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

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

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

Exelon

Executive Overview

Exelon is a utility services holding company engaged in the energy distribution and transmission businesses through ComEd, PECO, BGE, Pepco, DPL, and ACE.

Exelon has six reportable segments consisting of ComEd, PECO, BGE, Pepco, DPL, and ACE. See Note 1 — Significant Accounting Policies and Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information regarding Exelon's principal subsidiaries and reportable segments.

Exelon’s consolidated financial information includes the results of its seven separate operating subsidiary registrants, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE, which, along with Exelon, are collectively referred to as the Registrants. The following combined Management’s Discussion and Analysis of Financial Condition and Results of Operations is separately filed by Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE. However, none of the Registrants makes any representation as to information related solely to any of the other Registrants.

Financial Results of Operations

GAAP Results of Operations. The following table sets forth Exelon's GAAP consolidated Net income attributable to common shareholders from continuing operations and the Utility Registrants' Net income for the three and six months ended June 30, 2022 compared to the same period in 2021. For additional information regarding the financial results for the three and six months ended June 30, 2022 and 2021 see the discussions of Results of Operations by Registrant.

Three Months Ended June 30,Favorable (Unfavorable) VarianceSix Months Ended June 30,Favorable (Unfavorable) Variance
2022202120222021
Exelon$465$326$139$946$851$95
ComEd2271923541539025
PECO1331042933927168
BGE3745(8)234254(20)
PHI100141(41)230269(39)
Pepco7075(5)116134(18)
DPL2130(9)7786(9)
ACE1137(26)3751(14)
Other(a)(32)(156)124(272)(333)61

(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 June 30, 2022 Compared to Three Months Ended June 30, 2021. Net income attributable to common shareholders from continuing operations increased by $139 million and diluted

earnings per average common share from continuing operations increased to $0.47 in 2022 from $0.33 in 2021 primarily due to:

  • Higher electric distribution earnings from higher allowed electric distribution ROE due to an increase in treasury rates and higher rate base at ComEd;

  • The favorable impacts of rate increases at PECO, BGE, and PHI; and

  • Lower BSC costs, which were previously allocated to Generation but do not qualify as expenses of the discontinued operations per the accounting rules. Such costs, on a pre-tax basis, were $99 million for the three months ended June 30, 2021.

The increases were partially offset by:

  • The absence of favorable weather and volume as a result of the CIP at ACE;

  • Higher depreciation expense at BGE and PHI;

  • Higher credit loss expense at PHI; and

  • Higher interest expense at Exelon Corporate.

Six Months Ended June 30, 2022 Compared to Six Months Ended June 30, 2021. Net income attributable to common shareholders from continuing operations increased by $95 million and diluted earnings per average common share from continuing operations increased to $0.96 in 2022 from $0.87 in 2021 primarily due to:

  • Higher electric distribution earnings from higher allowed electric distribution ROE due to an increase in treasury rates and higher rate base at ComEd;

  • The favorable impacts of rate increases at PECO, BGE, and PHI;

  • 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 $206 million for the six months ended June 30, 2021.

The increases were partially offset by:

  • An income tax expense recorded in connection with the separation primarily due to the long-term marginal state income tax rate change, the recognition of valuation allowances against the net deferred tax assets positions for certain standalone state filing jurisdictions, and nondeductible transaction costs partially offset by a one-time impact associated with a state tax benefit;

  • The absence of favorable weather and volume as a result of the CIP at ACE;

  • Higher depreciation expense at PECO, BGE, and PHI;

  • Higher credit loss expense at BGE and PHI;

  • Higher storm costs at PHI; and

  • Higher interest expense at PHI and Exelon Corporate.

Adjusted (non-GAAP) Operating Earnings. In addition to net income, Exelon evaluates its operating performance using the measure of Adjusted (non-GAAP) operating earnings because management believes it represents earnings directly related to the ongoing operations of the business. Adjusted (non-GAAP) operating earnings exclude certain costs, expenses, gains and losses, and other specified items. This information is intended to enhance an investor’s overall understanding of year-to-year operating results and provide an indication of Exelon’s baseline operating performance excluding items that are considered by management to be not directly related to the ongoing operations of the business. In addition, this information is among the primary indicators management uses as a basis for evaluating performance, allocating resources, setting incentive

compensation targets, and planning and forecasting of future periods. Adjusted (non-GAAP) operating earnings is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.

The following tables provide a reconciliation between net income attributable to common shareholders from continuing operations as determined in accordance with GAAP and adjusted (non-GAAP) operating earnings for the three and six months ended June 30, 2022 compared to the same period in 2021.

Three Months Ended June 30,
20222021
(In millions, except per share data)Earnings per Diluted ShareEarnings per Diluted Share
Net Income Attributable to Common Shareholders from Continuing Operations$465$0.47$326$0.33
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $1)——3—
Cost Management Program (net of taxes of $0)——1—
COVID-19 Direct Costs (net of taxes of $1)(a)——4—
Acquisition Related Costs (net of taxes of $1)(b)——2—
ERP System Implementation Costs (net of taxes $1)(c)——2—
Separation Costs (net of taxes of $4 and $6, respectively)(d)100.01100.01
Income Tax-Related Adjustments (entire amount represents tax expense)(e)(43)(0.04)——
Adjusted (non-GAAP) Operating Earnings$433$0.44$348$0.36
Six Months Ended June 30,
20222021
(In millions, except per share data)Earnings per Diluted ShareEarnings per Diluted Share
Net Income Attributable to Common Shareholders from Continuing Operations$946$0.96$851$0.87
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $1)——3—
Cost Program Management (net of taxes of $0)——1—
COVID-19 Direct Costs (net of taxes of $3) (a)——50.01
Acquisition Related Costs (net of taxes of $3)(b)——70.01
ERP System Implementation Costs (net of taxes of $0 and $1, respectively)(c)1—70.01
Separation Costs (net of taxes of $11 and $6, respectively)(d)270.03150.02
Income Tax-Related Adjustments (entire amount represents tax expense)(f)920.09(2)—
Adjusted (non-GAAP) Operating Earnings$1,065$1.08$887$0.91

Note:

Amounts may not sum due to rounding.

Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net Income from Continuing Operations and Adjusted (non-GAAP) Operating Earnings is based on the marginal statutory federal and state income tax rates for each Registrant, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part. The marginal statutory income tax rates for 2022 and 2021 ranged from 24.0% to 29.0%.

(a)Represents direct costs related to COVID-19 consisting primarily of costs to acquire personal protective equipment, costs for cleaning supplies and services, and costs to hire healthcare professionals to monitor the health of employees, which are recorded in Operating and maintenance expense.

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

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

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

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

(e)In connection with the separation, Exelon recorded a one-time impact associated with a state tax benefit.

