

•See Note 6 – Accounts Receivable of ~~$360 million as a result~~the Combined Notes to Consolidated Financial Statements for additional information on the Collection of ~~early termination~~DPP.

198

Table of ~~direct financing leases.~~Contents

~~Generation~~

During the nine months ended September 30, 2017, Exelon had expenditures of $23 million and $178 million relating to the acquisitions of ConEdison Solutions and the FitzPatrick facility, respectively.

Capital Expenditure Spending

~~Generation~~

~~Generation has entered into several agreements to acquire equity interests in privately held and development stage entities which develop energy-related technologies. The agreements contain a series~~As of ~~scheduled investment commitments, including in-kind service contributions. There are anticipated expenditures remaining through 2019 to~~

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fund anticipated planned capital and operating needs of the associated companies. See Note 24 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements of the Exelon 2016 Form 10-K for further details of Generation’s equity interests.

~~Capital expenditures by Registrant for the nine months ended~~ September 30, ~~2017~~2021, the most recent estimates of capital expenditures for plant additions and ~~2016 and projected amounts~~improvements for ~~the full year 2017~~2021 are as follows:


	Projected Full Year 2017^(a)		Nine Months Ended September 30,
			2017		2016
Exelon^(b)	$	8,075	$	5,556	$	6,368
(In millions)							(In millions)	Transmission	Distribution	Gas	Total
Exelon							Exelon	N/A	N/A	N/A	$	8,175
Generation	2,450		1,654		2,651		Generation	N/A	N/A	N/A	1,450
ComEd^(c)	2,200		1,698		1,950
ComEd							ComEd	475	1,925	N/A	2,400
PECO	775		537		448		PECO	150	775	350	1,275
BGE	925		615		611		BGE	325	475	400	1,200
PHI							PHI	550	1,125	75	1,750
Pepco	625		439		392		Pepco	250	650	N/A	900
DPL	425		294		260		DPL	100	250	75	425
ACE	300		242		227		ACE	200	225	N/A	425

Projected
Full Year
2017 ^(a)
Successor Predecessor
Nine Months Ended September 30, 2017
March 24, 2016 to September 30, 2016 January 1, 2016 to March 23, 2016
PHI^(d)
$ 1,375
$ 995
$ 624
$ 273

~~_________~~


~~(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 2017 projections include approximately $274 million of expected incremental spending pursuant to EIMA, ComEd has committed to invest approximately $2.6 billion over a ten year period, through 2022, to modernize and storm-harden its distribution system and to implement smart grid technology.


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

Projected capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors.

Approximately 37% and 21% of the projected 2017 capital expenditures at Generation are for the acquisition of nuclear fuel and growth (primarily new plant construction and distributed generation), respectively, with the remaining amounts reflecting additions and upgrades to existing facilities (including material condition improvements during nuclear refueling outages). Generation anticipates that they will fund capital expenditures with internally generated funds and borrowings.

~~ComEd, PECO, BGE, Pepco, DPL and ACE~~

Approximately 93% of the projected 2017 capital expenditures at ComEd and 100% of the projected of the projected 2017 capital expenditures at PECO, BGE, Pepco, DPL, and ACE are for continuing projects to maintain and improve operations, including enhancing reliability and adding capacity to the transmission and distribution systems such as ComEd’s reliability related investments required under EIMA, and the Utility Registrants' construction commitments under PJM’s RTEP. In addition to the capital expenditure for continuing projects, ComEd’s total expenditures include smart grid/smart meter technology required under EIMA.

The Utility Registrants as transmission owners are subject to NERC compliance requirements. NERC provides guidance to transmission owners regarding assessments of transmission lines. The results of these assessments could require the Utility Registrants to incur incremental capital or operating and maintenance expenditures to ensure their transmission lines meet NERC standards. In 2010, NERC provided guidance to transmission owners that recommended the Utility Registrants perform assessments of their transmission lines. ComEd, PECO and BGE submitted their final bi-annual reports to NERC in January 2014. ComEd, PECO and BGE will be incurring incremental capital expenditures associated with this guidance following the completion of the assessments. Specific projects and expenditures are identified as the assessments are completed. ComEd’s, PECO’s and BGE’s forecasted 2017 capital expenditures above reflect capital spending for remediation to be completed through 2018. Pepco, DPL and ACE have substantially completed their assessments and thus do not expect significant capital expenditures related to this guidance in 2017.

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The Utility Registrants anticipate that they will fund their capital expenditures with a combination of internally generated funds and borrowings and additional capital contributions from parent, including ComEd’s capital expenditures associated with EIMA as further discussed in Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements.

Cash Flows from Financing Activities (All Registrants)

~~Cash~~The following table provides a summary of the change in cash flows ~~provided by (used in)~~from financing activities for the nine months ended September 30, ~~2017~~2021 and ~~2016~~2020 by ~~Registrant~~Registrant:


Increase (decrease) in cash flows from financing activities	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Changes in short-term borrowings, net	$	825	$	320	$	(334)	$	—	$	76	$	127	$	87	$	(68)	$	108
Long-term debt, net	190		1,271		300		100		(100)		13		(24)		26		11
Changes in intercompany money pool	—		(285)		—		(40)		—		(14)		—		—		(117)

Dividends paid on common stock	(2)		—		(6)		1		(33)		—		(47)		(7)		(169)
Acquisition of noncontrolling interest	(885)		(885)		—		—		—		—		—		—		—
Distributions to member	—		33		—		—		—		(154)		—		—		—
Contributions from parent/member	—		—		105		166		(27)		174		(18)		8		186

Other financing activities	12		3		(2)		(4)		2		(2)		2		(3)		(4)
Increase (decrease) in cash flows from financing activities	$	140	$	457	$	63	$	223	$	(82)	$	144	$	—	$	(44)	$	15

Significant financing cash flow impacts for the Registrants for the nine months ended September 30, 2021 and 2020 were as follows:

Nine Months Ended
September 30,
2017 2016
Exelon $ 701
$ 1,251
Generation (297 ) (501 )
ComEd 812
147
PECO 121
77
BGE (112 ) 286
Pepco 199
28
DPL (42 ) (14 )
ACE (13 ) 74

Successor Predecessor
Nine Months Ended September 30, 2017 March 24, 2016 to September 30, 2016 January 1, 2016 to March 23, 2016
PHI $ 161
$ 65
$ 372

~~Debt~~

~~See~~•Changes in short-term borrowings, net, is driven by repayments on and issuances of notes due in less than 365 days. Refer to Note 1113 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for ~~further details~~additional information on short-term borrowings.

•Long-term debt, net, varies due to debt issuances and redemptions each year. Refer to Note 13 — Debt and Credit Agreements of the ~~Registrants’~~Combined Notes to Consolidated Financial Statements for additional information on debt issuances. Refer to the debt redemptions table below for additional information.

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

~~Cash~~

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•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 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements of the Exelon 2020 Form 10-K for additional information on dividend ~~payments~~restrictions. See below for quarterly dividends declared.

•See Note 2 – Mergers, Acquisitions, and ~~distributions during~~Dispositions of the Combined Notes to Consolidated Financial Statements for additional information related to the acquisition of CENG noncontrolling interest.

•For the nine months ended September 30, ~~2017~~2021, other financing activities primarily consists of debt issuance costs. See Note 13 — Debt and ~~2016 by Registrant were as follows:~~Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants’ debt issuances.

Nine Months Ended
September 30,
2017 2016
Exelon $ 921
$ 873
Generation 494
167
ComEd 316
275
PECO 216
208
BGE^(a)
148
142
Pepco 133
92
DPL 82
39
ACE 53
24
Debt

Successor Predecessor
Nine Months Ended September 30, 2017
March 24, 2016 to September 30, 2016 January 1, 2016 to March 23, 2016
PHI $ 267
$ 174
$ —
See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt issuances.

During the nine months ended September 30, 2021, the following long-term debt was retired and/or redeemed:


Company(a)	Type	Interest Rate			Maturity	Amount
Exelon	Senior Notes	2.45	%		April 15, 2021	$	300
Exelon	Long-Term Software License Agreement	3.95	%		May 1, 2024	24
Exelon	Long-Term Software License Agreements	3.62	%		December 1, 2025	1


Generation	Continental Wind Nonrecourse Debt(b)	6.00	%		February 28, 2033	35
Generation	EGR IV Nonrecourse Debt(b)	3 month LIBOR + 2.50 %		(c)	December 15, 2027	17
Generation	SolGen Nonrecourse Debt(b)	3.93	%		September 30, 2036	7
Generation	Antelope Valley DOE Nonrecourse Debt(b)	2.29% - 3.56%			January 5, 2037	13

Generation	West Medway II Nonrecourse Debt(b)	LIBOR + 3%		(d)	March 31, 2026	8
Generation	RPG Nonrecourse Debt(a)	4.11	%		March 31, 2035	9



ComEd	First Mortgage Bonds	3.40	%		September 1, 2021	350
PECO	First Mortgage Bonds	1.70	%		September 15, 2021	300
BGE	Senior Notes	3.50	%		November 15, 2021	300

ACE	First Mortgage Bonds	4.35	%		April 1, 2021	200
ACE	Tax-Exempt First Mortgage Bonds	6.80	%		March 1, 2021	39
ACE	Transition Bonds	5.55	%		October 20, 2021	15

_________


~~(a)~~	~~Includes dividends paid on BGE’s preference stock in 2016.~~

(a)On October 5, 2021, Generation redeemed $11 million of 2.29% - 3.56% Antelope Valley DOE nonrecourse debt. On October 20, 2021, ACE redeemed $6 million of 5.55% transition bonds.

~~259~~

~~Table~~(b)See Note 17 — Debt and Credit Agreements of ~~Contents~~the Exelon 2020 Form 10-K for additional information on nonrecourse debt.

(c)The interest rate was amended to 3 month LIBOR + 2.50 % on June 16, 2021.

(d)The nonrecourse debt has an average blended interest rate.

