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 transmission and distribution 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, 2023 compared to the same period in 2022. For additional information regarding the financial results for the three months ended March 31, 2023 and 2022 see the discussions of Results of Operations by Registrant.


	Three Months Ended March 31,					Favorable (Unfavorable) Variance
		2023			2022
Exelon			$	669		$	481	$	188
ComEd			241			188		53
PECO			166			206		(40)
BGE			200			198		2
PHI			155			130		25
Pepco			65			46		19
DPL			60			56		4
ACE			33			26		7
Other(a)			(93)			(241)		148

(a)Other primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities, and other financing and investment 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 the three months ended March 31, 2022 presented in the table above. See Note 1 — Significant Accounting Policies and Note 2 — Discontinued Operations for additional information.

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 and were $28 million on a pre-tax basis, for the three months ended March 31, 2022.

Three Months Ended March 31, 2023 Compared to Three Months Ended March 31, 2022. Net income attributable to common shareholders from continuing operations increased by $188 million and diluted earnings per average common share from continuing operations increased to $0.67 in 2023 from $0.49 in 2022 primarily due to:

Higher electric distribution formula rate earnings from higher allowed ROE due to an increase in U.S. treasury rates and impacts of higher rate base at ComEd;
The favorable impacts of rate increases at PECO, BGE, and PHI;
Lower BSC costs presented in Exelon’s continuing operations, which were previously allocated to Generation but did not qualify as discontinued operation expenses per the accounting rules; and
Carrying costs related to the CMC regulatory assets at ComEd.

The increases were partially offset by:

Unfavorable weather at PECO and PHI;
Higher interest expense at BGE and Exelon Corporate;
An increase in environmental liabilities at Pepco;
Higher depreciation expense at PECO; and
Higher credit loss expense at PECO.

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 months ended March 31, 2023 compared to the same period in 2022:


	Three Months Ended March 31,
	2023				2022
(In millions, except per share data)			Earnings per Diluted Share				Earnings per Diluted Share
Net Income Attributable to Common Shareholders from Continuing Operations	$	669	$	0.67	$	481	$	0.49
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $0)	(1)		—		—		—
Change in Environmental Liabilities (net of taxes of $7)	18		0.02		—		—
ERP System Implementation Costs (net of taxes of $0)(a)	—		—		1		—



Change in FERC Audit Liability (net of taxes of $4)	11		0.01		—		—

Separation Costs (net of taxes of $0 and $7, respectively)(b)	(1)		—		17		0.02
Income Tax-Related Adjustments (entire amount represents tax expense)(c)	—		—		134		0.14
Adjusted (non-GAAP) Operating Earnings	$	696	$	0.70	$	634	$	0.64

Note:

Amounts may not sum due to rounding.

Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net Income and Adjusted (non-GAAP) Operating Earnings is based on the marginal statutory federal and state income tax rates for each Registrant, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part. The marginal statutory income tax rates for 2023 and 2022 ranged from 24.0% to 29.0%.

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

(b)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.

(c)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 2023 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 met 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 $(1) million and $24 million on a pre-tax basis for the three months ended March 31, 2023 and 2022, respectively, which are recorded in Operating and maintenance expense. Total separation costs impacting continuing operations for the remainder of 2023 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 2023. 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 15, 2022	Electric	$	199	$	199		7.85	%	November 17, 2022	January 1, 2023

PECO - Pennsylvania	March 31, 2022	Natural Gas	82		55			N/A		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 - Maryland	October 26, 2020 (amended March 31, 2021)	Electric	104		52			9.55	%	June 28, 2021	June 28, 2021
DPL - Maryland	May 19, 2022	Electric	38		29			9.60	%	December 14, 2022	January 1, 2023

Pending Distribution Base Rate Case Proceedings


Registrant/Jurisdiction		Filing Date			Service	Requested Revenue Requirement Increase		Requested ROE		Expected Approval Timing
ComEd - Illinois		January 17, 2023			Electric	$	1,472	10.50% to 10.65%		Fourth quarter of 2023
ComEd - Illinois		April 21, 2023			Electric	247		8.91	%	Fourth quarter of 2023
BGE - Maryland		February 17, 2023			Electric	313		10.40	%	Fourth quarter of 2023
Natural Gas	289		10.40	%
Pepco - District of Columbia		April 13, 2023			Electric	191		10.50	%	First quarter of 2024
DPL - Delaware		December 15, 2022 (amended February 28, 2023)			Electric	48		10.50	%	Second quarter of 2024
ACE - New Jersey		February 15, 2023			Electric	105		10.50	%	First quarter of 2024

Transmission Formula Rates

For 2023, the following increases/(decreases) were included in BGE's annual 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		Total Revenue Requirement Increase		Allowed Return on Rate Base		Allowed ROE