(f)In connection with the separation, Exelon recorded an income tax expense primarily due to the long-term marginal state income tax rate change, the recognition of valuation allowances against the net deferred tax assets positions for certain standalone state filing jurisdictions, and nondeductible transaction costs partially offset by a one-time impact associated with a state tax benefit.

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 $14 million and $16 million on a pre-tax basis for the three months ended June 30, 2022 and 2021, respectively, and $38 million and $21 million on a pre-tax basis for the six months ended June 30, 2022 and 2021, respectively, which are recorded in Operating and maintenance expense. Total separation costs impacting continuing operations for the remainder of 2022 are not expected to be material. These costs are excluded from Adjusted (non-GAAP) Operating Earnings. The separation costs are primarily comprised of system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the separation, and employee-related severance costs.

Distribution Base Rate Case Proceedings

The Utility Registrants file base rate cases with their regulatory commissions seeking increases or decreases to their electric transmission and distribution, and gas distribution rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Utility Registrants’ current and future financial statements.

The following tables show the Utility Registrants’ completed and pending distribution base rate case proceedings in 2022. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Completed Distribution Base Rate Case Proceedings

Registrant/JurisdictionFiling DateServiceRequested Revenue Requirement IncreaseApproved Revenue Requirement IncreaseApproved ROEApproval DateRate Effective Date
ComEd - IllinoisApril 16, 2021Electric$51$467.36%December 1, 2021January 1, 2022
PECO - PennsylvaniaMarch 30, 2021Electric246132N/ANovember 18, 2021January 1, 2022
BGE - MarylandMay 15, 2020 (amended September 11, 2020)Electric2031409.50%December 16, 2020January 1, 2021
Natural Gas108749.65%
Pepco - District of ColumbiaMay 30, 2019 (amended June 1, 2020)Electric1361099.275%June 8, 2021July 1, 2021
Pepco - MarylandOctober 26, 2020 (amended March 31, 2021)Electric104529.55%June 28, 2021June 28, 2021
DPL - MarylandSeptember 1, 2021 (amended December 23, 2021)Electric27139.60%March 2, 2022March 2, 2022
ACE - New JerseyDecember 9, 2020 (amended February 26, 2021)Electric67419.60%July 14, 2021January 1, 2022

Pending Distribution Base Rate Case Proceedings

Registrant/JurisdictionFiling DateServiceRequested Revenue Requirement IncreaseRequested ROEExpected Approval Timing
ComEd - IllinoisApril 15, 2022Electric$1997.85%Fourth quarter of 2022
PECO - PennsylvaniaMarch 31, 2022Natural Gas8210.95%Fourth quarter of 2022
DPL - DelawareJanuary 14, 2022 (amended February 28, 2022)Natural Gas1510.30%First quarter of 2023
DPL - MarylandMay 19, 2022Electric3810.25%Fourth quarter of 2022

Transmission Formula Rates

For 2022, the following total increases/(decreases) were included in the Utility Registrants' electric transmission formula rate updates. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

RegistrantInitial Revenue Requirement IncreaseAnnual Reconciliation (Decrease) IncreaseTotal Revenue Requirement IncreaseAllowed Return on Rate BaseAllowed ROE
ComEd$24$(24)$—8.11%11.50%
PECO2316397.30%10.35%
BGE25(4)167.30%10.50%
Pepco1615317.60%10.50%
DPL92117.09%10.50%
ACE2113347.18%10.50%

Pennsylvania Corporate Income Tax Rate Change

On July 8, 2022, Pennsylvania enacted House Bill 1342, which will permanently reduce the corporate income tax rate from 9.99% to 4.99%. The tax rate will be reduced to 8.99% for the 2023 tax year. Starting with the 2024 tax year, the rate is reduced by 0.5% annually until it reaches 4.99% in 2031. As a result of the rate change, in the third quarter of 2022, Exelon and PECO will record an estimated one-time decrease to deferred income taxes of $390 million with a corresponding decrease to the deferred income taxes regulatory asset of $428 million for the amounts that are expected to be settled through future customer rates and an increase to income tax expense of $38 million (net of federal taxes), which will be excluded from Adjusted (non-GAAP) Operating Earnings. See Note 7 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.

Other Key Business Drivers and Management Strategies

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

Inflation Reduction Act

On July 27, 2022, the Inflation Reduction Act was introduced in the U.S. Senate. The bill extends tax benefits for renewable technologies like solar and wind and it creates new tax benefits for alternative clean energy sources like nuclear and hydrogen and it focuses on energy efficiency, electrification, and equity. However, the bill also implements a new 15% corporate minimum tax based on modified GAAP net income. Exelon estimates the bill could result in an increase in cash taxes for Exelon of approximately $300 million per year starting in 2023 if enacted as proposed. Exelon is continuing to assess the impacts of the bill on the financial statements. Exelon is working with legislators and cannot predict the outcome of the proposed legislation.

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 June 30, 2022, the Registrants’ critical accounting policies and estimates had not changed significantly from December 31, 2021. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates in the 2021 Recast Form 10-K for further information.

Results of Operations by Registrant

Results of Operations — ComEd

Three Months Ended June 30,Favorable (Unfavorable) VarianceSix Months Ended June 30,Favorable (Unfavorable) Variance
2022202120222021
Operating revenues$1,425$1,517$(92)$3,158$3,052$106
Operating expenses
Purchased power2835002179211,025104
Operating and maintenance338323(15)689639(50)
Depreciation and amortization328296(32)649589(60)
Taxes other than income taxes9077(13)185153(32)
Total operating expenses1,0391,1961572,4442,406(38)
Loss on sales of assets(2)—(2)(2)—(2)
Operating income3843216371264666
Other income and (deductions)
Interest expense, net(104)(98)(6)(204)(193)(11)
Other, net1315(2)26224
Total other income and (deductions)(91)(83)(8)(178)(171)(7)
Income before income taxes2932385553447559
Income taxes6646(20)11985(34)
Net income$227$192$35$415$390$25

Three Months Ended June 30, 2022 Compared to Three Months Ended June 30, 2021. Net income increased by $35 million as compared to the same period in 2021, primarily due to increases in electric distribution formula rate earnings (reflecting higher allowed electric distribution ROE due to an increase in treasury rates and the impacts of higher rate base).

Six Months Ended June 30, 2022 Compared to Six Months Ended June 30, 2021. Net income increased by $25 million as compared to the same period in 2021, primarily due to increases in electric distribution formula rate earnings (reflecting higher allowed electric distribution ROE due to an increase in treasury rates and the impacts of higher rate base) partially offset by the voluntary customer refund related to the ICC investigation of matters identified in the Deferred Prosecution Agreement. See Note 12 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.