Dividends

Quarterly dividends declared by the Exelon Board of Directors during the nine months ended September 30, ~~2017~~2021 and for the fourth quarter of ~~2017~~2021 were as follows:

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Table of Contents

Period Declaration Date Shareholder of Record Date Dividend Payable Date
Cash per Share^(a)
First Quarter 2017 January 31, 2017 February 15, 2017 March 10, 2017 $ 0.3275
Second Quarter 2017 April 25, 2017 May 15, 2017 June 9, 2017 $ 0.3275
Third Quarter 2017 July 25, 2017 August 15, 2017 September 8, 2017 $ 0.3275
Fourth Quarter 2017 September 25, 2017 November 15, 2017 December 8, 2017 $ 0.3275

~~_________~~

~~(a)~~Period

~~Exelon's Board~~

Declaration Date

Shareholder of ~~Directors approved a revised dividend policy. The approved policy will raise the dividend 2.5% each year for the next three years, beginning with the~~ Record Date

Dividend Payable Date

Cash per Share(a)

First Quarter 2021

February 21, 2021

March 8, 2021

March 15, 2021

0.3825

Second Quarter 2021

April 27, 2021

May 14, 2021

June ~~2016 dividend and subject to Board approval.~~10, 2021

0.3825

~~Short-Term Borrowings~~

~~Short-term borrowings incurred (repaid) during the nine months ended September 30, 2017 and 2016 by Registrant were as follows:~~

Nine Months Ended
September 30,
2017 2016
Exelon $ (559 ) $ (1,271 )
Generation (609 ) 43
ComEd —
(284 )
BGE (45 ) (210 )
Pepco (23 ) (64 )
DPL 54
(88 )
ACE 65
(5 )

Successor Predecessor
Nine Months Ended September 30, 2017
March 24, 2016 to September 30, 2016
January 1, 2016 to March 23, 2016
PHI $ (404 ) $ (820 ) $ 379

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~~Contributions from Parent/Member~~

~~Contributions received from Parent/Member for the nine months ended September 30, 2017 and 2016 by Registrant were as follows:~~

Nine Months Ended
September 30,
2017 2016
Generation $ 102
$ 142
ComEd ^(a)(b)
567
188
PECO ^(b)
16
18
BGE ^(b)
77
28
Pepco ^(c)
161
187
DPL ^(c)
—
113
ACE ^(c)
—
139

Successor Predecessor
Nine Months Ended September 30, 2017 March 24, 2016 to September 30, 2016 January 1, 2016 to March 23, 2016
PHI ^(b)
$ 758
$ 1,088
$ —

~~_________~~

Third Quarter 2021

July 27, 2021

August 13, 2021

September 10, 2021

0.3825

Fourth Quarter 2021

October 29, 2021

November 15, 2021

December 10, 2021

0.3825

~~(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.~~

~~(c)~~

~~Contribution paid by PHI.~~

~~Other~~

~~For~~_________

(a)Exelon's Board of Directors approved an updated dividend policy for 2021. The 2021 quarterly dividend will remain the ~~nine months ended September 30, 2017, other financing activities primarily consist~~same as the 2020 dividend of ~~debt issuance costs. See Note 11 — Debt and Credit Agreements of the Combined Notes to the Consolidated Financial Statements for further details of the Registrants’ debt issuances.~~$0.3825 per share.

Credit Matters (All Registrants)

The Registrants fund liquidity needs for capital investment, working capital, energy hedging, and other financial commitments through cash flows from continuing operations, public debt offerings, commercial paper markets, and large, diversified credit facilities. The credit facilities include ~~$9.5~~$10.3 billion in aggregate total commitments of which ~~$8.3~~$7.7 billion was available to support additional commercial paper as of September 30, ~~2017,~~2021, and of which no financial institution has more than 7% of the aggregate commitments for the Registrants. The Registrants had access to the commercial paper ~~market~~markets and had availability under their revolving credit facilities during the ~~third quarter of 2017~~nine months ended September 30, 2021 to fund their short-term liquidity needs, when necessary. Generation used its available credit facilities to manage short-term liquidity needs as a result of the impacts of the February 2021 extreme cold weather event and continues to believe it has sufficient cash on hand and available capacity on its revolver to meet its liquidity requirements. The Registrants routinely review the sufficiency of their liquidity position, including appropriate sizing of credit facility commitments, by performing various stress test scenarios, such as commodity price movements, increases in margin-related transactions, changes in hedging levels, and the impacts of hypothetical credit downgrades. The Registrants have continued to closely monitor events in the financial markets and the financial institutions associated with the credit facilities, including monitoring credit ratings and outlooks, credit default swap levels, capital raising, and merger activity. See PART I. ITEM 1A. RISK FACTORS of the Exelon ~~2016~~2020 Form 10-K for ~~further~~additional information regarding the effects of uncertainty in the capital and credit markets.

The Registrants believe their cash flow from operating activities, access to credit markets, and their credit facilities provide sufficient liquidity. If Generation lost its investment grade credit rating as of September 30, ~~2017,~~2021, it would have been required to provide incremental collateral of ~~$1.8~~approximately $3.0 billion to meet collateral obligations for derivatives, non-derivatives, normal ~~purchase~~purchases and normal sales contracts, and applicable payables and receivables, net of the contractual right of offset under master netting agreements, which is well within ~~its current~~the $4.3 billion of available credit ~~facility capacities~~capacity of ~~$4.6 billion.~~

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its revolver.

The following table presents the incremental collateral that each Utility Registrant would have been required to provide in the event each Utility Registrant lost its investment grade credit rating at September 30, ~~2017~~2021 and available credit facility capacity prior to any incremental collateral at September 30, ~~2017:~~2021:


								PJM Credit Policy Collateral		Other Incremental Collateral Required(a)		Available Credit Facility Capacity Prior to Any Incremental Collateral
	PJM Credit Policy Collateral		Other Incremental Collateral Required ^(a)		Available Credit Facility Capacity Prior to Any Incremental Collateral
ComEd	$	18	$	—	$	998	ComEd	$	27	$	—	$	998
PECO	3		20		599		PECO	1		23		600
BGE	3		28		600		BGE	4		46		600

Pepco	4		—		300		Pepco	3		—		260
DPL	1		9		300		DPL	4		11		278
ACE	—		—		300		ACE	1		—		75

_________


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

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

Project Financing (Exelon and Generation)

Project financing is used to help mitigate risk of specific generating assets. Project financing is based upon a nonrecourse financial structure, in which project debt is paid back from the cash generated by the specific asset or portfolio of assets. Borrowings under these agreements are secured by the assets and equity of each

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respective project. The lenders do not have recourse against Exelon or Generation in the event of a default. If a specific project financing entity does not maintain compliance with its specific debt financing covenants, there could be a requirement to accelerate repayment of the associated debt or other project-related borrowings earlier than the stated maturity dates. In these instances, if such repayment was not satisfied, or restructured, the lenders or security holders would generally have rights to foreclose against the project-specific assets and related collateral. The potential requirement to satisfy its associated debt or other borrowings earlier than otherwise anticipated could lead to impairments due to a higher likelihood of disposing of the respective project-specific assets significantly before the end of their useful lives. Additionally, project financing has credit facilities. Refer to Note 17 — Debt and Credit Agreements of the Exelon 2020 Form 10-K and Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on credit facilities and nonrecourse debt.

Credit Facilities (All Registrants)

Exelon ~~Pepco, DPL and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and short-term notes.~~Corporate, ComEd, and BGE meet their short-term liquidity requirements primarily through the issuance of commercial paper. Generation and PECO meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the Exelon intercompany money pool. Pepco, DPL, and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the PHI intercompany money pool. PHI Corporate meets its short-term liquidity requirements primarily through the issuance of short-term notes and the Exelon intercompany money pool. The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit.

~~The following table reflects~~See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ ~~commercial paper programs supported by~~short-term borrowing activity. See Note 17 — Debt and Credit Agreements of the ~~revolving credit agreements and bilateral credit agreements at September 30, 2017:~~

~~Commercial Paper Programs~~

Commercial Paper Issuer
Maximum Program Size ^(a)(b)
Outstanding Commercial Paper at
September 30, 2017 Average Interest Rate on Commercial Paper Borrowings for the Nine Months Ended September 30, 2017
Exelon Corporate $ 600
$ —
1.16 %
Generation 5,300
—
1.20 %
ComEd 1,000
—
1.24 %
PECO 600
—
1.13 %
BGE 600
—
1.15 %
Pepco 500
—
1.04 %
DPL 500
54
1.40 %
ACE 350
65
1.36 %

~~_________~~


~~(a)~~	~~Excludes $525 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 expireExelon 2020 Form 10-K for additional information on October 12, 2018. These facilities are solely utilized to issue letters of credit. As of September 30, 2017, letters of credit issued under these agreements for Generation, ComEd, PECO and BGE totaled $5 million, $12 million, $21 million and $2 million, respectively.

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~~Table of Contents~~

~~In order to maintain their respective commercial paper programs in~~ the amounts indicated above, each Registrant must have credit facilities in place, at least equal to the amount of its commercial paper program. While the amount of its commercial paper outstanding does not reduce available capacity under a Registrant’s credit facility, a Registrant does not issue commercial paper in an aggregate amount exceeding the then available capacity under its credit facility. At September 30, 2017, the Registrants had the following aggregate bank commitments, credit facility borrowings and available capacity under their respective credit facilities:

~~Credit Agreements~~

Borrower Facility Type
Aggregate Bank
Commitment^(a)(b)(c)

Facility
Draws

Outstanding
Letters of
Credit
Available Capacity at
September 30, 2017
Actual
To Support
Additional
Commercial
Paper^(b)(d)
Exelon Corporate Syndicated Revolver $ 600
$ —
$ 45
$ 555
$ 555
Generation^(e)
Syndicated Revolver 5,300
—
887
4,413
4,413
Generation Bilaterals 525
70
235
220
—
ComEd Syndicated Revolver 1,000
—
2
998
998
PECO Syndicated Revolver 600
—
1
599
599
BGE Syndicated Revolver 600
—
—
600
600
Pepco Syndicated Revolver 300
—
—
300
300
DPL Syndicated Revolver 300
—
—
300
246
ACE Syndicated Revolver 300
—
—
300
235

~~_________~~

~~(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 September 30, 2017, letters of credit issued under these agreements for Generation, ComEd, PECO and BGE totaled $5 million, $12 million, $21 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 14 — Debt and Credit Agreements in the Exelon 2016 Form 10-K for further information on Continental Wind nonrecourse debt.~~


~~(d)~~	~~Excludes $525 million bilateral credit facilities that do not back Generation’s commercial paper program.~~


~~(e)~~	~~Excludes ExGen Texas Power Financing's $20 million of borrowed debt on its revolving credit facility.~~

~~As of September 30, 2017, there was $70 million of borrowings under Generation's bilateral~~Registrants’ credit facilities.

Borrowings under Exelon Corporate’s, Generation’s, ComEd’s, PECO’s, BGE's, Pepco's, DPL's, and ACE's revolving credit agreements bear interest at a rate based upon either the prime rate or a LIBOR-based rate, plus an adder based upon the particular Registrant’s credit rating. The adders for the prime based borrowings and LIBOR-based borrowings are presented in the following table:

Exelon Generation ComEd PECO BGE Pepco DPL ACE
Prime based borrowings 27.5 27.5 7.5 0.0 0.0 7.5
7.5
7.5
LIBOR-based borrowings 127.5 127.5 107.5 90.0 100.0 107.5
107.5
107.5

The maximum adders for prime rate borrowings and LIBOR-based rate borrowings are 90 basis points and 165 basis points, respectively. The credit agreements also require the borrower to pay a facility fee based upon the aggregate commitments. The fee varies depending upon the respective credit ratings of the borrower.

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~~Table of Contents~~

Each revolving credit agreement for Exelon, Generation, ComEd, PECO, BGE, Pepco, DPL and ACE requires the affected borrower to maintain a minimum cash from operations to interest expense ratio for the twelve-month period ended on the last day of any quarter. The following table summarizes the minimum thresholds reflected in the credit agreements for the nine months ended September 30, 2017:

~~Exelon~~

~~Generation~~

~~ComEd~~

~~PECO~~

~~BGE~~

~~Pepco~~

~~DPL~~

~~ACE~~

~~Credit agreement threshold~~

~~2.50 to 1~~

~~3.00 to 1~~

~~2.00 to 1~~

~~At September 30, 2017, the interest coverage ratios at Exelon, Generation, ComEd, PECO, BGE, Pepco, DPL and ACE were as follows:~~

Exelon Generation ComEd PECO BGE Pepco DPL ACE
Interest coverage ratio 6.27
9.02
10.83
8.26
10.66
6.83 8.78 6.03

An event of default under Exelon, Generation, ComEd, PECO or BGE's indebtedness will not constitute an event of default under any of the others’ credit facilities, except that a bankruptcy or other event of default in the payment of principal, premium or indebtedness in principal amount in excess of $100 million in the aggregate by Generation will constitute an event of default under the Exelon Corporate credit facility. An event of default under Pepco, DPL or ACE's indebtedness will not constitute an event of default under any of the others’ credit facilities, except that a bankruptcy or other event of default in the payment of principal, premium or indebtedness in principal amount in excess of $50 million in the aggregate will constitute an event of default under the credit facility.

