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 months ended March 31, 2022 compared to the same period in 2021. For additional information regarding the financial results for the three months ended March 31, 2022 and 2021 see the discussions of Results of Operations by Registrant.


	Three Months Ended March 31,					(Unfavorable) Favorable Variance
		2022			2021
Exelon			$	481		$	525	$	(44)
ComEd			188			197		(9)
PECO			206			167		39
BGE			198			209		(11)
PHI			130			128		2
Pepco			46			59		(13)
DPL			56			56		—
ACE			26			14		12
Other(a)			(241)			(176)		(65)

(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 March 31, 2022 Compared to Three Months Ended March 31, 2021. Net income attributable to common shareholders from continuing operations decreased by $44 million and diluted

earnings per average common share from continuing operations decreased to $0.49 in 2022 from $0.53 in 2021 primarily due to:

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;
Higher depreciation expense at BGE and PHI; and
Higher storm costs at PHI.

The decreases were partially offset by:

Higher electric distribution earnings from higher rate base and higher allowed electric distribution ROE due to an increase in treasury rates at ComEd;
The favorable impacts of regulatory rate increases at PECO, BGE, and PHI; 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 $106 million for the three months ended March 31, 2021.

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 table provides 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 months ended March 31, 2022 compared to the same period in 2021.


	Three Months Ended March 31,
	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	$	481	$	0.49	$	525	$	0.53
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $1)	—		—		(1)		—
COVID-19 Direct Costs (net of taxes of $1)(a)	—		—		2		—
Acquisition Related Costs (net of taxes of $2)(b)	—		—		6		0.01
ERP System Implementation Costs (net of taxes of $0 and $2, respectively)(c)	1		—		5		0.01
Separation Costs (net of taxes of $7 and $1, respectively)(d)	17		0.02		5		0.01
Income Tax-Related Adjustments (entire amount represents tax expense)(e)	134		0.14		—		—
Adjusted (non-GAAP) Operating Earnings	$	634	$	0.64	$	542	$	0.55

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 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 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.

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 costs impacting continuing operations of $24 million and $4 million on a pre-tax basis for the three months ended March 31, 2022 and March 31, 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.

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 on these and other regulatory proceedings.

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
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			9.28	%	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
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

PECO - Pennsylvania	March 31, 2022	Natural Gas	82		10.95	%	Fourth quarter of 2022



DPL - Delaware	January 14, 2022 (amended February 28, 2022)	Natural Gas	15		10.30	%	First quarter of 2023

Transmission Formula Rates

For 2022, the following total increases were included in ComEd’s and BGE's electric transmission formula rate update. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on these and other regulatory proceedings.


Registrant	Initial Revenue Requirement Increase		Annual Reconciliation Decrease		Total Revenue Requirement Increase		Allowed Return on Rate Base		Allowed ROE
ComEd	$	24	$	(24)	$	—	8.11	%	11.50	%
BGE	25		(4)		16		7.30	%	10.50	%

Other Key Business Drivers and Management Strategies

The following discussion of other key business driver and management strategies includes current developments of previously disclosed matters and new issues arising during the period that may impact future financial statements. This section should be read in conjunction with ITEM 1. Business and ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations — Other Key Business Drivers and Management Strategies in the Registrants' combined 2021 Form 10-K and Note 12 — 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 in the process of 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 analyzing 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.

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 March 31, 2022, the Registrants’ critical accounting policies and estimates had not changed significantly from December 31, 2021 except for critical accounting policies and estimates that relate to Generation, which are no longer applicable to the Registrants. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates in the Registrants' 2021 Form 10-K for further information.

