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 energy distribution and transmission businesses through ComEd, PECO, BGE, Pepco, DPL, and ACE.

Exelon has six reportable segments consisting of 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 seven separate operating subsidiary registrants, 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, 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 from continuing operations and the Utility Registrants' Net income for the three and nine months ended September 30, 2022 compared to the same period in 2021. For additional information regarding the financial results for the three and nine months ended September 30, 2022 and 2021 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
	2022		2021				2022			2021
Exelon	$	676	$	457	$	219		$	1,622		$	1,307	$	315
ComEd	291		220		71			706			609		97
PECO	135		111		24			474			383		91
BGE	33		36		(3)			267			290		(23)
PHI	289		266		23			518			535		(17)
Pepco	145		130		15			261			264		(3)
DPL	52		50		2			130			135		(5)
ACE	94		90		4			131			141		(10)
Other(a)	(72)		(176)		104			(343)			(510)		167

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

The separation of Constellation, including Generation and its subsidiaries, meets the criteria for discontinued operations and as such, Generation's results of operations are presented as discontinued operations and have been excluded from Exelon's continuing operations for all periods presented.

Accounting rules require that certain BSC costs previously allocated to Generation be presented as part of Exelon’s continuing operations as these costs do not qualify as expenses of the discontinued operations. Such costs are included in Other in the table above. See further discussion below.

Three Months Ended September 30, 2022 Compared to Three Months Ended September 30, 2021. Net income attributable to common shareholders from continuing operations increased by $219 million and

diluted earnings per average common share from continuing operations increased to $0.68 in 2022 from $0.47 in 2021 primarily due to:

Higher electric distribution earnings from higher allowed electric distribution ROE due to an increase in treasury rates and higher rate base at ComEd;
The favorable impacts of rate increases at PECO, BGE, and PHI;
Favorable impacts of decreased storm costs at PECO and BGE; and
Lower BSC costs, which were previously allocated to Generation but do not qualify as expenses of the discontinued operations per the accounting rules. Such costs, on a pre-tax basis, were $104 million for the three months ended September 30, 2021.

The increases were partially offset by:

An adjustment at PECO to exclude one-time non-cash impacts associated with the remeasurement of deferred income taxes as a result of the reduction in Pennsylvania corporate income tax rate;
Higher depreciation expense at PECO and PHI; and
Higher interest expense at Exelon Corporate.

Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021. Net income attributable to common shareholders from continuing operations increased by $315 million and diluted earnings per average common share from continuing operations increased to $1.65 in 2022 from $1.33 in 2021 primarily due to:

Higher electric distribution earnings from higher allowed electric distribution ROE due to an increase in treasury rates and higher rate base at ComEd;
The favorable impacts of rate increases at PECO, BGE, and PHI;
Favorable impacts of decreased storm costs at PECO and BGE; and
Lower BSC costs presented in Exelon’s continuing operations, which were previously allocated to Generation but do not qualify as expenses of the discontinued operation per the accounting rules. Such costs, on a pre-tax basis, were $28 million for the period in 2022 prior to the separation on February 1, 2022 (January 1, 2022 to January 31, 2022) and $309 million for the nine months ended September 30, 2021.

The increases were partially offset by:

An income tax expense recorded in connection with the separation primarily due to the long-term marginal state income tax rate change, the recognition of valuation allowances against the net deferred tax assets positions for certain standalone state filing jurisdictions, and nondeductible transaction costs partially offset by a one-time impact associated with a state tax benefit;
An adjustment at PECO to exclude one-time non-cash impacts associated with the remeasurement of deferred income taxes as a result of the reduction in Pennsylvania corporate income tax rate;
The absence of favorable weather and volume as a result of the CIP at ACE;
Higher depreciation expense at PECO, BGE, and PHI;
Higher credit loss expense at BGE and PHI;
Higher storm costs at PHI; and
Higher interest expense at PHI and Exelon Corporate.

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 from continuing operations as determined in accordance with GAAP and adjusted (non-GAAP) operating earnings for the three and nine months ended September 30, 2022 compared to the same period in 2021.


	Three Months Ended September 30,
	2022				2021
(In millions, except per share data)			Earnings per Diluted Share				Earnings per Diluted Share
Net Income Attributable to Common Shareholders from Continuing Operations	$	676	$	0.68	$	457	$	0.47
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $1)	—		—		3		—
Cost Management Program (net of taxes of $0)	—		—		4		—
COVID-19 Direct Costs (net of taxes of $0)(a)	—		—		3		—
Asset Retirement Obligation (net of taxes of $2 and $1)	(4)		—		2		—
Acquisition Related Costs (net of taxes of $2)(b)	—		—		7		0.01
ERP System Implementation Costs (net of taxes $1)(c)	—		—		4		—
Asset Impairments (net of taxes of $10)	37		0.04		—		—
Separation Costs (net of taxes of $1 and $8, respectively)(d)	(3)		—		16		0.02
Income Tax-Related Adjustments (entire amount represents tax expense)(e)	38		0.04		26		0.03
Adjusted (non-GAAP) Operating Earnings	$	745	$	0.75	$	522	$	0.53


	Nine Months Ended September 30,
	2022				2021
(In millions, except per share data)			Earnings per Diluted Share				Earnings per Diluted Share
Net Income Attributable to Common Shareholders from Continuing Operations	$	1,622	$	1.65	$	1,307	$	1.33
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $2)	—		—		6		0.01
Cost Program Management (net of taxes of $0)	—		—		5		0.01
COVID-19 Direct Costs (net of taxes of $3)(a)	—		—		7		0.01
Asset Retirement Obligation (net of taxes of $2 and $1)	(4)		—		2		—
Acquisition Related Costs (net of taxes of $5)(b)	—		—		15		0.02
ERP System Implementation Costs (net of taxes of $0 and $2, respectively)(c)	1		—		10		0.01
Asset Impairments (net of taxes of $10)	37		0.04		—		—
Separation Costs (net of taxes of $10 and $13, respectively)(d)	25		0.03		29		0.03
Income Tax-Related Adjustments (entire amount represents tax expense)(f)	130		0.13		24		0.02
Adjusted (non-GAAP) Operating Earnings	$	1,811	$	1.84	$	1,405	$	1.43

Note:

Amounts may not sum due to rounding.

Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net Income from Continuing Operations 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. The marginal statutory income tax rates for 2022 and 2021 ranged from 24.0% to 29.0%.

(a)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, which are recorded in Operating and maintenance expense.

(b)Reflects certain BSC costs related to the acquisition of Electricite de France SA's (EDF's) interest in CENG, which was completed in the third quarter of 2021, that were historically allocated to Constellation Energy Generation, LLC

(Generation) but are presented as part of continuing operations in Exelon’s results as these costs do not qualify as expenses of the discontinued operations per the accounting rules.

(c)Reflects costs related to a multi-year Enterprise Resource Program (ERP) system implementation, which are recorded in Operating and maintenance expense.

(d)Represents costs related to the separation primarily comprised of system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the separation, and employee-related severance costs, which are recorded in Operating and maintenance expense.

(e)In 2022, for PECO, reflects an adjustment to exclude one-time non-cash impacts associated with the remeasurement of deferred income taxes as a result of the reduction in Pennsylvania corporate income tax rate. In 2021, for Corporate, primarily reflects the adjustment to deferred income taxes due to changes in forecasted apportionment.

(f)In 2022, for PECO, reflects an adjustment to exclude one-time non-cash impacts associated with the remeasurement of deferred income taxes as a result of the reduction in Pennsylvania corporate income tax rate. In 2022, for Corporate, in connection with the separation, Exelon recorded an income tax expense primarily due to the long-term marginal state income tax rate change, the recognition of valuation allowances against the net deferred tax assets positions for certain standalone state filing jurisdictions, and nondeductible transaction costs partially offset by a one-time impact associated with a state tax benefit. In 2021, for Corporate, primarily reflects the adjustment to deferred income taxes due to changes in forecasted apportionment.

Significant 2022 Transactions and Developments

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 (“the separation”). Exelon completed the separation on February 1, 2022. Constellation was newly formed and incorporated in Pennsylvania on June 15, 2021 for the purpose of separation and holds Generation. The separation represented a strategic shift that would have a major effect on Exelon’s operations and financial results. Accordingly, the separation meets the criteria for discontinued operations. See Note 2 — Discontinued Operations of the Combined Notes to Consolidated Financial Statements for additional information on the separation and discontinued operations.