The absence of a material adverse change in Exelon's or PHI’s business, property, results of operations or financial condition is not a condition to the availability of credit under the credit agreement. The credit agreement does not include any rating triggers.

Security Ratings (All Registrants)

The Registrants’ access to the capital markets, including the commercial paper market, and their respective financing costs in those markets, may depend on the securities ratings of the entity that is accessing the capital markets.

The Registrants’ borrowings are not subject to default or prepayment as a result of a downgrading of securities, although such a downgrading of a Registrant’s securities could increase fees and interest charges under that Registrant’s credit agreements.

As part of the normal course of business, the Registrants enter into contracts that contain express provisions or otherwise permit the Registrants and their counterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable contracts law, if the Registrants are downgraded by a credit rating agency, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance, which could include the posting of collateral. See Note 1012 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral provisions.

The credit ratings for Exelon Corporate and the Utility Registrants did not change for the nine months ended September 30, 2021.

~~264~~

~~Table~~On February 24, 2021, S&P lowered Generation’s senior unsecured debt rating to ‘BBB-‘ from ‘BBB’ in response to the financial impacts of ~~Contents~~

the February 2021 weather event and Texas-based generating assets outages. See Significant 2021 Transactions and Developments for additional information. The S&P ratings changes did not materially impact Generation's financial statements. Furthermore, there were no material increases in required collateral or financial assurances or material impacts to our anticipated access to liquidity or cost of financing.

Intercompany Money Pool (All Registrants)

To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing, both Exelon and PHI operate an intercompany money ~~pools.~~pool. Maximum amounts contributed to and borrowed from the money pool by participant and the net contribution or

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Table of Contents

borrowing as of September 30, ~~2017,~~2021, are presented in the following ~~table:~~table. ACE had no activity within the PHI Intercompany Money Pool for the nine months ended September 30, 2021.


	During the Nine Months Ended September 30, 2021				As of September 30, 2021
Exelon Intercompany Money Pool	Maximum Contributed		Maximum Borrowed		Contributed (Borrowed)
Exelon Corporate	$	735	$	—	$	239
Generation	—		(426)		—
PECO	303		(100)		—
BSC	—		(435)		(273)
PHI Corporate	—		(40)		(16)
PCI	60		—		50

Exelon Intercompany Money Pool During the Three Months Ended September 30, 2017 As of September 30, 2017
Contributed (borrowed)
Maximum
Contributed

Maximum
Borrowed

Contributed
(Borrowed)
Exelon Corporate $ 579
n/a
$ 280
Generation —
(417 ) (146 )
PECO 97
(10 ) 57
BSC —
(369 ) (245 )
PHI Corporate ^(a)

n/a
(33 ) (1 )
PCI ^(a)
54
—
54

~~_________~~


~~(a)~~
	During the Nine Months Ended September 30, 2021				As ~~a result~~ of ~~the merger,~~ September 30, 2021
PHI ~~Corporate and PCI began to participate in the Exelon~~ Intercompany Money Pool ~~effective March 24, 2016.~~	Maximum Contributed		Maximum Borrowed		Contributed (Borrowed)

Pepco	$	—	$	(30)	$	—
DPL	30		—		—

PHI Intercompany Money Pool During the Three Months Ended September 30, 2017 As of September 30, 2017
Contributed (borrowed)
Maximum
Contributed

Maximum
Borrowed

Contributed
(Borrowed)
PHI Corporate $ 51
$ (1 ) $ —
PHISCO 24
(25 ) —

~~Investments in Nuclear Decommissioning Trust Funds~~Shelf Registration Statements (All Registrants)

Exelon, Generation, and ~~CENG maintain trust funds, as required by~~ the NRC, to fund certain costs of decommissioning nuclear plants. The mix of securities in the trust funds is designed to provide returns to be used to fund decommissioning and to offset inflationary increases in decommissioning costs. Generation actively monitors the investment performance of the trust funds and periodically reviews asset allocations in accordance with Generation’s NDT fund investment policy. Generation’s and CENG’s investment policies establish limits on the concentration of holdings in any one company and also in any one industry. See Note 13 —Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements for further information regarding the trust funds, the NRC’s minimum funding requirements and related liquidity ramifications.

~~Shelf Registration Statements~~

~~Exelon, Generation, ComEd, PECO, BGE, Pepco, DPL and ACE~~Utility Registrants have a currently effective combined shelf registration statement unlimited in amount, filed with the SEC, that will expire in August ~~2019.~~2022. The ability of each Registrant to sell securities off the shelf registration statement or to access the private placement markets will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, as applicable, the current financial condition of the Registrant, its securities ratings and market conditions.

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Regulatory Authorizations (All Registrants)

~~Generation, ComEd, PECO, BGE, Pepco, DPL and ACE~~The Utility Registrants are required to obtain short-term and long-term financing authority from Federal and State Commissions as follows:

As of September 30, 2021

Short-term Financing Authority^(a)(b)

Long-term Financing Authority^(c)

Short-term Financing Authority(a)(b)

Remaining Long-term Financing Authority(a)

Commission

Expiration Date

Amount (in millions)

Commission

Expiration Date

Amount (in millions)

Commission

Expiration Date

Amount

Commission

Expiration Date

Amount

ComEd^(d)(c)

FERC

December 31, 2017

2,500

ICC

2019

1,383

FERC

December 31, 2021

2,500

ICC

February 1, 2023

PECO(d)

FERC

December 31, 2017

1,500

PAPUC

December 31, 2018

1,275

FERC

December 31, 2021

1,500

PAPUC

December 31, 2021

475

BGE

FERC

December 31, 2017

700

MDPSC

N/A

700

BGE

FERC

December 31, 2021

700

MDPSC

N/A

500

Pepco

FERC

June 30, 2018

500

MDPSC / DCPSC

September 25, 2017

—

Pepco

FERC

December 31, 2021

500

MDPSC / DCPSC

December 31, 2022

625

DPL

FERC

June 30, 2018

500

MDPSC / DPSC

December 31, 2017

125

DPL

FERC

December 31, 2021

500

MDPSC / DPSC

December 31, 2022

172

ACE

NJPU

January 1, 2018

350

NJBPU

December 31, 2017

300

ACE

NJBPU

December 31, 2021

350

NJBPU

December 31, 2022

250

_________


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


~~(b)~~	On October 31, 2017, ComEd, PECO, BGE, Pepco and DPL filed applications with FERC for renewal of their short-term financing authority through December 31, 2019. ComEd, PECO, BGE, Pepco and DPL expect approval of the applications before the end of the year.


~~(c)~~	~~Pepco, DPL, and ACE, are currently in the process renewing their long-term financing authority with their respective commissions and expect approvals before the end of the year.~~


~~(d)~~	ComEd had $1,140 million available in long-term debt refinancing authority and $243 million available in new money long term debt financing authority from the ICC as of September 30, 2017 and has an expiration date of June 1, 2019 and March 1, 2019, respectively.

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

(b)On October 15, 2021, ComEd, PECO, BGE, Pepco, and DPL filed applications with FERC and on July 21, 2021, ACE filed an application with NJBPU for renewal of their short-term financing authority through December 31, 2023. ComEd, PECO, BGE, Pepco, DPL, and ACE expect approval of their applications by December 31, 2021.

(c)ComEd had $93 million available in new money long-term debt financing authority from the ICC as of September 30, 2021 and has an expiration date of February 1, 2023. On June 29, 2021, ComEd filed an application for $2 billion in new money long-term debt financing authority from the ICC and expects approval by December 31, 2021.

(d)PECO is currently in the process of renewing its long-term financing authority with PAPUC and expects approval by December 31, 2021.

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Table of Contents

Contractual Obligations and Off-Balance Sheet Arrangements

Contractual obligations represent cash obligations that are considered to be firm commitments and commercial commitments triggered by future events. See Note 2415 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements ~~in the Exelon 2016 Form 10-K.~~for additional information.

Generation, ComEd, PECO, BGE, Pepco, DPL, and ACE have obligations related to contracts for the purchase of power and fuel supplies, and ComEd and PECO have obligations related to their financing trusts. The power and fuel purchase contracts and the financing trusts have been considered for consolidation in the Registrants’ respective financial statements pursuant to the authoritative guidance for VIEs. See Note 1 — ~~Basis of Presentation~~Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements in the Exelon 2020 Form 10-K for ~~further~~additional information.

For an in-depth discussion of the Registrants' contractual obligations and off-balance sheet arrangements, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Contractual Obligations and Off-Balance Sheet Arrangements” in the Exelon ~~2016~~2020 Form 10-K and ~~"Management's Discussion and Analysis~~Note 6 — Accounts Receivable of the Combined Notes to Consolidated Financial ~~Condition and Results~~Statements.

204

Table of ~~Operations - Contractual Obligations and Commercial Commitments."~~Contents

~~Item~~ITEM 3. ~~Quantitative and Qualitative Disclosures about Market Risk~~QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

The Registrants are exposed to market risks associated with adverse changes in commodity prices, counterparty credit, interest rates, and equity prices. Exelon’s RMC approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of risk exposures. The RMC is chaired by the chief executive officer and includes the chief risk officer, chief strategy officer, chief executive officer of Exelon Utilities, chief commercial officer, chief financial officer, and chief executive officer of Constellation. The RMC reports to the Finance and Risk Committee of the Exelon Board of Directors on the scope of the risk management activities. The following discussion serves as an update to ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK of Exelon’s ~~2016~~2020 Annual Report on Form 10-K incorporated herein by reference.

Commodity Price Risk (All Registrants)

Commodity price risk is associated with price movements resulting from changes in supply and demand, fuel costs, market liquidity, weather conditions, governmental regulatory and environmental policies, and other factors. To the extent the total amount of energy Exelon generates and purchases differs from the amount of energy it has contracted to sell, Exelon ~~has price risk from~~is exposed to market fluctuations in commodity ~~price movements.~~prices. Exelon seeks to mitigate its commodity price risk through the sale and purchase of electricity, fossil fuel, and other commodities.

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~~Table of Contents~~

Generation

~~Normal Operations and Hedging Activities.~~Electricity available from Generation’s owned or contracted generation supply in excess of Generation’s obligations to customers, including portions of the Utility Registrants' retail load, is sold into the wholesale markets. To reduce commodity price risk caused by market fluctuations, Generation enters into non-derivative contracts as well as derivative contracts, including ~~forwards,~~swaps, futures, ~~swaps~~forwards, and options, with approved counterparties to hedge anticipated exposures. Generation ~~believes these~~uses derivative instruments ~~represent~~as economic hedges ~~that~~to mitigate exposure to fluctuations in commodity prices. Generation expects the settlement of the majority of its economic hedges will occur during ~~2017~~2021 through ~~2019.~~2023.

In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on Generation’s owned and contracted generation positions which have not been hedged. Exelon's hedging program involves the hedging of commodity risk for Exelon's expected generation, typically on a ratable basis over a three-year period. As of September 30, ~~2017,~~2021, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York, and ERCOT reportable segments is ~~98%-101%, 79%-82% and 45%-48%~~96%-99% for ~~2017, 2018 and 2019, respectively. The percentage~~the remainder of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted generating facilities based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products and options. Equivalent sales represent all hedging products, which include economic hedges and certain non-derivative contracts including Generation’s sales to the Utility Registrants to serve their retail load.