BGE	$	19	$	(12)	$	4	7.34	%	10.50	%

ComEd's FERC Audit

The Utility Registrants are subject to periodic audits and investigations by FERC. FERC’s Division of Audits and Accounting initiated a nonpublic audit of ComEd in May 2021 evaluating ComEd’s compliance with (1) approved terms, rates and conditions of its federally regulated service; (2) accounting requirements of the Uniform System of Accounts; (3) reporting requirements of the FERC Form 1; and (4) the requirements for record retention. The audit covered the period from January 1, 2017 through August 31, 2022. On January 17 and February 21, 2023, ComEd was provided with information on a series of potential findings, including concerning ComEd's methodology regarding the allocation of certain overhead costs to capital under FERC regulations. As of March 31, 2023, ComEd has continued discussions with FERC staff and determined that a loss is probable and has recorded a liability that reflects management's best estimate. The final outcome and resolution of the findings or of the audit itself cannot be predicted and the results, while not reasonably estimable at this time, could be material to the Exelon and ComEd financial statements. See Note 3 — Regulatory Matters 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 2022 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 2022 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

City of Chicago Franchise Agreement

The current ComEd Franchise Agreement with the City of Chicago (the City) has been in force since 1992. The Franchise Agreement grants rights to use the public right of way to install, maintain, and operate the wires, poles, and other infrastructure required to deliver electricity to residents and businesses across the City. The Franchise Agreement became terminable on one year notice as of December 31, 2020. It now continues in effect indefinitely unless and until either party issues a notice of termination, effective one year later, or it is replaced by mutual agreement with a new franchise agreement between ComEd and the City. If either party terminates and no new agreement is reached between the parties, the parties could continue with ComEd providing electric services within the City with no franchise agreement in place. The City also has an option to terminate and purchase the ComEd system (“municipalize”), which also requires one year notice. Neither party has issued a notice of termination at this time, the City has not exercised its municipalization option, and no new agreement has become effective. Accordingly, the 1992 Franchise Agreement remains in effect at this time. In April 2021, the City invited interested parties to respond to a Request for Information (RFI) regarding the franchise for electricity delivery. Final responses to the RFI were due on July 30, 2021, however, on July 29, 2021, the City chose to extend the final submission deadline to September 30, 2021. ComEd submitted its response to the RFI by the due date. However, the City did not proceed to issue an RFP. Since that time, ComEd and the City continued to negotiate and have arrived at a proposed Chicago Franchise Agreement (CFA) and an Energy and Equity Agreement (EEA). These agreements together are intended to grant ComEd the right to continue providing electric utility services using public ways within the City of Chicago, and to create a new non-profit entity to advance energy and energy-related equity projects. On February 1, 2023, the proposed CFA and EEA were introduced to the City Council. The proposed CFA and EEA remain subject to approval by the City Council and the Exelon Board.

While Exelon and ComEd cannot predict the ultimate outcome of these processes, fundamental changes in the agreements or other adverse actions affecting ComEd’s business in the City would require changes in their business planning models and operations and could have a material adverse impact on Exelon’s and ComEd’s consolidated financial statements. If the City were to disconnect from the ComEd system, ComEd would seek full compensation for the business and its associated property taken by the City, as well as for all damages resulting to ComEd and its system. ComEd would also seek appropriate compensation for stranded costs with FERC.

Infrastructure Investment and Jobs Act

On November 15, 2021, President Biden signed the $1.2 trillion 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.

In September 2022, ComEd and BGE applied for the 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. The grant process is expected to be highly competitive, and therefore, ComEd and

BGE cannot predict how many of their total applications will be approved as filed or the precise timing of receiving any funds if they are awarded a grant.

In March 2023, Exelon, ComEd and PHI submitted three applications related to the Smart Grid Grants program under section 40107 of IIJA. These applications are focused on replacing existing Advanced Distribution Management Systems (ADMS) in support of distributed energy resources (DERs) and grid-edged technologies, strengthening interoperability and data architecture of systems in support of two-way power flows and accelerating advanced metering deployment in disadvantaged communities. In April 2023, ComEd, PECO BGE and PHI submitted seven applications related to the Grid Resilience Grants program under section 40101(c) of IIJA. These applications are broadly focused on improving grid resilience with an emphasis on disadvantaged communities, relief of capacity constraints and modernizing infrastructure, deployment of DER and microgrid technologies and providing improved resilience through storm hardening projects. Through its applications under section 40107 and 40101(c) of IIJA, the Registrants are requesting nearly $700 million in proposed federal funding. The grant process is expected to be highly competitive, and therefore, the Registrants cannot predict how many of their total applications will be approved as filed, or the precise timing of receiving any funds if they are awarded a grant.

The Registrants are supporting three different Regional Clean Hydrogen Hub opportunities, covering all five states that Exelon operates in plus Washington D.C. under a program that will create networks of hydrogen producers, consumers, and local connective infrastructure to accelerate the use of hydrogen as a clean energy carrier that can deliver or store energy. Applications for the three opportunities under this program were submitted in April 2023. The selection process is expected to be highly competitive, and therefore, the Registrants cannot predict how many of their total applications will be approved as filed or the precise 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. As of March 31, 2023, the Registrants’ critical accounting policies and estimates had not changed significantly from December 31, 2022. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates in the 2022 Form 10-K for further information.