The changes in Operating revenues consisted of the following:

Three Months Ended June 30, 2022Six Months Ended June 30, 2022
Increase (Decrease)Increase (Decrease)
Distribution$65$110
Transmission1738
Energy efficiency1420
Other—3
96171
Regulatory required programs(188)(65)
Total increase$(92)$106

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

ComEd

Distribution Revenue. EIMA and FEJA provide for a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs that the ICC determines are prudently and reasonably incurred in a given year. Electric distribution revenue varies from year to year based upon fluctuations in the underlying costs, (e.g., severe weather and storm restoration), investments being recovered, and allowed ROE. Electric distribution revenue increased for the three and six months ended June 30, 2022 as compared to the same period in 2021, due to higher allowed ROE due to an increase in treasury rates, the impact of a higher rate base, and higher fully recoverable costs.

Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered, and the highest daily peak load, which is updated annually in January based on the prior calendar year. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. Transmission revenue increased for the three and six months ended June 30, 2022 as compared to the same period in 2021 primarily due to the impact of higher rate base and higher fully recoverable costs.

Energy Efficiency Revenue. FEJA provides for a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs that the ICC determines are prudently and reasonably incurred in a given year. Under FEJA, energy efficiency revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered, and allowed ROE. Energy efficiency revenue increased for the three and six months ended June 30, 2022 as compared to the same period in 2021, primarily due to increased regulatory asset amortization, which is fully recoverable.

Other Revenue primarily includes assistance provided to other utilities through mutual assistance programs. Other revenue remained relatively the same for the three and six months ended June 30, 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, 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 $217 million and $104 million for the three and six months ended June 30, 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 June 30, 2022Six Months Ended June 30, 2022
(Decrease) Increase(Decrease) Increase
Storm-related costs$(1)$—
Pension and non-pension postretirement benefits expense(7)(14)
Labor, other benefits, contracting and materials911
BSC costs922
Other(a)426
1445
Regulatory required programs(b)15
Total increase$15$50

(a)For the six months ended June 30, 2022, the increase is primarily due to the voluntary customer refund related to the ICC investigation of matters identified in the Deferred Prosecution Agreement. See Note 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 June 30, 2022Six Months Ended June 30, 2022
IncreaseIncrease
Depreciation and amortization(a)$19$33
Regulatory asset amortization(b)1327
Total increase$32$60

(a)Reflects ongoing capital expenditures.

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

Taxes other than income taxes increased by $13 million and by $32 million for the three and six months ended June 30, 2022, respectively, compared to the same period in 2021, primarily due to taxes related to ETAC, which is recovered through Operating revenues.

Effective income tax rat****es were 22.5% and 19.3% for the three months ended June 30, 2022 and 2021, respectively, and 22.3% and 17.9% for the six months ended June 30, 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 June 30,Favorable (Unfavorable) VarianceSix Months Ended June 30,Favorable (Unfavorable) Variance
2022202120222021
Operating revenues$816$693$123$1,863$1,582$281
Operating expenses
Purchased power and fuel283207(76)689523(166)
Operating and maintenance215209(6)463443(20)
Depreciation and amortization9387(6)185173(12)
Taxes other than income taxes484919592(3)
Total operating expenses639552(87)1,4321,231(201)
Operating income1771413643135180
Other income and (deductions)
Interest expense, net(43)(42)(1)(84)(80)(4)
Other, net87116124
Total other income and (deductions)(35)(35)—(68)(68)—
Income before income taxes1421063636328380
Income taxes92(7)2412(12)
Net income$133$104$29$339$271$68

Three Months Ended June 30, 2022 Compared to Three Months Ended June 30, 2021. Net income increased by $29 million, primarily due to increases in electric and gas distribution rates.

Six Months Ended June 30, 2022 Compared to Six Months Ended June 30, 2021**.** Net income increased by $68 million, primarily due to increases in electric and gas distribution rates.

The changes in Operating revenues consisted of the following:

Three Months Ended June 30, 2022Six Months Ended June 30, 2022
(Decrease) Increase(Decrease) Increase
ElectricGasTotalElectricGasTotal
Weather$(1)$(1)$(2)$(5)$(5)$(10)
Volume(2)4241014
Pricing32638652388
Transmission3—38—8
Other61711415
3810488332115
Regulatory required programs5817759571166
Total increase$96$27$123$178$103$281

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 June 30, 2022 compared to the same period in 2021, Operating revenues related to weather remained relatively consistent. During the six months ended June 30, 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 and six months ended June 30, 2022 compared to the same period in 2021 and normal weather consisted of the following:

Three Months Ended June 30,% Change
PECO Service Territory20222021Normal2022 vs. 20212022 vs. Normal
Heating Degree-Days385404424(4.7)%(9.2)%
Cooling Degree-Days4344183913.8%11.0%
Six Months Ended June 30,% Change
20222021Normal2022 vs. 20212022 vs. Normal
Heating Degree-Days2,6132,7062,840(3.4)%(8.0)%
Cooling Degree-Days4354233922.8%11.0%

Volume. Electric volume, exclusive of the effects of weather, for the three and six months ended June 30, 2022, compared to the same period in 2021, remained relatively consistent. Natural gas volume for the three and six months ended June 30, 2022 compared to the same period in 2021, increased due to retail load growth.

Electric Retail Deliveries to Customers (in GWhs)Three Months Ended June 30,% ChangeWeather - Normal % Change**(b)**Six Months Ended June 30,% ChangeWeather - Normal % Change**(b)**
2022202120222021
Residential3,0603,116(1.8)%(1.1)%6,8186,883(0.9)%0.1%
Small commercial & industrial1,8131,7583.1%3.0%3,7503,6393.1%3.2%
Large commercial & industrial3,4163,475(1.7)%(1.8)%6,7486,747—%—%
Public authorities & electric railroads13512111.6%11.9%31727017.4%17.7%
Total electric retail deliveries(a)8,4248,470(0.5)%(0.4)%17,63317,5390.5%1.0%
As of June 30,
Number of Electric Customers20222021
Residential1,521,7281,513,456
Small commercial & industrial155,484154,842
Large commercial & industrial3,1143,108
Public authorities & electric railroads10,38610,285
Total1,690,7121,681,691

(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 June 30,% ChangeWeather - Normal % Change**(b)**Six Months Ended June 30,% ChangeWeather - Normal % Change**(b)**
2022202120222021
Residential5,2065,0273.6%4.9%26,04325,7011.3%4.4%
Small commercial & industrial3,6383,12116.6%17.2%14,18413,2916.7%8.4%
Large commercial & industrial42100.0%12.6%14955.6%11.4%
Transportation5,7075,4684.4%5.7%13,34613,1181.7%2.7%
Total natural gas retail deliveries(a)14,55513,6186.9%8.0%53,58752,1192.8%5.0%

PECO

As of June 30,
Number of Natural Gas Customers20222021
Residential499,678494,895
Small commercial & industrial44,72644,450
Large commercial & industrial106
Transportation659677
Total545,073540,028

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

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

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

Transmission Revenue. Under a FERC approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered.

