Exelon Corp: Form 10-Q for the period ended Jun 30, 2023

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

Exelon

Executive Overview

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

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

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

Financial Results of Operations

GAAP Results of Operations. The following table sets forth Exelon's GAAP consolidated Net income attributable to common shareholders from continuing operations by Registrant for the three and six months ended June 30, 2023 compared to the same period in 2022. For additional information regarding the financial results for the three and six months ended June 30, 2023 and 2022, see the discussions of Results of Operations by Registrant.

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

The separation of Constellation, including Generation and its subsidiaries, meets the criteria for discontinued operations and as such, Generation's results of operations are presented as discontinued operations and have been excluded from Exelon's continuing operations for the three and six months ended June 30, 2022 presented in the table above. See Note 1 — Significant Accounting Policies and Note 2 — Discontinued Operations for additional information.

Accounting rules require that certain BSC costs previously allocated to Generation be presented as part of Exelon’s continuing operations as these costs do not qualify as expenses of the discontinued operations. Such costs are included in Other in the table above and were $28 million on a pre-tax basis, for the six months ended

June 30, 2022. There were no such costs included in Exelon's continuing operations for the three months ended June 30, 2022

Three Months Ended June 30, 2023 Compared to Three Months Ended June 30, 2022. Net income attributable to common shareholders from continuing operations decreased by $122 million and diluted earnings per average common share from continuing operations decreased to $0.34 in 2023 from $0.47 in 2022 primarily due to:

• Higher interest expense at BGE and Exelon Corporate;
• Unfavorable weather at PECO; and
• Higher depreciation expense at PECO.

The decreases were partially offset by:

• The favorable impacts of rate increases at PECO, BGE, and PHI;
• Higher electric distribution formula rate earnings from higher allowed ROE due to an increase in U.S. treasury rates and impacts of higher rate base at ComEd; and
• Carrying costs related to the CMC regulatory assets at ComEd.

Six Months Ended June 30, 2023 Compared to Six Months Ended June 30, 2022. Net income attributable to common shareholders from continuing operations increased by $66 million and diluted earnings per average common share from continuing operations increased to $1.02 in 2023 from $0.96 in 2022 primarily due to:

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

The increases were partially offset by:

• Unfavorable weather at PECO and PHI;
• Higher interest expense at PECO, BGE, and Exelon Corporate;
• An increase in environmental liabilities at PHI;
• Higher contracting costs due to timing at PECO; and
• Higher depreciation expense at PECO.

Adjusted (non-GAAP) Operating Earnings. In addition to Net income, Exelon evaluates its operating performance using the measure of Adjusted (non-GAAP) operating earnings because management believes it represents earnings directly related to the ongoing operations of the business. Adjusted (non-GAAP) operating earnings exclude certain costs, expenses, gains and losses, and other specified items. This information is intended to enhance an investor’s overall understanding of year-to-year operating results and provide an indication of Exelon’s baseline operating performance excluding items that are considered by management to be not directly related to the ongoing operations of the business. In addition, this information is among the primary indicators management uses as a basis for evaluating performance, allocating resources, setting incentive compensation targets, and planning and forecasting of future periods. Adjusted (non-GAAP) operating earnings is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.

The following tables provide a reconciliation between Net income attributable to common shareholders from continuing operations as determined in accordance with GAAP and Adjusted (non-GAAP) operating earnings for the three and six months ended June 30, 2023 compared to the same period in 2022:

(In millions, except per share data)

(In millions, except per share data)

Note:

Amounts may not sum due to rounding.

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

(a) 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.

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

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

(d) 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 2023 Transactions and Developments

Separation

On February 21, 2021, Exelon’s Board of Directors approved a plan to separate the Utility Registrants and Generation, creating two publicly traded companies (“the separation”). Exelon completed the separation on February 1, 2022. Constellation was newly formed and incorporated in Pennsylvania on June 15, 2021 for the purpose of separation and holds Generation. The separation represented a strategic shift that would have a major effect on Exelon’s operations and financial results. Accordingly, the separation met the criteria for discontinued operations. See Note 2 — Discontinued Operations of the Combined Notes to Consolidated Financial Statements for additional information on the separation and discontinued operations.

In connection with the separation, Exelon incurred separation costs impacting continuing operations of $7 million and $14 million on a pre-tax basis for the three months ended June 30, 2023 and 2022, respectively, and $5 million and $38 million on a pre-tax basis for the six months ended June 30, 2023 and 2022, respectively, which are recorded in Operating and maintenance expense. Total separation costs impacting continuing operations for the remainder of 2023 are not expected to be material. These costs are excluded from Adjusted (non-GAAP) Operating Earnings. The separation costs are primarily comprised of system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the separation, and employee-related severance costs.

Distribution Base Rate Case Proceedings

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

The following tables show the Utility Registrants’ completed and pending distribution base rate case proceedings in 2023. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Completed Distribution Base Rate Case Proceedings

Pending Distribution Base Rate Case Proceedings

Transmission Formula Rates

For 2023, 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.

