Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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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 is a utility services holding company engaged in the generation, delivery, and marketing of energy through Generation and the energy distribution and transmission businesses through ComEd, PECO, BGE, Pepco, DPL, and ACE.

Exelon has eleven reportable segments consisting of Generation’s five reportable segments (Mid-Atlantic, Midwest, New York, ERCOT, and Other Power Regions), ComEd, PECO, BGE, Pepco, DPL, and ACE. See Note 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.

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 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. The following table sets forth Exelon's GAAP consolidated Net Income attributable to common shareholders by Registrant for the three and nine months ended September 30, 2021 compared to the same period in 2020. For additional information regarding the financial results for the three and nine months ended September 30, 2021 and 2020 see the discussions of Results of Operations by 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:

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 facilities and 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;
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;
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;
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;
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. In addition to net income, Exelon evaluates its operating performance using the measure of 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 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.

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, 2021 compared to the same period in 2020.



	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


	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 25.0% to 29.0%. Under IRS regulations, NDT fund investment returns are taxed at different rates for investments if they are in qualified or non-qualified funds. The effective tax rates for the unrealized gains and losses related to NDT fund investments were 56.2% and 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.

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, 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 other experts assisting in the planned separation, and 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 option to sell its 49.99% equity interest in CENG to Generation exercisable beginning on January 1, 2016 and thereafter until June 30, 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

Generation. The difference between the net purchase price and EDF’s noncontrolling interest as of the closing date was 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 August 6, 2021, Generation issued approximately $880 million under a term loan credit agreement to fund the transaction, which will expire on August 5, 2022.

See Note 2 – Mergers, Acquisitions, and Dispositions and Note 13 — Debt and Credit Agreements of the 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, if awarded contracts, would be committed to operate through May 31, 2027. Selected generators will by December 3, 2021 contract directly with ComEd for the procurement of the 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 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 the third and fourth quarters of 2020. Further, there were ongoing annual financial impacts stemming from shortening the expected economic useful lives of these facilities, primarily related to accelerated depreciation of plant assets (including any ARC) and accelerated amortization of nuclear 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 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.

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 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 the three and nine months ended September 30, 2021. For Mystic Units 8 and 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 accelerated depreciation of plant assets, including any ARC.

(b)Reflects contractual offset for ARO accretion, ARC depreciation, and net impacts associated with the remeasurement of the ARO for Byron and Dresden and exclude any changes in earnings in the NDT funds. Decommissioning-related activities 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 Statements of Operations and Comprehensive 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 7 — Early Plant Retirements, Note 8 — Nuclear Decommissioning, and Note 9 - Asset Impairments of the Combined Notes to Consolidated Financial Statements for additional information.

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.

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 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.

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 April 28, 2021, Generation and ReGenerate entered into a purchase agreement, under which ReGenerate agreed to purchase Generation's interest in the Albany Green Energy biomass facility. As a result, in the second quarter of 2021, Exelon and Generation recorded a pre-tax impairment charge of $140 million which is excluded from Exelon’s and Generation’s Adjusted (non-GAAP) Operating Earnings. The sale was completed on June 30, 2021 for a net purchase price of $36 million. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional 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 financial statements.

The following tables show the Utility Registrants’ completed and pending distribution base rate case proceedings in 2021. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on these and other regulatory proceedings.

Completed Distribution Base Rate Case Proceedings


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

Pending Distribution Base Rate Case Proceedings


Registrant/Jurisdiction	Filing Date	Service	Requested Revenue Requirement Increase		Requested ROE		Expected Approval Timing
ComEd - Illinois	April 16, 2021	Electric	$	51	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	29		10.10	%	First quarter of 2022

Transmission Formula Rates

The following total increases/(decreases) were included in the Utility Registrants' 2021 electric transmission formula rate updates. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional 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	%

Other Key Business Drivers and Management Strategies

The following discussion of other key business driver and management strategies includes current developments of previously disclosed matters and new issues arising during the period that may impact future financial statements. This section should be read in conjunction with ITEM 1. Business and ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations — Other Key Business Drivers and Management Strategies in the Registrants' combined 2020 Form 10-K and Note 15 — Commitments and Contingencies to the Consolidated Financial Statements in this report for additional information on various environmental matters.