In connection with the separation, Exelon incurred separation (benefit)/costs impacting continuing operations of $(2) million and $24 million on a pre-tax basis for the three months ended September 30, 2022 and 2021, respectively, and $35 million and $42 million on a pre-tax basis for the nine months ended September 30, 2022 and 2021, respectively, which are recorded in Operating and maintenance expense. Total separation costs impacting continuing operations for the remainder of 2022 are not expected to be material. These costs are excluded from Adjusted (non-GAAP) Operating Earnings. The separation costs are primarily comprised of system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the separation, and employee-related severance costs.

Equity Securities Offering

On August 4, 2022, Exelon entered into an agreement with certain underwriters in connection with an underwritten public offering of 12.995 million shares of its common stock, no par value. The net proceeds were $563 million before expenses paid by Exelon. See Note 14 – Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information.

ComEd Electric Distribution Rates

On November 3, 2022, ComEd announced it plans on filing a four-year MRP in January 2023. The MRP will 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 of the Combined Notes to Consolidated Financial Statements for additional information.

Distribution Base Rate Case 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 2022. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Completed Distribution Base Rate Case Proceedings


Registrant/Jurisdiction		Filing Date		Service		Requested Revenue Requirement Increase			Approved Revenue Requirement Increase			Approved ROE		Approval Date	Rate Effective Date
ComEd - Illinois		April 16, 2021		Electric		$	51		$	46		7.36	%	December 1, 2021	January 1, 2022
PECO - Pennsylvania		March 30, 2021		Electric		246			132			N/A		November 18, 2021	January 1, 2022
	March 31, 2022		Natural Gas		82			55				October 27, 2022		January 1, 2023
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 - Maryland		September 1, 2021 (amended December 23, 2021)		Electric		27			13			9.60	%	March 2, 2022	March 2, 2022
DPL - Delaware		January 14, 2022 (amended August 15, 2022)		Natural Gas		13			8			9.60	%	October 12, 2022	November 1, 2022
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 15, 2022	Electric	$	199	7.85	%	Fourth quarter of 2022





DPL - Maryland	May 19, 2022	Electric	38		10.25	%	Fourth quarter of 2022

Transmission Formula Rates

For 2022, the following total increases/(decreases) were included in the Utility Registrants' 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		Annual Reconciliation (Decrease) Increase		Total Revenue Requirement Increase		Allowed Return on Rate Base		Allowed ROE
ComEd	$	24	$	(24)	$	—	8.11	%	11.50	%
PECO	23		16		39		7.30	%	10.35	%
BGE	25		(4)		16		7.30	%	10.50	%
Pepco	16		15		31		7.60	%	10.50	%
DPL	9		2		11		7.09	%	10.50	%
ACE	21		13		34		7.18	%	10.50	%

Pennsylvania Corporate Income Tax Rate Change

On July 8, 2022, Pennsylvania enacted House Bill 1342, which will permanently reduce the corporate income tax rate from 9.99% to 4.99%. The tax rate will be reduced to 8.99% for the 2023 tax year. Starting with the 2024 tax year, the rate is reduced by 0.50% annually until it reaches 4.99% in 2031. As a result of the rate change, in the third quarter of 2022, Exelon and PECO recorded a one-time decrease to deferred income taxes of $390 million with a corresponding decrease to the deferred income taxes regulatory asset of $428 million for the amounts that are expected to be settled through future customer rates and an increase to income tax expense of $38 million (net of federal taxes), which was excluded from Exelon's Adjusted (non-GAAP) Operating Earnings. The tax rate decrease is not expected to have a material ongoing impact to Exelon’s and PECO’s financial statements. See Note 8 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.

Inflation Reduction Act

On August 16, 2022, the Inflation Reduction Act (IRA) was signed into law. The bill extends tax benefits for renewable technologies like solar and wind, creates new tax benefits for alternative clean energy sources like nuclear and hydrogen and it focuses on energy efficiency, electrification, and equity. However, the bill also implements a new 15.0% corporate alternative minimum tax based on adjusted GAAP income. Exelon estimates the IRA could result in an increase in cash taxes for Exelon of approximately $200 million per year starting in 2023. Exelon is continuing to assess the impacts of the IRA on the financial statements and will update estimates based on guidance to be issued by the U.S. Treasury and IRS in the future.

Asset Impairment

In the third quarter of 2022, a review of the impacts of COVID-19 on office use resulted in plans to cease the renovation and dispose of an office building at BGE before the asset was placed into service. As a result, Exelon and BGE recorded a pre-tax impairment charge of $46 million in the third quarter of 2022, which was excluded from Exelon's Adjusted (non-GAAP) Operating Earnings. See Note 7 – Asset Impairments of the Combined Notes to Consolidated Financial Statements for additional information.

Other Key Business Drivers and Management Strategies

The following discussion of other key business drivers 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 in the 2021 Form 10-K, ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations — Other Key Business Drivers and Management Strategies in the 2021 Recast Form 10-K, and Note 13 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in this report for additional information on various environmental matters.

Legislative and Regulatory Developments

Infrastructure Investment and Jobs Act

On November 15, 2021, President Biden signed the $1.2 trillion Infrastructure Investment and Jobs Act (IIJA) into law. IIJA provides for approximately $550 billion in new federal spending. Categories of funding include funding for a variety of infrastructure needs, including but not limited to: (1) power and grid reliability and resilience, (2) resilience for cybersecurity to address critical infrastructure needs, and (3) electric vehicle charging infrastructure for alternative fuel corridors. Federal agencies are developing guidelines to implement spending programs under IIJA. The time needed to develop these guidelines will vary with some limited program applications opened as early as the first quarter of 2022. The Registrants are continuing to analyze the legislation and considering possible opportunities to apply for funding, either directly or in potential collaborations with state and/or local agencies and key stakeholders. The Registrants cannot predict the ultimate timing and success of securing funding from programs under IIJA.

ComEd and BGE applied for the Middle Mile Grant (MMG), which establishes and funds construction, improvement, or acquisition of middle mile broadband infrastructure which creates high-speed internet services. The MMG addresses inequitable broadband access by expansion and extension of the middle mile infrastructure in underserved communities. ComEd and BGE cannot predict if their applications will be approved as filed or the timing of receiving any funds if they are awarded a grant.

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, 2022, the Registrants’ critical accounting policies and estimates had not changed significantly from December 31, 2021. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates in the 2021 Recast Form 10-K for further information.

Results of Operations by Registrant

Results of Operations — ComEd


	Three Months Ended September 30,				(Unfavorable) Favorable Variance			Nine Months Ended September 30,					(Unfavorable) Favorable Variance
	2022		2021				2022			2021
Operating revenues	$	1,378	$	1,789	$	(411)		$	4,536		$	4,840	$	(304)
Operating expenses
Purchased power	121		703		582			1,041			1,728		687
Operating and maintenance	355		330		(25)			1,045			969		(76)
Depreciation and amortization	333		304		(29)			982			893		(89)
Taxes other than income taxes	104		91		(13)			289			243		(46)
Total operating expenses	913		1,428		515			3,357			3,833		476
Loss on sales of assets	—		—		—			(2)			—		(2)
Operating income	465		361		104			1,177			1,007		170
Other income and (deductions)
Interest expense, net	(104)		(98)		(6)			(308)			(292)		(16)
Other, net	14		13		1			40			35		5
Total other income and (deductions)	(90)		(85)		(5)			(268)			(257)		(11)
Income before income taxes	375		276		99			909			750		159
Income taxes	84		56		(28)			203			141		(62)
Net income	$	291	$	220	$	71		$	706		$	609	$	97

Three Months Ended September 30, 2022 Compared to Three Months Ended September 30, 2021. Net income increased by $71 million as compared to the same period in 2021, primarily due to increases in electric distribution formula rate earnings (reflecting higher allowed electric distribution ROE due to an increase in treasury rates and the impacts of higher rate base).

Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021. Net income increased by $97 million as compared to the same period in 2021, primarily due to increases in electric distribution formula rate earnings (reflecting higher allowed electric distribution ROE due to an increase in treasury rates and the impacts of higher rate base) partially offset by the voluntary customer refund related to the ICC investigation of matters identified in the Deferred Prosecution Agreement. See Note 13 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.