Other revenue primarily includes revenue related to late payment charges. Other revenue for the three and six months ended June 30, 2022 compared to the same period in 2021 increased primarily due to revenue related to late payment charges.

Regulatory Required Programs represents revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency, PGC, and the GSA. The riders are designed to provide full and current cost recovery as well as a return. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Income taxes. Customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers. Customer choice programs do not impact the volume of deliveries as PECO remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation or natural gas from competitive suppliers, PECO either acts as the billing agent or the competitive supplier separately bills its own customers and therefore PECO does not record Operating revenues or Purchased power and fuel expense related to the electricity and/or natural gas. For customers that choose to purchase electric generation or natural gas from PECO, PECO is permitted to recover the electricity, natural gas, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power and fuel expense related to the electricity, natural gas, and RECs.

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

The increase of $76 million and $166 million for the three and six months ended June 30, 2022 compared to the same period in 2021, respectively, in Purchased power and fuel expense is offset in Operating revenues as part of regulatory required programs.

PECO

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

Three Months Ended June 30, 2022Six Months Ended June 30, 2022
Increase (Decrease)Increase (Decrease)
BSC costs$7$16
Credit loss expense15
Storm-related costs13
Pension and non-pension post retirement benefit expense(3)(4)
Labor, other benefits, contracting and materials(6)(8)
Other43
415
Regulatory required programs25
Total increase$6$20

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

Three Months Ended June 30, 2022Six Months Ended June 30, 2022
IncreaseIncrease
Depreciation and amortization(a)$6$12
Regulatory asset amortization——
Total increase$6$12

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

Interest expense, net increased $1 million and $4 million for the three and six months ended June 30, 2022 compared to the same period in 2021, primarily due to the issuance of debt in 2021 and 2022.

Effective income tax rates were 6.3% and 1.9% for the three months ended June 30, 2022 and 2021 respectively, and 6.6% and 4.2% for the for the six months ended June 30, 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 June 30,Favorable (Unfavorable) VarianceSix Months Ended June 30,Favorable (Unfavorable) Variance
2022202120222021
Operating revenues$786$682$104$1,940$1,656$284
Operating expenses
Purchased power and fuel289219(70)743550(193)
Operating and maintenance205193(12)423390(33)
Depreciation and amortization152141(11)322293(29)
Taxes other than income taxes7167(4)148139(9)
Total operating expenses717620(97)1,6361,372(264)
Operating income6962730428420
Other income and (deductions)
Interest expense, net(36)(34)(2)(71)(67)(4)
Other, net59(4)1116(5)
Total other income and (deductions)(31)(25)(6)(60)(51)(9)
Income before income taxes3837124423311
Income taxes1(8)(9)10(21)(31)
Net income$37$45$(8)$234$254$(20)

Three Months Ended June 30, 2022 Compared to Three Months Ended June 30, 2021. Net income decreased $8 million primarily due to an increase in depreciation 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.

Six Months Ended June 30, 2022 Compared to Six Months Ended June 30, 2021**.** Net income decreased $20 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 June 30, 2022Six Months Ended June 30, 2022
IncreaseIncrease
ElectricGasTotalElectricGasTotal
Distribution$17$5$22$31$15$46
Transmission2—27—7
Other32510515
22729482068
Regulatory required programs50257512888216
Total increase$72$32$104$176$108$284

Revenue Decoupling. The demand for electricity and natural gas is affected by weather and customer usage. However, Operating revenues are not impacted by abnormal weather or usage per customer as a result of a monthly rate adjustment that provides for fixed distribution revenue per customer by customer class. While Operating revenues are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.

BGE

As of June 30,
Number of Electric Customers20222021
Residential1,200,3971,192,135
Small commercial & industrial115,769114,682
Large commercial & industrial12,72112,528
Public authorities & electric railroads267267
Total1,329,1541,319,612
As of June 30,
Number of Natural Gas Customers20222021
Residential653,409647,534
Small commercial & industrial38,22738,223
Large commercial & industrial6,2116,132
Total697,847691,889

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

Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue increased for the three and six months ended June 30, 2022, compared to the same period in 2021, primarily due to increases in capital investments.

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

Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as conservation, demand response, STRIDE, and the POLR mechanism. The riders are designed to provide full and current cost recovery, as well as a return in certain instances. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers. Customer choice programs do not impact the volume of deliveries as BGE remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation or natural gas from competitive suppliers, BGE acts as the billing agent and therefore does not record Operating revenues or Purchased power and fuel expense related to the electricity and/or natural gas. For customers that choose to purchase electric generation or natural gas from BGE, BGE is permitted to recover the electricity and natural gas procurement costs from customers and therefore records the amounts related to the electricity and/or natural gas in Operating revenues and Purchased power and fuel expense. BGE recovers electricity and natural gas procurement costs from customers with a slight mark-up.

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

The increase of $70 million and $193 million for the three and six months ended June 30, 2022 compared to the same period in 2021, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.

BGE

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

Three Months Ended June 30, 2022Six Months Ended June 30, 2022
Increase (Decrease)Increase (Decrease)
Labor, other benefits, contracting, and materials$5$7
Storm-related costs(2)(1)
Pension and non-pension postretirement benefits expense(3)(6)
BSC costs614
Credit loss expense—14
Other52
1130
Regulatory required programs13
Total increase$12$33

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

Three Months Ended June 30, 2022Six Months Ended June 30, 2022
IncreaseIncrease
Depreciation and amortization(a)$9$19
Regulatory required programs18
Regulatory asset amortization12
Total increase$11$29

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

Taxes other than income taxes increased by $4 million and $9 million for the three and six months ended June 30, 2022, respectively, compared to the same period in 2021, primarily due to increased property taxes.

Effective income tax rates were 2.6% and (21.6)% for the three months ended June 30, 2022 and 2021, respectively, and 4.1% and (9.0)% for the six months ended June 30, 2022 and 2021, respectively. The change is primarily due to decreases in the multi-year plans' accelerated income tax benefits in 2022 as compared to 2021. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the three-year electric and natural gas distribution multi-year plans and Note 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 and six months ended June 30, 2022 compared to the same period in 2021. See the Results of Operations for Pepco, DPL, and ACE for additional information.