Power Markets

Complaint at FERC Seeking to 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 is too high, resulting in an overstated default offer cap that obviates the need for most sellers to seek unit-specific approval of their offers. The IMM argued that this allows for the exercise of market power. The IMM asked FERC to require PJM to reduce the number of performance assessment intervals used to calculate the opportunity costs of a 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 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 cap. FERC did not establish the number of performance assessment intervals that should be used to calculate the default offer cap and instead requested briefs on the matter, including alternative approaches to mitigation in the capacity market. 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 IMM’s unit-specific avoidable cost offer review methodology and directed PJM to submit a compliance filing establishing new deadlines for offer review and related other activities leading up to the base residual auction for the 2023-2024 planning year and an additional compliance filing revising the PJM Tariff to comply with FERC’s order. Exelon filed at FERC for rehearing on this matter on October 4, 2021. Generation cannot predict the outcome of these proceedings or the financial statement impact.

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. 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. Generation has been and will continue to be proactive in using hedging strategies to mitigate commodity price risk.

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. Approximately 60% of Generation’s uranium concentrate requirements from 2021 through 2025 are supplied by three 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 consolidated financial statements.

See Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements and ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for additional information.

The Utility Registrants mitigate commodity price risk through regulatory mechanisms that allow them to recover procurement costs from retail customers.

Environmental Regulation

Exelon is well positioned to support increasingly ambitious government climate policy and to partner with our customers and communities to reduce GHG emissions.

In August 2021, the Utility Registrants announced a “path to clean” goal to collectively reduce their operations-driven emissions 50% by 2030 against a 2015 baseline, and to reach net zero operations-driven emissions by 2050. This goal builds upon Exelon’s long-standing commitment to reducing our GHG emissions. The Utility Registrants “path to clean” will include efficiency and clean electricity for operations, vehicle fleet electrification, equipment and processes to reduce sulfur hexafluoride (SF6) leakage, modern natural gas infrastructure to minimize 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 among the lowest in the industry.

The United States has set an economy-wide target of reducing its net GHG emissions by 50-52% below 2005 levels by 2030.

Other Legislative and Regulatory Developments

FERC Supplemental Notice of Proposed Rulemaking

On April 15, 2021, FERC issued a Supplemental Notice of 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 NOPR, the ROE incentive adder would only be available for 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 ROE incentive adder. Exelon submitted comments to FERC 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 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 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 and ComEd cannot predict the ultimate outcome of the RFI and the

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 National Union of Nuclear Security Officers, which covers 88 security officers at Braidwood. The CBA 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 in the Registrants' 2020 Form 10-K for further information.

Generation

Results of Operations by Registrant

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, 2021 Compared to Three Months Ended September 30, 2020. Net income attributable to membership interest increased by $558 million primarily due to:

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 facilities and Mystic Units 8 and 9, and the

Generation

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; and
Higher New York ZEC revenues due to higher generation and an increase in ZEC prices.

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 membership interest decreased by $817 million primarily due to:

Impacts of the February 2021 extreme cold weather event;
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;
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;
Impairments of the New England asset group, the Albany Green Energy biomass facility at Generation, and a wind project at Generation, 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;
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 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;
Lower nuclear outage days; and
Higher New York ZEC revenues due to higher generation and an increase in ZEC prices.

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

Generation

with these same geographic regions. Generation's five reportable segments are Mid-Atlantic, Midwest, New York, ERCOT, and Other Power Regions. See Note 5 — Segment Information of the 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 overall operating revenues or results of operations.

For the three and nine months ended September 30, 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	%

(a)% Change in mark-to-market is not a meaningful measure.