ComEd's FERC Audit

The Utility Registrants are subject to periodic audits by FERC. FERC’s Division of Audits and Accounting initiated a nonpublic audit of ComEd in April 2021 evaluating ComEd’s compliance with (1) approved terms, rates and conditions of its federally regulated service; (2) accounting requirements of the Uniform System of Accounts; (3) reporting requirements of the FERC Form 1; and (4) the requirements for record retention. The audit covered the period from January 1, 2017 to present. During the first quarter of 2023, ComEd was provided with information from FERC about several potential findings, including ComEd's methodology regarding the allocation of certain overhead costs to capital under FERC regulations. Based on the preliminary findings and discussions with FERC staff, ComEd determined that a loss was probable and recorded a regulatory liability to reflect its best estimate of that loss as of March 31, 2023.

On July 27, 2023, FERC issued a final audit report which included, among other things, findings and recommendations related to ComEd's methodology regarding the allocation of certain overhead costs to capitalized construction costs under FERC regulations. ComEd disagrees with various findings and recommendations in the audit report, as indicated in ComEd's public reply to the report. The final outcome and resolution of any contested audit issues as well as a reasonable estimate of potential future losses cannot be accurately estimated at this stage; however, the final resolution of these matters could result in recognition of future losses, above the amounts currently accrued, that could be material to the Exelon and ComEd financial statements. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Other Key Business Drivers and Management Strategies

The following discussion of other key business drivers and management strategies includes current developments of previously disclosed matters and new issues arising during the period that may impact future financial statements. This section should be read in conjunction with ITEM 1. Business in the 2022 Form 10-K, ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations — Other Key Business Drivers and Management Strategies in the 2022 Form 10-K, and Note 12 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in this report for additional information on various environmental matters.

Legislative and Regulatory Developments

City of Chicago Franchise Agreement

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

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

Infrastructure Investment and Jobs Act

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

In September 2022, ComEd and BGE applied for the MMG, which establishes and funds construction, improvement, or acquisition of middle mile broadband infrastructure which creates high-speed internet services. The MMG addresses inequitable broadband access by expansion and extension of the middle mile infrastructure in underserved communities. In June 2023, the National Telecommunications and Information Administration (NTIA) announced it selected two of the applications submitted by BGE and ComEd; awarding ComEd and BGE $14.5 million and $15.4 million respectively. The applications selected by NTIA for BGE and ComEd proposed projects designed to enhance electric grid reliability and resiliency while leading and advancing shared local, state, and national goals to increase broadband connectivity, redundancy, affordability, and equity.

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

The Registrants are supporting three different Regional Clean Hydrogen Hub opportunities, covering all five states that Exelon operates in plus Washington D.C. under a program that will create networks of hydrogen producers, consumers, and local connective infrastructure to accelerate the use of hydrogen as a clean energy carrier that can deliver or store energy. Applications for the three opportunities under this program were submitted in April 2023. The selection process is expected to be highly competitive, and therefore, the Registrants cannot predict how many of their total applications will be approved as filed or the precise timing of receiving any funds if they are awarded a grant.

PJM Regional Transmission Expansion

On April 6, 2023, PJM received a deactivation notice for Brandon Shores, a 1,282 MW coal generation plant located in BGE service territory. The deactivation was requested for June 1, 2025 and will result in numerous reliability issues across the region. In June 2023, PJM assigned a portion of transmission system upgrades to mitigate these reliability impacts to PECO, BGE and Pepco. In July 2023, PJM Board of Managers approved assigning Exelon transmission system upgrades to mitigate these reliability impacts to PECO, BGE and Pepco. The projected capital expenditures associated with these upgrades are approximately $140 million, $650 million, and $80 million for PECO, BGE and Pepco, respectively, and are expected to be completed by the end of 2028.

Separately, PJM held a competitive transmission proposal window from February 24, 2023 through May 31, 2023 to address reliability issues driven by significant load increases in northern Virginia. PECO, BGE and Pepco submitted four solution proposals, with projected capital expenditures ranging from approximately $322 million to $2.26 billion. PJM is expected to approve the solution in December 2023. The selection process is expected to be highly competitive, and therefore, PECO, BGE, and Pepco cannot predict which, if any, of their solution proposals will be selected by PJM.

Critical Accounting Policies and Estimates

Management of each of the Registrants makes a number of significant estimates, assumptions, and judgments in the preparation of its financial statements. As of June 30, 2023, the Registrants’ critical accounting policies and estimates had not changed significantly from December 31, 2022. See ITEM 7. MANAGEMENT'S DISCUSSION

AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates in the 2022 Form 10-K for further information.

Results of Operations by Registrant

Results of Operations — ComEd

Three Months Ended June 30, 2023 Compared to Three Months Ended June 30, 2022. Net income increased by $22 million as compared to the same period in 2022, primarily due to increases in electric distribution formula rate earnings (reflecting higher allowed ROE due to an increase in U.S. Treasury rates and the impacts of higher rate base) and carrying costs related to the CMC regulatory assets.

Six Months Ended June 30, 2023 Compared to Six Months Ended June 30, 2022. Net income increased by $74 million as compared to the same period in 2022, primarily due to increases in electric distribution formula rate earnings (reflecting higher allowed ROE due to an increase in U.S. Treasury rates and the impacts of higher rate base) and carrying costs related to the CMC regulatory assets.