Results of Operations by Registrant

Results of Operations — ComEd


	Three Months Ended March 31,					(Unfavorable) Favorable Variance
		2023			2022
Operating revenues			$	1,667		$	1,734	$	(67)
Operating expenses
Purchased power			488			638		150
Operating and maintenance			337			351		14
Depreciation and amortization			338			321		(17)
Taxes other than income taxes			93			96		3
Total operating expenses			1,256			1,406		150

Operating income			411			328		83
Other income and (deductions)
Interest expense, net			(117)			(100)		(17)
Other, net			18			12		6
Total other income and (deductions)			(99)			(88)		(11)
Income before income taxes			312			240		72
Income taxes			71			52		(19)
Net income			$	241		$	188	$	53

Three Months Ended March 31, 2023 Compared to Three Months Ended March 31, 2022. Net income increased by $53 million as compared to the same period in 2022, primarily due to increases in electric distribution formula rate earnings (reflecting higher allowed ROE due to an increase in U.S. Treasury rates and the impacts of higher rate base) and carrying costs related to the CMC regulatory assets.

The changes in Operating revenues consisted of the following:


	Three Months Ended March 31, 2023
	Increase (Decrease)
Distribution	$	111
Transmission	(12)
Energy efficiency	14
Other	2
	115
Regulatory required programs	(182)
Total decrease	$	(67)

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, 2023 as compared to the same period in 2022, due to higher allowed ROE due to an increase in U.S. 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

ComEd

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.

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, 2023 as compared to the same period in 2022, 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 months ended March 31, 2023 as compared to the same period in 2022, 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 $150 million for the three months ended March 31, 2023 compared to the same period in 2022, in Purchased power expense is primarily due to the CMCs from the participating nuclear-powered generating facilities including the deferral of any associated carrying costs. 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.

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


	Three Months Ended March 31, 2023
	Increase (Decrease)

Labor, other benefits, contracting and materials	$	17
Storm-related costs	1
Pension and non-pension postretirement benefits expense	(4)

BSC costs	(2)

Other(a)	(8)
	4
Regulatory required programs(b)	(18)
Total decrease	$	(14)

(a)For the three months ended March 31, 2023, the decrease is primarily due to the voluntary customer refund made in 2022 related to the ICC investigation of matters identified in the Deferred Prosecution Agreement. See Note 12 —

ComEd

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, 2023
	Increase
Depreciation and amortization(a)	$	13
Regulatory asset amortization(b)	4

Total increase	$	17

(a)Reflects ongoing capital expenditures and higher depreciation rates effective January 2023.

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

Interest expense, net increased by $17 million for the three months ended March 31, 2023, compared to the same period in 2022, primarily due to an increase in interest rates and the issuance of debt during the year.

Effective income tax rat****es were 22.8% and 21.7% for the three months ended March 31, 2023 and 2022, 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
		2023			2022
Operating revenues			$	1,112		$	1,047	$	65
Operating expenses
Purchased power and fuel			484			407		(77)
Operating and maintenance			270			247		(23)
Depreciation and amortization			98			92		(6)
Taxes other than income taxes			50			47		(3)
Total operating expenses			902			793		(109)

Operating income			210			254		(44)
Other income and (deductions)
Interest expense, net			(48)			(41)		(7)
Other, net			8			7		1
Total other income and (deductions)			(40)			(34)		(6)
Income before income taxes			170			220		(50)
Income taxes			4			14		10


Net income			$	166		$	206	$	(40)

Three Months Ended March 31, 2023 Compared to Three Months Ended March 31, 2022**.** Net income decreased by $40 million, primarily due to unfavorable weather and credit loss expense, partially offset by an increase in gas distribution rates.

The changes in Operating revenues consisted of the following:


	Three Months Ended March 31, 2023
	(Decrease) Increase
		Electric		Gas		Total
Weather		$	(25)	$	(25)	$	(50)
Volume		(7)		2		(5)
Pricing		11		23		34
Transmission		(2)		—		(2)
Other		(1)		6		5
		(24)		6		(18)
Regulatory required programs		78		5		83
Total increase		$	54	$	11	$	65

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, 2023 compared to the same period in 2022, 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, 2023 compared to the same period in 2022 and normal weather consisted of the following:


	Three Months Ended March 31,				% Change
PECO Service Territory	2023	2022	Normal	2023 vs. 2022	2023 vs. Normal





Heating Degree-Days	1,888	2,228		2,418	(15.3)	%	(21.9)	%
Cooling Degree-Days	—	1		1	(100.0)	%	(100.0)	%

Volume. Electric volume, exclusive of the effects of weather, for the three months ended March 31, 2023, compared to the same period in 2022, remained relatively consistent. Natural gas volume for the three months ended March 31, 2023 compared to the same period in 2022, remained relatively consistent.