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

(c)Includes results of transactions with ComEd.

Generation

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)	%

(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 the acquisition of EDF’s interest on August 6, 2021 as CENG was fully consolidated. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information on Generation’s acquisition of EDF’s interest in CENG.

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

Nuclear Fleet Capacity Factor. The following table presents nuclear fleet operating data for the Generation-operated 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

Generation

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

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	%

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.

Generation


	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	%

(a)Reflects New England, which comprises the majority of the activity in the Other region.

Generation

For the three and nine months ended September 30, 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 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.

Generation

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 mark-to-market is not a meaningful measure.

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

(c)Includes results of transactions with ComEd.

Generation

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.

Generation

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		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, 2021 compared to the same period in 2020, primarily due to the accelerated depreciation and amortization 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 businesse****s increased for the three and nine months ended September 30, 2021 compared to the 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, 2021 compared to the same period in 2020, due to a gain on sale of Generation's solar business.

Interest expense, net decreased for the nine months ended September 30, 2021 compared to the same period in 2020, primarily due to 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 Exelon 2020 Form 10-K for additional information on the interest swaps.

Other, net decreased for the three months ended September 30, 2021 compared to the same period in 2020 and increased for the nine months ended September 30, 2021 compared to the same period in 2020, due to activity described in the table below:

Generation


	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 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, 2021 and 2020, respectively, and (1,350.0)% and 7.7% for the nine months ended September 30, 2021 and 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 same period in 2020, primarily due to lower net gains on NDT fund investments for CENG prior to Generation's acquisition of 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 fund investments for CENG prior to Generation's acquisition of EDF's interest in CENG on August 6, 2021, partially offset by the noncontrolling portion of a wind project impairment.

ComEd

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 income increased 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 15 - Commitments and Contingencies of the Combined Notes to the Consolidated Financial Statements for additional information related to the Deferred Prosecution Agreement.

The changes in Operating revenues 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

Revenue Decoupling. The demand for electricity is affected by weather conditions and customer usage. Operating revenues are not impacted by abnormal weather, usage per customer or number of customers as a result of the revenue decoupling mechanisms as allowed by FEJA.

Distribution Revenue. EIMA and 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. 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. Electric distribution revenue increased for the three and nine months ended September 30, 2021 as

ComEd

compared to the same period in 2020, due to higher allowed ROE due to an increase in treasury rates and the impact of 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. Transmission revenue increased for the three and nine months ended September 30, 2021 as compared to the same periods in 2020 primarily due to the impact of a higher rate base.

Energy Efficiency Revenue. 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 FEJA, energy efficiency revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered, and 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 three and nine months ended September 30, 2021 as compared to the same period in 2020, which primarily reflects mutual assistance revenues associated with storm restoration efforts.

Regulatory Required Programs represents revenues collected under approved riders to recover costs incurred for regulatory programs such as recoveries under the credit loss expense tariff, environmental costs associated with MGP sites, and costs related to electricity, ZEC and REC procurement. The riders are designed to provide full and current cost recovery. The costs of these programs are included in Purchased power expense, Operating and maintenance expense, 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 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 therefore ComEd does not record Operating revenues or Purchased power expense related to the electricity. For customers that choose to 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 the Combined Notes to Consolidated Financial Statements for the presentation of ComEd's revenue disaggregation.

The increase of $97 million and of $171 million for the three and nine months ended September 30, 2021 compared to the same period in 2020, respectively, in Purchased power expense is offset in Operating revenues as part of regulatory required programs.

ComEd

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)

(a)See Note 15 - Commitments and Contingencies of the Combined Notes to the Consolidated Financial Statements for additional information.

(b)Primarily reflects the absence of 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.

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
Depreciation and amortization(a)	$	12	$	36
Regulatory asset amortization(b)	(2)		16

Total increase	$	10	$	52

(a)Reflects ongoing capital expenditures.