The changes in Operating revenues consisted of the following:

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

Distribution Revenue. EIMA and FEJA provide for a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs that the ICC determines are prudently and reasonably incurred in a given year. Electric distribution revenue varies from year to year based upon fluctuations

ComEd

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, 2023 as compared to the same period in 2022, due to higher allowed ROE due to an increase in U.S. Treasury rates, the impact of a higher rate base, and higher fully recoverable costs.

Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered, and the highest daily peak load, which is updated annually in January based on the prior calendar year. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue.

Energy Efficiency Revenue. FEJA provides for a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs that the ICC determines are prudently and reasonably incurred in a given year. Under FEJA, energy efficiency revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered, and allowed ROE. Energy efficiency revenue increased for the three and six months ended June 30, 2023 as compared to the same period in 2022, primarily due to increased regulatory asset amortization, which is fully recoverable.

Other Revenue primarily includes assistance provided to other utilities through mutual assistance programs. Other revenue increased for the three and six months ended June 30, 2023 as compared to the same period in 2022, which primarily reflects mutual assistance revenues associated with storm restoration efforts.

Regulatory Required Programs represents revenues collected under approved riders to recover costs incurred for regulatory programs such as recoveries under the credit loss expense tariff, environmental costs associated with MGP sites, ETAC, and costs related to electricity, ZEC, CMC, and REC procurement. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding CMCs. ETAC is a retail customer surcharge collected by electric utilities operating in Illinois established by CEJA and remitted to an Illinois state agency for programs to support clean energy jobs and training. The riders are designed to provide full and current cost recovery. The costs of these programs are included in Purchased power expense, Operating and maintenance expense, Depreciation and amortization expense and Taxes other than income. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries as ComEd remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, ComEd either acts as the billing agent or the competitive supplier separately bills its own customers, and therefore does not record Operating revenues or Purchased power expense related to the electricity. For customers that choose to purchase electric generation from ComEd, ComEd is permitted to recover the electricity, ZEC, CMC, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power expense related to the electricity, ZECs, CMCs, and RECs.

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

The increase of $402 million and $251 million for the three and six months ended June 30, 2023 compared to the same period in 2022, in Purchased power expense is primarily due to the CMCs from the participating nuclear-powered generating facilities including the deferral of any associated carrying costs. This increase is primarily offset by an increase in Operating revenues as part of regulatory required programs. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding CMCs.

ComEd

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

(a) 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:

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

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

Interest expense, net increased by $16 million and $33 million for the three and six months ended June 30, 2023, compared to the same period in 2022, primarily due to an increase in interest rates and the issuance of debt during the year.

Effective income tax rates were 22.2% and 22.5% for the three months ended June 30, 2023 and 2022, respectively, and 22.5% and 22.3% for the six months ended June 30, 2023 and 2022, respectively. See Note 7 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

PECO

Results of Operations — PECO

Three Months Ended June 30, 2023 Compared to Three Months Ended June 30, 2022. Net income decreased by $36 million primarily due to unfavorable weather and increase in depreciation and amortization expense, partially offset by an increase in gas distribution rates.

Six Months Ended June 30, 2023 Compared to Six Months Ended June 30, 2022. Net income decreased by $76 million, primarily due to unfavorable weather and increases in operating expenses, depreciation and amortization expense, and interest expense, partially offset by an increase in gas distribution rates.

The changes in Operating revenues consisted of the following:

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 and six months ended June 30, 2023 compared to the same period in 2022, Operating revenues related to weather decreased by the impact of unfavorable weather conditions in PECO's service territory.

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

PECO

PECO’s service territory for the three and six months ended June 30, 2023 compared to the same period in 2022 and normal weather consisted of the following:

Volume. Electric volume, exclusive of the effects of weather, for the three and six months ended June 30, 2023 compared to the same period in 2022, remained relatively consistent. Natural gas volume for the three and six months ended June 30, 2023 compared to the same period in 2022, remained relatively consistent.

(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.

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PECO

(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, 2023 compared to the same period in 2022 increased primarily due to an increase in gas distribution rates charged to customers.

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

Other revenue primarily includes revenue related to late payment charges. Other revenue for the three and six months ended June 30, 2023 compared to the same period in 2022 remained relatively consistent.

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

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

The increase of $97 million and $19 million for the three and six months ended June 30, 2023 compared to the same period in 2022, in Purchased power and fuel expense is offset in Operating revenues as part of regulatory required programs.

PECO

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

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

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

Interest expense, net increased $5 million and $13 million for the three and six months ended June 30, 2023, compared to the same period in 2022, primarily due to an increase in interest rates and the issuance of debt in 2022.

Effective income tax rates were 2.0% and 6.3% for the three months ended June 30, 2023 and 2022, respectively, and 1.9% and 6.6% for the six months ended June 30, 2023 and 2022, respectively. See Note 7 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

BGE

Results of Operations — BGE

Three Months Ended June 30, 2023 Compared to Three Months Ended June 30, 2022. Net income increased $5 million primarily due to favorable impacts of the multi-year plans, partially offset by an increase in interest expense. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the three-year electric and natural gas distribution multi-year plans.

Six Months Ended June 30, 2023 Compared to Six Months Ended June 30, 2022. Net Income increased $7 million primarily due to favorable impacts of the multi-year plans, partially offset by an increase in interest expense. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the three-year electric and natural gas distribution multi-year plans.