Electric Retail Deliveries to Customers (in GWhs)		Three Months Ended March 31,		% Change	Weather - Normal % Change(b)
	2023	2022
Residential			3,358	3,758	(10.6)	%	(0.1)	%
Small commercial & industrial			1,843	1,937	(4.9)	%	0.4	%
Large commercial & industrial			3,237	3,332	(2.9)	%	(1.2)	%
Public authorities & electric railroads			168	182	(7.7)	%	9.3	%
Total electric retail deliveries(a)			8,606	9,209	(6.5)	%	(0.2)	%


	As of March 31,
Number of Electric Customers	2023	2022
Residential	1,529,779	1,521,255
Small commercial & industrial	155,846	155,485
Large commercial & industrial	3,118	3,102
Public authorities & electric railroads	10,401	10,342
Total	1,699,144	1,690,184

(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)
	2023	2022
Residential			17,190	20,837	(17.5)	%	(2.4)	%
Small commercial & industrial			8,699	10,546	(17.5)	%	(3.4)	%
Large commercial & industrial			29	10	190.0	%	21.7	%
Transportation			7,014	7,639	(8.2)	%	(5.4)	%
Total natural gas retail deliveries(a)			32,932	39,032	(15.6)	%	(3.2)	%


	As of March 31,
Number of Natural Gas Customers	2023	2022
Residential	504,181	499,188
Small commercial & industrial	45,003	44,959
Large commercial & industrial	9	5
Transportation	650	664
Total	549,843	544,816

(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, 2023 compared to the same period in 2022 increased primarily due to an increase in 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 March 31, 2023 compared to the same period in 2022 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 $77 million for the three months ended March 31, 2023 compared to the same period in 2022, 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, 2023
	Increase (Decrease)
Labor, other benefits, contracting and materials	$	14
Credit loss expense	10
BSC costs	2
Pension and non-pension postretirement benefit expense	(2)
Storm-related costs	(4)
Other	(3)
	17
Regulatory required programs	6
Total increase	$	23

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


	Three Months Ended March 31, 2023
	Increase (Decrease)
Depreciation and amortization(a)	$	7
Regulatory asset amortization	(1)

Total increase	$	6

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

PECO

Interest expense, net increased $7 million for the three months ended March 31, 2023, compared to the same period in 2022, primarily due to the issuance of debt in 2022 and increases in interest rates.

Effective income tax rates were 2.4% and 6.4% for the three months ended March 31, 2023 and 2022, 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
		2023			2022
Operating revenues			$	1,257		$	1,154	$	103
Operating expenses
Purchased power and fuel			492			454		(38)
Operating and maintenance			222			218		(4)
Depreciation and amortization			167			171		4
Taxes other than income taxes			83			76		(7)
Total operating expenses			964			919		(45)

Operating income			293			235		58
Other income and (deductions)
Interest expense, net			(44)			(35)		(9)
Other, net			3			7		(4)
Total other income and (deductions)			(41)			(28)		(13)
Income before income taxes			252			207		45
Income taxes			52			9		(43)
Net income			$	200		$	198	$	2

Three Months Ended March 31, 2023 Compared to Three Months Ended March 31, 2022. Net income increased $2 million primarily due to a favorable impacts of the multi-year plans, partially offset by an increase in interest expense. 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, 2023
	Increase
		Electric		Gas		Total
Distribution		$	26	$	23	$	49
Transmission		18		—		18
Other		—		1		1
		44		24		68
Regulatory required programs		34		1		35
Total increase		$	78	$	25	$	103

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	2023	2022
Residential	1,207,486	1,199,272
Small commercial & industrial	115,658	115,363
Large commercial & industrial	12,911	12,674
Public authorities & electric railroads	266	268
Total	1,336,321	1,327,577

BGE


	As of March 31,
Number of Natural Gas Customers	2023	2022
Residential	656,583	653,397
Small commercial & industrial	38,260	38,356
Large commercial & industrial	6,261	6,193

Total	701,104	697,946

Distribution Revenue increased for the three months ended March 31, 2023, compared to the same period in 2022, 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, 2023, compared to the same period in 2022, primarily due to 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.

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 $38 million for the three months ended March 31, 2023 compared to the same period in 2022, 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, 2023
	Increase (Decrease)
Labor, other benefits, contracting, and materials	$	8
Storm-related costs	(5)
Pension and non-pension postretirement benefits expense	1
BSC costs	3


Other	(3)
	4
Regulatory required programs	—

Total increase	$	4

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


	Three Months Ended March 31, 2023
	Increase (Decrease)
Depreciation and amortization(a)	$	7
Regulatory required programs	(9)
Regulatory asset amortization	(2)

Total decrease	$	(4)

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

Interest expense, net increased by $9 million for the three months ended March 31, 2023, compared to the same period in 2022, primarily due to an increase in interest rates and the issuance of debt in Q2 2022.

Effective income tax rates were 20.6% and 4.3% for the three months ended March 31, 2023 and 2022, respectively. The change is primarily due to a decrease in the multi-year plans' accelerated income tax benefits in 2023 as compared to 2022. 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, 2023 compared to the same period in 2022. See the Results of Operations for Pepco, DPL, and ACE for additional information.


	Three Months Ended March 31,				Favorable (Unfavorable) Variance
	2023		2022
PHI	$	155	$	130	$	25
Pepco	65		46		19
DPL	60		56		4
ACE	33		26		7
Other(a)	(3)		2		(5)

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

Three Months Ended March 31, 2023 Compared to Three Months Ended March 31, 2022. Net Income increased by $25 million primarily due to favorable impacts as a result of Pepco Maryland and DPL Maryland multi-year plans, timing of decoupling revenues in the District of Columbia, higher distribution rates at DPL Delaware, and higher transmission rates at Pepco and ACE, partially offset by an increase in environmental liabilities at Pepco, and unfavorable weather conditions at DPL Delaware electric and natural gas service territories.