(b)Includes amortization of ComEd's energy efficiency formula rate regulatory asset and amortization related to the August 2020 storm regulatory asset.

Effective income tax rat****es were 20.3% and 23.4% for the three months ended September 30, 2021 and 2020, respectively, and 18.8% and 31.8% for the nine months ended September 30, 2021 and 2020, respectively. See Note 10 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

PECO

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, 2021 Compared to Three Months Ended September 30, 2020. Net income decreased by $27 million primarily due to an increase in storm cost activity, net of tax repair deductions.

Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020. Net income increased by $66 million primarily due to favorable weather, an increase in primarily electric volume, and a decrease in storm cost activity, net of tax repair deductions.

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
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

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, 2021 compared to the same period in 2020, Operating revenues related to weather fell due to unfavorable weather. During the nine months ended September 30, 2021 compared to the same period in 2020, revenues related to weather increased by the impact of favorable weather conditions in PECO's 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 30-year period in PECO's service territory. The changes in heating and cooling degree-days in

PECO

PECO’s service territory for the three and nine months ended September 30, 2021 compared to the same period in 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	%

Volume. Electric volume, exclusive of the effects of weather, for the three and nine months ended September 30, 2021, compared to the same period in 2020, increased on a net basis due to an increase in overall usage for customers further increased by customer growth. Natural gas volume for the three and nine months ended September 30, 2021 compared to the same period in 2020, increased due to 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 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	%

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, 2021 compared to the same period in 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 represents 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. 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 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 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 PECO, PECO is permitted to recover the electricity, natural gas, and 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, 2021 compared to the same period in 2020, remained relatively consistent.

See Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of PECO's revenue disaggregation.

The increase of $8 million and the increase of $32 million for the three and nine months ended September 30, 2021 compared to the same period in 2020, respectively, in Purchased power and fuel expense is partially offset in Operating revenues as part of regulatory required programs.

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)

(a) YTD primarily reflects the absence of costs in 2021 due to the June and August 2020 storms.

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)	$	6	$	11
Regulatory asset amortization	(5)		(11)

Total increase	$	1	$	—

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

Interest expense, net increased $1 million and $11 million for the three and nine months ended September 30, 2021 compared to the same period in 2020, respectively, primarily due to the issuance of debt in March 2021 and June 2020.

Effective income tax rates were (2.8)% and (13.1)% for the three months ended September 30, 2021 and 2020 respectively, and 2.3% and (2.3)% for the nine months ended September 30, 2021 and 2020, respectively. See Note 10 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

BGE

Results of Operations — BGE


	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 income decreased 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 the multi-year plan.

Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020. Net incom****e increased by $17 million primarily due to favorable impacts of 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.

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 and 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 Revenue includes 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 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, BGE either acts as the billing agent or the competitive supplier separately bills its own customers, and 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 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of BGE's revenue disaggregation.

The increase of $40 million and $109 million for the three and nine months ended September 30, 2021 compared to the same period in 2020, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.

BGE

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)
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 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)	$	12	$	31
Regulatory asset amortization	1		1
Regulatory required programs	(4)		(3)

Total increase	$	9	$	29

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

Taxes other than income taxes increased for the three and nine months ended September 30, 2021 compared to the same period in 2020, primarily due to higher property taxes.

Effective income tax rates were (12.5)% and 13.1% for the three months ended September 30, 2021 and 2020, respectively, and (9.0)% and 8.7% for the nine months ended September 30, 2021 and 2020, respectively. The change is primarily due to the multi-year plan which resulted in the acceleration of certain income tax benefits and the April 24, 2020 settlement agreement of ongoing transmission related income tax regulatory liabilities. 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, 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.

PHI

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, 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.

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 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.

Pepco


	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, 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 costs and capital investments being recovered. Transmission revenue increased for the three months ended September 30, 2021 compared to the same period in 2020, primarily due to increases in underlying costs. 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 and increases in underlying costs.