The changes in Operating revenues consisted of the following:

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

Distribution Revenue increased for the three and six months ended June 30, 2023, compared to the same period in 2022, due to favorable impacts of the multi-year plans.

Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue increased for the three and six months ended June 30, 2023, compared to the same period in 2022, primarily due to increases in underlying costs and capital investments.

Other Revenue includes revenue related to late payment, charges, mutual assistance, off-system sales, and service application fees. Other Revenue remained relatively the same for the three and six months ended June 30, 2023 compared to the same period in 2022.

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 decrease of $17 million and increase of $21 million for the three and six months ended June 30, 2023 compared to the same period in 2022, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.

BGE

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

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

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

Interest expense, net increased by $8 million and $17 million for the three and six months ended June 30, 2023, respectively compared to the same period in 2022, primarily due to an increase in interest rates and the issuance of debt in 2023 and 2022.

Taxes other than income taxes increased by $5 million and $11 million for the three and six months ended June 30, 2023, respectively, compared to the same period in 2022, primarily due to increased property taxes.

Effective income tax rates were 22.2% and 2.6% for the three months ended June 30, 2023 and 2022 respectively, and 21.2% and 4.1% for the six months ended June 30, 2023 and 2022, respectively. See Note 7 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

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, 2023 compared to the same period in 2022. See the Results of Operations for Pepco, DPL, and ACE for additional information.

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

Three Months Ended June 30, 2023 Compared to Three Months Ended June 30, 2022. Net Income increased by $3 million primarily due to favorable impacts of the Pepco Maryland and DPL Maryland multi-year plans, higher distribution rates at DPL Delaware, higher transmission rates at Pepco and ACE, and a decrease in various operating expenses, partially offset by an increase in environmental liabilities at Pepco.

Six Months Ended June 30, 2023 Compared to Six Months Ended June 30, 2022. Net Income increased by $28 million primarily due to favorable impacts of the Pepco Maryland and DPL Maryland multi-year plans, customer growth in the District of Columbia and Maryland, timing of decoupling revenues in the District of Columbia, higher distribution rates at DPL Delaware, and higher transmission rates at Pepco and ACE, partially offset by an increase in environmental liabilities at Pepco, and unfavorable weather conditions at DPL Delaware electric and natural gas service territories.

Pepco

Results of Operations — Pepco

Three Months Ended June 30, 2023 Compared to Three Months Ended June 30, 2022. Net Income decreased by $6 million primarily due to an increase in environmental liabilities, partially offset by higher transmission rates and favorable impacts of the Pepco Maryland multi-year plan.

Six Months Ended June 30, 2023 Compared to Six Months Ended June 30, 2022. Net Income increased by $14 million primarily due to favorable impacts of the Maryland multi-year plan, timing of decoupling revenues in the District of Columbia, higher transmission rates and customer growth in the District of Columbia and Maryland, partially offset by an increase in environmental liabilities.

The changes in Operating revenues consisted of the following:

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

Pepco

Distribution Revenue increased for the three months ended June 30, 2023 compared to the same period in 2022 primarily due to higher rates due to the expiration of customer offsets and favorable impacts of the Maryland multi-year plan. Distribution revenue increased for the six months ended June 30, 2023 compared to the same period in 2022 primarily due to favorable impacts of the Maryland multi-year plan, higher rates due to the expiration of customer offsets, timing of decoupling revenues in the District of Columbia, and customer growth in the District of Columbia and Maryland.

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 both the three and six months ended June 30, 2023, compared to the same period in 2022, 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 $42 million and $87 million for the three and six months ended June 30, 2023 compared to the same period in 2022, respectively, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.

Pepco

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

(a) Primarily reflects an increase in environmental liabilities for the six months ended June 30, 2023.

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

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

Interest expense, net increased by $5 million and $7 million for the three and six months ended June 30, 2023 compared to the same period in 2022, respectively, primarily due to the issuance of debt in 2023.

Other, net increased by $3 million and $7 million for the three and six months ended June 30, 2023 compared to the same period in 2022, respectively, primarily due to higher AFUDC equity.

Effective income tax rates were 13.5% and (1.4)% for the three months ended June 30, 2023 and 2022, respectively, and 14.5% and (2.7)% for the six months ended June 30, 2023 and 2022, respectively. See Note 7 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

DPL

Results of Operations — DPL

Three Months Ended June 30, 2023 Compared to Three Months Ended June 30, 2022. Net income increased $4 million primarily due to favorable impacts of the Maryland multi-year plan, and higher Delaware electric and natural gas distribution rates, partially offset by unfavorable weather conditions at Delaware electric and natural gas service territories.

Six Months Ended June 30, 2023 Compared to Six Months Ended June 30, 2022. Net income increased $8 million primarily due to favorable impacts of the Maryland multi-year plan, and higher Delaware electric and natural gas distribution rates, partially offset by unfavorable weather conditions at Delaware electric and natural gas service territories.

The changes in Operating revenues consisted of the following:

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

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

DPL

weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the three and six months ended June 30, 2023 compared to the same period in 2022, Operating revenues related to weather decreased due to unfavorable weather conditions in Delaware electric and natural gas service territories.

Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 20-year period in the Delaware electric service territory and a 30-year period in the Delaware natural gas service territory. The changes in heating and cooling degree days in the Delaware service territory for the three and six months ended June 30, 2023 compared to same period in 2022 and normal weather consisted of the following:

Volume, exclusive of the effects of weather, remained consistent for the three months ended June 30, 2023 compared to the same period in 2022 and decreased for the six months ended June 30, 2023 compared to the same period in 2022 primarily due to customer usage, partially offset by customer growth.

131

DPL

(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.

(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 both the three and six months ended June 30, 2023 compared to the same period in 2022 primarily due to favorable impacts of the Maryland multi-year plan that became effective in January 2023, higher natural gas distribution rates effective in August 2022, and higher electric DSIC rates in Delaware that became effective in January 2023.

Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. During the three and six months ended June 30, 2023 compared to the same period in 2022, transmission revenue increased primarily due to increases in underlying costs.

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, 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 $4 million and $36 million for the three and six months ended June 30, 2023, compared to the same period in 2022, respectively, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.

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

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

(a) For the three months ended June 30, 2023, reflects ongoing capital expenditures and higher transmission depreciation rates effective September 2022. For the six months ended June 30, 2023, reflects ongoing capital expenditures, higher distribution depreciation rates in Maryland effective March 2022, and higher transmission depreciation rates effective September 2022.

Effective income tax rates were 16.7% and 8.7% for the three months ended June 30, 2023 and 2022, respectively, and 16.7% and 7.2% for the six months ended June 30, 2023 and 2022, respectively. See Note 7 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

ACE

Results of Operations — ACE

Three Months Ended June 30, 2023 Compared to Three Months Ended June 30, 2022. Net income increased by $7 million primarily due to higher transmission rates and decreases in various operating expenses.

Six Months Ended June 30, 2023 Compared to Six Months Ended June 30, 2022. Net income increased by $14 million primarily due to higher transmission rates and decreases in various operating expenses.

The changes in Operating revenues consisted of the following:

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

ACE

Distribution Revenue increased for both the three and six months ended June 30, 2023 compared to the same period in 2022 due to higher distribution rates primarily due to the expiration of customer credits related to the TCJA tax benefits.

Transmission Revenues. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue increased for both the three and six months ended June 30, 2023 compared to the same period in 2022, primarily due to increases in underlying costs and capital investment.

Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, Societal Benefits Charge, Transition Bond Charge, and BGS procurement and administrative costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Purchased power expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries, as ACE remains the distribution service provider for all customers and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation from competitive suppliers, ACE acts as the billing agent and therefore, ACE does not record Operating revenues or Purchased power expense related to the electricity. For customers that choose to purchase electric generation from ACE, ACE is permitted to recover the electricity, ZEC, and REC procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power expense related to the electricity, ZECs, and RECs.

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

The increase of $1 million and decrease of $28 million for the three and six months ended June 30, 2023 compared to the same period in 2022, 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:

(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:

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

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

Effective income tax rates were 25.0% and 0.0% for the three months ended June 30, 2023 and 2022, respectively, and 25.0% and 2.6% for the six months ended June 30, 2023 and 2022, respectively. See Note 7 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

Liquidity and Capital Resources (All Registrants)

All results included throughout the liquidity and capital resources section are presented on a GAAP basis.

The Registrants’ operating and capital expenditures requirements are provided by internally generated cash flows from operations, as well as funds from external sources in the capital markets and through bank borrowings. The Registrants’ businesses are capital intensive and require considerable capital resources. Each of the Registrants annually evaluates its financing plan, dividend practices, and credit line sizing, focusing on maintaining its investment grade ratings while meeting its cash needs to fund capital requirements, including construction expenditures, retire debt, pay dividends, and fund pension and OPEB obligations. The Registrants spend a significant amount of cash on capital improvements and construction projects that have a long-term return on investment. Additionally, the Utility Registrants operate in rate-regulated environments in which the amount of new investment recovery may be delayed or limited and where such recovery takes place over an extended period of time. Each Registrant’s access to external financing on reasonable terms depends on its credit ratings and current overall capital market business conditions, including that of the utility industry in general. If these conditions deteriorate to the extent that the Registrants no longer have access to the capital markets at reasonable terms, the Registrants have access to credit facilities with aggregate bank commitments of $4.0 billion. The Registrants utilize their credit facilities to support their commercial paper programs, provide for other short-term borrowings, and to issue letters of credit. See the “Credit Matters and Cash Requirements” section below for additional information. The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs, and capital expenditure requirements. See Note 10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt and credit agreements.

Cash flows related to Generation have not been presented as discontinued operations and are included in the Consolidated Statements of Cash Flows for only 2022. The Exelon Consolidated Statement of Cash Flows for the six months ended June 30, 2022 includes one month of cash flows from Generation.

Cash Flows from Operating Activities

The Utility Registrants' cash flows from operating activities primarily result from the transmission and distribution of electricity and, in the case of PECO, BGE, and DPL, gas distribution services. The Utility Registrants' distribution services are provided to an established and diverse base of retail customers. The Utility Registrants' future cash flows may be affected by the economy, weather conditions, future legislative initiatives, future regulatory proceedings with respect to their rates or operations, and their ability to achieve operating cost reductions. Additionally, ComEd is required to purchase CMCs from participating nuclear-powered generating facilities for a five-year period that began in June 2022, and all of its costs of doing so will be recovered through a rider. The price to be paid for each CMC is established through a competitive bidding process. ComEd will provide net payments to, or collect net payments from, customers for the difference between customer credits issued and the credit to be received from the participating nuclear-powered generating facilities. ComEd’s cash flows are affected by the establishment of CMC prices and the timing of recovering costs through the CMC regulatory asset.