~~A portion of Generation’s hedging strategy may be accomplished with fuel products based on assumed correlations between power and fuel prices, which routinely change in the market.~~2021. Market price risk exposure is the risk of a change in the value of unhedged positions. The forecasted market price risk exposure for Generation’s entire ~~non-proprietary trading~~economic hedge portfolio associated with a $5 reduction in the annual average around-the-clock energy price based on September 30, ~~2017~~2021 market conditions and hedged position would be ~~an increase in pre-tax net income of approximately $10 million~~immaterial for ~~2017 and decreases of approximately $170 million and $500 million, respectively, for 2018and 2019.~~ Power price sensitivities are derived by adjusting power price assumptions while keeping all other price inputs constant. Generation expects to actively manage its portfolio to mitigate market price risk exposure for its unhedged position. Actual results could differ depending on the specific timing of, and markets affected by, price changes, as well as future changes in Generation’s portfolio.

~~Proprietary Trading Activities.~~Generation also enters into certain energy-related derivatives for proprietary trading purposes. Proprietary trading includes all contracts entered into with the intent of benefiting from shifts or changes in market prices as opposed to those entered into with the intent of hedging or managing risk. Proprietary trading activities are subject to limits established by Exelon’s RMC. The proprietary trading portfolio is subject to a risk management policy that includes stringent risk management limits, including volume, stop loss and Value-at-Risk (VaR) limits to manage exposure to market risk. Additionally, the Exelon risk management group and Exelon’s RMC monitor the financial risks2021. See Note 12 — Derivative Financial Instruments of the ~~proprietary trading activities. The proprietary trading activities, which included physical volumes of 2,601 GWhs and 6,763 GWhs~~Combined Notes to Consolidated Financial Statements for the three and nine months ended September 30, 2017, respectively, and 1,506 GWhs and 4,015 GWhs and for the three and nine months September 30, 2016, respectively, are a complement to Generation’s energy marketing portfolio, but represent a small portion of Generation’s overall revenue from energy marketing activities. Proprietary trading portfolio activity for the nine months ended September 30, 2017 resulted in $11 million of pre-tax gains due to net mark-to-market gains of $3 million and realized gains of $8 million. Generation uses a 95% confidence interval, assuming standard normal distribution, one day holding period and a one-tailed statistical measure in calculating its VaR. The daily VaR on proprietary trading activity averaged $0.1 million of exposure during the quarter. Generation has not segregated proprietary trading activity within the following discussion because of the relative size of the proprietary trading portfolio in comparison to Generation’s total Revenue net of purchase power and fuel expense for the nine months ended September 30, 2017 of $6,526 million.additional information.

Fuel ~~Procurement.~~Generation procures natural gas through long-term and short-term contracts and spot-market purchases. Nuclear fuel assemblies are obtained predominantly through long-term uranium concentrate supply contracts, contracted conversion services, contracted enrichment services, or a combination thereof, and contracted fuel fabrication services. The supply markets for uranium concentrates and certain nuclear fuel services are subject to price fluctuations and availability restrictions. Supply market conditions may make Generation’s procurement contracts subject to credit risk related to the potential non-performance of counterparties to deliver the contracted commodity or service at the contracted prices. Procurement

Approximately 60% of Generation’s uranium concentrate requirements

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~~Table of Contents~~

from ~~2017~~2021 through ~~2021~~2025 are supplied by three ~~producers.~~suppliers. In the event of non-performance by these or other suppliers, Generation believes that replacement uranium concentrates can be obtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements. Non-performance by these counterparties could have a material adverse impact onin Exelon’s and Generation’s ~~results of operations, cash flows and~~ financial ~~positions.~~statements.

~~ComEd~~Utility Registrants

~~ComEd entered into 20-year contracts for renewable energy and RECs beginning in June 2012. ComEd is permitted to recover its renewable energy and REC costs from retail customers with~~There have been no ~~mark-up. The annual commitments represent the maximum settlements with suppliers for renewable energy and RECs under the existing contract terms. Pursuant~~significant changes or additions to the ~~ICC’s Order~~Utility Registrants exposures to commodity price risk that were described in ITEM 1A. RISK FACTORS of Exelon’s 2020 Annual Report on December 19, 2012, ComEd’s commitments under the existing long-term contracts were reduced for the June 2013 through May 2014 procurement period. In addition, the ICC’s December 18, 2013 Order approved the reduction of ComEd’s commitments under those contracts for the June 2014 through May 2015 procurement period, and the amount of the reduction was approved by the ICC in March 2014.Form 10-K. See Note ~~5 — Regulatory Matters and Note 10~~12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding ~~energy procurement and derivatives. ComEd does not enter into derivatives for speculative or proprietary trading purposes.~~

~~PECO~~

PECO has contracts to procure electric supply that were executed through the competitive procurement process outlined in its PAPUC-approved DSP Programs, which are further discussed in Note 5 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements. PECO has certain full requirements contracts which are considered derivatives and qualify for the normal purchases and normal sales scope exception under current derivative authoritative guidance, and as a result are accounted for on an accrual basis of accounting. Under the DSP Programs, PECO is permitted to recover its electric supply procurement costs from retail customers with no mark-up.

PECO has also entered into derivative natural gas contracts, which either qualify for the normal purchases and normal sales exception or have no mark-to-market balances because the derivatives are index priced, to hedge its long-termcommodity price risk in the natural gas market. PECO’s hedging program for natural gas procurement has no direct impact on its financial position or results of operations as natural gas costs are fully recovered from customers under the PGC.exposure.

PECO does not enter into derivatives for speculative or proprietary trading purposes. For additional information on these contracts, see Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements.

~~BGE~~

BGE procures electric supply for default service customers through full requirements contracts pursuant to BGE’s MDPSC-approved SOS program. BGE’s full requirements contracts that are considered derivatives qualify for the normal purchases and normal sales scope exception under current derivative authoritative guidance, and as a result, are accounted for on an accrual basis of accounting. Under the SOS program, BGE is permitted to recover its electricity procurement costs from retail customers, plus an administrative fee which includes a shareholder return component and an incremental cost component.

BGE has also entered into natural gas contracts, which qualify for the normal purchases and normal sales scope exception, to hedge its price risk in the natural gas market. The hedging program for natural gas procurement has no direct impact on BGE’s financial position. However, under BGE’s market-based rates incentive mechanism, BGE’s actual cost of gas is compared to a market index (a measure of the market price of gas in a given period). The difference between BGE’s actual cost and the market index is shared equally between shareholders and customers.

BGE does not enter into derivatives for speculative or proprietary trading purposes. For additional information on these contracts, see Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements.

~~Pepco~~

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~~Table of Contents~~

include an administrative fee. The administrative fee includes an incremental cost component and a shareholder return component for residential and commercial rate classes. Pepco’s price risk related to electric supply procurement is limited. Pepco locks in fixed prices for all of its SOS requirements through full requirements contracts. Certain of Pepco’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other Pepco full requirements contracts are not derivatives.

Pepco does not enter into derivatives for speculative or proprietary trading purposes. For additional information on these contracts, see Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements.

~~DPL~~

DPL provides natural gas to its customers under a GCR mechanism approved by the DPSC. The demand portion of the GCR is based upon DPL’s firm transportation and storage contracts. DPL has firm deliverability of swing and seasonal storage; a liquefied natural gas facility and firm transportation capacity to meet customer demand and provide a reserve margin. The commodity portion of the GCR includes a commission approved hedging program which is intended to reduce gas commodity price volatility while limiting the firm natural gas customers’ exposure to adverse changes in the market price of natural gas.

DPL does not enter into derivatives for speculative or proprietary trading purposes. See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding energy procurement and derivatives.

~~ACE~~

ACE has contracts to procure BGS electric supply that are executed through a competitive procurement process approved by the NJBPU. The BGS rates charged recover ACE's wholesale power supply costs. ACE does not make any profit or incur any loss on the supply component of the BGS it supplies to customers. ACE’s price risk related to electric supply procurement is limited. ACE locks in fixed prices for all of its BGS requirements through full requirements contracts. ACE’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other ACE full requirements contracts are not derivatives.

ACE does not enter into derivatives for speculative or proprietary trading purposes. For additional information on these contracts, see Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements.

Trading and Non-Trading Marketing ~~Activities.~~Activities

The following ~~detailed presentation of~~table detailing Exelon’s, Generation’s, ~~ComEd’s, PHI's~~ and ~~DPL's~~ComEd’s trading and non-trading marketing activities is included to address the recommended disclosures by the energy industry’s Committee of Chief Risk Officers (CCRO).

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205

Table of Contents

The following table provides detail on changes in Exelon’s, Generation’s, ~~ComEd’s, PHI's~~ and ~~DPL's~~ComEd’s commodity mark-to-market net asset or liability balance sheet position from December 31, ~~2016~~2020 to September 30, ~~2017.~~2021. It indicates the drivers behind changes in the balance sheet amounts. This table incorporates the mark-to-market activities that are immediately recorded in earnings. This table excludes all ~~normal purchase and normal sales~~NPNS contracts and does not segregate proprietary trading activity. See Note 1012 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on the balance sheet classification of the mark-to-market energy contract net assets (liabilities) recorded as of September 30, ~~2017~~2021 and December 31, ~~2016.~~2020.

Exelon Generation ComEd PHI DPL
Total mark-to-market energy contract net assets (liabilities) at December 31, 2016^(a)
$ 719
$ 977
$ (258 ) $ —
$ —
Total change in fair value during 2017 of contracts recorded in results of operations (13 ) (13 ) —
—
—
Reclassification to realized of contracts recorded in results of operations (138 ) (138 ) —
—
—
Contracts received at acquisition date —
—
—
—
—
Changes in fair value — recorded through regulatory assets and liabilities^(b)
(21 ) —
(19 ) (2 ) (2 )
Changes in allocated collateral 88
86
—
2
2
Changes in net option premium paid/(received) (35 ) (35 ) —
—
—
Option premium amortization (15 ) (15 ) —
—
—
Upfront payments and amortizations^(c)
(54 ) (54 ) —
—
—
Total mark-to-market energy contract net assets (liabilities) at September 30, 2017^(a)
$ 531
$ 808
$ (277 ) $ —
$ —


	Exelon		Generation		ComEd
Total mark-to-market energy contract net assets (liabilities) at December 31, 2020(a)	$	428	$	729	$	(301)
Total change in fair value during 2021 of contracts recorded in results of operations	1,434		1,434		—
Reclassification to realized at settlement of contracts recorded in results of operations	(186)		(186)		—

Changes in fair value — recorded through regulatory assets(b)	87		—		87
Changes in allocated collateral	(2,061)		(2,061)		—
Net option premium paid	186		186		—
Option premium amortization	(45)		(45)		—
Upfront payments and amortizations(c)	(107)		(107)		—
Total mark-to-market energy contract net liabilities at September 30, 2021(a)	$	(264)	$	(50)	$	(214)

_________


~~(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 September 30, 2017, ComEd recorded a regulatory liability of $277 million related to its mark-to-market derivative liabilities with Generation and unaffiliated suppliers. For the nine months ended September 30, 2017, ComEd also recorded $32 million of decreases in fair value and an increase for realized losses due to settlements of $13 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.~~

(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 September 30, 2021, ComEd recorded a regulatory asset of $214 million related to its mark-to-market derivative liabilities with unaffiliated suppliers. For the nine months ended September 30, 2021, ComEd recorded $72 million of increases in fair value and an increase for realized losses due to settlements of $15 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.