Other Revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues, and recoveries of 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, 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 Pepco 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, 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 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 the Combined Notes to Consolidated Financial Statements for the presentation of Pepco's revenue disaggregation.

The increase of $9 million and $4 million for the three and nine months ended September 30, 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.

Pepco

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 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.

DPL

Results of Operations — 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, 2021 Compared to Three Months Ended September 30, 2020. Net income increased by $23 million primarily due to higher electric distribution rates and a decrease in storm costs due to the August 2020 storms in Delaware.

Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020. Net income increased by $44 million primarily due to higher electric distribution rates, a decrease in storm costs due to the August 2020 storms in Delaware, higher 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

Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in Maryland 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 from electric distribution customers in Maryland are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.

DPL

Weather. The demand for electricity and natural gas in 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 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, 2021 compared to the same period in 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, 2021 compared to same period in 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	%


Delaware Natural Gas Service Territory				% Change
Three Months Ended September 30,	2021	2020	Normal	2021 vs. 2020		2021 vs. Normal
Heating Degree-Days	11	55	38	(80.0)	%	(71.1)	%

				% Change
Nine Months Ended September 30,	2021	2020	Normal	2021 vs. 2020		2021 vs. Normal
Heating Degree-Days	2,848	2,664	3,025	6.9	%	(5.9)	%

Volume, exclusive of the effects of weather, remained relatively consistent for the three and nine months ended September 30, 2021 compared to the same period in 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	%

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 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 directly from DPL and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges.

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

Distribution Revenue increased for the three 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, 2021 compared to the same period in 2020 primarily due to higher electric distribution rates in Maryland that became effective in July 2020 and higher electric distribution rates in Delaware that became effective in October 2020.

Other Revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues, and recoveries of other taxes.

DPL

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, 2021, compared to the same period in 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)

The changes in Depreciation and amortization expense consisted of the following:


	Three Months Ended September 30, 2021		Nine Months Ended September 30, 2021
	Increase		Increase (Decrease)
Depreciation and amortization(a)	$	3	$	10
Regulatory asset amortization	—		(1)
Regulatory required programs	2		5
Total increase	$	5	$	14

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

Effective income tax rates were 5.7% and 3.6% for the three months ended September 30, 2021 and 2020, respectively, and 6.3% and (28.2)% for the nine months ended September 30, 2021 and 2020, respectively. For the 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 ongoing transmission related income tax regulatory liabilities. See 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.

ACE

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, 2021 Compared to Three Months Ended September 30, 2020. Net income increased by $15 million primarily due to higher distribution rates and higher transmission revenues due to an increase in capital investments.

Nine Months Ended September 30, 2021 Compared to Nine Months Ended September 30, 2020. Net income increased by $35 million primarily due to higher 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 Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in New Jersey are not impacted by abnormal weather or usage per customer as a result of the Conservation Incentive Program (CIP) which became effective, prospectively, in the third quarter 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 Consolidated Financial Statements for additional information.

ACE

Weather. Prior to the third quarter of 2021, the demand for electricity was 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 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, 2021 compared to the same period in 2020, Operating revenues related to weather remained relatively consistent.

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 nine months ended September 30, 2021 compared to same period in 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	%

Volume, exclusive of the effects of weather, increased for the nine months ended September 30, 2021 compared to the same period in 2020, primarily due to customer growth and usage.


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

Distribution Revenue increased for the three and nine months ended September 30, 2021 compared to the same period in 2020 due to higher distribution rates.

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. Transmission revenue increased for the three months ended September 30, 2021 compared to the same period in 2020, primarily due to increases in capital investment. 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 and increases in capital investment.

Other Revenue includes rental revenue, service connection fees, and mutual assistance revenues.