See Note 3 — Regulatory Matters of the 2022 Form 10-K and Notes 3 — Regulatory Matters and 12 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on regulatory and legal proceedings and proposed legislation.

The following table provides a summary of the change in cash flows from operating activities for the six months ended June 30, 2023 and 2022 by Registrant:

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, 2023 and 2022 were as follows:

• See Note 15 — Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements and the Registrants’ Consolidated Statements of Cash Flows for additional information on non-cash operating activities.
• Changes in collateral depended upon whether Generation was in a net mark-to-market liability or asset position, and collateral may have been required to be posted with or collected from its counterparties. In addition, the collateral posting and collection requirements differed depending on whether the transactions were on an exchange or in the over-the-counter markets. Changes in collateral for the Registrants are dependent upon the credit exposure of procurement contracts that may require suppliers to post collateral. The amount of cash collateral received from external counterparties decreased due to decreasing energy prices. See Note 9 — Derivative Financial Instruments for additional information.
• See Note 7 — Income Taxes of the Combined Notes to Consolidated Financial Statements and the Registrants' Consolidated Statements of Cash Flows for additional information on income taxes.
• Changes in Pension and non-pension postretirement benefit contributions relate to Exelon's funding strategy and incremental contributions made in 2022 in connection with the separation. See Note 14 — Retirement Benefits of the 2022 Form 10-K for additional information.
• Changes in regulatory assets and liabilities, net, are due to the timing of cash payments for costs recoverable, or cash receipts for costs recovered, under our regulatory mechanisms differs from the recovery period of those costs. Included within the changes is energy efficiency spend for ComEd of $192 million and $115 million for the six months ended June 30, 2023 and 2022, respectively. Also included within the changes is energy efficiency and demand response programs spend for BGE, Pepco, DPL and ACE of $66 million, $32 million, $12 million, and $8 million for the six months ended June 30, 2023 and $53 million, $33 million, $13 million, and $4 million for the six months ended June 30, 2022, respectively. PECO had no energy efficiency and demand response programs spend recorded to the regulatory asset for the six months ended June 30, 2023 and

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

• Changes in working capital and other assets and liabilities for the Utility Registrants and Exelon Corporate totaled $476 million and for Generation total $323 million. The change for Generation primarily relates to the revolving accounts receivable financing arrangement which was entered into in April 2020. The change in working capital and other noncurrent assets and liabilities for Exelon Corporate and the Utility Registrants is dependent upon the normal course of operations for all Registrants. For ComEd, it is also dependent upon whether the participating nuclear-powered generating facilities are owed money from ComEd as a result of the established pricing for CMCs. For the six months ended June 30, 2023, the established pricing resulted in ComEd owing payments to nuclear-powered generating facilities, which is reported within the cash flows from operations as a change in accounts payable and accrued expense.

Cash Flows from Investing Activities

The following table provides a summary of the change in cash flows from investing activities for the six months ended June 30, 2023 and 2022 by Registrant:

Significant investing cash flow impacts for the Registrants for six months ended June 30, 2023 and 2022 were as follows:

• Changes in capital expenditures are primarily due to the timing of cash expenditures for capital projects. See the "Credit Matters and Cash Requirements" section below for additional information on projected capital expenditure spending for the Utility Registrants. See Note 2 — Discontinued Operations of the Combined Notes to Consolidated Financial Statements for capital expenditures related to Generation prior to the separation.
• Collection of DPP relates to Generation's revolving accounts receivable financing agreement which Generation entered into in April 2020.
• Changes in intercompany money pool are driven by short-term borrowing needs. Refer to more information regarding the intercompany money pool below.

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, 2023 and 2022 by Registrant:

Significant financing cash flow impacts for the Registrants for the six months ended June 30, 2023 and 2022 were as follows:

• Changes in short-term borrowings, net, is driven by repayments on and issuances of notes due in less than 365 days. See Note 10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on short-term borrowings for the Registrants.
• Long-term debt, net, varies due to debt issuances and redemptions each year. See Note 10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on debt issuances. Refer to the debt redemptions table below for additional information.
• Changes in intercompany money pool are driven by short-term borrowing needs. Refer below for more information regarding the intercompany money pool.
• Exelon’s ability to pay dividends on its common stock depends on the receipt of dividends paid by its operating subsidiaries. The payments of dividends to Exelon by its subsidiaries in turn depend on their results of operations and cash flows and other items affecting retained earnings. See Note 18 — Commitments and Contingencies of the 2022 Form 10-K for additional information on dividend restrictions. See below for quarterly dividends declared.
• Refer to Note 2 — Discontinued Operations for the transfer of cash, restricted cash, and cash equivalents to Constellation related to the separation.

Debt

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

During the six months ended June 30, 2023, the following long-term debt was retired and/or redeemed:

Dividends

Quarterly dividends declared by the Exelon Board of Directors during the six months ended June 30, 2023 and for the second quarter of 2023 were as follows:

(a) Exelon's Board of Directors approved an updated dividend policy for 2023. The 2023 quarterly dividend will be $0.36 per share.