Pepco

Results of Operations — Pepco


	Three Months Ended March 31,					Favorable (Unfavorable) Variance
2023			2022
Operating revenues	$	710		$	614	$	96


Operating expenses
Purchased power	258			213		(45)
Operating and maintenance	150			131		(19)
Depreciation and amortization	108			108		—
Taxes other than income taxes	94			95		1
Total operating expenses	610			547		(63)

Operating income	100			67		33
Other income and (deductions)
Interest expense, net	(39)			(36)		(3)
Other, net	16			13		3
Total other income and (deductions)	(23)			(23)		—
Income before income taxes	77			44		33
Income taxes	12			(2)		(14)
Net income	$	65		$	46	$	19

Three Months Ended March 31, 2023 Compared to Three Months Ended March 31, 2022. Net Income increased by $19 million primarily due to favorable impacts of the Maryland multi-year plan, timing of decoupling revenues in the District of Columbia, and higher transmission rates, partially offset by an increase in environmental liabilities.

The changes in Operating revenues consisted of the following:


	Three Months Ended March 31, 2023
	Increase
Distribution	$	40
Transmission	18

	58
Regulatory required programs	38
Total increase	$	96

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 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	2023	2022
Residential	859,207	846,258
Small commercial & industrial	54,089	54,509
Large commercial & industrial	22,858	22,620
Public authorities & electric railroads	201	184
Total	936,355	923,571

Pepco

Distribution Revenue increased for the three months ended March 31, 2023 compared to the same period in 2022 primarily due to favorable impacts of the Maryland multi-year plan and higher rates due to the expiration of customer offsets and timing of decoupling revenues in the District of Columbia.

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 $45 million for the three months ended March 31, 2023 compared to the same period in 2022, 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, 2023
	Increase (Decrease)
Labor, other benefits, contracting and materials(a)	$	24
Pension and non-pension postretirement benefits expense	3


Storm-related costs	(5)
Credit loss expense	(4)
BSC and PHISCO Costs	(1)
Other	(3)
	14

Regulatory required programs	5
Total increase	$	19

(a)Primarily reflects an increase in environmental liabilities.

Pepco

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


	Three Months Ended March 31, 2023
	Increase (Decrease)
Depreciation and amortization(a)	$	3
Regulatory asset amortization	4
Regulatory required programs	(7)
Total increase	$	—

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

Effective income tax rates were 15.6% and (4.5)% for three months ended March 31, 2023 and 2022, 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.

DPL

Results of Operations — DPL


	Three Months Ended March 31,					Favorable (Unfavorable) Variance
2023			2022
Operating revenues	$	474		$	431	$	43
Operating expenses
Purchased power and fuel	221			189		(32)
Operating and maintenance	87			93		6
Depreciation and amortization	60			57		(3)
Taxes other than income taxes	20			18		(2)
Total operating expenses	388			357		(31)

Operating income	86			74		12
Other income and (deductions)
Interest expense, net	(17)			(16)		(1)
Other, net	3			2		1
Total other income and (deductions)	(14)			(14)		—
Income before income taxes	72			60		12
Income taxes	12			4		(8)
Net income	$	60		$	56	$	4

Three Months Ended March 31, 2023 Compared to Three Months Ended March 31, 2022. Net income increased $4 million primarily due to favorable impacts of the Maryland multi-year plan, higher Delaware electric and natural gas distribution rates, partially offset by unfavorable weather conditions at Delaware electric and natural gas service territories.

The changes in Operating revenues consisted of the following:


	Three Months Ended March 31, 2023
	(Decrease) Increase
	Electric		Gas		Total
Weather	$	(5)	$	(4)	$	(9)
Volume	(2)		(2)		(4)
Distribution	11		5		16
Transmission	7		—		7

	11		(1)		10
Regulatory required programs	18		15		33
Total increase	$	29	$	14	$	43

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 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, 2023 compared to the same period in 2022, Operating revenues related to weather decreased due to unfavorable weather conditions in Delaware electric and natural gas service territories.

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 the Delaware electric service territory and a 30-year period in the Delaware natural gas service territory. The changes in heating and cooling degree days in the Delaware service territory for the three months ended March 31, 2023 compared to same period in 2022 and normal weather consisted of the following:







	Three Months Ended March 31,			% Change
Delaware Electric Service Territory	2023	2022	Normal	2023 vs. 2022		2023 vs. Normal
Heating Degree-Days	1,952	2,355	2,489	(17.1)	%	(21.6)	%
Cooling Degree-Days	—	3	1	(100.0)	%	(100.0)	%






	Three Months Ended March 31,			% Change
Delaware Natural Gas Service Territory	2023	2022	Normal	2023 vs. 2022		2023 vs. Normal
Heating Degree-Days	1,952	2,355	2,497	(17.1)	%	(21.8)	%

Volume, exclusive of the effects of weather, decreased for the three months ended March 31, 2023 compared to the same period in 2022 primarily due to customer usage, partially offset by customer growth.