ACE

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 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, 2021 compared to the same period in 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
	Increase (Decrease)		Increase (Decrease)
BSC and PHISCO costs	$	2	$	4
Labor, other benefits, contracting and materials	2		(2)
Pension and non-pension postretirement benefits expense	—		(1)

Storm-related costs	(2)		(5)
Other	(3)		(2)
	(1)		(6)

Regulatory required programs(a)	5		(1)
Total increase (decrease)	$	4	$	(7)

_________

(a)ACE is allowed to recover from or refund to customers the difference between its annual credit loss expense and the amounts collected in rates annually through the Societal Benefits Charge.

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)	$	4	$	11
Regulatory asset amortization	—		(1)
Regulatory required programs	(6)		(11)
Total decrease	$	(2)	$	(1)

_________

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

Effective income tax rates were (13.9)% and (10.3)% for the three months ended September 30, 2021 and 2020, respectively, and (9.3)% and (58.2)% for the nine months ended September 30, 2021 and 2020, respectively. For the 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 ongoing transmission related income tax regulatory liabilities, partially offset by the July 14, 2021 settlement which allowed ACE to retain certain tax benefits. See Note 3 — Regulatory Matters of the 2020 Exelon Form 10-K for additional information on the April 24, 2020

ACE

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, respectively.

Liquidity and Capital Resources

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 credit facilities with aggregate bank commitments of $10.3 billion. 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 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 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, 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 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for 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 8 — Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements for additional 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 funds could appreciate in value. A shortfall could require 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 funding assurance. However, the amount of any assurance will ultimately depend on the decommissioning approach, the associated level of costs, and the NDT fund investment performance going forward. No later than two years after shutting down a plant, Generation must submit a PSDAR to the NRC that includes the planned option for decommissioning the site. As a result of the early retirement reversal, additional financial assurance is no longer required for Byron.

Upon issuance of any required financial 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. However, under the regulations, the NRC must approve an exemption in order for Generation to utilize the NDT funds to pay for non-radiological decommissioning costs (i.e. spent fuel management and site restoration costs, if applicable). If a unit does not receive this exemption, those costs would be borne by Generation without reimbursement from or access to the NDT funds.

As of September 30, 2021, Generation is not required to provide any additional financial assurances for TMI Unit 1 under the SAFSTOR scenario which is the planned decommissioning option as described in the TMI 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 use the TMI Unit 1 NDT funds for spent fuel management costs. An additional exemption request to allow the TMI Unit 1 NDT funds to be used for site restoration costs was submitted to the NRC on May 20, 2021 and is pending NRC review.

Cash Flows from Operating Activities (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 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, and their ability to achieve operating cost reductions.

See Note 3 — Regulatory Matters and Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements of the Exelon 2020 Form 10-K for additional information on regulatory and legal proceedings and proposed legislation.

The following table provides a summary of the change in cash flows from operating activities for the nine months ended September 30, 2021 and 2020 by Registrant:


(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

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, 2021 and 2020 were as follows:

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.
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 over-the-counter markets. See Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ collateral.

Cash Flows from Investing Activities (All Registrants)

The following table provides a summary of the change in cash flows from investing activities for the nine months ended September 30, 2021 and 2020 by Registrant:


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, 2021 and 2020 were as follows:

Variances in capital expenditures are primarily due to the timing of cash expenditures for capital projects. Refer below for additional information on projected capital expenditure spending.
Proceeds from sales of assets and businesses** increased primarily due to the sale of 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.
Changes in intercompany money pool are driven by short-term borrowing needs. Refer below for more information regarding the intercompany money pool.
See Note 6 – Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information on the Collection of DPP.

Capital Expenditure Spending

As of September 30, 2021, the most recent estimates of capital expenditures for plant additions and improvements for 2021 are as follows:


(In millions)	Transmission	Distribution	Gas	Total
Exelon	N/A	N/A	N/A	$	8,175
Generation	N/A	N/A	N/A	1,450
ComEd	475	1,925	N/A	2,400
PECO	150	775	350	1,275
BGE	325	475	400	1,200
PHI	550	1,125	75	1,750
Pepco	250	650	N/A	900
DPL	100	250	75	425
ACE	200	225	N/A	425

Projected capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors.

Cash Flows from Financing Activities (All Registrants)

The following table provides a summary of the change in cash flows from financing activities for the nine months ended September 30, 2021 and 2020 by 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:

Changes in short-term borrowings, net**, is driven by repayments on and issuances of notes due in less than 365 days. Refer to Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on short-term borrowings.
Long-term debt, net**, varies due to debt issuances and redemptions each year. Refer to Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on debt issuances. Refer to the debt redemptions table below for additional information.
Changes in intercompany money pool** are driven by short-term borrowing needs. Refer below for more information regarding the intercompany money pool.
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 restrictions. See below for quarterly dividends declared.
See Note 2 – Mergers, Acquisitions, and 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, 2021, other financing activities primarily consists of debt issuance costs. See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants’ debt issuances.

Debt

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)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.

(b)See Note 17 — Debt and Credit Agreements of 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, 2021 and for the fourth quarter of 2021 were as follows:


Period	Declaration Date	Shareholder of 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 10, 2021	$	0.3825
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)Exelon's Board of Directors approved an updated dividend policy for 2021. The 2021 quarterly dividend will remain the same as the 2020 dividend of $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 $10.3 billion in aggregate total commitments of which $7.7 billion was available to support additional commercial paper as of September 30, 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 markets and had availability under their revolving credit facilities during the 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 2020 Form 10-K for 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, 2021, it would have been required to provide incremental collateral of approximately $3.0 billion to meet collateral obligations for derivatives, non-derivatives, normal 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 the $4.3 billion of available credit capacity of 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, 2021 and available credit facility capacity prior to any incremental collateral at September 30, 2021:


	PJM Credit Policy Collateral		Other Incremental Collateral Required(a)		Available Credit Facility Capacity Prior to Any Incremental Collateral

ComEd	$	27	$	—	$	998
PECO	1		23		600
BGE	4		46		600

Pepco	3		—		260
DPL	4		11		278
ACE	1		—		75

(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

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 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.

See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ short-term borrowing activity. See Note 17 — Debt and Credit Agreements of the Exelon 2020 Form 10-K for additional information on the Registrants’ credit facilities.

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 12 — 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.

On February 24, 2021, S&P lowered Generation’s senior unsecured debt rating to ‘BBB-‘ from ‘BBB’ in response to the financial impacts of 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 pool. Maximum amounts contributed to and borrowed from the money pool by participant and the net contribution or

borrowing as of September 30, 2021, are presented in the following 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



	During the Nine Months Ended September 30, 2021				As of September 30, 2021
PHI Intercompany Money Pool	Maximum Contributed		Maximum Borrowed		Contributed (Borrowed)

Pepco	$	—	$	(30)	$	—
DPL	30		—		—

Shelf Registration Statements (All Registrants)

Exelon, Generation, and the Utility Registrants have a currently effective combined shelf registration statement unlimited in amount, filed with the SEC, that will expire in August 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.

Regulatory Authorizations (All Registrants)

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)						Remaining Long-term Financing Authority(a)
Commission	Expiration Date	Amount	Commission			Expiration Date		Amount
ComEd(c)	FERC	December 31, 2021		$	2,500		ICC		February 1, 2023	$	93
PECO(d)	FERC	December 31, 2021		1,500			PAPUC		December 31, 2021	475
BGE	FERC	December 31, 2021		700			MDPSC		N/A	500
Pepco	FERC	December 31, 2021		500			MDPSC / DCPSC		December 31, 2022	625
DPL	FERC	December 31, 2021		500			MDPSC / DPSC		December 31, 2022	172
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 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.

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 15 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements 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 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements in the Exelon 2020 Form 10-K for 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 2020 Form 10-K and Note 6 — Accounts Receivable of the Combined Notes to Consolidated Financial Statements.

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