Three Months Ended June 30,(Unfavorable) VarianceSix Months Ended June 30,(Unfavorable) Favorable Variance
2022202120222021
PHI$100$141$(41)$230$269$(39)
Pepco7075(5)116134(18)
DPL2130(9)7786(9)
ACE1137(26)3751(14)
Other(a)(2)(1)(1)—(2)2

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

Three Months Ended June 30, 2022 Compared to Three Months Ended June 30, 2021. Net Income decreased by $41 million primarily due to the absence of favorable weather and volume as a result of the CIP at ACE, an increase in credit loss expense at Pepco, higher contracting costs partially due to timing of maintenance projects at Pepco, depreciation and amortization expense, and the timing of excess deferred tax amortization at ACE, partially offset by favorable impacts as a result of Pepco's Maryland and District of Columbia multi-year plans and higher electric distribution rates at DPL and ACE.

Six Months Ended June 30, 2022 Compared to Six Months Ended June 30, 2021. Net Income decreased by $39 million primarily due to the absence of favorable weather and volume as a result of the CIP at ACE, an increase in storm costs at Pepco and DPL, credit loss expense at Pepco and DPL, higher contracting costs partially due to timing of maintenance projects at Pepco, depreciation and amortization expense, interest expense, and timing of excess deferred tax amortization at Pepco and ACE, partially offset by favorable impacts as a result of Pepco's Maryland and District of Columbia multi-year plans and higher electric distribution rate at DPL and ACE.

Pepco

Results of Operations — Pepco

Three Months Ended June 30,Favorable (Unfavorable) VarianceSix Months Ended June 30,Favorable (Unfavorable) Variance
2022202120222021
Operating revenues$581$523$58$1,195$1,076$119
Operating expenses
Purchased power162133(29)375298(77)
Operating and maintenance128113(15)260221(39)
Depreciation and amortization10596(9)213199(14)
Taxes other than income taxes9287(5)186177(9)
Total operating expenses487429(58)1,034895(139)
Operating income9494—161181(20)
Other income and (deductions)
Interest expense, net(38)(35)(3)(74)(69)(5)
Other, net1313—26251
Total other income and (deductions)(25)(22)(3)(48)(44)(4)
Income before income taxes6972(3)113137(24)
Income taxes(1)(3)(2)(3)36
Net income$70$75$(5)$116$134$(18)

Three Months Ended June 30, 2022 Compared to Three Months Ended June 30, 2021. Net Income decreased by $5 million primarily due to an increase in depreciation expense, credit loss expense, and higher contracting costs partially due to timing of maintenance projects, partially offset by the favorable impacts of the Maryland and District of Columbia multi-year plans.

Six Months Ended June 30, 2022 Compared to Six Months Ended June 30, 2021. Net income decreased by $18 million primarily due to an increase in depreciation expense, credit loss expense, storm costs, higher contracting costs partially due to timing of maintenance projects, and timing of excess deferred tax amortization, partially offset by the favorable impacts of the Maryland and District of Columbia multi-year plans.

The changes in Operating revenues consisted of the following:

Three Months Ended June 30, 2022Six Months Ended June 30, 2022
IncreaseIncrease
Distribution$20$26
Transmission58
Other4—
2934
Regulatory required programs2985
Total increase$58$119

Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in both Maryland and the District of Columbia are not impacted by abnormal weather or usage per customer as a result of a bill stabilization adjustment (BSA) that provides for a fixed distribution charge per customer by customer class. While Operating revenues are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.

Pepco

As of June 30,
Number of Electric Customers20222021
Residential850,569837,744
Small commercial & industrial54,34953,669
Large commercial & industrial22,77122,579
Public authorities & electric railroads194178
Total927,883914,170

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

Transmission Revenue Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue increased for the three and six months ended June 30, 2022, compared to the same period in 2021, primarily due to increases in capital investment and 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 $29 million and $77 million for the three and six months ended June 30, 2022 compared to the same period in 2021, respectively, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.

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

Three Months Ended June 30, 2022Six Months Ended June 30, 2022
Increase (Decrease)Increase
BSC and PHISCO Costs$7$11
Labor, other benefits, contracting and materials(a)69
Credit loss expense59
Storm-related costs—6
Other(5)2
1337
Regulatory required programs22
Total increase$15$39

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

Pepco

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

Three Months Ended June 30, 2022Six Months Ended June 30, 2022
IncreaseIncrease (Decrease)
Depreciation and amortization(a)$6$11
Regulatory asset amortization2(3)
Regulatory required programs16
Total increase$9$14

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

Effective income tax rates were (1.4)% and (4.2)% for three months ended June 30, 2022 and 2021, respectively, and (2.7)% and 2.2% for the six months ended June 30, 2022 and 2021, respectively. The three months ended June 30, 2022 change is primarily due to the acceleration of certain income tax benefits as a result of the Maryland and District of Columbia multi-year plans. The six months ended June 30, 2022 change is primarily due to the acceleration of certain income tax benefits as a result of the Maryland and District of Columbia multi-year plans, partially offset with the timing of excess deferred tax amortization. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statement for additional information on the three-year electric distribution multi-year plans and Note 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 June 30,Favorable (Unfavorable) VarianceSix Months Ended June 30,Favorable (Unfavorable) Variance
2022202120222021
Operating revenues$332$298$34$763$680$83
Operating expenses
Purchased power and fuel135108(27)324263(61)
Operating and maintenance8880(8)181164(17)
Depreciation and amortization5651(5)113104(9)
Taxes other than income taxes1716(1)3533(2)
Total operating expenses296255(41)653564(89)
Operating income3643(7)110116(6)
Other income and (deductions)
Interest expense, net(17)(16)(1)(33)(30)(3)
Other, net44—66—
Total other income and (deductions)(13)(12)(1)(27)(24)(3)
Income before income taxes2331(8)8392(9)
Income taxes21(1)66—
Net income$21$30$(9)$77$86$(9)

Three Months Ended June 30, 2022 Compared to Three Months Ended June 30, 2021. Net income decreased $9 million primarily due to an increase in depreciation expense and various operating expenses partially offset by higher electric distribution rates.

Six Months Ended June 30, 2022 Compared to Six Months Ended June 30, 2021. Net income decreased $9 million primarily due to an increase in credit loss expense, depreciation expense, and various operating expenses, partially offset by higher electric distribution rates.

The changes in Operating revenues consisted of the following:

Three Months Ended June 30, 2022Six Months Ended June 30, 2022
(Decrease) Increase(Decrease) Increase
ElectricGasTotalElectricGasTotal
Weather$(1)$—$(1)$(1)$—$(1)
Volume(1)21336
Distribution51610313
Transmission(1)—(1)2—2
23514620
Regulatory required programs181129432063
Total increase$20$14$34$57$26$83

Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in Maryland are not impacted by abnormal weather or usage per customer as a result of a bill stabilization adjustment (BSA) that provides for a fixed distribution charge per customer by customer class. While Operating revenues from electric distribution customers in Maryland are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.