The changes in Operating revenues consisted of the following:


	Three Months Ended September 30, 2022		Nine Months Ended September 30, 2022
	Increase (Decrease)		Increase (Decrease)
Distribution	$	112	$	223
Transmission	9		47
Energy efficiency	19		39
Other	6		9




	146		318
Regulatory required programs	(557)		(622)
Total increase	$	(411)	$	(304)

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

ComEd

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, 2022 as compared to the same period in 2021, due to higher allowed ROE due to an increase in treasury rates, the impact of a higher rate base, and higher fully recoverable costs.

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, 2022 as compared to the same period in 2021 primarily due to the impact of higher rate base and higher fully recoverable costs.

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 increased for the three and nine months ended September 30, 2022 as compared to the same period in 2021, 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, 2022 as compared to the same period in 2021, 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, ETAC, and costs related to electricity, ZEC, CMC, and REC procurement. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding CMCs. ETAC is a retail customer surcharge collected by electric utilities operating in Illinois established by CEJA and remitted to an Illinois state agency for programs to support clean energy jobs and training. 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 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, CMC, 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, CMCs, and RECs.

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

The decrease of $582 million and $687 million for the three and nine months ended September 30, 2022 compared to the same period in 2021, in Purchased power expense is primarily due to the CMCs from the participating nuclear-powered generating facilities. This favorability is offset by a decrease in Operating revenues as part of regulatory required programs. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding CMCs.

ComEd

The changes in Operating and maintenance expense consisted of the following:


	Three Months Ended September 30, 2022		Nine Months Ended September 30, 2022
	Increase (Decrease)		Increase (Decrease)

Storm-related costs	$	10	$	10
Pension and non-pension postretirement benefits expense	(8)		(22)
Labor, other benefits, contracting and materials	21		32

BSC costs	(2)		20

Other(a)	3		30
	24		70
Regulatory required programs(b)	1		6
Total increase	$	25	$	76

(a)For the nine months ended September 30, 2022, the increase is primarily due to the voluntary customer refund related to the ICC investigation of matters identified in the Deferred Prosecution Agreement. See Note 13 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information related to the Deferred Prosecution Agreement.

(b)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, 2022		Nine Months Ended September 30, 2022
	Increase		Increase
Depreciation and amortization(a)	$	17	$	50
Regulatory asset amortization(b)	12		39

Total increase	$	29	$	89

(a)Reflects ongoing capital expenditures.

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

Taxes other than income taxes increased by $13 million and by $46 million for the three and nine months ended September 30, 2022, respectively, compared to the same period in 2021, primarily due to taxes related to ETAC, which is recovered through Operating revenues.

Effective income tax rat****es were 22.4% and 20.3% for the three months ended September 30, 2022 and 2021, respectively, and 22.3% and 18.8% for the nine months ended September 30, 2022 and 2021, respectively. See Note 8 — 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
	2022		2021				2022			2021
Operating revenues	$	1,014	$	818	$	196		$	2,877		$	2,399	$	478
Operating expenses
Purchased power and fuel	403		277		(126)			1,093			800		(293)
Operating and maintenance	243		263		20			705			706		1
Depreciation and amortization	92		86		(6)			277			259		(18)
Taxes other than income taxes	60		51		(9)			155			143		(12)
Total operating expenses	798		677		(121)			2,230			1,908		(322)

Operating income	216		141		75			647			491		156
Other income and (deductions)
Interest expense, net	(45)		(40)		(5)			(129)			(119)		(10)
Other, net	8		7		1			23			20		3
Total other income and (deductions)	(37)		(33)		(4)			(106)			(99)		(7)
Income before income taxes	179		108		71			541			392		149
Income taxes	44		(3)		(47)			67			9		(58)


Net income	$	135	$	111	$	24		$	474		$	383	$	91

Three Months Ended September 30, 2022 Compared to Three Months Ended September 30, 2021. Net income increased by $24 million, primarily due to increases in electric distribution rates and lower storm costs, partially offset by a decrease in electrical volume and the one-time non-cash impacts associated with the Pennsylvania corporate income tax legislation passed in July 2022.

Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021**.** Net income increased by $91 million, primarily due to increases in electric and gas distribution rates, partially offset by the one-time non-cash impacts associated with the Pennsylvania corporate income tax legislation passed in July 2022.

The changes in Operating revenues consisted of the following:


	Three Months Ended September 30, 2022						Nine Months Ended September 30, 2022
	Increase (Decrease)						Increase (Decrease)
	Electric		Gas		Total		Electric		Gas		Total
Weather	$	28	$	—	$	28	$	23	$	(5)	$	18
Volume	(23)		1		(22)		(19)		11		(8)
Pricing	45		1		46		110		24		134
Transmission	2		—		2		10		—		10
Other	3		1		4		14		5		19
	55		3		58		138		35		173
Regulatory required programs	123		15		138		218		87		305
Total increase	$	178	$	18	$	196	$	356	$	122	$	478

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, 2022 compared to the same period in 2021, Operating revenues related to weather increased by the impact of favorable weather conditions. During the nine months ended September 30, 2022 compared to the same period in 2021, Operating revenues related to weather increased by the impact of favorable weather conditions in PECO's service territory.

PECO

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’s service territory for the three and nine months ended September 30, 2022 compared to the same period in 2021 and normal weather consisted of the following:


	Three Months Ended September 30,					% Change
PECO Service Territory	2022	2021	Normal	2022 vs. 2021		2022 vs. Normal

Heating Degree-Days	19	4		24		375.0	%		(20.8)	%
Cooling Degree-Days	1,290	1,094		1,021		17.9	%		26.3	%
	Nine Months Ended September 30,					% Change
	2022	2021		Normal	2022 vs. 2021			2022 vs. Normal
Heating Degree-Days	2,632	2,710		2,864		(2.9)	%		(8.1)	%
Cooling Degree-Days	1,725	1,517		1,413		13.7	%		22.1	%

Volume. Electric volume, exclusive of the effects of weather, for the three and nine months ended September 30, 2022, compared to the same period in 2021, decreased due to customer mix and load growth. Natural gas volume for the three months ended September 30, 2022 compared to the same period in 2021, remained relatively consistent. Natural gas volume for the nine months ended September 30, 2022 compared to the same period in 2021 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)
2022		2021		2022		2021
Residential	4,386		4,318	1.6	%	(5.6)	%	11,204	11,201	—	%	(2.0)	%
Small commercial & industrial	2,139		2,157	(0.8)	%	(3.3)	%	5,889	5,796	1.6	%	0.8	%
Large commercial & industrial	3,943		3,880	1.6	%	0.1	%	10,691	10,627	0.6	%	—	%
Public authorities & electric railroads	172		155	11.0	%	10.5	%	489	425	15.1	%	15.1	%
Total electric retail deliveries(a)	10,640		10,510	1.2	%	(2.8)	%	28,273	28,049	0.8	%	(0.4)	%


	As of September 30,
Number of Electric Customers	2022	2021
Residential	1,523,269	1,514,836
Small commercial & industrial	155,516	155,006
Large commercial & industrial	3,120	3,108
Public authorities & electric railroads	10,393	10,271
Total	1,692,298	1,683,221

(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.

PECO


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)
2022		2021		2022		2021
Residential	2,197		2,244	(2.1)	%	0.3	%	28,240	27,945	1.1	%	4.1	%
Small commercial & industrial	2,054		1,926	6.6	%	9.5	%	16,238	15,217	6.7	%	8.5	%
Large commercial & industrial	6		4	50.0	%	19.6	%	20	13	53.8	%	14.0	%
Transportation	5,162		5,356	(3.6)	%	(9.3)	%	18,508	18,474	0.2	%	(0.7)	%
Total natural gas retail deliveries(a)	9,419		9,530	(1.2)	%	(3.1)	%	63,006	61,649	2.2	%	3.8	%


	As of September 30,
Number of Natural Gas Customers	2022	2021
Residential	500,934	495,752
Small commercial & industrial	46,074	44,435
Large commercial & industrial	9	6
Transportation	656	670
Total	547,673	540,863

(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 months ended September 30, 2022 compared to the same period in 2021 increased primarily due to increases in electric distribution rates charged to customers. Pricing for the nine months ended September 30, 2022 compared to the same period in 2021 increased primarily due to increases in electric and gas distribution rates charged to customers.