Credit Matters and Cash Requirements

The Registrants fund liquidity needs for capital investment, working capital, energy hedging, and other financial commitments through cash flows from continuing operations, public debt offerings, commercial paper markets, and large, diversified credit facilities. The credit facilities include $4.0 billion in aggregate total commitments of which $3.7 billion was available to support additional commercial paper as of June 30, 2023, and of which no financial institution has more than 6% of the aggregate commitments for the Registrants. The Registrants had access to the commercial paper markets and had availability under their revolving credit facilities during the six months ended June 30, 2023 to fund their short-term liquidity needs, when necessary. Exelon Corporate and the Utility Registrants each have a 5-year revolving credit facility. See Note 10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. The Registrants routinely review the sufficiency of their liquidity position, including appropriate sizing of credit facility commitments, by performing various stress test scenarios, such as commodity price movements, increases in margin-related transactions, changes in hedging levels, and the impacts of hypothetical credit downgrades. The Registrants have continued to closely monitor events in the financial markets and the financial institutions associated with the credit facilities, including monitoring credit ratings and outlooks, credit default swap levels, capital raising, and merger activity. See PART I. ITEM 1A. RISK FACTORS of the 2022 Form 10-K for additional information regarding the effects of uncertainty in the capital and credit markets.

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

On August 4, 2022, Exelon executed an equity distribution agreement (“Equity Distribution Agreement”) with certain sales agents and forward sellers and certain forward purchasers establishing an ATM equity distribution program under which it may offer and sell shares of its common stock, having an aggregate gross sales price of up to $1.0 billion. Exelon has no obligation to offer or sell any shares of common stock under the Equity Distribution Agreement and may at any time suspend or terminate offers and sales under the Equity Distribution Agreement. As of June 30, 2023, Exelon has not issued any shares of common stock under the ATM program and has not entered into any forward sale agreements.

The following table presents the incremental collateral that each Utility Registrant would have been required to provide in the event each Utility Registrant lost its investment grade credit rating at June 30, 2023 and available credit facility capacity prior to any incremental collateral at June 30, 2023:

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

Capital Expenditure Spending

As of June 30, 2023, the most recent estimates of capital expenditures for plant additions and improvements for 2023 are as follows:

(In millions)

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

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

Retirement Benefits

Management considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006 (the Act), management of the pension obligation, and regulatory implications. The Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification). The projected contributions reflect a funding strategy to make annual contributions with the objective of achieving 100% funded status on an ABO basis over time. This funding strategy helps minimize volatility of future period required pension contributions. Exelon’s estimated annual qualified pension contributions will be $20 million in 2023. Unlike the qualified pension plans, Exelon’s non-qualified pension plans are not funded, given that they are not subject to statutory minimum contribution requirements.

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

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

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

Credit Facilities

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

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

Security Ratings

The Registrants’ access to the capital markets, including the commercial paper market, and their respective financing costs in those markets, may depend on the securities ratings of the entity that is accessing the capital markets.

The Registrants’ borrowings are not subject to default or prepayment as a result of a downgrading of securities, although such a downgrading of a Registrant’s securities could increase fees and interest charges under that Registrant’s credit agreements.

As part of the normal course of business, the Registrants enter into contracts that contain express provisions or otherwise permit the Registrants and their counterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable contracts law, if the Registrants are downgraded by a credit rating agency, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance, which could include the posting of collateral. See Note 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral provisions.

The credit ratings for the Registrants did not change for the six months ended June 30, 2023. On July 26, 2023, S&P raised ComEd's long-term issuer credit rating from 'BBB+' to a 'A-'. S&P also affirmed the current 'A' rating on ComEd's senior secured debt and 'A-2' short-term rating, which influences long and short-term borrowing cost.

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, 2023, are presented in the following table:

Shelf Registration Statements

Exelon and the Utility Registrants have a currently effective combined shelf registration statement, unlimited in amount, that will expire in August 2025. The ability of each Registrant to sell securities off the shelf registration statement or to access the private placement markets will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, as applicable, the current financial condition of the Registrant, its securities ratings and market conditions.

Regulatory Authorizations

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

(a) On June 29, 2023, ComEd filed an application for $2 billion in new money long-term debt financing authority from the ICC and expects approval by December 31, 2023.

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

(c) The financing authority filed with MDPSC does not have an expiration date, while the financing authority filed with DCPSC and DEPSC have an expiration date of December 31, 2025.

(d) On July 14, 2023, ACE filed an application with the NJBPU for renewal of their short-term financing authority through January 1, 2026. ACE expects approval of their application by December 31, 2023.