Fair ~~Values.~~Values

The following tables present maturity and source of fair value for Exelon, Generation, and ComEd mark-to-market commodity contract net assets (liabilities). The tables provide two fundamental pieces of information. First, the tables provide the source of fair value used in determining the carrying amount of the Registrants’ total mark-to-market net assets (liabilities), net of allocated collateral. Second, the tables show the maturity, by year, of the Registrants’ commodity contract net assets (liabilities), net of allocated collateral, giving an indication of when these mark-to-market amounts will settle and either generate or require cash. See Note 914 — Fair Value of Financial Assets and Liabilities of the Combined Notes to Consolidated Financial Statements for additional information regarding fair value measurements and the fair value hierarchy.

~~270~~

206

Table of Contents

Exelon


	Maturities Within																Total Fair Value				Maturities Within												Total Fair Value
	2017		2018		2019			2020			2021			2022 and Beyond							2021		2022		2023		2024		2025		2026 and Beyond
Normal Operations, Commodity derivative contracts^(a)(b):																				Normal Operations, Commodity derivative contracts(a)(b):
Actively quoted prices (Level 1)	$	27	$	1	$	(29	)	$	(13	)	$	2		$	(2	)	$	(14	)	Actively quoted prices (Level 1)	$	302	$	578	$	63	$	53	$	38	$	23	$	1,057
Prices provided by external sources (Level 2)	112		109		7			(6		)	5			—			227			Prices provided by external sources (Level 2)	17		737		40		(40)		—		—		754
Prices based on model or other valuation methods (Level 3)^(c)	47		339		111			18			(32		)	(165		)	318			Prices based on model or other valuation methods (Level 3)(c)	(566)		(1,304)		17		(15)		(18)		(189)		(2,075)
Total	$	186	$	449	$	89		$	(1	)	$	(25	)	$	(167	)	$	531		Total	$	(247)	$	11	$	120	$	(2)	$	20	$	(166)	$	(264)

_________


~~(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 $415 million at September 30, 2017.~~


~~(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 results of operations.

(b)Amounts are shown net of collateral paid/(received) from counterparties (and offset against mark-to-market assets and liabilities) of $(1,645) million at September 30, 2021.

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

Generation


	Maturities Within																Total Fair Value				Maturities Within												Total Fair Value
	2017		2018		2019			2020			2021			2022 and Beyond							2021		2022		2023		2024		2025		2026 and Beyond
Normal Operations, Commodity derivative contracts^(a)(b):																				Normal Operations, Commodity derivative contracts(a)(b):
Actively quoted prices (Level 1)	$	27	$	1	$	(29	)	$	(13	)	$	2		$	(2	)	$	(14	)	Actively quoted prices (Level 1)	$	302	$	578	$	63	$	53	$	38	$	23	$	1,057
Prices provided by external sources (Level 2)	112		109		7			(6		)	5			—			227			Prices provided by external sources (Level 2)	17		737		40		(40)		—		—		754
Prices based on model or other valuation methods (Level 3)	53		360		133			40			(11		)	20			595			Prices based on model or other valuation methods (Level 3)	(565)		(1,293)		39		8		5		(55)		(1,861)
Total	$	192	$	470	$	111		$	21		$	(4	)	$	18		$	808		Total	$	(246)	$	22	$	142	$	21	$	43	$	(32)	$	(50)

_________


~~(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 $415 million at September 30, 2017.~~

(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/(received) from counterparties (and offset against mark-to-market assets and liabilities) of $(1,645) million at September 30, 2021.

ComEd


	Maturities Within																		Total Fair Value				Maturities Within												Total Fair Value
	2017			2018			2019			2020			2021			2022 and Beyond							2021		2022		2023		2024		2025		2026 and Beyond
Commodity derivative contracts^(a):																						Commodity derivative contracts(a):
Prices based on model or other valuation methods (Level 3)	$	(6	)	$	(21	)	$	(22	)	$	(22	)	$	(21	)	$	(185	)	$	(277	)
Prices based on model or other valuation methods (Level 3)(a)																						Prices based on model or other valuation methods (Level 3)(a)	$	(1)	$	(11)	$	(22)	$	(23)	$	(23)	$	(134)	$	(214)



Exelon Corporation Common Stock, without par value			~~960,852,473~~978,317,787
Exelon Generation Company, LLC			not applicable
Commonwealth Edison Company Common Stock, $12.50 par value			~~127,021,214~~127,021,383
PECO Energy Company Common Stock, without par value			170,478,507
Baltimore Gas and Electric Company Common Stock, without par value			1,000
Pepco Holdings LLC			not applicable
Potomac Electric Power Company Common Stock, ~~$.01~~$0.01 par value			100
Delmarva Power & Light Company Common Stock, $2.25 par value			1,000
Atlantic City Electric Company Common Stock, $3.00 par value			8,546,017


				Page No.


			~~Page No.~~
~~GLOSSARY OF TERMS AND ABBREVIATIONS~~ ITEM 2.		6
~~FILING FORMAT~~		12
~~CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION~~		12
~~WHERE TO FIND MORE INFORMATION~~		12
~~PART I.~~	~~FINANCIAL INFORMATION~~	13
~~ITEM 1.~~	~~FINANCIAL STATEMENTS~~	13
	~~Exelon Corporation~~
	~~Consolidated Statements of Operations and Comprehensive Income~~	14
	~~Consolidated Statements of Cash Flows~~	15
	~~Consolidated Balance Sheets~~	16
	~~Consolidated Statement of Changes in Shareholders’ Equity~~	18
	~~Exelon Generation Company, LLC~~
	~~Consolidated Statements of Operations and Comprehensive Income~~	19
	~~Consolidated Statements of Cash Flows~~	20
	~~Consolidated Balance Sheets~~	21
	~~Consolidated Statement of Changes in Equity~~	23
	~~Commonwealth Edison Company~~
	~~Consolidated Statements of Operations and Comprehensive Income~~	24
	~~Consolidated Statements of Cash Flows~~	25
	~~Consolidated Balance Sheets~~	26
	~~Consolidated Statement of Changes in Shareholders' Equity~~	28
	~~PECO Energy Company~~
	~~Consolidated Statements of Operations and Comprehensive Income~~	29
	~~Consolidated Statements of Cash Flows~~	30
	~~Consolidated Balance Sheets~~	31
	~~Consolidated Statement of Changes in Shareholder's Equity~~	33
	~~Baltimore Gas and Electric Company~~
	~~Consolidated Statements of Operations and Comprehensive Income~~	34
	~~Consolidated Statements of Cash Flows~~	35
	~~Consolidated Balance Sheets~~	36
	~~Consolidated Statement of Changes in Shareholders’ Equity~~	38
	~~Pepco Holdings LLC~~
	~~Consolidated Statements of Operations and Comprehensive Income~~	39
	~~Consolidated Statements of Cash Flows~~	40
	~~Consolidated Balance Sheets~~	41
	~~Consolidated Statement of Changes in Equity~~	43



		~~Page No.~~
~~ITEM 2.~~	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	~~180~~150
			Exelon Corporation		~~180~~150
			Executive Overview		~~180~~150
			Financial Results of Operations		~~181~~150
			Significant ~~2017~~2021 Transactions and Developments		~~189~~155
			~~Exelon's Strategy and Outlook for 2017 and Beyond~~		~~194~~
			~~Liquidity Considerations~~		~~195~~
			Other Key Business Drivers and Management Strategies		~~196~~160
			Critical Accounting Policies and Estimates		~~202~~162
			Results of Operations By Registrant		~~203~~163
			Exelon Generation Company, LLC		~~204~~163
			Commonwealth Edison Company		~~212~~174
			PECO Energy Company		~~218~~177
			Baltimore Gas and Electric Company		~~224~~181
			Pepco Holdings LLC		~~231~~184
			Potomac Electric Power Company		~~234~~185
			Delmarva Power & Light Company		~~240~~188
			Atlantic City Electric Company		~~248~~192
			Liquidity and Capital Resources		~~253~~196
			Contractual Obligations and Off-Balance Sheet Arrangements		~~266~~204
ITEM 3.			QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		~~266~~205
ITEM 4.			CONTROLS AND PROCEDURES		~~275~~209
PART II.			OTHER INFORMATION		~~276~~210
ITEM 1.			LEGAL PROCEEDINGS		~~276~~210
ITEM 1A.			RISK FACTORS		~~276~~210
ITEM 4.			MINE SAFETY DISCLOSURES		~~276~~210
ITEM 6.			~~EXHIBITS~~5.	~~276~~OTHER INFORMATION		211
~~SIGNATURES~~ ITEM 6.			~~279~~EXHIBITS		211
					~~Exelon Corporation~~ SIGNATURES	~~279~~214
			Exelon Corporation		214
			Exelon Generation Company, LLC		~~280~~215
			Commonwealth Edison Company		~~281~~216
			PECO Energy Company		~~282~~217
			Baltimore Gas and Electric Company		~~283~~218
			Pepco Holdings LLC		~~284~~219
			Potomac Electric Power Company		~~285~~220
			Delmarva Power & Light Company		~~286~~221
			Atlantic City Electric Company		~~287~~222



GLOSSARY OF TERMS AND ABBREVIATIONS
Exelon Corporation and Related Entities
Exelon		Exelon Corporation
Generation		Exelon Generation Company, LLC
ComEd		Commonwealth Edison Company
PECO		PECO Energy Company
BGE		Baltimore Gas and Electric Company
Pepco Holdings or PHI		Pepco Holdings LLC ~~(formerly Pepco Holdings, Inc.)~~
Pepco		Potomac Electric Power Company
~~Pepco Energy Services or PES~~DPL		~~Pepco Energy Services, Inc. and its subsidiaries~~
~~PCI~~	~~Potomac Capital Investment Corporation and its subsidiaries~~
~~DPL~~	Delmarva Power & Light Company
ACE		Atlantic City Electric Company
~~ACE Funding or ATF~~Registrants		~~Atlantic City Electric Transition Funding LLC~~
~~BSC~~	~~Exelon Business Services Company, LLC~~
~~PHISCO~~	~~PHI Service Company~~
~~Exelon Corporate~~	~~Exelon in its corporate capacity as a holding company~~
~~PHI Corporate~~	~~PHI in its corporate capacity as a holding company~~
~~Registrants~~	Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE, collectively
Utility Registrants		ComEd, PECO, BGE, Pepco, DPL, and ACE, collectively
~~AmerGen~~ACE Funding or ATF		~~AmerGen Energy Company,~~Atlantic City Electric Transition Funding LLC
Antelope Valley		Antelope Valley Solar Ranch One
~~BondCo~~	~~RSB BondCo LLC~~
~~CENG~~	~~Constellation Energy Nuclear Group, LLC~~
~~ConEdison Solutions~~	~~The competitive retail electricity and natural gas business of Consolidated Edison Solutions, Inc., a subsidiary of Consolidated Edison, Inc.~~
~~Constellation~~	~~Constellation Energy Group, Inc.~~
~~EGTP~~	~~ExGen Texas Power, LLC~~
~~EGR~~	~~ExGen Renewables I, LLC~~
~~Entergy~~	~~Entergy Nuclear FitzPatrick, LLC~~
~~Exelon Transmission Company~~	~~Exelon Transmission Company, LLC~~
~~Exelon Wind~~	~~Exelon Wind, LLC and Exelon Generation Acquisition Company, LLC~~
~~FitzPatrick~~	~~James A. FitzPatrick nuclear generating station~~
~~Legacy PHI~~	~~PHI, Pepco, DPL and ACE, collectively~~
~~PEC L.P.~~	~~PECO Energy Capital, L.P.~~
~~PECO Trust III~~	~~PECO Capital Trust III~~
~~PECO Trust IV~~	~~PECO Energy Capital Trust IV~~
~~PETT~~	~~PECO Energy Transition Trust~~
~~RPG~~	~~Renewable Power Generation~~
~~SolGen~~	~~SolGen, LLC~~
~~TMI~~	~~Three Mile Island nuclear facility~~
~~UII~~	~~Unicom Investments, Inc.~~
~~Ventures~~	~~Exelon Ventures Company, LLC~~


GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
Note ~~“—”~~- of the ~~Exelon 2016~~2020 Form 10-K		Reference to specific Combined Note to Consolidated Financial Statements within ~~Exelon’s 2016~~Exelon's 2020 Annual Report on Form 10-K
~~Act 11~~AEC		~~Pennsylvania Act 11 of 2012~~
~~Act 129~~	~~Pennsylvania Act 129 of 2008~~
~~AEC~~	Alternative Energy Credit that is issued for each megawatt hour of generation from a qualified alternative energy source
~~AEPS~~AESO		~~Pennsylvania Alternative Energy Portfolio Standards~~
~~AEPS Act~~	~~Pennsylvania Alternative Energy Portfolio Standards Act of 2004, as amended~~
~~AESO~~	Alberta Electric Systems Operator
AFUDC		Allowance for Funds Used During Construction
~~AGE~~		~~Albany Green Energy Project~~
AMI		Advanced Metering Infrastructure
~~AOCI~~
AOCI		Accumulated Other Comprehensive Income (Loss)
ARC		Asset Retirement Cost
ARO		Asset Retirement Obligation
~~ASC~~		~~Accounting Standards Codification~~
BGS		Basic Generation Service
~~Block Contracts~~CAISO		~~Forward Purchase Energy Block Contracts~~California Independent System Operator
~~CAIR~~		~~Clean Air Interstate Rule~~
~~CAISO~~		~~California ISO~~
~~CAMR~~		~~Federal Clean Air Mercury Rule~~
~~CAP~~CBA		~~Customer Assistance Program~~Collective Bargaining Agreement
CERCLA		Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended
CES		Clean Energy Standard
~~CFL~~		~~Compact Fluorescent Light~~
Clean ~~Air~~Energy Law		Illinois Public Act	~~Clean Air Act of 1963, as amended~~ 102-0662 signed into law on September 15, 2021
Clean Water Act		Federal Water Pollution Control Amendments of 1972, as amended
~~Competition Act~~CMC		~~Pennsylvania Electricity Generation Customer Choice and Competition Act of 1996~~Carbon Mitigation Credit
~~Conectiv~~CODM		~~Conectiv, LLC, a wholly owned subsidiary of PHI and the parent of DPL and ACE~~Chief Operating Decision Maker(s)
~~Conectiv Energy~~		~~Conectiv Energy Holdings, Inc. and substantially all of its subsidiaries, which were sold to Calpine in July 2010~~
~~CPUC~~	~~California Public Utilities Commission~~
~~CSAPR~~	~~Cross-State Air Pollution Rule~~
~~D.C. Circuit Court~~	~~United States Court of Appeals for the District of Columbia Circuit~~
~~DCPSC~~	~~District of Columbia Public Service Commission~~
~~DC PLUG~~	~~District of Columbia Power Line Undergrounding~~
~~Default Electricity Supply~~	The supply of electricity by PHI’s electric utility subsidiaries at regulated rates to retail customers who do not elect to purchase electricity from a competitive supplier, and which, depending on the jurisdiction, is also known as Standard Offer Service or BGS
~~DOE~~	~~United States Department of Energy~~
~~DOJ~~	~~United States Department of Justice~~
~~DPSC~~	~~Delaware Public Service Commission~~



x			☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934



o			☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934


		Page No.
GLOSSARY OF TERMS AND ABBREVIATIONS		4
FILING FORMAT		8
CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION		8
WHERE TO FIND MORE INFORMATION		8
PART I.	FINANCIAL INFORMATION	9
ITEM 1.	FINANCIAL STATEMENTS	9
	Exelon Corporation
	Consolidated Statements of Operations and Comprehensive Income	10
	Consolidated Statements of Cash Flows	11
	Consolidated Balance Sheets	12
	Consolidated Statements of Changes in Shareholders’ Equity	14
	Exelon Generation Company, LLC
	Consolidated Statements of Operations and Comprehensive Income	16
	Consolidated Statements of Cash Flows	17
	Consolidated Balance Sheets	18
	Consolidated Statements of Changes in Equity	20
	Commonwealth Edison Company
	Consolidated Statements of Operations and Comprehensive Income	22
	Consolidated Statements of Cash Flows	23
	Consolidated Balance Sheets	24
	Consolidated Statements of Changes in Shareholders' Equity	26
	PECO Energy Company
	Consolidated Statements of Operations and Comprehensive Income	27
	Consolidated Statements of Cash Flows	28
	Consolidated Balance Sheets	29
	Consolidated Statements of Changes in Shareholder's Equity	31
	Baltimore Gas and Electric Company
	Statements of Operations and Comprehensive Income	32
	Statements of Cash Flows	33
	Balance Sheets	34
	Statements of Changes in Shareholder's Equity	36
	Pepco Holdings LLC
	Consolidated Statements of Operations and Comprehensive Income	37
	Consolidated Statements of Cash Flows	38
	Consolidated Balance Sheets	39
	Consolidated Statements of Changes in Member's Equity	41



		~~Page No.~~
	~~Potomac Electric Power Company~~
	~~Statements of Operations and Comprehensive Income~~	44
	~~Statements of Cash Flows~~	45
	~~Balance Sheets~~	46
	~~Statement of Changes in Shareholder's Equity~~	48
	~~Delmarva Power & Light Company~~
	~~Statements of Operations and Comprehensive Income~~	49
	~~Statements of Cash Flows~~	50
	~~Balance Sheets~~	51
	~~Statement of Changes in Shareholder’s Equity~~	53
	~~Atlantic City Electric Company~~
	~~Consolidated Statements of Operations and Comprehensive Income~~	54
	~~Consolidated Statements of Cash Flows~~	55
	~~Consolidated Balance Sheets~~	56
	~~Consolidated Statement of Changes in Shareholder’s Equity~~	58
	~~Combined Notes to Consolidated Financial Statements~~	59
	~~1. Basis of Presentation~~	59
	~~2. New Accounting Standards~~	60
	~~3. Variable Interest Entities~~	63
	~~4. Mergers, Acquisitions and Dispositions~~	70
	~~5. Regulatory Matters~~	78
	~~6. Impairment of Long-Lived Assets~~	94
	~~7. Early Nuclear Plant Retirements~~	95
	~~8. Intangible Assets~~	97
	~~9. Fair Value of Financial Assets and Liabilities~~	97
	~~10. Derivative Financial Instruments~~	~~118~~
	~~11. Debt and Credit Agreements~~	~~132~~
	~~12. Income Taxes~~	~~136~~
	~~13. Nuclear Decommissioning~~	~~141~~
	~~14. Retirement Benefits~~	~~144~~
	~~15. Severance~~	~~146~~
	~~16. Changes in Accumulated Other Comprehensive Income~~	~~149~~
	~~17. Earnings Per Share and Equity~~	~~154~~
	~~18. Commitments and Contingencies~~	~~155~~
	~~19. Supplemental Financial Information~~	~~166~~
	~~20. Segment Information~~	~~173~~



BSC						Exelon Business Services Company, LLC
CENG						Constellation Energy Nuclear Group, LLC
Constellation						Constellation Energy Group, Inc.
EGR IV						ExGen Renewables IV, LLC
EGRP						ExGen Renewables Partners, LLC
Exelon Corporate						Exelon in its corporate capacity as a holding company
FitzPatrick						James A. FitzPatrick nuclear generating station
NER						NewEnergy Receivables LLC
PCI						Potomac Capital Investment Corporation and its subsidiaries
PECO Trust III						PECO Energy Capital Trust III
PECO Trust IV						PECO Energy Capital Trust IV
Pepco Energy Services						Pepco Energy Services, Inc. and its subsidiaries
PHI Corporate						PHI in its corporate capacity as a holding company
PHISCO						PHI Service Company
RPG						Renewable Power Generation
SolGen						SolGen, LLC
TMI						Three Mile Island nuclear facility



~~GLOSSARY OF TERMS AND ABBREVIATIONS~~
~~Other Terms and Abbreviations~~
~~DRP~~DC PLUG		~~Direct Stock Purchase and Dividend Reinvestment Plan~~District of Columbia Power Line Undergrounding Initiative
~~DSP~~DCPSC		~~Default~~Public Service ~~Provider~~Commission of the District of Columbia
~~DSP Program~~		~~Default Service Provider Program~~
~~EDCs~~DOE		~~Electric distribution companies~~United States Department of Energy
~~EDF~~DOEE		District of Columbia Department of Energy & Environment
DOJ		United States Department of Justice
DPP		Deferred Purchase Price
DPSC		Delaware Public Service Commission



EDF		Electricite de France SA and its subsidiaries
~~EE&C~~		~~Energy Efficiency and Conservation/Demand Response~~
~~EGS~~EIMA		~~Electric Generation Supplier~~
~~EIMA~~	Energy Infrastructure Modernization Act (Illinois Senate Bill 1652 and Illinois House Bill 3036)
~~EmPower Maryland~~		~~A Maryland demand-side management program for Pepco and DPL~~
EPA		United States Environmental Protection Agency
~~EPSA~~		~~Electric Power Supply Association~~
ERCOT		Electric Reliability Council of Texas
~~ERISA~~		~~Employee Retirement Income Security Act of 1974, as amended~~
~~EROA~~		~~Expected Rate of Return on Assets~~
~~FASB~~		~~Financial Accounting Standards Board~~
~~FEJA~~
FEJA		Illinois Public Act 99-0906 or Future Energy Jobs Act
FERC		Federal Energy Regulatory Commission
FRCC		Florida Reliability Coordinating Council
~~GAAP~~FRR		Fixed Resource Requirement
GAAP		Generally Accepted Accounting Principles in the United States
GCR		Gas Cost Rate
GHG		Greenhouse Gas
GSA		Generation Supply Adjustment
~~GWh~~		~~Gigawatt hour~~
~~Health Care Reform Acts~~	~~Patient Protection and Affordable Care Act and Health Care and Education Reconciliation Act of 2010~~
~~HSR Act~~	~~The Hart-Scott-Rodino Antitrust Improvements Act of 1976~~
~~IBEW~~	~~International Brotherhood of Electrical Workers~~
~~ICC~~	~~Illinois Commerce Commission~~
~~ICE~~	~~Intercontinental Exchange~~
~~Illinois Act~~	~~Illinois Electric Service Customer Choice and Rate Relief Law of 1997~~
~~Illinois EPA~~	~~Illinois Environmental Protection Agency~~
~~Illinois Settlement Legislation~~	~~Legislation enacted in 2007 affecting electric utilities in Illinois~~
~~Integrys~~	~~Integrys Energy Services, Inc.~~
~~IPA~~	~~Illinois Power Agency~~
~~IRC~~	~~Internal Revenue Code~~
~~IRS~~	~~Internal Revenue Service~~
~~ISO~~	~~Independent System Operator~~
~~ISO-NE~~	~~Independent System Operator New England Inc.~~
~~ISO-NY~~	~~Independent System Operator New York~~
kV	~~Kilovolt~~
kW	~~Kilowatt~~
~~kWh~~	~~Kilowatt-hour~~
~~LIBOR~~	~~London Interbank Offered Rate~~