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.

Other revenue primarily includes revenue related to late payment charges. Other revenue for the three months ended September 30, 2022 compared to the same period in 2021 remained relatively consistent. Other revenue for the nine months ended September 30, 2022 compared to the same period in 2021 increased primarily due to revenue related to late payment charges.

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.

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

The increase of $126 million and $293 million for the three and nine months ended September 30, 2022 compared to the same period in 2021, respectively, in Purchased power and fuel expense is 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, 2022		Nine Months Ended September 30, 2022
	(Decrease) Increase		(Decrease) Increase
Storm-related costs	$	(40)	$	(39)
Credit loss expense	(7)		(3)
Pension and non-pension post retirement benefit expense	(3)		(6)
Labor, other benefits, contracting and materials	17		8
BSC costs	5		21
Other	3		8
	(25)		(11)
Regulatory required programs	5		10
Total decrease	$	(20)	$	(1)

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


	Three Months Ended September 30, 2022		Nine Months Ended September 30, 2022
	Increase		Increase
Depreciation and amortization(a)	$	6	$	18
Regulatory asset amortization	—		—

Total increase	$	6	$	18

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

Taxes other than income taxes increased by $9 million for the three months ended September 30, 2022 compared to the same period in 2021, primarily due to higher PA gross receipts tax, which is offset in operating revenues. Increased by $12 million for the nine months ended September 30, 2022 compared to the same period in 2021, primarily due to higher PA gross receipts tax, which is offset in operating revenues, and offset by lower PA Use Tax.

Interest expense, net increased $5 million and $10 million for the three and nine months ended September 30, 2022 compared to the same period in 2021, respectively, primarily due to the issuance of debt in 2021 and 2022.

Effective income tax rates were 24.6% and (2.8)% for the three months ended September 30, 2022 and 2021 respectively, and 12.4% and 2.3% for the nine months ended September 30, 2022 and 2021, respectively. See Note 8 — 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
	2022		2021				2022			2021
Operating revenues	$	870	$	770	$	100		$	2,810		$	2,426	$	384
Operating expenses
Purchased power and fuel	350		290		(60)			1,093			840		(253)
Operating and maintenance	235		205		(30)			658			595		(63)
Depreciation and amortization	148		142		(6)			470			434		(36)
Taxes other than income taxes	77		72		(5)			225			211		(14)
Total operating expenses	810		709		(101)			2,446			2,080		(366)

Operating income	60		61		(1)			364			346		18
Other income and (deductions)
Interest expense, net	(39)		(36)		(3)			(110)			(103)		(7)
Other, net	5		7		(2)			16			23		(7)
Total other income and (deductions)	(34)		(29)		(5)			(94)			(80)		(14)
Income before income taxes	26		32		(6)			270			266		4
Income taxes	(7)		(4)		3			3			(24)		(27)
Net income	$	33	$	36	$	(3)		$	267		$	290	$	(23)

Three Months Ended September 30, 2022 Compared to Three Months Ended September 30, 2021. Net income decreased $3 million primarily due to an asset impairment in 2022, and an increase in depreciation expense and credit loss expense, partially offset by favorable impacts of the multi-year plans. See Note 7 — Asset Impairments for additional information on the asset impairment. 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 plans.

Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021**.** Net income decreased $23 million primarily due to an asset impairment in 2022, and an increase in depreciation expense and credit loss expense, partially offset by favorable impacts of the multi-year plans. See Note 7 — Asset Impairments for additional information on the asset impairment. 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 plans.

The changes in Operating revenues consisted of the following:


	Three Months Ended September 30, 2022						Nine Months Ended September 30, 2022
	Increase						Increase
	Electric		Gas		Total		Electric		Gas		Total
Distribution	$	20	$	3	$	23	$	51	$	18	$	69
Transmission	13		—		13		20		—		20
Other	1		1		2		10		6		16
	34		4		38		81		24		105
Regulatory required programs	47		15		62		175		104		279
Total increase	$	81	$	19	$	100	$	256	$	128	$	384

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 monthly rate adjustment that provides for fixed distribution revenue 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	2022	2021
Residential	1,200,786	1,194,254
Small commercial & industrial	115,778	114,814
Large commercial & industrial	12,774	12,584
Public authorities & electric railroads	266	268
Total	1,329,604	1,321,920


	As of September 30,
Number of Natural Gas Customers	2022	2021
Residential	653,413	649,745
Small commercial & industrial	38,128	38,216
Large commercial & industrial	6,222	6,167

Total	697,763	694,128

Distribution Revenue increased for the three and nine months ended September 30, 2022, compared to the same period in 2021, due to favorable impacts of the multi-year plans.

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 increased for the three months ended September 30, 2022, compared to the same period in 2021, primarily due to increases in capital investments and underlying costs and increased for the nine months ended September 30, 2022, compared to the same period in 2021, primarily due to increases in capital investments.

Other Revenue includes revenue related to late payment charges, mutual assistance, off-system sales, and service application fees. Other revenue increased for the three and nine months ended September 30, 2022, compared to the same period in 2021, primarily due to an increase in late fees charged to customers.

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 acts as the billing agent and therefore 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 $60 million and $253 million for the three and nine months ended September 30, 2022 compared to the same period in 2021, 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, 2022		Nine Months Ended September 30, 2022
	(Decrease) Increase		Increase (Decrease)
Labor, other benefits, contracting, and materials	$	(2)	$	4
Storm-related costs	(9)		(10)
Pension and non-pension postretirement benefits expense	(3)		(9)
BSC costs	—		14
Credit loss expense	(4)		10
Asset impairment (a)	46		46
Other	2		5
	30		60
Regulatory required programs	—		3

Total increase	$	30	$	63

(a)See Note 7 — Asset Impairments for additional information on the asset impairment.

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


	Three Months Ended September 30, 2022		Nine Months Ended September 30, 2022
	Increase (Decrease)		Increase
Depreciation and amortization(a)	$	10	$	30
Regulatory required programs	(4)		2
Regulatory asset amortization	—		4

Total increase	$	6	$	36

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

Taxes other than income taxes increased by $5 million and $14 million for the three and nine months ended September 30, 2022, respectively, compared to the same period in 2021, primarily due to increased property taxes.

Effective income tax rates were (26.9)% and (12.5)% for the three months ended September 30, 2022 and 2021, respectively, and 1.1% and (9.0)% for the nine months ended September 30, 2022 and 2021, respectively. The change is primarily due to decreases in the multi-year plans' accelerated income tax benefits in 2022 as compared to 2021. 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 plans and Note 8 — 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, 2022 compared to the same period in 2021. 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,					(Unfavorable) Favorable Variance
	2022		2021				2022			2021
PHI	$	289	$	266	$	23		$	518		$	535	$	(17)
Pepco	145		130		15			261			264		(3)
DPL	52		50		2			130			135		(5)
ACE	94		90		4			131			141		(10)
Other(a)	(2)		(4)		2			(4)			(5)		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, 2022 Compared to Three Months Ended September 30, 2021. Net Income increased by $23 million primarily due to favorable impacts as a result of Pepco's Maryland and District of Columbia multi-year plans and higher electric distribution rates at DPL and ACE, partially offset by an increase in depreciation expense.

Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021. Net Income decreased by $17 million primarily due to an increase in depreciation expense, interest expense at Pepco and ACE, credit loss expense at Pepco and DPL, storm costs at Pepco and DPL, higher contracting costs partially due to timing of maintenance projects at Pepco, the absence of favorable weather and volume as a result of the CIP at ACE, and timing of excess deferred tax amortization at Pepco, partially offset by favorable impacts as a result of Pepco's Maryland and District of Columbia multi-year plans and higher electric distribution rates at DPL and ACE.