Results of Operations by Registrant

Results of Operations — ComEd


	Three Months Ended March 31,					Favorable (Unfavorable) Variance
		2022			2021
Operating revenues			$	1,734		$	1,535	$	199
Operating expenses
Purchased power			638			527		(111)
Operating and maintenance			351			316		(35)
Depreciation and amortization			321			292		(29)
Taxes other than income taxes			96			75		(21)
Total operating expenses			1,406			1,210		(196)

Operating income			328			325		3
Other income and (deductions)
Interest expense, net			(100)			(96)		(4)
Other, net			12			7		5
Total other income and (deductions)			(88)			(89)		1
Income before income taxes			240			236		4
Income taxes			52			39		(13)
Net income			$	188		$	197	$	(9)

Three Months Ended March 31, 2022 Compared to Three Months Ended March 31, 2021. Net income decreased by $9 million as compared to the same period in 2021, primarily due to the voluntary customer refund related to the ICC investigation of matters identified in the Deferred Prosecution Agreement, partially offset by increases in electric distribution formula rate earnings (reflecting the impacts of higher rate base and higher allowed electric distribution ROE due to an increase in treasury rates). See Note 12 - Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information related to the Deferred Prosecution Agreement.

The changes in Operating revenues consisted of the following:


	Three Months Ended March 31, 2022
	Increase
Distribution	$	45
Transmission	21
Energy efficiency	7
Other	3




	76
Regulatory required programs	123
Total increase	$	199

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.

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 months ended March 31, 2022 as compared to the

ComEd

same period in 2021, due to the impact of higher rate base, higher allowed ROE due to an increase in treasury rates, 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 months ended March 31, 2022 as compared to the same periods 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 months ended March 31, 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 remained relatively the same for the three months ended March 31, 2022 as compared to the same period in 2021.

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, Energy Transition Assistance Charge ("ETAC"), and costs related to electricity, ZEC and REC procurement. 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, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power expense related to the electricity, ZECs, and RECs.

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

The increase of $111 million for the three months ended March 31, 2022 compared to the same period in 2021, in Purchased power expense is offset in Operating revenues as part of regulatory required programs.

ComEd

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


	Three Months Ended March 31, 2022
	Increase (Decrease)

Storm-related costs	$	1
Pension and non-pension postretirement benefits expense	(7)
Labor, other benefits, contracting and materials	2

BSC costs	14

Other(a)	21
	31
Regulatory required programs(b)	4
Total increase	$	35

(a)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 12 - 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 March 31, 2022
	Increase
Depreciation and amortization(a)	$	15
Regulatory asset amortization(b)	14

Total increase	$	29

(a)Reflects ongoing capital expenditures.

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

Taxes other than income taxes increased by $21 million for the three months ended March 31, 2022 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 21.7% and 16.5% for the three months ended March 31, 2022 and 2021, respectively. See Note 7 — 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 March 31,					Favorable (Unfavorable) Variance
		2022			2021
Operating revenues			$	1,047		$	889	$	158
Operating expenses
Purchased power and fuel			407			316		(91)
Operating and maintenance			247			234		(13)
Depreciation and amortization			92			86		(6)
Taxes other than income taxes			47			43		(4)
Total operating expenses			793			679		(114)

Operating income			254			210		44
Other income and (deductions)
Interest expense, net			(41)			(38)		(3)
Other, net			7			5		2
Total other income and (deductions)			(34)			(33)		(1)
Income before income taxes			220			177		43
Income taxes			14			10		(4)


Net income			$	206		$	167	$	39

Three Months Ended March 31, 2022 Compared to Three Months Ended March 31, 2021. Net income increased by $39 million, primarily due to increases in electric and gas distribution rates, and volume.

The changes in Operating revenues consisted of the following:


	Three Months Ended March 31, 2022
	(Decrease) Increase
		Electric		Gas		Total
Weather		$	(4)	$	(5)	$	(9)
Volume		7		7		14
Pricing		33		17		50
Transmission		5		—		5
Other		5		3		8
		46		22		68
Regulatory required programs		36		54		90
Total increase		$	82	$	76	$	158

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 March 31, 2022 compared to the same period in 2021, Operating revenues related to weather decreased by the impact of unfavorable weather conditions in PECO's service territory.

Heating and cooling degree-days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree-days for a 30-year period in PECO's service territory. The changes in heating and cooling degree-days in

PECO

PECO’s service territory for the three months ended March 31, 2022 compared to the same period in 2021 and normal weather consisted of the following:


	Three Months Ended March 31,				% Change
PECO Service Territory	2022	2021	Normal	2022 vs. 2021	2022 vs. Normal




Heating Degree-Days	2,228	2,302		2,416	(3.2)	%	(7.8)	%
Cooling Degree-Days	1	5		1	(80.0)	%	—	%

Volume. Electric volume, exclusive of the effects of weather, for the three months ended March 31, 2022, compared to the same period in 2021, increased on a net basis due to an increase in overall usage for customers further increased by customer growth. Natural gas volume for the three months ended March 31, 2022 compared to the same period in 2021, increased due to retail load growth.