IBEW						International Brotherhood of Electrical Workers
ICC						Illinois Commerce Commission
ICE						Intercontinental Exchange



IPA						Illinois Power Agency
IRC						Internal Revenue Code
IRS						Internal Revenue Service


GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
~~LLRW~~ISO		~~Low-Level Radioactive Waste~~Independent System Operator
~~LT Plan~~ISO-NE		~~Long-term renewable resources procurement plan~~Independent System Operator New England Inc.
~~LTIP~~		~~Long-Term Incentive Plan~~
~~MAPP~~		~~Mid-Atlantic Power Pathway~~
~~MATS~~		~~U.S. EPA Mercury and Air Toxics Rule~~
~~MBR~~		~~Market Based Rates Incentive~~
~~MDE~~LIBOR		London Interbank Offered Rate







MDE		Maryland Department of the Environment
MDPSC		Maryland Public Service Commission
MGP		Manufactured Gas Plant
MISO		Midcontinent Independent System Operator, Inc.
mmcf		Million Cubic Feet
~~Moody’s~~		~~Moody’s Investor Service~~
MOPR		Minimum Offer Price Rule
~~MRV~~		~~Market-Related Value~~
MWMPSC		~~Megawatt~~Missouri Public Service Commission
~~MWh~~MW		Megawatt ~~hour~~
~~NAAQS~~MWh		~~National Ambient Air Quality Standards~~Megawatt hour
~~n.m.~~		~~not meaningful~~
~~NAV~~
NAV		Net Asset Value
~~NDT~~N/A		Not applicable
NDT		Nuclear Decommissioning Trust
~~NEIL~~		~~Nuclear Electric Insurance Limited~~
NERC		North American Electric Reliability Corporation
~~NGS~~NGX		Natural Gas ~~Supplier~~Exchange
NJBPU		New Jersey Board of Public Utilities
~~NJDEP~~		~~New Jersey Department of Environmental Protection~~

Non-Regulatory ~~Agreements~~Agreement Units		Nuclear generating units or portions thereof whose decommissioning-related activities are not subject to contractual elimination under regulatory accounting
NOSA		Nuclear Operating Services Agreement
~~NPDES~~		~~National Pollutant Discharge Elimination System~~
~~NRC~~NPNS		Normal Purchase Normal Sale scope exception
NPS		National Park Service
NRC		Nuclear Regulatory Commission
~~NSPS~~		~~New Source Performance Standards~~
~~NUGs~~	~~Non-utility generators~~
~~NWPA~~	~~Nuclear Waste Policy Act of 1982~~
~~NYMEX~~	~~New York Mercantile Exchange~~
~~NYPSC~~	~~New York Public Service Commission~~
~~OCI~~	~~Other Comprehensive Income~~
~~OIESO~~	~~Ontario Independent Electricity System Operator~~
~~OPC~~	~~Office of People’s Counsel~~
~~OPEB~~	~~Other Postretirement Employee Benefits~~
~~PA DEP~~	~~Pennsylvania Department of Environmental Protection~~
~~PAPUC~~	~~Pennsylvania Public Utility Commission~~
~~PGC~~	~~Purchased Gas Cost Clause~~
~~PJM~~	~~PJM Interconnection, LLC~~



~~GLOSSARY OF TERMS AND ABBREVIATIONS~~
~~Other Terms and Abbreviations~~NYISO						New York Independent System Operator Inc.
~~POLR~~NYMEX						New York Mercantile Exchange
NYPSC						New York Public Service Commission
OCI						Other Comprehensive Income
OIESO						Ontario Independent Electricity System Operator

OPEB						Other Postretirement Employee Benefits


PAPUC						Pennsylvania Public Utility Commission

PGC						Purchased Gas Cost Clause
PG&E						Pacific Gas and Electric Company
PJM						PJM Interconnection, LLC
POLR						Provider of Last Resort
~~POR~~						~~Purchase of Receivables~~
PPA						Power Purchase Agreement

Price-Anderson Act						Price-Anderson Nuclear Industries Indemnity Act of 1957
~~Preferred Stock~~						~~Originally issued shares of non-voting, non-convertible and non-transferable Series A preferred stock, par value $0.01 per share~~
PRP						Potentially Responsible Parties
~~PSEG~~PSDAR						Post-Shutdown Decommissioning Activities Report
PSEG						Public Service Enterprise Group Incorporated
~~PURTA~~						~~Pennsylvania Public Realty Tax Act~~
PV						~~Photovoltaic~~
~~RCRA~~PUCT						~~Resource Conservation and Recovery Act~~Public Utility Commission of ~~1976, as amended~~Texas
REC						Renewable Energy Credit which is issued for each megawatt hour of generation from a qualified renewable energy source

Regulatory Agreement Units						Nuclear generating units or portions thereof whose decommissioning-related activities are subject to contractual elimination under regulatory accounting
~~RES~~						~~Retail Electric Suppliers~~
RFP						Request for Proposal


~~Rider~~GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
Rider		Reconcilable Surcharge Recovery Mechanism
~~RGGI~~RMC		~~Regional Greenhouse Gas Initiative~~
~~RMC~~	Risk Management Committee
ROE		Return on ~~equity~~Equity
~~RPM~~		~~PJM Reliability Pricing Model~~
~~RPS~~
RPS		Renewable Energy Portfolio Standards
~~RSSA~~		~~Reliability Support Services Agreement~~
~~RTEP~~		~~Regional Transmission Expansion Plan~~
RTO		Regional Transmission Organization
S&P		Standard & Poor’s Ratings Services
SEC		United States Securities and Exchange Commission
~~Senate Bill 1~~		~~Maryland Senate Bill 1~~
~~SERC~~
SERC		SERC Reliability Corporation (formerly Southeast Electric Reliability Council)
~~SGIG~~		~~Smart Grid Investment Grant from DOE~~
~~SILO~~SNF		~~Sale-In, Lease-Out~~
~~SMPIP~~	~~Smart Meter Procurement and Installation Plan~~
~~SNF~~	Spent Nuclear Fuel
SOS		Standard Offer Service
~~SPFPA~~		~~Security, Police and Fire Professionals of America~~
~~SPP~~	~~Southwest Power Pool~~
~~Transition Bond Charge~~	~~Revenue ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds and related taxes, expenses and fees~~
~~Transition Bonds~~	~~Transition Bonds issued by ACE Funding~~
~~UGSOA~~	~~United Government Security Officers of America~~
~~Upstream~~	~~Natural gas exploration and production activities~~
~~VIE~~	~~Variable Interest Entity~~



~~GLOSSARY OF TERMS AND ABBREVIATIONS~~
~~Other Terms~~STRIDE	Maryland Strategic Infrastructure Development and ~~Abbreviations~~	Enhancement Program
~~WECC~~TCJA	Tax Cuts and Jobs Act

Transition Bonds	Transition Bonds issued by ACE Funding

UGSOA	United Government Security Officers of America
U.S. Court of Appeals for the D.C. Circuit	United States Court of Appeals for the District of Columbia Circuit
VIE	Variable Interest Entity
WECC	Western Electric Coordinating Council
ZEC	Zero Emission Credit or Zero Emission Certificate
ZES	Zero Emission Standard



(In millions)	September 30, 2017		December 31, 2016
ASSETS
Current assets
Cash and cash equivalents	$	1,203	$	635
Restricted cash and cash equivalents	320		253
Deposit with IRS	1,250		1,250
Accounts receivable, net
Customer	3,854		4,158
Other	950		1,201
Mark-to-market derivative assets	699		917
Unamortized energy contract assets	81		88
Inventories, net
Fossil fuel and emission allowances	387		364
Materials and supplies	1,281		1,274
Regulatory assets	1,264		1,342
Other	1,435		930
Total current assets	12,724		12,412
Property, plant and equipment, net	73,067		71,555
Deferred debits and other assets
Regulatory assets	10,238		10,046
Nuclear decommissioning trust funds	12,966		11,061
Investments	634		629
Goodwill	6,677		6,677
Mark-to-market derivative assets	426		492
Unamortized energy contract assets	407		447
Pledged assets for Zion Station decommissioning	57		113
Other	1,277		1,472
Total deferred debits and other assets	32,682		30,937
Total assets^(a)	$	118,473	$	114,904


	Nine Months Ended September 30, 2021
(In millions, shares in thousands)	Issued Shares	Common Stock		Treasury Stock		Retained Earnings		Accumulated Other Comprehensive Loss, net		Noncontrolling Interests		Total Shareholders' Equity
Balance, December 31, 2020	977,466	$	19,373	$	(123)	$	16,735	$	(3,400)	$	2,283	$	34,868
Net (loss) income	—	—		—		(289)		—		25		(264)
Long-term incentive plan activity	640	5		—		—		—		—		5
Employee stock purchase plan issuances	902	34		—		—		—		—		34


Changes in equity of noncontrolling interests	—	—		—		—		—		(10)		(10)

Common stock dividends ($0.38/common share)	—	—		—		(374)		—		—		(374)
Other comprehensive income, net of income taxes	—	—		—		—		54		—		54

Balance, March 31, 2021	979,008	$	19,412	$	(123)	$	16,072	$	(3,346)	$	2,298	$	34,313
Net income	—	—		—		401		—		75		476
Long-term incentive plan activity	237	24		—		—		—		—		24
Employee stock purchase plan issuances	420	18		—		—		—		—		18

Changes in equity of noncontrolling interests	—	—		—		—		—		(13)		(13)


Common stock dividends ($0.38/common share)	—	—		—		(375)		—		—		(375)
Other comprehensive income, net of income taxes	—	—		—		—		57		—		57

Balance, June 30, 2021	979,665	$	19,454	$	(123)	$	16,098	$	(3,289)	$	2,360	$	34,500
Net income	—	—		—		1,203		—		26		1,229
Long-term incentive plan activity	94	9		—		—		—		—		9
Employee stock purchase plan issuances	391	18		—		—		—		—		18
Changes in equity of noncontrolling interests	—	—		—		—		—		(13)		(13)
Acquisition of CENG noncontrolling interest	—	1,080		—		—		—		(1,965)		(885)
Deferred tax adjustment related to acquisition of CENG noncontrolling interest	—	(290)		—		—		—		—		(290)
Common stock dividends ($0.38/common share)	—	—		—		(375)		—		—		(375)
Other comprehensive income net of income taxes	—	—		—		—		66		—		66
Balance, September 30, 2021	980,150	$	20,271	$	(123)	$	16,926	$	(3,223)	$	408	$	34,259


	Nine Months Ended September 30, 2021
	Member’s Equity
(In millions)	Membership Interest		Undistributed Earnings		Accumulated Other Comprehensive Loss, net		Noncontrolling Interests		Total Equity
Balance, December 31, 2020	$	9,624	$	2,805	$	(30)	$	2,277	$	14,676
Net (loss) income	—		(793)		—		24		(769)
Changes in equity of noncontrolling interests	—		—		—		(10)		(10)