Pepco

Results of Operations — Pepco


	Three Months Ended September 30,					Favorable (Unfavorable) Variance		Nine Months Ended September 30,				Favorable (Unfavorable) Variance
2022			2021			2022		2021
Operating revenues	$	724		$	660	$	64	$	1,919	$	1,736	$	183


Operating expenses
Purchased power	230			172		(58)		605		471		(134)
Operating and maintenance	121			120		(1)		380		341		(39)
Depreciation and amortization	99			104		5		312		302		(10)
Taxes other than income taxes	105			105		—		291		282		(9)
Total operating expenses	555			501		(54)		1,588		1,396		(192)

Operating income	169			159		10		331		340		(9)
Other income and (deductions)
Interest expense, net	(37)			(35)		(2)		(111)		(104)		(7)
Other, net	14			12		2		39		37		2
Total other income and (deductions)	(23)			(23)		—		(72)		(67)		(5)
Income before income taxes	146			136		10		259		273		(14)
Income taxes	1			6		5		(2)		9		11
Net income	$	145		$	130	$	15	$	261	$	264	$	(3)

Three Months Ended September 30, 2022 Compared to Three Months Ended September 30, 2021. Net Income increased by $15 million primarily due to favorable impacts of the Maryland and District of Columbia multi-year plans, partially offset by an increase in depreciation expense.

Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021. Net income decreased by $3 million primarily due to higher contracting costs partially due to timing of maintenance projects, an increase in depreciation expense, credit loss expense, storm costs, interest expense, and timing of excess deferred tax amortization, partially offset by the favorable impacts of the Maryland and District of Columbia multi-year plans.

The changes in Operating revenues consisted of the following:


	Three Months Ended September 30, 2022		Nine Months Ended September 30, 2022
	Increase (Decrease)		Increase (Decrease)
Distribution	$	20	$	47
Transmission	(8)		—
Other	(3)		(3)
	9		44
Regulatory required programs	55		139
Total increase	$	64	$	183

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	2022	2021
Residential	853,873	839,574
Small commercial & industrial	54,423	53,849
Large commercial & industrial	22,789	22,586
Public authorities & electric railroads	196	179
Total	931,281	916,188

Distribution Revenue increased for the three and nine months ended September 30, 2022 compared to the same period in 2021 primarily due to favorable impacts of the Maryland and District of Columbia multi-year plans.

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, 2022, compared to the same period in 2021, primarily due to decreases in underlying costs. Transmission revenue remained consistent for the nine months ended September 30, 2022.

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 acts as the billing agent 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 $58 million and $134 million for the three and nine months ended September 30, 2022 compared to the same period in 2021, 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, 2022		Nine Months Ended September 30, 2022
	Increase (Decrease)		Increase (Decrease)
BSC and PHISCO Costs	$	1	$	14
Storm-related costs	1		7
Credit loss expense	—		9
Labor, other benefits, contracting and materials(a)	(1)		7
Pension and non-pension postretirement benefits expense	—		1


Other	(2)		(3)
	(1)		35

Regulatory required programs	2		4
Total increase	$	1	$	39

Pepco

(a) Primarily reflects higher contracting costs partially due to timing of maintenance projects.

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


	Three Months Ended September 30, 2022		Nine Months Ended September 30, 2022
	(Decrease)		Increase (Decrease)
Depreciation and amortization(a)	$	(1)	$	10
Regulatory asset amortization	(1)		(3)
Regulatory required programs	(3)		3
Total (decrease) increase	$	(5)	$	10

(a)Depreciation and amortization decreased for the three months ended September 30, 2022 primarily due to a reduction in transmission depreciation rates approved on August 16, 2022, which is fully offset in Operating revenues as part of the FERC-approved formula. Depreciation and amortization increased for the nine months ended September 30, 2022 primarily due to ongoing capital expenditures.

Taxes other than income taxes remained consistent for the for three months ended September 30, 2022 and 2021 and increased by $9 million for the nine months ended September 30, 2022 compared to the same period in 2021, primarily due to an increase in property taxes.

Interest expense, net increased by $2 million and $7 million for the three and nine months ended September 30, 2022 compared to the same period in 2021, respectively, primarily due to the issuance of debt in 2021 and 2022.

Effective income tax rates were 0.7% and 4.4% for three months ended September 30, 2022 and 2021, respectively, and (0.8)% and 3.3% for the nine months ended September 30, 2022 and 2021, respectively. The three and nine months ended September 30, 2022 change is primarily due to the acceleration of certain income tax benefits as a result of the Maryland and District of Columbia multi-year plans, partially offset by the timing of excess deferred tax amortization. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statement for additional information on the three-year electric distribution multi-year plans and Note 8 — 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
2022			2021			2022		2021
Operating revenues	$	412		$	360	$	52	$	1,176	$	1,040	$	136
Operating expenses
Purchased power and fuel	183			138		(45)		507		402		(105)
Operating and maintenance	84			87		3		266		249		(17)
Depreciation and amortization	59			53		(6)		172		157		(15)
Taxes other than income taxes	19			17		(2)		54		50		(4)
Total operating expenses	345			295		(50)		999		858		(141)

Operating income	67			65		2		177		182		(5)
Other income and (deductions)
Interest expense, net	(16)			(15)		(1)		(48)		(47)		(1)
Other, net	3			3		—		9		9		—
Total other income and (deductions)	(13)			(12)		(1)		(39)		(38)		(1)
Income before income taxes	54			53		1		138		144		(6)
Income taxes	2			3		1		8		9		1
Net income	$	52		$	50	$	2	$	130	$	135	$	(5)

Three Months Ended September 30, 2022 Compared to Three Months Ended September 30, 2021. Net income remained relatively consistent.

Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021. Net income decreased $5 million primarily due to an increase in credit loss expense, storm costs, and depreciation expense, partially offset by higher electric distribution rates.

The changes in Operating revenues consisted of the following:


	Three Months Ended September 30, 2022						Nine Months Ended September 30, 2022
	Increase (Decrease)						Increase (Decrease)
	Electric		Gas		Total		Electric		Gas		Total
Weather	$	1	$	—	$	1	$	—	$	—	$	—
Volume	—		(1)		(1)		4		2		6
Distribution	3		1		4		13		4		17
Transmission	4		—		4		6		—		6
Other	(1)		—		(1)		(2)		—		(2)
	7		—		7		21		6		27
Regulatory required programs	30		15		45		74		35		109
Total increase	$	37	$	15	$	52	$	95	$	41	$	136

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.

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

DPL

demand. During the three and nine months ended September 30, 2022 compared to the same period in 2021, 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 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, 2022 compared to same period in 2021 and normal weather consisted of the following:


	Three Months Ended September 30,			% Change
Delaware Electric Service Territory	2022	2021	Normal	2022 vs. 2021		2022 vs. Normal
Heating Degree-Days	32	11	26	190.9	%	23.1	%
Cooling Degree-Days	1,043	969	906	7.6	%	15.1	%

	Nine Months Ended September 30,			% Change
	2022	2021	Normal	2022 vs. 2021		2022 vs. Normal
Heating Degree-Days	2,828	2,848	2,977	(0.7)	%	(5.0)	%
Cooling Degree-Days	1,374	1,333	1,243	3.1	%	10.5	%


	Three Months Ended September 30,			% Change
Delaware Natural Gas Service Territory	2022	2021	Normal	2022 vs. 2021		2022 vs. Normal
Heating Degree-Days	32	11	36	190.9	%	(11.1)	%

	Nine Months Ended September 30,			% Change
	2022	2021	Normal	2022 vs. 2021		2022 vs. Normal
Heating Degree-Days	2,828	2,848	3,029	(0.7)	%	(6.6)	%

Volume, exclusive of the effects of weather, remained relatively consistent for the three months ended September 30, 2022 compared to the same period in 2021 and increased for the nine months ended September 30, 2022 compared to the same period in 2021 primarily due to customer growth and usage.


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)
2022		2021				2022			2021
Residential	978		973	0.5	%		(2.1)	%		2,548	2,530	0.7	%	0.2	%
Small commercial & industrial	400		412	(2.9)	%		(4.0)	%		1,107	1,111	(0.4)	%	(0.6)	%
Large commercial & industrial	856		860	(0.5)	%		(1.2)	%		2,394	2,359	1.5	%	1.4	%
Public authorities & electric railroads	7		7	—	%		(1.7)	%		24	26	(7.7)	%	(6.1)	%
Total electric retail deliveries(a)	2,241		2,252	(0.5)	%		(2.1)	%		6,073	6,026	0.8	%	0.5	%


	As of September 30,
Number of Total Electric Customers (Maryland and Delaware)	2022	2021
Residential	480,779	476,008
Small commercial & industrial	63,685	62,990
Large commercial & industrial	1,230	1,215
Public authorities & electric railroads	597	605
Total	546,291	540,818

(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.