Electric Retail Deliveries to Delaware Customers (in GWhs)		Three Months Ended March 31,			% Change	Weather - Normal % Change(b)
	2023		2022
Residential				797	895	(10.9)	%	(1.2)	%
Small commercial & industrial				327	370	(11.6)	%	(7.2)	%
Large commercial & industrial				719	765	(6.0)	%	(4.7)	%
Public authorities & electric railroads				9	9	—	%	(6.3)	%
Total electric retail deliveries(a)				1,852	2,039	(9.2)	%	(3.6)	%


	As of March 31,
Number of Total Electric Customers (Maryland and Delaware)	2023	2022
Residential	482,979	478,009
Small commercial & industrial	63,794	63,296
Large commercial & industrial	1,236	1,221
Public authorities & electric railroads	595	603
Total	548,604	543,129

(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)
	2023		2022
Residential				3,581	4,453	(19.6)	%	(6.6)	%
Small commercial & industrial				1,652	1,983	(16.7)	%	(1.8)	%
Large commercial & industrial				414	457	(9.4)	%	(9.5)	%
Transportation				1,900	2,207	(13.9)	%	(6.9)	%
Total natural gas deliveries(a)				7,547	9,100	(17.1)	%	(5.8)	%

DPL


	As of March 31,
Number of Delaware Natural Gas Customers	2023	2022
Residential	129,791	128,695
Small commercial & industrial	10,158	10,097
Large commercial & industrial	16	17
Transportation	158	159
Total	140,123	138,968

(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, 2023 compared to the same period in 2022 primarily due to favorable impacts of the Maryland multi-year plan that became effective in January 2023, higher natural gas distribution rates effective in August 2022, and higher DSIC rates in Delaware that became effective in January 2023.

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 months ended March 31, 2023 compared to the same period in 2022, transmission revenue increased, primarily due to increases underlying costs.

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 $32 million for the three months ended March 31, 2023, compared to the same period in 2022, 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, 2023
	(Decrease) Increase
Labor, other benefits, contracting and materials	$	(3)
Storm-related costs	(3)
BSC and PHISCO costs	(1)
Credit loss expense	(1)
Pension and non-pension postretirement benefits expense	1

	(7)
Regulatory required programs	1
Total decrease	$	(6)

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


	Three Months Ended March 31, 2023
	Increase (Decrease)
Depreciation and amortization(a)	$	7
Regulatory asset amortization	(1)
Regulatory required programs	(3)
Total increase	$	3

(a)Reflects ongoing capital expenditures, higher distribution depreciation rates in Maryland effective March 2022 and higher transmission depreciation rates effective September 2022.

Effective income tax rates were 16.7% and 6.7% for the three months ended March 31, 2023 and 2022, 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
	2023		2022
Operating revenues	$	353	$	349	$	4


Operating expenses
Purchased power	148		178		30
Operating and maintenance	81		84		3
Depreciation and amortization	67		47		(20)
Taxes other than income taxes	2		2		—
Total operating expenses	298		311		13

Operating income	55		38		17
Other income and (deductions)
Interest expense, net	(16)		(14)		(2)
Other, net	5		3		2
Total other income and (deductions)	(11)		(11)		—
Income before income taxes	44		27		17
Income taxes	11		1		(10)
Net income	$	33	$	26	$	7

Three Months Ended March 31, 2023 Compared to Three Months Ended March 31, 2022. Net income increased by $7 million primarily due to higher transmission rates and decreases in various operating expenses.

The changes in Operating revenues consisted of the following:


	Three Months Ended March 31, 2023
	Increase (Decrease)


Distribution	$	8
Transmission	12

	20




Regulatory required programs	(16)
Total increase	$	4

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.

ACE


	As of March 31,
Number of Electric Customers	2023	2022
Residential	503,260	500,511
Small commercial & industrial	62,230	62,124
Large commercial & industrial	3,030	3,124
Public authorities & electric railroads	726	724
Total	569,246	566,483

Distribution Revenue increased for the three months ended March 31, 2023 compared to the same period in 2022 due to higher distribution rates primarily due to the expiration of customer credits related to the TCJA tax benefits.

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, 2023 compared to the same period in 2022, primarily due to increases in capital investment and underlying costs.

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 Bond Charge, 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 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 $30 million for the three months ended March 31, 2023 compared to the same period in 2022, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.

ACE

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


	Three Months Ended March 31, 2023
	(Decrease) Increase
Labor, other benefits, contracting and materials	$	(2)

Storm-related costs	(2)


Other	2
	(2)

Regulatory required programs(a)	(1)
Total decrease	$	(3)

(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, 2023
	Increase
Depreciation and amortization(a)	$	7
Regulatory asset amortization	—
Regulatory required programs(b)	13
Total increase	$	20

(a)Reflects ongoing capital expenditures and higher transmission depreciation rates effective September 2022.

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

Effective income tax rates were 25.0% and 3.7% for the three months ended March 31, 2023 and 2022, 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 Generation have not been presented as discontinued operations and are included in the Consolidated Statements of Cash Flows for only 2022. The Exelon Consolidated Statement of Cash Flows for the three months ended March 31, 2022 includes one month of cash flows from Generation.