Distributions to member	—		(458)		—		—		(458)
Other comprehensive income, net of income taxes	—		—		1		—		1

Balance, March 31, 2021	$	9,624	$	1,554	$	(29)	$	2,291	$	13,440
Net (loss) income	—		(61)		—		74		13
Changes in equity of noncontrolling interests	—		—		—		(12)		(12)




Distributions to member	—		(458)		—		—		(458)
Other comprehensive income, net of income taxes	—		—		2		—		2
Balance, June 30, 2021	$	9,624	$	1,035	$	(27)	$	2,353	$	12,985
Net income	—		607		—		26		633
Changes in equity of noncontrolling interests	—		—		—		(13)		(13)

Acquisition of CENG noncontrolling interest	1,080		—		—		(1,965)		(885)


Deferred tax adjustment related to acquisition of CENG noncontrolling interest	(288)		—		—		—		(288)
Contribution from member	64		—		—		—		64
Distributions to member	—		(457)		—		—		(457)
Other comprehensive loss, net of income taxes	—		—		(4)		—		(4)
Balance, September 30, 2021	$	10,480	$	1,185	$	(31)	$	401	$	12,035



(In millions)	Common Stock		Other Paid-In Capital		Retained Deficit Unappropriated			Retained Earnings Appropriated			Total Shareholders’ Equity
Balance, December 31, 2016	$	1,588	$	6,150	$	(1,639	)	$	2,626		$	8,725
Net income	—		—		447			—			447
Appropriation of retained earnings for future dividends	—		—		(447		)	447			—
Common stock dividends	—		—		—			(316		)	(316		)
Contributions from parent	—		567		—			—			567
Parent tax matter indemnification	—		21		—			—			21
Balance, September 30, 2017	$	1,588	$	6,738	$	(1,639	)	$	2,757		$	9,444



	Successor												Predecessor
	Three Months Ended September 30,						Nine Months Ended September 30,			March 24 to September 30,			January 1 to March 23,
(In millions)	2017			2016			2017			2016			2016
Operating revenues
Electric operating revenues	$	1,280		$	1,366		$	3,417		$	2,485		$	1,096
Natural gas operating revenues	18			17			105			46			57
Operating revenues from affiliates	12			11			35			34			—
Total operating revenues	1,310			1,394			3,557			2,565			1,153
Operating expenses
Purchased power	354			370			901			658			471
Purchased fuel	7			6			46			17			26
Purchased power and fuel from affiliates	112			207			371			362			—
Operating and maintenance	214			200			666			870			294
Operating and maintenance from affiliates	37			26			108			51			—
Depreciation and amortization	179			182			511			355			152
Taxes other than income	122			124			344			248			105
Total operating expenses	1,025			1,115			2,947			2,561			1,048
Gain on sales of assets	—			—			1			—			—
Operating income	285			279			611			4			105
Other income and (deductions)
Interest expense, net	(62		)	(64		)	(183		)	(135		)	(65		)
Other, net	13			19			40			31			(4		)
Total other income and (deductions)	(49		)	(45		)	(143		)	(104		)	(69		)
Income (loss) before income taxes	236			234			468			(100		)	36
Income taxes	83			68			109			(9		)	17
Net income (loss)	$	153		$	166		$	359		$	(91	)	$	19
Comprehensive income (loss), net of income taxes
Net income (loss)	$	153		$	166		$	359		$	(91	)	$	19
Other comprehensive income, net of income taxes
Pension and non-pension postretirement benefit plans:
Actuarial loss reclassified to periodic cost	—			—			—			—			1
Other comprehensive income	—			—			—			—			1
Comprehensive income (loss)	$	153		$	166		$	359		$	(91	)	$	20


	Nine Months Ended September 30, 2021
(In millions)	Membership Interest		Undistributed (Losses)/Earnings		Total Member's Equity
Balance, December 31, 2020	$	10,112	$	(68)	$	10,044
Net income	—		128		128
Distributions to member	—		(81)		(81)
Contributions from member	560		—		560
Balance, March 31, 2021	$	10,672	$	(21)	$	10,651
Net income	—		141		141
Distributions to member	—		(333)		(333)

Balance, June 30, 2021	$	10,672	$	(213)	$	10,459
Net income	—		266		266
Distributions to member	—		(191)		(191)
Contributions from member	107		—		107

Balance, September 30, 2021	$	10,779	$	(138)	$	10,641



(In millions)	Membership Interest		Undistributed Earnings (Losses)			Member's Equity
Successor
Balance, December 31, 2016	$	8,077	$	(61	)	$	8,016
Net income	—		359			359
Distribution to member	—		(267		)	(267		)
Contribution from member	751		—			751
Allocation of tax benefit from member	7		—			7
Balance, September 30, 2017	$	8,835	$	31		$	8,866


	Nine Months Ended September 30, 2021
(In millions)	Common Stock		Retained Earnings		Total Shareholder's Equity
Balance, December 31, 2020	$	2,058	$	1,145	$	3,203
Net income	—		59		59
Common stock dividends	—		(28)		(28)
Contributions from parent	138		—		138
Balance, March 31, 2021	$	2,196	$	1,176	$	3,372
Net income	—		75		75



Common stock dividends	—		(95)		(95)

Balance, June 30, 2021	$	2,196	$	1,156	$	3,352
Net income	—		130		130



Common stock dividends	—		(98)		(98)
Contributions from parent	106		—		106
Balance, September 30, 2021	$	2,302	$	1,188	$	3,490


	Three Months Ended September 30, 2021		Nine Months Ended September 30, 2021
Net income attributable to Exelon's common shareholders	$	1,203	$	1,315
Pre-tax increase in Exelon's common stock for purchase of EDF's 49.99% equity interest(a)	1,080		1,080
Decrease in Exelon's common stock due to deferred tax liabilities resulting from purchase of EDF's 49.99% equity interest(a)	(290)		(290)
Change from net income attributable to common stock and transfers from noncontrolling interest	$	1,993	$	2,105

	Three Months Ended September 30, 2021		Nine Months Ended September 30, 2021
Net income (loss) attributable to Generation's membership interest	$	607	$	(247)
Pre-tax increase in Generation's membership interest for purchase of EDF's 49.99% equity interest(a)	1,080		1,080
Decrease in Generation's membership interest due to deferred tax liabilities resulting from purchase of EDF's 49.99% equity interest(a)	(288)		(288)
Change from net income (loss) attributable to membership interest and transfers from noncontrolling interest	$	1,399	$	545


Registrant(a)	Initial Revenue Requirement Increase (Decrease)		Annual Reconciliation Increase		Total Revenue Requirement Increase(b)		Allowed Return on Rate Base(c)		Allowed ROE(d)
ComEd	$	33	$	12	$	45	8.20	%	11.50	%
PECO	(2)		26		24		7.37	%	10.35	%
BGE	38		27		65		7.35	%	10.50	%
Pepco	(9)		21		12		7.68	%	10.50	%
DPL	19		33		52		7.20	%	10.50	%
ACE	27		24		51		7.45	%	10.50	%



Cash paid for purchase price	$	110
Cash paid for net cost reimbursement	125
Nuclear fuel transfer	54
Total consideration transferred	$	289

Identifiable assets acquired and liabilities assumed
Current assets	$	60
Property, plant and equipment	298
Nuclear decommissioning trust funds	807
Other assets^(a)	114
Total assets	$	1,279

Current liabilities	$	6
Nuclear decommissioning ARO	444
Pension and OPEB obligations	33
Deferred income taxes	149
Spent nuclear fuel obligation	110
Other liabilities	15
Total liabilities	$	757
Total net identifiable assets, at fair value	$	522

Bargain purchase gain (after-tax)	$	233



Total consideration transferred	$	257

Identifiable assets acquired and liabilities assumed
Working capital assets	$	204
Property, plant and equipment	2
Mark-to-market derivative assets	6
Unamortized energy contract assets	100
Customer relationships	9
Other assets	1
Total assets	$	322

Mark-to-market derivative liabilities	$	65
Total liabilities	$	65
Total net identifiable assets, at fair value	$	257



	Expected Payment Period							Successor
Description	Expected Payment Period	Pepco		DPL		ACE		PHI		Exelon
Rate credits	2016 - 2017	$	91	$	67	$	101	$	259	$	259
Energy efficiency	2016 - 2021	—		—		—		—		122
Charitable contributions	2016 - 2026	28		12		10		50		50
Delivery system modernization	Q2 2017	—		—		—		—		22
Green sustainability fund	Q2 2017	—		—		—		—		14
Workforce development	2016 - 2020	—		—		—		—		17
Other		1		5		—		6		29
Total		$	120	$	84	$	111	$	315	$	513



(In millions of dollars, except per share data)	Total Consideration
Cash paid to PHI shareholders at $27.25 per share (254 million shares outstanding at March 23, 2016)	$	6,933
Cash paid for PHI preferred stock	180
Cash paid for PHI stock-based compensation equity awards^(a)	29
Total purchase price	$	7,142



Purchase Price Allocation^(a)
Current assets	$	1,441
Property, plant and equipment	11,088
Regulatory assets	5,015
Other assets	248
Goodwill	4,005
Total assets	$	21,797

Current liabilities	$	2,752
Unamortized energy contracts	1,515
Regulatory liabilities	297
Long-term debt, including current maturities	5,636
Deferred income taxes	3,447
Pension and OPEB obligations	821
Other liabilities	187
Total liabilities	$	14,655
Total purchase price	$	7,142



	Three Months Ended September 30,					Nine Months Ended September 30,
Acquisition, Integration and Financing Costs^(a)	2017			2016		2017			2016
Exelon	$	(8	)	$	20	$	10		$	123
Generation	5			9		18			29
ComEd^(b)	—			—		1			(6		)
PECO	1			1		3			3
BGE^(c)	1			1		3			(3		)
Pepco^(d)	(8		)	3		(6		)	26
DPL^(e)	1			2		(6		)	18
ACE^(f)	(8		)	2		(6		)	17



	Three Months Ended September 30,		Nine Months Ended September 30,		Year Ended December 31,
	2016^(a)		2016^(a)		2016^(b)
Total operating revenues	$	9,002	$	24,468	$	32,342
Net income attributable to common shareholders	501		1,346		1,562

Basic earnings per share	$	0.54	$	1.46	$	1.69
Diluted earnings per share	0.54		1.45		1.69



	2017
Annual Transmission Filings^(a)	ComEd			BGE			Pepco			DPL			ACE
Initial revenue requirement increase	$	44		$	31		$	5		$	6		$	20
Annual reconciliation (decrease) increase	(33		)	3			15			8			22
Dedicated facilities decrease^(b)	—			(8		)	—			—			—
Total revenue requirement increase	$	11		$	26		$	20		$	14		$	42

Allowed return on rate base^(c)	8.43		%	7.47		%	7.92		%	7.16		%	8.02		%
Allowed ROE^(d)	11.50		%	10.50		%	10.50		%	10.50		%	10.50		%



	Exelon		ComEd^(a)		PECO		BGE^(b)		PHI		Pepco^(c)		DPL^(c)		ACE
September 30, 2017	$	71	$	7	$	—	$	54	$	10	$	6	$	4	$	—

	Exelon		ComEd^(a)		PECO		BGE^(b)		PHI		Pepco^(c)		DPL^(c)		ACE
December 31, 2016	$	72	$	5	$	—	$	57	$	10	$	6	$	4	$	—