DPL


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)
2022		2021				2022			2021
Residential	374		399	(6.3)	%		(15.2)	%		5,810	5,507	5.5	%	4.7	%
Small commercial & industrial	331		352	(6.0)	%		(10.2)	%		2,882	2,647	8.9	%	9.1	%
Large commercial & industrial	397		395	0.5	%		0.6	%		1,259	1,247	1.0	%	0.9	%
Transportation	1,284		1,303	(1.5)	%		(2.1)	%		4,934	4,997	(1.3)	%	(1.1)	%
Total natural gas deliveries(a)	2,386		2,449	(2.6)	%		(5.2)	%		14,885	14,398	3.4	%	3.2	%


	As of September 30,
Number of Delaware Natural Gas Customers	2022	2021
Residential	129,005	127,740
Small commercial & industrial	10,044	9,935
Large commercial & industrial	16	21
Transportation	156	158
Total	139,221	137,854

(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 and nine months ended September 30, 2022 compared to the same period in 2021 primarily due to higher electric distribution rates in Maryland that became effective in March 2022 and higher DSIC rates in Delaware that became effective in January and July 2022.

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. During the three and nine months ended September 30, 2022 compared to the same period in 2021, transmission revenue increased, primarily due to 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, DE Renewable Portfolio Standards, SOS procurement and administrative costs, and GCR costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. All customers have the choice to purchase electricity from competitive electric generation suppliers; however, only certain commercial and industrial customers have the choice to purchase natural gas from competitive natural gas 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 or natural gas from competitive suppliers, DPL either acts as the billing agent or the competitive supplier separately bills its own customers, and therefore 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 DPL, DPL is permitted to recover the electricity, natural gas, and REC procurement costs from customers and therefore records the amounts related to the electricity, natural gas, and RECs in Operating revenues and Purchased power and fuel expense. DPL recovers electricity and REC procurement costs from customers with a slight mark-up, and natural gas costs without mark-up.

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

DPL

The increase of $45 million and $105 million for the three and nine months ended September 30, 2022, compared to the same period in 2021, 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, 2022		Nine Months Ended September 30, 2022
	Increase (Decrease)		Increase (Decrease)
Storm-related costs	$	1	$	4
BSC and PHISCO costs	1		7
Credit loss expense	—		4

Labor, other benefits, contracting and materials	(5)		(3)
Other	(2)		1
	(5)		13
Regulatory required programs	2		4
Total (decrease) increase	$	(3)	$	17

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


	Three Months Ended September 30, 2022		Nine Months Ended September 30, 2022
	Increase (Decrease)		Increase (Decrease)
Depreciation and amortization(a)	$	7	$	15
Regulatory asset amortization	(1)		(2)
Regulatory required programs	—		2
Total increase	$	6	$	15

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

Taxes other than income taxes increased by $2 million and $4 million for the three and nine months ended September 30, 2022 compared to the same period in 2021, respectively, primarily due to an increase in property taxes and gross receipts taxes.

Effective income tax rates were 3.7% and 5.7% for the three months ended September 30, 2022 and 2021, respectively, and 5.8% and 6.3% for the nine months ended September 30, 2022 and 2021, respectively. See Note 8 — 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
	2022		2021				2022			2021
Operating revenues	$	462	$	451	$	11		$	1,120		$	1,080	$	40


Operating expenses
Purchased power	197		230		33			497			541		44
Operating and maintenance	80		81		1			251			231		(20)
Depreciation and amortization	74		46		(28)			192			133		(59)
Taxes other than income taxes	2		2		—			7			6		(1)
Total operating expenses	353		359		6			947			911		(36)

Operating income	109		92		17			173			169		4
Other income and (deductions)
Interest expense, net	(17)		(14)		(3)			(49)			(43)		(6)
Other, net	3		1		2			9			3		6
Total other income and (deductions)	(14)		(13)		(1)			(40)			(40)		—
Income before income taxes	95		79		16			133			129		4
Income taxes	1		(11)		(12)			2			(12)		(14)
Net income	$	94	$	90	$	4		$	131		$	141	$	(10)

Three Months Ended September 30, 2022 Compared to Three Months Ended September 30, 2021. Net income increased by $4 million primarily due to increases in distribution rates, partially offset by an increase in depreciation expense.

Nine Months Ended September 30, 2022 Compared to Nine Months Ended September 30, 2021. Net income decreased by $10 million primarily due to the absence of favorable weather and volume as a result of the CIP, an increase in depreciation expense, and interest expense, partially offset by increases in distribution rates.

The changes in Operating revenues consisted of the following:


	Three Months Ended September 30, 2022		Nine Months Ended September 30, 2022
	Increase (Decrease)		(Decrease) Increase
Weather	$	—	$	(3)
Volume	—		(11)
Distribution	15		35
Transmission	5		8

	20		29




Regulatory required programs	(9)		11
Total increase	$	11	$	40

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 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.

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

ACE

are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity. Conversely, mild weather reduces demand. During the nine months ended September 30, 2022 compared to the same period in 2021, Operating revenues related to weather decreased due to the absence of favorable impacts in the first and second quarter of 2022 as a result of the CIP.

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, 2022 compared to same period in 2021 and normal weather consisted of the following:


	Nine Months Ended September 30,		Normal		% Change
Heating and Cooling Degree-Days	2022	2021		2022 vs. 2021			2022 vs. Normal
Heating Degree-Days	3,007	2,884	3,024		4.3	%		(0.6)	%
Cooling Degree-Days	1,231	1,246	1,178		(1.2)	%		4.5	%

Volume, exclusive of the effects of weather, decreased for the nine months ended September 30, 2022 compared to the same period in 2021, due to the absence of favorable impacts in the first and second quarter of 2022 as a result of the CIP.


	Nine Months Ended September 30,		% Change	Weather - Normal % Change(b)
Electric Retail Deliveries to Customers (in GWhs)	2022	2021
Residential		3,293	3,443	(4.4)	%	(4.6)	%
Small commercial & industrial		1,179	1,073	9.9	%	9.8	%
Large commercial & industrial		2,396	2,351	1.9	%	1.8	%
Public authorities & electric railroads		34	33	3.0	%	—	%
Total electric retail deliveries(a)		6,902	6,900	—	%	(0.2)	%


	As of September 30,
Number of Electric Customers	2022	2021
Residential	501,869	499,775
Small commercial & industrial	62,204	61,838
Large commercial & industrial	3,075	3,209
Public authorities & electric railroads	731	707
Total	567,879	565,529

(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, 2022 compared to the same period in 2021 due to higher distribution rates that became effective in January 2022.

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, 2022 compared to the same period in 2021, primarily due to increases in underlying costs. Transmission revenue increased for the nine months ended September 30, 2022 compared to the same period in 2021, primarily due to increases in underlying costs and capital investment.

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

ACE

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 acts as the billing agent 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 decrease of $33 million and $44 million for the three and nine months ended September 30, 2022 compared to the same period in 2021, 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, 2022		Nine Months Ended September 30, 2022
	(Decrease) Increase		Increase (Decrease)
Labor, other benefits, contracting and materials	$	(2)	$	2
BSC and PHISCO costs	(1)		3
Storm-related costs	(1)		1


Other	4		7
	—		13

Regulatory required programs(a)	(1)		7
Total (decrease) increase	$	(1)	$	20

(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, 2022		Nine Months Ended September 30, 2022
	Increase		Increase
Depreciation and amortization(a)	$	4	$	11
Regulatory asset amortization	—		1
Regulatory required programs(b)	24		47
Total increase	$	28	$	59

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

(b)Regulatory required programs increased primarily due to the regulatory asset amortization of the PPA termination obligation which is fully offset in Operating revenues.

Interest expense, net increased $3 million and $6 million for the three and nine months ended September 30, 2022 compared to the same period in 2021, respectively, primarily due to the issuance of debt in 2021 and 2022.

Other, net increased by $2 million and $6 million for the three and nine months ended September 30, 2022 compared to the same period in 2021, respectively, primarily due to higher AFUDC equity.