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. Additionally, ComEd is required to purchase CMCs from participating nuclear-powered generating facilities for a five-year period that began in June 2022, and all of its costs of doing so will be recovered through a rider. The price to be paid for each CMC is established through a competitive bidding process. ComEd will provide net payments to, or collect net payments from, customers for the difference between customer credits issued and the credit to be received from the participating nuclear-powered generating facilities. ComEd’s cash flows are affected by the establishment of CMC prices and the timing of recovering costs through the CMC regulatory asset.

See Note 3 — Regulatory Matters of the 2022 Form 10-K and Notes 3 — Regulatory Matters and 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, 2023 and 2022 by Registrant:


Increase (decrease) in cash flows from operating activities	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Net income (loss)	$	71	$	53	$	(40)	$	2	$	25	$	19	$	4	$	7
Adjustments to reconcile net income to cash:
Non-cash operating activities	(683)		(126)		(7)		(61)		(8)		(17)		(9)		14
Option premiums (paid), net	39		—		—		—		—		—		—		—
Collateral (paid) received, net	(1,356)		(47)		—		(52)		(226)		(26)		(150)		(41)
Income taxes	(54)		17		20		25		15		7		10		5
Pension and non-pension postretirement benefit contributions	530		153		12		48		60		1		1		6
Regulatory assets and liabilities, net	(293)		(330)		19		(23)		45		4		27		6
Changes in working capital and other assets and liabilities	448		24		23		93		113		70		30		3
(Decrease) increase in cash flows from operating activities	$	(1,298)	$	(256)	$	27	$	32	$	24	$	58	$	(87)	$	—

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, 2023 and 2022 were as follows:

See Note 15 — 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 decreased due to decreasing energy prices. See Note 9 — Derivative Financial Instruments for additional information.
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 Pension and non-pension postretirement benefit contributions relates to Exelon receiving an updated valuation of its pension and OPEB to reflect census data as of January 1, 2023. See Note 8 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information.
Changes in regulatory assets and liabilities, net, are due to the timing of cash payments for costs recoverable, or cash receipts for costs recovered, under our regulatory mechanisms differs from the recovery period of those costs. Included within the changes is energy efficiency spend for ComEd of $72 million and $50 million for the three months ended March 31, 2023 and 2022, respectively. Also included within the changes is energy efficiency and demand response programs spend for BGE, Pepco, DPL and ACE of $33 million, $14 million, $5 million, and $4 million for the three months ended March 31, 2023 and $26 million, $13 million, $6 million, and $2 million for the three months ended March 31, 2022, respectively. PECO had no energy efficiency and demand response programs spend recorded to the regulatory asset for the three months ended March 31,

2023 and 2022. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Changes in working capital and other assets and liabilities for the Utility Registrants and Exelon Corporate totaled $125 million and for Generation total $323 million. The change for Generation primarily relates to the revolving accounts receivable financing arrangement which was entered into in April 2020. The change in working capital and other noncurrent assets and liabilities for Exelon Corporate and the Utility Registrants is dependent upon the normal course of operations for all Registrants. For ComEd, it is also dependent upon whether the participating nuclear-powered generating facilities are owed money from ComEd as a result of the established pricing for CMCs. For the three months ended March 31, 2023, the established pricing resulted in a ComEd owing payments to nuclear-powered generating facilities, which is reported within the cash flows from operations as a change in accounts payable and accrued expense.

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, 2023 and 2022 by Registrant:


Increase (decrease) in cash flows from investing activities	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Capital expenditures	$	41	$	—	$	9	$	(47)	$	(152)	$	(46)	$	(31)	$	(74)

Investment in NDT fund sales, net	28		—		—		—		—		—		—		—
Collection of DPP	(169)		—		—		—		—		—		—		—
Proceeds from sales of assets and businesses	(16)		—		—		—		—		—		—		—


Other investing activities	64		(6)		(2)		—		6		7		(1)		—
(Decrease) increase in cash flows from investing activities	$	(52)	$	(6)	$	7	$	(47)	$	(146)	$	(39)	$	(32)	$	(74)

Significant investing cash flow impacts for the Registrants for three months ended March 31, 2023 and 2022 were as follows:

Changes 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 for the Utility Registrants. 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 Generation's revolving accounts receivable financing agreement which Generation entered into in April 2020.

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, 2023 and 2022 by Registrant:


(Decrease) increase in cash flows from financing activities	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Changes in short-term borrowings, net	$	(1,380)	$	(168)	$	(94)	$	(285)	$	54	$	(124)	$	34	$	144
Long-term debt, net	(1,227)		225		—		—		(250)		(150)		—		(100)
Changes in intercompany money pool	—		—		(65)		—		(31)		—		—		—

Dividends paid on common stock	(26)		(43)		(1)		(4)		—		(6)		(1)		(2)

Distributions to member	—		—		—		—		(10)		—		—		—
Contributions from parent/member	—		19		103		237		(299)		(144)		(45)		(110)
Transfer of cash, restricted cash, and cash equivalents to Constellation	2,594		—		—		—		—		—		—		—
Other financing activities	3		(1)		1		1		(8)		(9)		—		2
(Decrease) increase in cash flows from financing activities	$	(36)	$	32	$	(56)	$	(51)	$	(544)	$	(433)	$	(12)	$	(66)

Significant financing cash flow impacts for the Registrants for the three months ended March 31, 2023 and 2022 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 10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on short-term borrowings for the Registrants.
Long-term debt, net**, varies due to debt issuances and redemptions each year. See 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 18 — Commitments and Contingencies of the 2022 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.