The Registrants hold commodity and financial instruments that are exposed to the following market risks:

• Commodity price risk, which is discussed further below.
• Counterparty credit risk associated with non-performance by counterparties on executed derivative instruments and participation in all, or some of the established, wholesale spot energy markets that are administered by PJM. The credit policies of PJM may, under certain circumstances, require that losses arising from the default of one member on spot energy market transactions be shared by the remaining participants. See Note 9 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for a detailed discussion of counterparty credit risk related to derivative instruments.
• Equity price and interest rate risk associated with Exelon’s pension and OPEB plan trusts. See Note 8 — Retirement Benefits of the 2022 Form 10-K for additional information.
• Interest rate risk associated with changes in interest rates for the Registrants’ outstanding long-term debt. This risk is significantly reduced as substantially all of the Registrants’ outstanding debt has fixed interest rates. There is inherent interest rate risk related to refinancing maturing debt by issuing new long-term debt. The Registrants use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. See Note 10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. In addition, Exelon may utilize interest rate derivatives to lock in rate levels in anticipation of future financings, which are typically designated as cash flow hedges, or to lock in rate levels on borrowings, which are typically designated as economic hedges. See Note 9 – Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
• Electric operating revenues risk associated with ComEd's distribution formula rate. ComEd's ROE for its electric distribution service through 2023 is directly correlated to yields on U.S. Treasury bonds. Exelon Corporate may utilize interest rate derivatives to mitigate volatility and manage risk to Exelon, which are typically accounted for as economic hedges. See Note 9 – Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.

The Registrants operate primarily under cost-based rate regulation limiting exposure to the effects of market risk. Hedging programs are utilized to reduce exposure to energy and natural gas price volatility and have no direct earnings impacts as the costs are fully recovered through regulatory-approved recovery mechanisms.

Exelon manages these risks through risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of risk exposures. Risk management issues are reported to Exelon’s Executive Committee, the Risk Management Committees of each Utility Registrant, and the Audit and Risk Committee of Exelon’s Board of Directors.

Commodity Price Risk

Commodity price risk is associated with price movements resulting from changes in supply and demand, fuel costs, market liquidity, weather conditions, governmental regulatory and environmental policies, and other factors. To the extent the total amount of energy Exelon purchases differs from the amount of energy it has contracted to sell, Exelon is exposed to market fluctuations in commodity prices. Exelon seeks to mitigate its commodity price risk through the sale and purchase of electricity and natural gas.

ComEd entered into 20-year floating-to-fixed renewable energy swap contracts beginning in June 2012, which are considered an economic hedge and have changes in fair value recorded to an offsetting regulatory asset or liability. ComEd has block energy contracts to procure electric supply that are executed through a competitive procurement process, which are considered derivatives and qualify for NPNS, and as a result are accounted for on an accrual basis of accounting. PECO, BGE, Pepco, DPL, and ACE have contracts to procure electric supply that are executed through a competitive procurement process. PECO, BGE, Pepco, DPL, and ACE have certain full requirements contracts, which are considered derivatives and qualify for NPNS, and as a result are accounted for on an accrual basis of accounting. Other full requirements contracts are not derivatives.

PECO, BGE, and DPL also have executed derivative natural gas contracts, which qualify for NPNS, to hedge their long-term price risk in the natural gas market. The hedging programs for natural gas procurement have no direct impact on their financial statements.

For additional information on these contracts, see Note 9 — Derivative Financial Instruments and Note 11 — Fair Value of Financial Assets and Liabilities of the Combined Notes to Consolidated Financial Statements.

The following table presents the maturity and source of fair value for Exelon’s and ComEd’s mark-to-market commodity contract net liabilities. These net liabilities are associated with ComEd’s floating-to-fixed energy swap contracts with unaffiliated suppliers. The table provides two fundamental pieces of information. First, the table provides the source of fair value used in determining the carrying amount of Exelon's and ComEd's total mark-to-market net liabilities. Second, the table shows the maturity, by year, of Exelon's and ComEd's commodity contract net liabilities giving an indication of when these mark-to-market amounts will settle and either generate or require cash. See Note 11 — Fair Value of Financial Assets and Liabilities of the Combined Notes to Consolidated Financial Statements for additional information regarding fair value measurements and the fair value hierarchy.

(a) Represents ComEd's net liabilities associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.

During the second quarter of 2023, each of the Registrants' management, including its principal executive officer and principal financial officer, evaluated its disclosure controls and procedures related to the recording, processing, summarizing, and reporting of information in its periodic reports that it files with the SEC. These disclosure controls and procedures have been designed by the Registrants to ensure that (a) material information relating to that Registrant, including its consolidated subsidiaries, is accumulated and made known to that Registrant's management, including its principal executive officer and principal financial officer, by other employees of that Registrant and its subsidiaries as appropriate to allow timely decisions regarding required disclosure, and (b) this information is recorded, processed, summarized, evaluated, and reported, as applicable, within the time periods specified in the SEC’s rules and forms. Due to the inherent limitations of control systems, not all misstatements may be detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls could be circumvented by the individual acts of some persons or by collusion of two or more people.

Accordingly, as of June 30, 2023, the principal executive officer and principal financial officer of each of the Registrants concluded that such Registrant’s disclosure controls and procedures were effective to accomplish its objectives. The Registrants continually strive to improve their disclosure controls and procedures to enhance the quality of its financial reporting and to maintain dynamic systems that change as conditions warrant. There were no changes in internal control over financial reporting during the second quarter of 2023 that materially affected, or are reasonably likely to materially affect, any of the Registrants' internal control over financial reporting.

Risks Related to All Registrants

At June 30, 2023, the Registrants' risk factors were consistent with the risk factors described in the 2022 Form 10-K in ITEM 1A. RISK FACTORS.