Electric Retail Deliveries to Customers (in GWhs)		Three Months Ended March 31,		% Change	Weather - Normal % Change(b)
	2022	2021
Residential			3,758	3,767	(0.2)	%	1.1	%
Small commercial & industrial			1,937	1,881	3.0	%	3.4	%
Large commercial & industrial			3,332	3,272	1.8	%	1.9	%
Public authorities & electric railroads			182	149	22.1	%	22.4	%
Total electric retail deliveries(a)			9,209	9,069	1.5	%	2.2	%


	As of March 31,
Number of Electric Customers	2022	2021
Residential	1,521,255	1,512,255
Small commercial & industrial	155,485	154,637
Large commercial & industrial	3,102	3,109
Public authorities & electric railroads	10,342	10,237
Total	1,690,184	1,680,238

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

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


Natural Gas Deliveries to Customers (in mmcf)		Three Months Ended March 31,		% Change	Weather - Normal % Change(b)
	2022	2021
Residential			20,837	20,674	0.8	%	4.3	%
Small commercial & industrial			10,546	10,170	3.7	%	5.8	%
Large commercial & industrial			10	7	42.9	%	10.2	%
Transportation			7,639	7,650	(0.1)	%	0.7	%
Total natural gas retail deliveries(a)			39,032	38,501	1.4	%	4.0	%


	As of March 31,
Number of Natural Gas Customers	2022	2021
Residential	499,188	493,857
Small commercial & industrial	44,959	44,604
Large commercial & industrial	5	5
Transportation	664	685
Total	544,816	539,151

(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.

PECO

Pricing for the three months ended March 31, 2022 compared to the same period in 2021 increased primarily due to an increase 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 revenues for the three months ended March 31, 2022 compared to the same period in 2021, remained relatively consistent.

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 $91 million for the three months ended March 31, 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.

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


	Three Months Ended March 31, 2022
	Increase (Decrease)
BSC costs	$	10
Credit loss expense	3
Storm-related costs	2
Labor, other benefits, contracting and materials	(2)
Pension and non-pension post retirement benefit expense	(1)
Other	(2)
	10
Regulatory required programs	3









Total increase	$	13

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


	Three Months Ended March 31, 2022
	Increase
Depreciation and amortization(a)	$	6
Regulatory asset amortization	—

Total increase	$	6

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

PECO

Interest expense, net increased $3 million for the three months ended March 31, 2022 compared to the same period in 2021, primarily due to the issuance of debt in 2021.

Effective income tax rates were 6.4% and 5.6% for the three months ended March 31, 2022 and 2021 respectively. See Note 7 — 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 March 31,					Favorable (Unfavorable) Variance
		2022			2021
Operating revenues			$	1,154		$	974	$	180
Operating expenses
Purchased power and fuel			454			331		(123)
Operating and maintenance			218			197		(21)
Depreciation and amortization			171			152		(19)
Taxes other than income taxes			76			72		(4)
Total operating expenses			919			752		(167)

Operating income			235			222		13
Other income and (deductions)
Interest expense, net			(35)			(34)		(1)
Other, net			7			8		(1)
Total other income and (deductions)			(28)			(26)		(2)
Income before income taxes			207			196		11
Income taxes			9			(13)		(22)
Net income			$	198		$	209	$	(11)

Three Months Ended March 31, 2022 Compared to Three Months Ended March 31, 2021. Net income decreased $11 million primarily due to an increase in depreciation expense and credit loss expense, partially offset by favorable impacts of the multi-year plans. 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 March 31, 2022
	Increase
		Electric		Gas		Total
Distribution		$	14	$	10	$	24
Transmission		5		—		5
Other		8		2		10
		27		12		39
Regulatory required programs		78		63		141
Total increase		$	105	$	75	$	180

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.


	As of March 31,
Number of Electric Customers	2022	2021
Residential	1,199,272	1,192,470
Small commercial & industrial	115,363	114,819
Large commercial & industrial	12,674	12,505
Public authorities & electric railroads	268	266
Total	1,327,577	1,320,060

BGE


	As of March 31,
Number of Natural Gas Customers	2022	2021
Residential	653,397	648,824
Small commercial & industrial	38,356	38,318
Large commercial & industrial	6,193	6,120
Total	697,946	693,262

Distribution Revenue increased for the three months ended March 31, 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 March 31, 2022, compared to the same period in 2021, primarily due to the increases in underlying costs and 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 months ended March 31, 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 $123 million for the three months ended March 31, 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 March 31, 2022
	Increase (Decrease)
Labor, other benefits, contracting, and materials	$	4

Pension and non-pension postretirement benefits expense	(3)
BSC costs	8
Credit loss expense	14
Other	(3)
	20
Regulatory required programs	1

Total increase	$	21

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


	Three Months Ended March 31, 2022
	Increase
Depreciation and amortization(a)	$	9
Regulatory required programs	7
Regulatory asset amortization	3

Total increase	$	19

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

Effective income tax rates were 4.3% and (6.6)% for the three months ended March 31, 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 7 — 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 months ended March 31, 2022 compared to the same period in 2021. See the Results of Operations for Pepco, DPL, and ACE for additional information.


	Three Months Ended March 31,					Favorable (Unfavorable) Variance
		2022			2021
PHI			$	130		$	128	$	2
Pepco			46			59		(13)
DPL			56			56		—
ACE			26			14		12
Other(a)			2			(1)		3

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

Three Months Ended March 31, 2022 Compared to Three Months Ended March 31, 2021. Net Income increased by $2 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 storm costs and depreciation expense.

Pepco

Results of Operations — Pepco


	Three Months Ended March 31,			Favorable (Unfavorable) Variance
	2022	2021
Operating revenues		$	614	$	553	$	61


Operating expenses
Purchased power		213		166		(47)
Operating and maintenance		131		108		(23)
Depreciation and amortization		108		102		(6)
Taxes other than income taxes		95		90		(5)
Total operating expenses		547		466		(81)

Operating income		67		87		(20)
Other income and (deductions)
Interest expense, net		(36)		(34)		(2)
Other, net		13		12		1
Total other income and (deductions)		(23)		(22)		(1)
Income before income taxes		44		65		(21)
Income taxes		(2)		6		8
Net income		$	46	$	59	$	(13)

Three Months Ended March 31, 2022 Compared to Three Months Ended March 31, 2021. Net income decreased $13 million primarily due to an increase in storm costs, depreciation expense, and credit loss expense, 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 March 31, 2022
	Increase (Decrease)
Distribution	$	6
Transmission	3
Other	(3)
	6
Regulatory required programs	55
Total increase	$	61

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.


	As of March 31,
Number of Electric Customers	2022	2021
Residential	846,258	835,415
Small commercial & industrial	54,509	53,738
Large commercial & industrial	22,620	22,492
Public authorities & electric railroads	184	174
Total	923,571	911,819

Distribution Revenue increased for the three months ended March 31, 2022 compared to the same period in 2021 primarily due to favorable impacts of the Maryland and District of Columbia multi-year plans.

Pepco

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 March 31, 2022, compared to the same period in 2021, 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, 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 $47 million for the three months ended March 31, 2022 compared to the same period in 2021, 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 March 31, 2022
	Increase
Storm-related costs	$	6
BSC and PHISCO Costs	6
Credit loss expense	4
Labor, other benefits, contracting and materials	4



Other	3
	23

Regulatory required programs	—
Total increase	$	23

Pepco

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


	Three Months Ended March 31, 2022
	Increase (Decrease)
Depreciation and amortization(a)	$	5
Regulatory asset amortization	(4)
Regulatory required programs	5
Total increase	$	6

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

Effective income tax rates were (4.5)% and 9.2% for the three months ended March 31, 2022 and 2021, respectively. The 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. 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 7 — 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 March 31,			Favorable (Unfavorable) Variance
	2022	2021
Operating revenues		$	431	$	382	$	49
Operating expenses
Purchased power and fuel		189		156		(33)
Operating and maintenance		93		83		(10)
Depreciation and amortization		57		53		(4)
Taxes other than income taxes		18		17		(1)
Total operating expenses		357		309		(48)

Operating income		74		73		1
Other income and (deductions)
Interest expense, net		(16)		(15)		(1)
Other, net		2		3		(1)
Total other income and (deductions)		(14)		(12)		(2)
Income before income taxes		60		61		(1)
Income taxes		4		5		1
Net income		$	56	$	56	$	—

Three Months Ended March 31, 2022 Compared to Three Months Ended March 31, 2021. Net income remained consistent.

The changes in Operating revenues consisted of the following:


	Three Months Ended March 31, 2022
	Increase
		Electric		Gas		Total

Volume		$	5	$	1	$	6
Distribution		6		2		8
Transmission		2		—		2

		13		3		16
Regulatory required programs		25		8		33
Total increase		$	38	$	11	$	49

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 demand. During the three months ended March 31, 2022 compared to the same period in 2021, Operating revenues related to weather remained consistent.

DPL

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 months ended March 31, 2022 compared to same period in 2021 and normal weather consisted of the following:


	Three Months Ended March 31,			% Change
Delaware Electric Service Territory	2022	2021	Normal	2022 vs. 2021		2022 vs. Normal





Heating Degree-Days	2,355	2,358	2,480	(0.1)	%	(5.0)	%
Cooling Degree-Days	3	3	—	—	%	—	%


	Three Months Ended March 31,			% Change
Delaware Natural Gas Service Territory	2022	2021	Normal	2022 vs. 2021		2022 vs. Normal




Heating Degree-Days	2,355	2,358	2,500	(0.1)	%	(5.8)	%

Volume, exclusive of the effects of weather, increased for the three months ended March 31, 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 March 31,			% Change	Weather - Normal % Change(b)
	2022		2021
Residential				895	854	4.8	%	4.2	%
Small commercial & industrial				370	342	8.2	%	7.7	%
Large commercial & industrial				765	689	11.0	%	11.0	%
Public authorities & electric railroads				9	9	—	%	5.3	%
Total electric retail deliveries(a)				2,039	1,894	7.7	%	7.3	%


	As of March 31,
Number of Total Electric Customers (Maryland and Delaware)	2022	2021
Residential	478,009	473,917
Small commercial & industrial	63,296	62,647
Large commercial & industrial	1,221	1,208
Public authorities & electric railroads	603	608
Total	543,129	538,380

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

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


Natural Gas Retail Deliveries to Delaware Customers (in mmcf)		Three Months Ended March 31,			% Change	Weather - Normal % Change(b)
	2022		2021
Residential				4,453	4,394	1.3	%	0.3	%
Small commercial & industrial				1,983	1,868	6.2	%	6.0	%
Large commercial & industrial				457	457	—	%	0.1	%
Transportation				2,207	2,224	(0.8)	%	(0.7)	%
Total natural gas deliveries(a)				9,100	8,943	1.8	%	1.3	%

DPL


	As of March 31,
Number of Delaware Natural Gas Customers	2022	2021
Residential	128,695	127,522
Small commercial & industrial	10,097	10,043
Large commercial & industrial	17	19
Transportation	159	160
Total	138,968	137,744

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

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

Distribution Revenue increased for the three months ended March 31, 2022 compared to the same period in 2021 primarily due to higher electric distribution rates in Maryland that became effective in March 2022, higher Distribution System Improvement Charge (DSIC) rates in Delaware that became effective in January 2022, and higher approved electric distribution rates in Delaware that became effective in September 2021.

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 March 31, 2022, compared to the same period in 2021, 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.

The increase of $33 million for the three months ended March 31, 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.

DPL

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


	Three Months Ended March 31, 2022
	Increase
BSC and PHISCO costs	$	3
Storm-related costs	3
Credit loss expense	2

Labor, other benefits, contracting and materials	(2)
Other	3
	9
Regulatory required programs	1
Total increase	$	10

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


	Three Months Ended March 31, 2022
	Increase
Depreciation and amortization(a)	$	3
Regulatory asset amortization	—
Regulatory required programs	1
Total increase	$	4

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

Effective income tax rates were 6.7% and 8.2% for the three months ended March 31, 2022 and 2021, respectively. See Note 7 — 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 March 31,					Favorable (Unfavorable) Variance
		2022			2021
Operating revenues			$	349		$	310	$	39


Operating expenses
Purchased power			178			157		(21)
Operating and maintenance			84			76		(8)
Depreciation and amortization			47			47		—
Taxes other than income taxes			2			2		—
Total operating expenses			311			282		(29)

Operating income			38			28		10
Other income and (deductions)
Interest expense, net			(14)			(15)		1
Other, net			3			1		2
Total other income and (deductions)			(11)			(14)		3
Income before income taxes			27			14		13
Income taxes			1			—		(1)
Net income			$	26		$	14	$	12

Three Months Ended March 31, 2022 Compared to Three Months Ended March 31, 2021. Net income increased $12 million primarily due to increases in distribution rates.

The changes in Operating revenues consisted of the following:


	Three Months Ended March 31, 2022
	Increase
Weather	$	1
Volume	2
Distribution	11
Transmission	5

	19




Regulatory required programs	20
Total increase	$	39

Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in New Jersey are not impacted by abnormal weather or usage per customer as a result of the Conservation Incentive Program (CIP) which became effective, prospectively, in the third quarter of 2021. The CIP compares current distribution revenues by customer class to approved target revenues established in ACE’s most recent distribution base rate case. The CIP is calculated annually, and recovery is subject to certain conditions, including an earnings test and ceilings on customer rate increases. While Operating revenues are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers. See Note 3 — Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for additional information.

Weather. Prior to the third quarter of 2021, the demand for electricity was affected by weather conditions. With respect to the electric business, very warm weather in summer months and very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity. Conversely, mild weather reduces demand. During the three months ended March 31, 2022 compared to the same period in 2021, Operating revenues related to weather increased due to the absence of impacts in the first quarter of 2022 as a result of the CIP.

ACE

Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 20-year period in ACE’s service territory. The changes in heating and cooling degree days in ACE’s service territory for the three months ended March 31, 2022 compared to same period in 2021 and normal weather consisted of the following:


	Three Months Ended March 31,		Normal		% Change
Heating and Cooling Degree-Days	2022	2021		2022 vs. 2021			2022 vs. Normal





Heating Degree-Days	2,436	2,348	2,454		3.7	%		(0.7)	%
Cooling Degree-Days	2	4	1		(50.0)	%		100.0	%

Volume, exclusive of the effects of weather, increased for the three months ended March 31, 2022 compared to the same period in 2021, due to the absence of impacts in the first quarter of 2022 as a result of the CIP.


Electric Retail Deliveries to Customers (in GWhs)		Three Months Ended March 31,			% Change	Weather - Normal % Change(b)
	2022		2021
Residential				918	928	(1.1)	%	(2.3)	%
Small commercial & industrial				339	305	11.1	%	9.7	%
Large commercial & industrial				703	716	(1.8)	%	(2.4)	%
Public authorities & electric railroads				14	13	7.7	%	6.2	%
Total electric retail deliveries(a)				1,974	1,962	0.6	%	(0.4)	%


	As of March 31,
Number of Electric Customers	2022	2021
Residential	500,511	498,396
Small commercial & industrial	62,124	61,771
Large commercial & industrial	3,124	3,267
Public authorities & electric railroads	724	704
Total	566,483	564,138

(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 months ended March 31, 2022 compared to the same period in 2021 due to higher distribution rates that become effective in January 2022.

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

Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, Societal Benefits Charge, Transition Bonds, and BGS procurement and administrative costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Purchased power expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries, as ACE remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, ACE 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

ACE

electricity, ZEC, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power expense related to the electricity, ZECs, and RECs.

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

The increase of $21 million for the three months ended March 31, 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 March 31, 2022
	Increase
BSC and PHISCO costs	$	2
Labor, other benefits, contracting and materials	1

Storm-related costs	1


	4

Regulatory required programs(a)	4
Total increase	$	8

_________

(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 March 31, 2022
	Increase (Decrease)
Depreciation and amortization(a)	$	3
Regulatory asset amortization	1
Regulatory required programs	(4)
Total	$	—

_________

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

Effective income tax rates were 3.7% and 0.0% for the three months ended March 31, 2022 and 2021, respectively. See Note 7 — Income Taxes of the Combined Notes to 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 10 — 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 three months ended March 31, 2022 includes one month of cash flows from Generation. The Exelon Consolidated Statement of Cash Flows for the three months ended March 31, 2021 includes three 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 Exelon 2021 Form 10-K and Note 12 — 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 three months ended March 31, 2022 and 2021 by Registrant:


Increase (decrease) in cash flows from operating activities	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Net income (loss)	$	862	$	(9)	$	39	$	(11)	$	2	$	(13)	$	—	$	12
Adjustments to reconcile net income to cash:
Non-cash operating activities	69		20		17		70		66		37		17		11
Option premiums (paid), net	(55)		—		—		—		—		—		—		—
Collateral received, net	869		38		—		—		—		—		—		—
Income taxes	(36)		21		(3)		13		2		(1)		(4)		(1)
Pension and non-pension postretirement benefit contributions	(37)		(5)		4		9		(31)		—		(1)		(4)
Changes in working capital and other noncurrent assets and liabilities	1,371		53		(41)		67		(16)		—		31		(28)
Increase (decrease) in cash flows from operating activities	$	3,043	$	118	$	16	$	148	$	23	$	23	$	43	$	(10)

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 three months ended March 31, 2022 and 2021 were as follows:

See Note 14 — 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.
See Note 7 — Income Taxes of the Combined Notes to Consolidated Financial Statements and the Registrants' Consolidated Statements of Cash Flows for additional information on income taxes.
Changes in working capital and other noncurrent assets and liabilities for the Utility Registrants and Exelon Corporate total $88 million and for Generation total $1,283 million. The change for Generation primarily relates to the revolving accounts receivable financing arrangement. See Note 6 — Accounts Receivable of the Exelon 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 three months ended March 31, 2022 and 2021 by Registrant:


(Decrease) increase in cash flows from investing activities	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Capital expenditures	$	218	$	(4)	$	(49)	$	33	$	47	$	2	$	9	$	36

Investment in NDT fund sales, net	3		—		—		—		—		—		—		—
Collection of DPP	(1,405)		—		—		—		—		—		—		—
Proceeds from sales of assets and businesses	(664)		—		—		—		—		—		—		—
Changes in intercompany money pool	—		—		48		—		—		—		—		—

Other investing activities	(66)		—		1		1		1		—		1		—
(Decrease) increase in cash flows from investing activities	$	(1,914)	$	(4)	$	—	$	34	$	48	$	2	$	10	$	36

Significant investing cash flow impacts for the Registrants for three months ended March 31, 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 Exelon 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 in 2021. See Note 2 — Mergers, Acquisitions, and Dispositions of the Exelon 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 three months ended March 31, 2022 and 2021 by Registrant:


Increase (decrease) in cash flows from financing activities	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Changes in short-term borrowings, net	$	(997)	$	188	$	—	$	(36)	$	(100)	$	(140)	$	(3)	$	43
Long-term debt, net	2,669		50		(375)		—		119		250		—		(131)
Changes in intercompany money pool	—		—		105		—		36		—		—		—

Dividends paid on common stock	42		(17)		(15)		(2)		—		(14)		(1)		(5)
Distributions to member	—		—		—		—		(21)		—		—		—
Contributions from(to) parent/member	—		(31)		227		—		144		249		24		(130)
Transfer of cash, restricted cash, and cash equivalents to Constellation	(2,594)		—		—		—		—		—		—		—
Other financing activities	(38)		(1)		3		(1)		(4)		(4)		—		—
Increase (decrease) in cash flows from financing activities	$	(918)	$	189	$	(55)	$	(39)	$	174	$	341	$	20	$	(223)

Significant financing cash flow impacts for the Registrants for the three months ended March 31, 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. Refer to Note 10 — 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. Refer to Note 10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on debt issuances. Refer to the debt redemptions table below for additional information.
Changes in intercompany money pool** are driven by short-term borrowing needs. Refer below for more information regarding the intercompany money pool.
Exelon’s ability to pay dividends on its common stock depends on the receipt of dividends paid by its operating subsidiaries. The payments of dividends to Exelon by its subsidiaries in turn depend on their results of operations and cash flows and other items affecting retained earnings. See Note 19 — Commitments and Contingencies of the Exelon 2021 Form 10-K for additional information on dividend restrictions. See below for quarterly dividends declared.
Refer to Note 2 - Discontinued Operations for the transfer of cash, restricted cash, and cash equivalents to Constellation related to the separation.
For the three months ended March 31, 2022, other financing activities primarily consists of debt issuance costs. See Note 10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants’ debt issuances.

Debt

See Note 10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt issuances.

During the three months ended March 31, 2022, there were no long-term debt retirements or redemptions. However, as of May 9, 2022, the following long-term debt was retired and/or redeemed:


Company	Type	Interest Rate		Maturity	Amount
Pepco	First Mortgage Bonds	3.05	%	April 1, 2022	$	200
Exelon	Junior Subordinated Notes	3.50	%	May 2, 2022	1,150

Dividends

Quarterly dividends declared by the Exelon Board of Directors during the three months ended March 31, 2022 and for the second 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

(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 $3.7 billion was available to support additional commercial paper as of March 31, 2022, and of which no financial institution has more than 7% of the aggregate commitments for the Registrants. The Registrants had access to the commercial paper markets and had availability under their revolving credit facilities during the three months ended March 31, 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 10 — 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 Exelon 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.

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 March 31, 2022 and available credit facility capacity prior to any incremental collateral at March 31, 2022:


	PJM Credit Policy Collateral		Other Incremental Collateral Required(a)		Available Credit Facility Capacity Prior to Any Incremental Collateral
ComEd	$	40	$	—	$	998
PECO	2		39		600
BGE	2		62		350

Pepco	2		—		300
DPL	2		16		300
ACE	1		—		300

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

Capital Expenditure Spending

As of March 31, 2022, the most recent estimates of capital expenditures for plant additions and improvements for 2022 are as follows:


(In millions)	Transmission	Distribution	Gas	Total(a)
Exelon	N/A	N/A	N/A	$	6,900
ComEd	475	2,000	N/A	2,475
PECO	200	800	325	1,325
BGE	250	500	475	1,225
PHI	575	1,200	75	1,850
Pepco	275	675	N/A	950
DPL	125	250	75	450
ACE	175	275	N/A	450

(a)Numbers rounded to the nearest $25M and may not sum due to rounding.

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 meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the Exelon intercompany money pool. Pepco, DPL, and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the PHI intercompany money pool. PHI Corporate meets its short-term liquidity requirements primarily through the issuance of short-term notes and the Exelon intercompany money pool. The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit.

See Note 10 — 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 9 — 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 three months ended March 31, 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 March 31, 2022, are presented in the following table. Pepco, ACE, and DPL had no activity within the PHI intercompany money pool during the three months ended March 31, 2022.


	During the Three Months Ended March 31, 2022				As of March 31, 2022
Exelon Intercompany Money Pool	Maximum Contributed		Maximum Borrowed		Contributed (Borrowed)
Exelon Corporate	$	396	$	—	$	312
PECO	—		(95)		(65)
BSC	—		(377)		(246)
PHI Corporate	—		(54)		(46)
PCI	50		—		45

Shelf Registration Statements

Exelon and the Utility Registrants have a currently effective combined shelf registration statement unlimited in amount, filed with the SEC, that will expire in August 2022. The ability of each Registrant to sell securities off the

shelf registration statement or to access the private placement markets will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, as applicable, the current financial condition of the Registrant, its securities ratings and market conditions.

Regulatory Authorizations

The Utility Registrants are required to obtain short-term and long-term financing authority from Federal and State Commissions as follows:


	As of March 31, 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	1,900
BGE	FERC	December 31, 2023		700			MDPSC		N/A	500
Pepco	FERC	December 31, 2023		500			MDPSC / DCPSC		December 31, 2022	225
DPL	FERC	December 31, 2023		500			MDPSC / DEPSC		December 31, 2022	47
ACE(c)	NJBPU	December 31, 2023		350			NJBPU		December 31, 2022	—

(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)ACE is currently in the process of renewing its long-term financing authority with the NJBPU and expects approval by August 1, 2022.

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