Weather. The demand for electricity and natural gas in Delaware is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as "favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces

DPL

demand. During the three and six months ended June 30, 2022 compared to the same period in 2021, Operating revenues related to weather remained relatively consistent.

Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 20-year period in DPL's Delaware electric service territory and a 30-year period in DPL's Delaware natural gas service territory. The changes in heating and cooling degree days in DPL’s Delaware service territory for the three and six months ended June 30, 2022 compared to same period in 2021 and normal weather consisted of the following:

Three Months Ended June 30,% Change
Delaware Electric Service Territory20222021Normal2022 vs. 20212022 vs. Normal
Heating Degree-Days441480471(8.1)%(6.4)%
Cooling Degree-Days328361336(9.1)%(2.4)%
Six Months Ended June 30,% Change
20222021Normal2022 vs. 20212022 vs. Normal
Heating Degree-Days2,7962,8382,951(1.5)%(5.3)%
Cooling Degree-Days331364336(9.1)%(1.5)%
Three Months Ended June 30,% Change
Delaware Natural Gas Service Territory20222021Normal2022 vs. 20212022 vs. Normal
Heating Degree-Days441480492(8.1)%(10.4)%
Six Months Ended June 30,% Change
20222021Normal2022 vs. 20212022 vs. Normal
Heating Degree-Days2,7962,8382,993(1.5)%(6.6)%

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

Electric Retail Deliveries to Delaware Customers (in GWhs)Three Months Ended June 30,% ChangeWeather - Normal % Change**(b)**Six Months Ended June 30,% ChangeWeather - Normal % Change**(b)**
2022202120222021
Residential675703(4.0)%(1.7)%1,5701,5570.8%1.6%
Small commercial & industrial337357(5.6)%(4.8)%7066991.0%1.4%
Large commercial & industrial773810(4.6)%(4.2)%1,5381,4992.6%2.8%
Public authorities & electric railroads810(20.0)%(19.9)%1719(10.5)%(7.9)%
Total electric retail deliveries(a)1,7931,880(4.6)%(3.5)%3,8313,7741.5%2.0%
As of June 30,
Number of Total Electric Customers (Maryland and Delaware)20222021
Residential479,728475,061
Small commercial & industrial63,57462,880
Large commercial & industrial1,2221,213
Public authorities & electric railroads598607
Total545,122539,761

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

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

DPL

Natural Gas Retail Deliveries to Delaware Customers (in mmcf)Three Months Ended June 30,% ChangeWeather - Normal % Change**(b)**Six Months Ended June 30,% ChangeWeather - Normal % Change**(b)**
2022202120222021
Residential98371337.9%44.6%5,4365,1076.4%6.3%
Small commercial & industrial57043032.6%39.2%2,5502,29511.1%12.0%
Large commercial & industrial4023932.3%2.3%8638531.2%1.1%
Transportation1,4441,470(1.8)%(0.7)%3,6503,694(1.2)%(0.7)%
Total natural gas deliveries(a)3,3993,00613.1%16.3%12,49911,9494.6%4.9%
As of June 30,
Number of Delaware Natural Gas Customers20222021
Residential128,715127,503
Small commercial & industrial10,0689,953
Large commercial & industrial1618
Transportation157158
Total138,956137,632

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

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

Distribution Revenue increased for the three and six months ended June 30, 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 remained relatively consistent for the three months ended June 30, 2022 compared to the same period in 2021. Transmission revenue increased for the six months ended June 30, 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.

DPL

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

The increase of $27 million and $61 million for the three and six months ended June 30, 2022, compared to the same period in 2021, respectively, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.

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

Three Months Ended June 30, 2022Six Months Ended June 30, 2022
Increase (Decrease)Increase
BSC and PHISCO costs$4$7
Credit loss expense24
Storm-related costs—3
Labor, other benefits, contracting and materials21
Other(1)—
715
Regulatory required programs12
Total increase$8$17

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

Three Months Ended June 30, 2022Six Months Ended June 30, 2022
IncreaseIncrease (Decrease)
Depreciation and amortization(a)$5$9
Regulatory asset amortization—(1)
Regulatory required programs—1
Total increase$5$9

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

Effective income tax rates were 8.7% and 3.2% for the three months ended June 30, 2022 and 2021, respectively, and 7.2% and 6.5% for the six months ended June 30, 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 June 30,(Unfavorable)Favorable VarianceSix Months Ended June 30,Favorable (Unfavorable) Variance
2022202120222021
Operating revenues$309$319$(10)$658$629$29
Operating expenses
Purchased power1231543130131110
Operating and maintenance8673(13)170150(20)
Depreciation and amortization7240(32)11887(31)
Taxes other than income taxes22—44—
Total operating expenses283269(14)593552(41)
Operating income2650(24)6577(12)
Other income and (deductions)
Interest expense, net(17)(14)(3)(32)(29)(3)
Other, net2—2523
Total other income and (deductions)(15)(14)(1)(27)(27)—
Income before income taxes1136(25)3850(12)
Income taxes—(1)(1)1(1)(2)
Net income$11$37$(26)$37$51$(14)

Three Months Ended June 30, 2022 Compared to Three Months Ended June 30, 2021. Net income decreased by $26 million primarily due to the absence of favorable weather and volume as a result of the CIP, an increase in depreciation expense, various operating expenses, and timing of excess deferred tax amortization, partially offset by increases in distribution rates.

Six Months Ended June 30, 2022 Compared to Six Months Ended June 30, 2021. Net income decreased by $14 million primarily due to the absence of favorable weather and volume as a result of the CIP, an increase in depreciation expense, various operating expenses, and timing of excess deferred tax amortization, partially offset by increases in distribution rates.

The changes in Operating revenues consisted of the following:

Three Months Ended June 30, 2022Six Months Ended June 30, 2022
(Decrease) Increase(Decrease) Increase
Weather$(3)$(3)
Volume(13)(11)
Distribution820
Transmission(3)3
(11)9
Regulatory required programs120
Total (decrease) increase$(10)$29

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

ACE

Weather. Prior to the third quarter of 2021, the demand for electricity was affected by weather conditions. With respect to the electric business, very warm weather in summer months and very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity. Conversely, mild weather reduces demand. During the three and six months ended June 30, 2022 compared to the same period in 2021, Operating revenues related to weather decreased due to the absence of favorable impacts in the first and second quarter of 2022 as a result of the CIP.

Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 20-year period in ACE’s service territory. The changes in heating and cooling degree days in ACE’s service territory for the three and six months ended June 30, 2022 compared to same period in 2021 and normal weather consisted of the following:

Three Months Ended June 30,Normal% Change
Heating and Cooling Degree-Days202220212022 vs. 20212022 vs. Normal
Heating Degree-Days5335255401.5%(1.3)%
Cooling Degree-Days275321305(14.3)%(9.8)%
Six Months Ended June 30,Normal% Change
Heating and Cooling Degree-Days202220212022 vs. 20212022 vs. Normal
Heating Degree-Days2,9692,8732,9943.3%(0.8)%
Cooling Degree-Days277325305(14.8)%(9.2)%

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

Electric Retail Deliveries to Customers (in GWhs)Three Months Ended June 30,% ChangeWeather - Normal % Change**(b)**Six Months Ended June 30,% ChangeWeather - Normal % Change**(b)**
2022202120222021
Residential859975(11.9)%(9.7)%1,7771,903(6.6)%(6.0)%
Small commercial & industrial3623338.7%9.7%7016389.9%9.7%
Large commercial & industrial8087616.2%6.7%1,5111,4772.3%2.3%
Public authorities & electric railroads1111—%(5.8)%25244.2%0.6%
Total electric retail deliveries(a)2,0402,080(1.9)%(0.5)%4,0144,042(0.7)%(0.5)%
As of June 30,
Number of Electric Customers20222021
Residential501,494499,436
Small commercial & industrial62,29161,836
Large commercial & industrial3,0853,243
Public authorities & electric railroads726707
Total567,596565,222

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

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

Distribution Revenue increased for the three and six months ended June 30, 2022 compared to the same period in 2021 due to higher distribution rates that became effective in January 2022.

ACE

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 decreased for the three months ended June 30, 2022 compared to the same period in 2021, primarily due to decreases in underlying costs, partially offset by increases in capital investment. Transmission revenue increased for the six months ended June 30, 2022 compared to the same period in 2021, primarily due to an increase in capital investment.

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 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 $31 million and $10 million for the three and six months ended June 30, 2022 compared to the same period in 2021, respectively, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.

ACE

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

Three Months Ended June 30, 2022Six Months Ended June 30, 2022
IncreaseIncrease
Labor, other benefits, contracting and materials$4$4
BSC and PHISCO costs34
Storm-related costs12
Credit loss expense1—
Other13
1013
Regulatory required programs(a)37
Total increase$13$20

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

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

Three Months Ended June 30, 2022Six Months Ended June 30, 2022
IncreaseIncrease
Depreciation and amortization(a)$4$7
Regulatory asset amortization—1
Regulatory required programs(b)2823
Total increase$32$31

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

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

Effective income tax rates were 0.0% and (2.8)% for the three months ended June 30, 2022 and 2021, respectively, and 2.6% and (2.0)% for the six months ended June 30, 2022 and 2021, respectively. The three and six months ended June 30, 2022 changes primarily reflect the timing of excess deferred tax amortization. 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.

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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 six months ended June 30, 2022 includes one month of cash flows from Generation. The Exelon Consolidated Statement of Cash Flows for the six months ended June 30, 2021 includes six months of cash flows from Generation. This is the primary reason for the changes in cash flows as shown in the tables unless otherwise noted below.

Cash Flows from Operating Activities

The Utility Registrants' cash flows from operating activities primarily result from the transmission and distribution of electricity and, in the case of PECO, BGE, and DPL, gas distribution services. The Utility Registrants' distribution services are provided to an established and diverse base of retail customers. The Utility Registrants' future cash flows may be affected by the economy, weather conditions, future legislative initiatives, future regulatory proceedings with respect to their rates or operations, and their ability to achieve operating cost reductions.

See Note 3 — Regulatory Matters of the 2021 Recast Form 10-K and Notes 3 — Regulatory Matters and 12 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on regulatory and legal proceedings and proposed legislation.

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

Increase (decrease) in cash flows from operating activitiesExelonComEdPECOBGEPHIPepcoDPLACE
Net income (loss)$852$25$68$(20)$(39)$(18)$(9)$(14)
Adjustments to reconcile net income to cash:
Non-cash operating activities(714)(2)1482164573372
Option premiums (paid), net(41)———————
Collateral received, net73258—18840385180137
Income taxes(167)1525—(1)(4)(8)6
Pension and non-pension postretirement benefit contributions(26)(5)212(30)—(1)(4)
Changes in regulatory assets and liabilities, net(100)(86)(10)25(38)22(29)
Changes in working capital and other assets and liabilities1,56625(61)1(46)(16)(7)(17)
Increase in cash flows from operating activities$2,102$30$38$288$413$106$190$151

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 six months ended June 30, 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. Changes in collateral for the Registrants are dependent upon the credit exposure of procurement contracts that may require suppliers to post collateral. The amount of cash collateral received from external counterparties increased due to rising energy prices. See Note 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.

  • See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on regulatory assets and liabilities.

  • Changes in working capital and other assets and liabilities** for the Utility Registrants and Exelon Corporate total $(74) million and for Generation total $1,640 million. The change for Generation primarily relates to the revolving accounts receivable financing arrangement. See Note 6 — Accounts Receivable of the 2021 Form 10-K and the Collection of DPP discussion below for additional information.

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Cash Flows from Investing Activities

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

Increase (decrease) in cash flows from investing activitiesExelonComEdPECOBGEPHIPepcoDPLACE
Capital expenditures$533$(46)$(81)$42$113$37$17$60
Investment in NDT fund sales, net72———————
Collection of DPP(2,040)———————
Proceeds from sales of assets and businesses(708)———————
Changes in intercompany money pool——————(64)—
Other investing activities(13)31(3)541—
(Decrease) increase in cash flows from investing activities$(2,156)$(43)$(80)$39$118$41$(46)$60

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

  • Variances in capital expenditures are primarily due to the timing of cash expenditures for capital projects. See the "Credit Matters and Cash Requirements" section below for additional information on projected capital expenditure spending. See Note 2 — Discontinued Operations of the Combined Notes to Consolidated Financial Statements for capital expenditures related to Generation prior to the separation.

  • Collection of DPP** relates to the revolving accounts receivable financing agreement which Generation entered into in April of 2020. See Note 6 — Accounts Receivable of the 2021 Form 10-K for additional information on the transaction and the DPP, including the $400 million of additional funding received in February and March of 2021.

  • Proceeds from sales of assets and businesses decreased primarily due to the sale of a significant portion of Generation's solar business in 2021. See Note 2 — Mergers, Acquisitions, and Dispositions of the 2021 Form 10-K for additional information.

  • Changes in intercompany money pool are driven by short-term borrowing needs. Refer below for more information regarding the intercompany money pool.