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, 2023, the following long-term debt was retired and/or redeemed:


Company	Type	Interest Rate		Maturity	Amount
Exelon	SMBC Term Loan Agreement	SOFR plus 0.65%		July 21, 2023	$	300
Exelon	US Bank Term Loan Agreement	SOFR plus 0.65%		July 21, 2023	300

Exelon	PNC Term Loan Agreement	SOFR plus 0.65%		July 24, 2023	250
Exelon	Long-Term Software License Agreement	3.70	%	August 9, 2025	6
Exelon	Long-Term Software License Agreement	3.70	%	August 9, 2025	1

Dividends

Quarterly dividends declared by the Exelon Board of Directors during the three months ended March 31, 2023 and for the second quarter of 2023 were as follows:


Period	Declaration Date	Shareholder of Record Date	Dividend Payable Date	Cash per Share(a)
First Quarter 2023	February 14, 2023	February 27, 2023	March 10, 2023	$	0.3600
Second Quarter 2023	April 25, 2023	May 15, 2023	June 9, 2023	$	0.3600

(a)Exelon's Board of Directors approved an updated dividend policy for 2023. The 2023 quarterly dividend will be $0.36 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 $3.2 billion was available to support additional commercial paper as of March 31, 2023, 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 three months ended March 31, 2023 to fund their short-term liquidity needs, when necessary. Exelon Corporate and the Utility Registrants each have a 5-year 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 2022 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 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 March 31, 2023, Exelon has not issued any shares of common stock under the ATM program and has not entered into any forward sale agreements.

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, 2023 and available credit facility capacity prior to any incremental collateral at March 31, 2023:


	PJM Credit Policy Collateral		Other Incremental Collateral Required(a)		Available Credit Facility Capacity Prior to Any Incremental Collateral
ComEd	$	17	$	—	$	586
PECO	1		39		455
BGE	3		73		357

Pepco	4		—		300
DPL	4		14		300
ACE	2		—		300

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

Capital Expenditure Spending

As of March 31, 2023, the most recent estimates of capital expenditures for plant additions and improvements for 2023 are as follows:


(In millions)	Transmission	Distribution	Gas	Total(a)
Exelon	N/A	N/A	N/A	$	7,175
ComEd	500	2,075	N/A	2,550
PECO	75	975	325	1,375
BGE	325	525	475	1,325
PHI	550	1,225	125	1,900
Pepco	250	650	N/A	900
DPL	175	275	125	575
ACE	125	300	N/A	425

(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.

Retirement 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 annual contributions with the objective of achieving 100% funded status on an ABO basis over time. This funding strategy helps minimize volatility of future period required pension contributions. Exelon’s estimated annual qualified pension contributions will be $20 million in 2023. 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).

To the extent interest rates decline significantly or the pension and OPEB plans earn less than the expected asset returns, annual pension contribution requirements in future years could increase. Conversely, to the extent interest rates increase significantly or the pension and OPEB plans earn greater than the expected asset returns, annual pension and OPEB contribution requirements in future years could decrease. Additionally, expected contributions could change if Exelon changes its pension or OPEB funding strategy.

See Note 14 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements of the 2022 Form 10-K for additional information on pension and OPEB contributions.

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 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 Exelon and the Utility Registrants did not change for the three months ended March 31, 2023.

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, 2023, are presented in the following table. Pepco, DPL, and ACE had no activity within the PHI intercompany money pool during the three months ended March 31, 2023.


	During the Three Months Ended March 31, 2023				As of March 31, 2023
Exelon Intercompany Money Pool	Maximum Contributed		Maximum Borrowed		Contributed (Borrowed)
Exelon Corporate	$	510	$	—	$	266
PECO	—		(238)		—
BSC	—		(327)		(259)
PHI Corporate	—		(52)		(52)
PCI	45		—		45

Shelf Registration Statements

Exelon and the Utility Registrants have a currently effective combined shelf registration statement, unlimited in amount, 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 March 31, 2023
	Short-term Financing Authority						Remaining Long-term Financing Authority
Commission	Expiration Date	Amount	Commission			Expiration Date		Amount
ComEd	FERC	December 31, 2023		$	2,500		ICC		January 1, 2025	$	368
PECO	FERC	December 31, 2023		1,500			PAPUC		December 31, 2024	1,125
BGE(a)	FERC	December 31, 2023		700			MDPSC		N/A	1,800
Pepco(b)	FERC	December 31, 2023		500			MDPSC / DCPSC		December 31, 2025	1,150
DPL(b)	FERC	December 31, 2023		500			MDPSC / DEPSC		December 31, 2025	1,075
ACE	NJBPU	December 31, 2023		350			NJBPU		December 31, 2024	625

(a)On December 21, 2022, BGE received approval from the MDPSC for $1.8 billion in new long-term financing authority with an effective date of January 4, 2023.

(b)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.

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