Effective income tax rates were 1.1% and (13.9)% for the three months ended September 30, 2022 and 2021, respectively, and 1.5% and (9.3)% for the nine months ended September 30, 2022 and 2021, respectively. The three and nine months ended September 30, 2022 changes primarily reflect the absence of impacts of the July 14, 2021 settlement, which allowed ACE to retain certain tax benefits in 2021, partially offset by the timing of excess deferred tax amortization. See Note 3 — Regulatory Matters of the 2021 Recast Form 10-K for additional information on the July 14, 2021 settlement agreement. See Note 8 — Income Taxes of the Combined Notes to

ACE

Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

Liquidity and Capital Resources (All Registrants)

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, 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, including construction expenditures, retire debt, pay dividends, and fund pension and OPEB obligations. 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. 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 $4.0 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 and Cash Requirements” section below for additional information. The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs, and capital expenditure requirements. See Note 11 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt and credit agreements.

Cash flows related to Constellation have not been presented as discontinued operations and are included in the Consolidated Statements of Cash Flows for all periods presented. The Exelon Consolidated Statement of Cash Flows for the nine months ended September 30, 2022 includes one month of cash flows from Generation. The Exelon Consolidated Statement of Cash Flows for the nine months ended September 30, 2021 includes nine months of cash flows from Generation. This is the primary reason for the changes in cash flows as shown in the tables unless otherwise noted below.

Cash Flows from Operating Activities

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 of the 2021 Recast Form 10-K and Notes 3 — Regulatory Matters and 13 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements 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, 2022 and 2021 by Registrant:


Increase (decrease) in cash flows from operating activities	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Net income (loss)	$	298	$	97	$	91	$	(23)	$	(17)	$	(3)	$	(5)	$	(10)
Adjustments to reconcile net income to cash:
Non-cash operating activities	(1,316)		(114)		58		100		228		67		43		125
Option premiums (paid), net	147		—		—		—		—		—		—		—
Collateral received, net	(655)		1		—		105		205		46		89		70
Income taxes	(247)		9		(25)		(23)		(20)		(15)		(15)		(3)
Pension and non-pension postretirement benefit contributions	6		(3)		2		12		(32)		—		—		(4)
Changes in regulatory assets and liabilities, net	(322)		(249)		(11)		(7)		(37)		11		(3)		(35)
Changes in working capital and other assets and liabilities	2,089		(84)		(96)		(56)		(88)		(45)		(13)		(34)
(Decrease) increase in cash flows from operating activities	$	—	$	(343)	$	19	$	108	$	239	$	61	$	96	$	109

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. See above for additional information related to cash flows from Generation. Significant operating cash flow impacts for the Registrants and Generation for the nine months ended September 30, 2022 and 2021 were as follows:

See Note 16 — 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.
Changes in collateral depended upon whether Generation was in a net mark-to-market liability or asset position, and collateral may have been required to be posted with or collected from its counterparties. In addition, the collateral posting and collection requirements differed depending on whether the transactions were on an exchange or in the over-the-counter markets. Changes in collateral for the Registrants are dependent upon the credit exposure of procurement contracts that may require suppliers to post collateral. The amount of cash collateral received from external counterparties increased due to rising energy prices. See Note 10 – Derivative Financial Instruments for additional information.
See Note 8 — Income Taxes of the Combined Notes to Consolidated Financial Statements and the Registrants' Consolidated Statements of Cash Flows for additional information on income taxes.
See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on regulatory assets and liabilities.
Changes in working capital and other assets and liabilities** for the Utility Registrants and Exelon Corporate total $(316) million and for Generation total $2,405 million. The change for Generation primarily relates to the revolving accounts receivable financing arrangement. See Note 6 — Accounts Receivable of the 2021 Form 10-K and the Collection of DPP discussion below for additional information.

Cash Flows from Investing Activities

The following table provides a summary of the change in cash flows from investing activities for the nine months ended September 30, 2022 and 2021 by Registrant:


Increase (decrease) in cash flows from investing activities	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Capital expenditures	$	791	$	(78)	$	(113)	$	(11)	$	125	$	46	$	26	$	52

Investment in NDT fund sales, net	106		—		—		—		—		—		—		—
Collection of DPP	(2,883)		—		—		—		—		—		—		—
Proceeds from sales of assets and businesses	(785)		—		—		—		—		—		—		—
Changes in intercompany money pool	—		—		—		—		—		—		(25)		—

Other investing activities	(4)		1		3		(6)		6		4		1		—
(Decrease) increase in cash flows from investing activities	$	(2,775)	$	(77)	$	(110)	$	(17)	$	131	$	50	$	2	$	52

Significant investing cash flow impacts for the Registrants for nine months ended September 30, 2022 and 2021 were as follows:

Variances in capital expenditures are primarily due to the timing of cash expenditures for capital projects. See the "Credit Matters and Cash Requirements" section below for additional information on projected capital expenditure spending. See Note 2 — Discontinued Operations of the Combined Notes to Consolidated Financial Statements for capital expenditures related to Generation prior to the separation.
Collection of DPP** relates to the revolving accounts receivable financing agreement which Generation entered into in April of 2020. See Note 6 — Accounts Receivable of the 2021 Form 10-K for additional information on the transaction and the DPP, including the $400 million of additional funding received in February and March of 2021.
Proceeds from sales of assets and businesses decreased primarily due to the sale of a significant portion of Generation's solar business and a biomass facility in 2021. See Note 2 — Mergers, Acquisitions, and Dispositions of the 2021 Form 10-K 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.

Cash Flows from Financing Activities

The following table provides a summary of the change in cash flows from financing activities for the nine months ended September 30, 2022 and 2021 by Registrant:


(Decrease) increase in cash flows from financing activities	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Changes in short-term borrowings, net	$	(746)	$	556	$	—	$	26	$	(387)	$	(180)	$	(25)	$	(182)
Long-term debt, net	1,946		(50)		(25)		(50)		120		41		—		79
Changes in intercompany money pool	—		—		40		—		41		25		—		—
Issuance of common stock	563		—		—		—		—		—		—		—
Dividends paid on common stock	122		(54)		(45)		(6)		—		(179)		11		152
Acquisition of noncontrolling interest	885		—		—		—		—		—		—		—
Distributions to member	—		—		—		—		(20)		—		—		—
Contributions from parent/member	—		(90)		(140)		(71)		120		221		27		(128)
Transfer of cash, restricted cash, and cash equivalents to Constellation	(2,594)		—		—		—		—		—		—		—
Other financing activities	(65)		6		(6)		(2)		(6)		(4)		—		1
Increase (decrease) in cash flows from financing activities	$	111	$	368	$	(176)	$	(103)	$	(132)	$	(76)	$	13	$	(78)

Significant financing cash flow impacts for the Registrants for the nine months ended September 30, 2022 and 2021 were as follows:

Changes in short-term borrowings, net**, is driven by repayments on and issuances of notes due in less than 365 days. See Note 11 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on short-term borrowings for the Registrants. These changes also included repayments of $552 million in commercial paper and term loans by Generation prior to the separation.
Long-term debt, net**, varies due to debt issuances and redemptions each year. See Note 11 — 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.
Issuance of common stock** relates to the August 2022 underwritten public offering of Exelon common stock. See Note 14 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information.
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 17 — Commitments and Contingencies of the 2021 Recast Form 10-K for additional information on dividend restrictions. See below for quarterly dividends declared.
Acquisition of noncontrolling interest relates to Generation's acquisition of CENG noncontrolling interest in 2021. See Note 2 — Mergers, Acquisitions, and Dispositions of the 2021 Form 10-K for additional information.
Refer to Note 2 - Discontinued Operations for the transfer of cash, restricted cash, and cash equivalents to Constellation related to the separation.
For the nine months ended September 30, 2022, other financing activities primarily consists of debt issuance costs. See Note 11 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants’ debt issuances.

Debt

See Note 11 — 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, 2022, the following long-term debt was retired and/or redeemed:


Company	Type	Interest Rate		Maturity	Amount
Exelon	Junior Subordinated Notes	3.50	%	May 2, 2022	$	1,150
Exelon	Long-Term Software License Agreement	3.96	%	May 1, 2024	2
PECO	First Mortgage Bonds	2.375	%	September 15, 2022	350
BGE	Notes	2.80	%	August 15, 2022	250
Pepco	First Mortgage Bonds	3.05	%	April 1, 2022	200
Pepco	Tax-Exempt Bonds	1.70	%	September 1, 2022	110

Dividends

Quarterly dividends declared by the Exelon Board of Directors during the nine months ended September 30, 2022 and for the fourth quarter of 2022 were as follows:


Period	Declaration Date	Shareholder of Record Date	Dividend Payable Date	Cash per Share(a)
First Quarter 2022	February 8, 2022	February 25, 2022	March 10, 2022	$	0.3375
Second Quarter 2022	April 26, 2022	May 13, 2022	June 10, 2022	$	0.3375
Third Quarter 2022	July 26, 2022	August 15, 2022	September 9, 2022	$	0.3375
Fourth Quarter 2022	October 28, 2022	November 15, 2022	December 9, 2022	$	0.3375

(a)Exelon's Board of Directors approved an updated dividend policy for 2022. The 2022 quarterly dividend will be $0.3375 per share.

Credit Matters and Cash Requirements

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 $4.0 billion in aggregate total commitments of which $3.4 billion was available to support additional commercial paper as of September 30, 2022, and of which no financial institution has more than 6% 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, 2022 to fund their short-term liquidity needs, when necessary. On February 1, 2022, Exelon Corporate and the Utility Registrants each entered into a new 5-year revolving credit facility that replaced its existing syndicated revolving credit facility. See Note 11 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. 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 2021 Form 10-K for additional information regarding the effects of uncertainty in the capital and credit markets.

The Registrants believe their cash flows from operating activities, access to credit markets, and their credit facilities provide sufficient liquidity to support the estimated future cash requirements.

On August 4, 2022, Exelon entered into an agreement with certain underwriters in connection with an underwritten public offering of 12.995 million shares of its common stock, no par value. The net proceeds were $563 million before expenses paid. Exelon used the proceeds, together with available cash balances, to repay $575 million in borrowings under a $1.15 billion term loan credit facility. See Note 14 — Shareholders' Equity and

Note 11 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.

On August 4, 2022, Exelon executed an equity distribution agreement (“Equity Distribution Agreement”) with certain sales agents and forward sellers and certain forward purchasers establishing an ATM equity distribution program under which it may offer and sell shares of its common stock, having an aggregate gross sales price of up to $1.0 billion. Exelon has no obligation to offer or sell any shares of common stock under the Equity Distribution Agreement and may at any time suspend or terminate offers and sales under the Equity Distribution Agreement. As of September 30, 2022, Exelon has not issued any shares of common stock under the ATM program and has not entered into any forward sale agreements.

Pursuant to the Separation Agreement between Exelon and Constellation, Exelon made a cash payment of $1.75 billion to Generation on January 31, 2022. See Note 2 — Discontinued Operations of the Combined Notes to Consolidated Financial Statements for additional information on the separation.

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, 2022 and available credit facility capacity prior to any incremental collateral at September 30, 2022:


	PJM Credit Policy Collateral		Other Incremental Collateral Required(a)		Available Credit Facility Capacity Prior to Any Incremental Collateral
ComEd	$	34	$	—	$	762
PECO	2		43		600
BGE	3		79		444

Pepco	3		—		300
DPL	3		16		300
ACE	1		—		300

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

Capital Expenditure Spending

As of September 30, 2022, the most recent estimates of capital expenditures for plant additions and improvements for 2022 are as follows:


(In millions)	Transmission	Distribution	Gas	Total
Exelon	N/A	N/A	N/A	$	6,950
ComEd	425	2,075	N/A	2,500
PECO	200	850	325	1,375
BGE	250	525	475	1,250
PHI	600	1,150	75	1,825
Pepco	275	625	N/A	900
DPL	150	225	75	450
ACE	175	300	N/A	475

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

Pension and Other Postretirement Benefits

Management considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006 (the Act), management of the pension obligation, and regulatory implications. The Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification). The projected contributions reflect a

funding strategy to make levelized annual contributions with the objective of achieving 100% funded status on an ABO basis over time. This level funding strategy helps minimize volatility of future period required pension contributions. Post-separation, Exelon's estimated annual qualified pension contributions will be approximately $313 million in 2022. In connection with the separation, additional qualified pension contributions of $207 million and $33 million were completed on February 1, 2022 and March 2, 2022, respectively. Unlike the qualified pension plans, Exelon’s non-qualified pension plans are not funded, given that they are not subject to statutory minimum contribution requirements.

While OPEB plans are also not subject to statutory minimum contribution requirements, Exelon does fund certain of its plans. For Exelon's funded OPEB plans, contributions generally equal accounting costs, however, Exelon’s management has historically considered several factors in determining the level of contributions to its OPEB plans, including liabilities management, levels of benefit claims paid, and regulatory implications (amounts deemed prudent to meet regulatory expectations and best assure continued rate recovery).

Credit Facilities

Exelon Corporate, ComEd, and BGE meet their short-term liquidity requirements primarily through the issuance of commercial paper. PECO meets its 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 11 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ credit facilities and short term borrowing activity.

Security Ratings

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 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral provisions.

The credit ratings for ComEd, PECO, BGE, and DPL did not change for the nine months ended September 30, 2022. On January 14, 2022, Fitch lowered Exelon Corporate's long-term and senior unsecured ratings from BBB+ to BBB and affirmed the short-term rating of F2. In addition, Fitch upgraded Pepco, ACE, and PHI's long-term rating from BBB to BBB+ and upgraded Pepco and ACE's senior secured rating from A- to A.

Intercompany Money Pool

To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing, both Exelon and PHI operate an intercompany money pool. Maximum amounts contributed to and borrowed from the money pool by participant and the net contribution or borrowing as of September 30, 2022, are presented in the following table. ACE had no activity within the PHI intercompany money pool during the nine months ended September 30, 2022.


	During the Nine Months Ended September 30, 2022				As of September 30, 2022
Exelon Intercompany Money Pool	Maximum Contributed		Maximum Borrowed		Contributed (Borrowed)
Exelon Corporate	$	396	$	—	$	299
PECO	138		(105)		—
BSC	—		(377)		(301)
PHI Corporate	—		(54)		(43)
PCI	50		—		45


	During the Nine Months Ended September 30, 2022				As of September 30, 2022
PHI Intercompany Money Pool	Maximum Contributed		Maximum Borrowed		Contributed (Borrowed)
Pepco	$	—	$	(108)	$	(25)
DPL	108		—		25

Shelf Registration Statements

Exelon and the Utility Registrants have a currently effective combined shelf registration statement unlimited in amount, filed with the SEC on August 3, 2022, that will expire in August 2025. 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

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, 2022
	Short-term Financing Authority						Remaining Long-term Financing Authority
Commission	Expiration Date	Amount	Commission			Expiration Date		Amount
ComEd(a)	FERC	December 31, 2023		$	2,500		ICC		January 1, 2025	$	1,343
PECO(b)	FERC	December 31, 2023		1,500			PAPUC		December 31, 2024	1,125
BGE(c)	FERC	December 31, 2023		700			MDPSC		N/A	—
Pepco(d)	FERC	December 31, 2023		500			MDPSC / DCPSC		2022 & 2025	1,400
DPL(e)	FERC	December 31, 2023		500			MDPSC / DEPSC		December 31, 2022	47
ACE(f)	NJBPU	December 31, 2023		350			NJBPU		December 31, 2022	700

(a)On November 18, 2021, ComEd received approval from the ICC for $2 billion in new money long-term debt financing authority with an effective date of January 1, 2022.

(b)On December 2, 2021, PECO received approval from the PAPUC for $2.5 billion in new long-term debt financing authority with an effective date of January 1, 2022.

(c)On October 28, 2022, BGE filed with the MDPSC for approval of $1.8 billion in new long-term financing authority. The long-term financing authority will become effective on the date of approval. This financing authority does not have an expiration date.

(d)On June 9, 2022 and June 30, 2022, Pepco received approval from the MDPSC and DCPSC, respectively, for $1.4 billion in new long-term financing authority. The long-term financing authority became effective on the date of respective approvals and has an expiration date of December 31, 2025.

(e)On November 2, 2022, DPL filed with the MDPSC and DEPSC for approval of $1.2 billion in new long-term financing authority. The long-term financing authority will become effective on the date of respective approvals. The financing authority filed with MDPSC does not have an expiration date, while the financing authority filed with DEPSC has an expiration date of December 31, 2025.

(f)On July 13, 2022, ACE received approval from the NJBPU for $700 million in new long-term debt financing authority with an effective date of July 20, 2022.

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