Cash Flows from Financing Activities

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

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Increase (decrease) in cash flows from financing activitiesExelonComEdPECOBGEPHIPepcoDPLACE
Changes in short-term borrowings, net$369$290$210$(130)$(389)$(251)$(3)$(135)
Long-term debt, net1,61950(375)(100)12450—74
Changes in intercompany money pool——40—2964——
Dividends paid on common stock84(36)(31)(4)—(177)7191
Distributions to member————19———
Contributions from(to) parent/member—(60)(168)18614424924(130)
Transfer of cash, restricted cash, and cash equivalents to Constellation(2,594)———————
Other financing activities(50)(1)(4)(1)(4)(4)(1)—
(Decrease) increase in cash flows from financing activities$(572)$243$(328)$(49)$(77)$(69)$27$—

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

  • Changes in short-term borrowings, net**, is driven by repayments on and issuances of notes due in less than 365 days. 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 17 — Commitments and Contingencies of the 2021 Recast 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 six months ended June 30, 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 six months ended June 30, 2022, the following long-term debt was retired and/or redeemed:

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Company**(a)**TypeInterest RateMaturityAmount
ExelonJunior Subordinated Notes3.50%May 2, 2022$1,150
ExelonLong-Term Software License Agreement3.96%May 1, 20242
PECOFirst Mortgage Bonds2.375%September 15, 2022350
PepcoFirst Mortgage Bonds3.05%April 1, 2022200

(a)On July 5, 2022, BGE redeemed $250 million of 2.80% senior notes originally due on August 15, 2022.

Dividends

Quarterly dividends declared by the Exelon Board of Directors during the six months ended June 30, 2022 and for the third quarter of 2022 were as follows:

PeriodDeclaration DateShareholder of Record DateDividend Payable DateCash per Share**(a)**
First Quarter 2022February 8, 2022February 25, 2022March 10, 2022$0.3375
Second Quarter 2022April 26, 2022May 13, 2022June 10, 2022$0.3375
Third Quarter 2022July 26, 2022August 15, 2022September 9, 2022$0.3375

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

Credit Matters and Cash Requirements

The Registrants fund liquidity needs for capital investment, working capital, energy hedging, and other financial commitments through cash flows from continuing operations, public debt offerings, commercial paper markets, and large, diversified credit facilities. The credit facilities include $4.0 billion in aggregate total commitments of which $3.6 billion was available to support additional commercial paper as of June 30, 2022, and of which no financial institution has more than 6% of the aggregate commitments for the Registrants. The Registrants had access to the commercial paper markets and had availability under their revolving credit facilities during the six months ended June 30, 2022 to fund their short-term liquidity needs, when necessary. On February 1, 2022, Exelon Corporate and the Utility Registrants each entered into a new 5-year revolving credit facility that replaced its existing syndicated revolving credit facility. See Note 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 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.

Exelon anticipates issuing up to $1.0 billion of registered shares of common stock through 2025. Exelon plans to establish a $1.0 billion at-the-market (ATM) program, under which Exelon can issue registered shares of common stock through designated broker-dealers at prevailing market prices. Exelon anticipates issuing $500 million in 2022 through the ATM, a one-time common equity offering, or a combination of these methods.

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

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PJM Credit Policy CollateralOther Incremental Collateral Required**(a)**Available Credit Facility Capacity Prior to Any Incremental Collateral
ComEd$12$—$995
PECO237390
BGE375600
Pepco3—257
DPL215300
ACE1—300

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

Capital Expenditure Spending

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

(In millions)TransmissionDistributionGasTotal
ExelonN/AN/AN/A$6,900
ComEd4752,000N/A2,475
PECO2008253251,350
BGE2505004751,225
PHI6251,150751,850
Pepco275625N/A900
DPL15025075475
ACE200275N/A475

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

Pension and Other Postretirement Benefits

Management considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006 (the Act), management of the pension obligation, and regulatory implications. The Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification). The projected contributions reflect a funding strategy to make levelized annual contributions with the objective of achieving 100% funded status on an ABO basis over time. This level funding strategy helps minimize volatility of future period required pension contributions. Post-separation, Exelon's estimated annual qualified pension contributions will be approximately $313 million in 2022. In connection with the separation, additional qualified pension contributions of $207 million and $33 million were completed on February 1, 2022 and March 2, 2022, respectively. Unlike the qualified pension plans, Exelon’s non-qualified pension plans are not funded, given that they are not subject to statutory minimum contribution requirements.

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

Credit Facilities

Exelon Corporate, ComEd, and BGE meet their short-term liquidity requirements primarily through the issuance of commercial paper. PECO meets its short-term liquidity requirements primarily through the issuance of

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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 six months ended June 30, 2022. On January 14, 2022, Fitch lowered Exelon Corporate's long-term and senior unsecured ratings from BBB+ to BBB and affirmed the short-term rating of F2. In addition, Fitch upgraded Pepco, ACE, and PHI's long-term rating from BBB to BBB+ and upgraded Pepco and ACE's senior secured rating from A- to A.

Intercompany Money Pool

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

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During the Six Months Ended June 30, 2022As of June 30, 2022
Exelon Intercompany Money PoolMaximum ContributedMaximum BorrowedContributed (Borrowed)
Exelon Corporate$396$—$287
PECO60(105)—
BSC—(377)(308)
PHI Corporate—(54)(24)
PCI50—45
During the Six Months Ended June 30, 2022As of June 30, 2022
PHI Intercompany Money PoolMaximum ContributedMaximum BorrowedContributed (Borrowed)
Pepco$—$(85)$(73)
DPL85—73

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 June 30, 2022
Short-term Financing AuthorityRemaining Long-term Financing Authority
CommissionExpiration DateAmountCommissionExpiration DateAmount
ComEd(a)FERCDecember 31, 2023$2,500ICCJanuary 1, 2025$1,343
PECO(b)FERCDecember 31, 20231,500PAPUCDecember 31, 20241,550
BGEFERCDecember 31, 2023700MDPSCN/A—
Pepco(c)FERCDecember 31, 2023500MDPSC / DCPSC2022 & 20251,625
DPLFERCDecember 31, 2023500MDPSC / DEPSCDecember 31, 202247
ACE(d)NJBPUDecember 31, 2023350NJBPUDecember 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)As of June 30, 2022, Pepco had $225 million in long-term financing authority from the MDPSC and DCPSC, which has an expiration date of December 31, 2022. On June 9, 2022 and June 30, 2022, Pepco received approval from the MDPSC and DCPSC, respectively, for $1.4 billion in new long-term financing authority. The long-term financing authority became effective on the date of respective approvals and has an expiration date of December 31, 2025.

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

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Previous: Item 1. FINANCIAL STATEMENTS · Next: Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK