Regulatory Matters (All Registrants)

12 Months Ended

Dec. 31, 2022

Regulated Operations [Abstract]

Regulatory Matters (All Registrants)

Regulatory Matters (All Registrants)

The following matters below discuss the status of material regulatory and legislative proceedings of the Registrants.

Distribution Base Rate Case Proceedings

The following tables show the completed and pending distribution base rate case proceedings in 2022.

Completed Distribution Base Rate Case Proceedings

Registrant/Jurisdiction	Filing Date	Service	Requested Revenue Requirement Increase		Approved Revenue Requirement Increase		Approved ROE	Approval Date	Rate Effective Date
ComEd - Illinois(a)	April 16, 2021	Electric	$	51	$	46	7.36%	December 1, 2021	January 1, 2022
	April 15, 2022	Electric	199		199		7.85%	November 17, 2022	January 1, 2023
PECO - Pennsylvania	March 30, 2021	Electric	246		132		N/A(b)	November 18, 2021	January 1, 2022
	March 31, 2022	Natural Gas	82		55			October 27, 2022	January 1, 2023
BGE - Maryland(c)	May 15, 2020 (amended September 11, 2020)	Electric	203		140		9.50%	December 16, 2020	January 1, 2021
		Natural Gas	108		74		9.65%
Pepco - District of Columbia(d)	May 30, 2019 (amended June 1, 2020)	Electric	136		109		9.275%	June 8, 2021	July 1, 2021
Pepco - Maryland(e)	October 26, 2020 (amended March 31, 2021)	Electric	104		52		9.55%	June 28, 2021	June 28, 2021
DPL - Maryland	September 1, 2021 (amended December 23, 2021)(f)	Electric	27		13		9.60%	March 2, 2022	March 2, 2022
	May 19, 2022(g)	Electric	38		29		9.60%	December 14, 2022	January 1, 2023
DPL - Delaware	January 14, 2022 (amended August 15, 2022)	Natural Gas	13		8		9.60%	October 12, 2022	August 14, 2022
ACE - New Jersey(h)	December 9, 2020 (amended February 26, 2021)	Electric	67		41		9.60%	July 14, 2021	January 1, 2022

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(a)Pursuant to EIMA and FEJA, ComEd’s electric distribution rates are established through a performance-based formula, which sunsets at the end of 2022. See discussion of CEJA below for details on the transition away from the electric distribution formula rate. The electric distribution formula rate includes decoupling provisions and, as a result, ComEd's electric distribution formula rate revenues are not impacted by abnormal weather, usage per customer, or number of customers. Under the performance-based formula, ComEd filed annual updates to its electric distribution formula rate on or before May 1st, with resulting rates effective in January of the following year. ComEd’s annual electric distribution formula rate update is based on prior year actual costs and current year projected capital additions (initial year revenue requirement). The update also reconciles any differences between the revenue requirement in effect for the prior year and actual costs incurred from the year (annual reconciliation).

ComEd’s 2022 approved revenue requirement reflects an increase of $37 million for the initial year revenue requirement for 2022 and an increase of $9 million related to the annual reconciliation for 2020. The revenue requirement for 2022 provides for a weighted average debt and equity return on distribution rate base of 5.72% inclusive of an allowed ROE of 7.36%, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. The reconciliation revenue requirement for 2020 provides for a weighted average debt and equity return on distribution rate base of 5.69%, inclusive of an allowed ROE of 7.29%, reflecting the monthly yields on 30-year treasury bonds plus 580 basis points less a performance metrics penalty of 7 basis points.

ComEd’s 2023 approved revenue requirement above reflects an increase of $144 million for the initial year revenue requirement for 2023 and an increase of $55 million related to the annual reconciliation for 2021. The revenue requirement for 2023 provides for a weighted average debt and equity return on distribution rate base of 5.94% inclusive of an allowed ROE of 7.85%, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. The reconciliation revenue requirement for 2021 provides for a weighted average debt and equity return on distribution rate base of 5.91%, inclusive of an allowed ROE of 7.78%, reflecting the monthly yields on 30-year treasury bonds plus 580 basis points less a performance metrics penalty of 7 basis points. This is ComEd's last performance-based electric distribution formula rate update filing under EIMA. See discussion of CEJA below for details on the transition away from the electric distribution formula rate.

(b)The PECO electric and natural gas base rate case proceedings were resolved through settlement agreements, which did not specify an approved ROE.

(c)Reflects a three-year cumulative multi-year plan for 2021 through 2023. BGE proposed to use certain tax benefits to fully offset the increases in 2021 and 2022 and partially offset the increase in 2023. The MDPSC awarded BGE electric revenue requirement increases of $59 million, $39 million, and $42 million, before offsets, in 2021, 2022, and 2023, respectively, and natural gas revenue requirement increases of $53 million, $11 million, and $10 million, before offsets, in 2021, 2022, and 2023, respectively. However, the MDPSC utilized the tax benefits to fully offset the increases in 2021 and January 2022 such that customer rates remained unchanged. For the remainder of 2022, the MDPSC chose to offset only 25% of the cumulative 2021 and 2022 electric revenue requirement increases and 50% of the cumulative gas revenue requirement increases. In 2021, the MDPSC deferred a decision on whether to use certain tax benefits to offset the revenue requirement increases in 2023 and directed BGE to make another proposal at the end of 2022. In September 2022 BGE proposed that tax benefits not be used to offset the 2023 revenue requirement increases. On October 26, 2022, the MDPSC accepted BGE's recommendation to not use tax benefits to offset the 2023 revenue requirement increases.

(d)Reflects a cumulative multi-year plan with 18-months remaining in 2021 through 2022. The DCPSC awarded Pepco electric incremental revenue requirement increases of $42 million and $67 million, before offsets, for 2021 and 2022, respectively. However, the DCPSC utilized the acceleration of refunds for certain tax benefits along with other rate relief to partially offset the customer rate increases by $22 million and $40 million for 2021 and 2022, respectively.

(e)Reflects a three-year cumulative multi-year plan for April 1, 2021 through March 31, 2024. The MDPSC awarded Pepco electric incremental revenue requirement increases of $21 million, $16 million, and $15 million, before offsets, for the 12-month periods ending March 31, 2022, 2023, and 2024, respectively. Pepco proposed to utilize certain tax benefits to fully offset the increase through 2023 and partially offset customer rate increases in 2024. However, the MDPSC only utilized the acceleration of refunds for certain tax benefits to fully offset the increases such that customer rates remain unchanged through March 31, 2022. On February 23, 2022, the MDPSC chose to offset 25% of the cumulative revenue requirement increase through March 31, 2023. Whether certain tax benefits will be used to offset the customer rate increases for the twelve months ended March 31, 2024 has not been decided, and Pepco cannot predict the outcome.

(f)The approved settlement reflects a 9.60% ROE, which is solely for the purposes of calculating AFUDC and regulatory asset carrying costs.

(g)Reflects a three-year cumulative multi-year plan for January 1, 2023 through December 31, 2025. The MDPSC awarded DPL electric incremental revenue requirement increases of $17 million, $6 million, and $6 million for 2023, 2024, and 2025, respectively.

(h)Requested and approved increases are before New Jersey sales and use tax. The order allows ACE to retain approximately $11 million of certain tax benefits which resulted in a decrease to income tax expense in Exelon's, PHI's, and ACE's Consolidated Statements of Operations and Comprehensive Income in the third quarter of 2021.

Pending Distribution Base Rate Case Proceedings

Registrant/Jurisdiction	Filing Date	Service	Requested Revenue Requirement Increase		Requested ROE	Expected Approval Timing
ComEd - Illinois(a)	January 17, 2023	Electric	$	1,472	10.50% to 10.65%	Fourth quarter of 2023
DPL - Delaware(b)	December 15, 2022	Electric	60		10.50%	Second quarter of 2024

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(a)Reflects a four-year cumulative MRP for January 1, 2024 to December 31, 2027 and total requested revenue requirement increases of $877 million effective January 1, 2024, $175 million effective January 1, 2025, $217 million effective January 1, 2026, and $203 million effective January 1, 2027, based on forecasted revenue requirements. The revenue requirement will provide for a weighted average debt and equity return on distribution rate base of 7.43% in 2024, 7.50% in 2025, 7.62% in 2026, and 7.70% in 2027, inclusive of an allowed ROE of 10.50% in 2024, 10.55% in 2025, 10.60% in 2026, and 10.65% in 2027. The requested revenue requirements are based on capital structures that reflect between 50.58% and 51.19% common equity. ComEd’s MRP also includes a proposed rate phase-in to defer approximately $307 million of the $877 million year-over-year increase for 2024 revenue from 2024 to 2026.

(b)The rates will go into effect on July 15, 2023, subject to refund.

Transmission Formula Rates

The Utility Registrants' transmission rates are each established based on a FERC-approved formula. ComEd, BGE, Pepco, DPL, and ACE are required to file an annual update to the FERC-approved formula on or before May 15, and PECO is required to file on or before May 31, with the resulting rates effective on June 1 of the same year. The annual update for ComEd is based on prior year actual costs and current year projected capital additions (initial year revenue requirement). The update for ComEd also reconciles any differences between the revenue requirement in effect beginning June 1 of the prior year and actual costs incurred for that year (annual reconciliation). The annual update for PECO is based on prior year actual costs and current year projected capital additions, accumulated depreciation, and accumulated deferred income taxes. The annual update for BGE, Pepco, DPL, and ACE is based on prior year actual costs and current year projected capital additions, accumulated depreciation, depreciation and amortization expense, and accumulated deferred income taxes. The update for PECO, BGE, Pepco, DPL, and ACE also reconciles any differences between the actual costs and actual revenues for the calendar year (annual reconciliation).

For 2022, the following total increases/(decreases) were included in the Utility Registrants' electric transmission formula rate updates:

Registrant(a)	Initial Revenue Requirement Increase		Annual Reconciliation (Decrease) Increase		Total Revenue Requirement Increase			Allowed Return on Rate Base(b)		Allowed ROE(c)
ComEd	$	24	$	(24)	$	—		8.11	%	11.50	%
PECO	23		16		39			7.30	%	10.35	%
BGE	25		(4)		16		(d)	7.30	%	10.50	%
Pepco	16		15		31			7.60	%	10.50	%
DPL	9		2		11			7.09	%	10.50	%
ACE	21		13		34			7.18	%	10.50	%

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(a)All rates are effective June 1, 2022 - May 31, 2023, subject to review by interested parties pursuant to review protocols of each Utility Registrants' tariff.

(b)Represents the weighted average debt and equity return on transmission rate bases. For ComEd and PECO, the common equity component of the ratio used to calculate the weighted average debt and equity return on the transmission formula rate base is currently capped at 55% and 55.75%, respectively.

(c)The rate of return on common equity for each Utility Registrant includes a 50-basis-point incentive adder for being a member of a RTO.

(d)The increase in BGE's transmission revenue requirement includes a $5 million reduction related to a FERC-approved dedicated facilities charge to recover the costs of providing transmission service to specifically designated load by BGE.

Other State Regulatory Matters

Illinois Regulatory Matters

CEJA (Exelon and ComEd). On September 15, 2021, the Governor of Illinois signed into law CEJA. CEJA includes, among other features, (1) procurement of CMCs from qualifying nuclear-powered generating facilities, (2) a requirement to file a general rate case or a new four-year MRP no later than January 20, 2023 to establish rates effective after ComEd’s existing performance-based distribution formula rate sunsets, (3) an extension of and certain adjustments to ComEd’s energy efficiency MWh savings goals, (4) revisions to the Illinois RPS requirements, including expanded charges for the procurement of RECs from wind and solar generation, (5) a requirement to accelerate amortization of ComEd’s unprotected excess deferred income taxes (EDIT) that ComEd was previously directed by the ICC to amortize using the average rate assumption method which equates to approximately 39.5 years, and (6) requirements that ComEd and the ICC initiate and conduct various regulatory proceedings on subjects including ethics, spending, grid investments, and performance metrics. Regulatory or legal challenges regarding the validity or implementation of CEJA are possible and Exelon and ComEd cannot reasonably predict the outcome of any such challenges.

ComEd Electric Distribution Rates

ComEd filed, and received approval for, its last performance-based electric distribution formula rate update filing under EIMA in 2022; those rates are in effect throughout 2023.

On February 3, 2022, the ICC approved a tariff that establishes the process under which ComEd will reconcile its 2022 and 2023 rate year revenue requirements with actual costs. Those reconciliation amounts will be determined using the same process as were used for prior reconciliations under the performance-based electric distribution formula rate. Using that process, for the rate years 2022 and 2023 ComEd will ultimately collect revenues from customers reflecting each year’s actual recoverable costs, year-end rate base, and a weighted average debt and equity return on distribution rate base, with the ROE component based on the annual average of the monthly yields of the 30-year U.S. Treasury bonds plus 580 basis points. ComEd will in 2023 file with the ICC the first such petition to reconcile its 2022 actual costs with the approved revenue requirement that was in effect in 2022. The rate year 2023 reconciliation will be filed in 2024.

Beginning in 2024, ComEd will recover from retail customers, subject to certain exceptions, the costs it incurs to provide electric delivery services either through its electric distribution rate or other recovery mechanisms authorized by CEJA. On January 17, 2023, ComEd filed a petition with the ICC seeking approval of a MRP for 2024-2027. The MRP supports a multi-year grid plan (Grid Plan), also filed on January 17, covering planned investments on the electric distribution system within ComEd’s service area through 2027. Costs incurred during each year of the multi-year plan are subject to ICC review and the plan’s revenue requirement for each year will be reconciled with the actual costs that the ICC determines are prudently and reasonably incurred for that year. The reconciliation is subject to adjustment for certain costs, including a limitation on recovery of costs that are more than 105% of certain costs in the previously approved MRP revenue requirement, absent a modification of the rate plan itself. Thus, for example, the rate adjustments necessary to reconcile 2024 revenues to ComEd’s actual 2024 costs incurred would take effect in January 2026 after the ICC’s review during 2025. The ICC must issue its decision on both the MRP and Grid Plan by mid-December 2023, for rates to begin with the January 2024 billing cycle.

In January 2022, ComEd filed a request with the ICC proposing performance metrics that would be used in determining ROE incentives and penalties in the event ComEd filed a MRP in January 2023. On September 27, 2022, the ICC issued a final order approving seven performance metrics that provide symmetrical performance adjustments of 32 total basis points to ComEd’s rate of return on common equity based on the extent to which ComEd achieves the annual performance goals. On November 10, 2022, the ICC granted ComEd's application for rehearing, in part. Rehearing on those issues must conclude by April 9, 2023. It is unclear if rehearing will result in modifications to the ICC-approved performance and tracking metrics. ComEd will make its initial filing in 2025 to assess performance achieved under the metrics in 2024, and to determine any ROE adjustment, which would take effect in 2026.

Carbon Mitigation Credit

CEJA establishes decarbonization requirements for Illinois as well as programs to support the retention and development of emissions-free sources of electricity. ComEd is required to purchase CMCs from participating

nuclear-powered generating facilities between June 1, 2022 and May 31, 2027. The price to be paid for each CMC was established through a competitive bidding process that included consumer-protection measures that capped the maximum acceptable bid amount and a formula that reduces CMC prices by an energy price index, the base residual auction capacity price in the ComEd zone of PJM, and the monetized value of any federal tax credit or other subsidy if applicable. The consumer protection measures contained in CEJA will result in net payments to ComEd ratepayers if the energy index, the capacity price and applicable federal tax credits or subsidy exceed the CMC contract price. ComEd began issuing credits to its retail customers under its new CMC rider in the June 2022 billing period and recorded a regulatory asset of $843 million as of December 31, 2022 for the difference between customer credits issued and the credit to be received from the participating nuclear-powered generating facilities.

Under CEJA, the costs of procuring CMCs will be recovered through a new rider, the Rider Carbon-Free Resource Adjustment (Rider CFRA). The Rider CFRA provides for an annual reconciliation and true-up to actual costs incurred or credits received by ComEd to purchase CMCs, with any difference to be credited to or collected from ComEd’s retail customers in subsequent periods. The difference between the net payments to (or receivables from) ComEd ratepayers and the credits received by ComEd to purchase CMCs is recorded to Purchased Power expense with an offset to the regulatory asset (or regulatory liability). On December 21, 2022, ComEd filed a supplemental statement to the Rider CFRA proposing that the company recover costs or provide credits faster than the tariff allows, implement monthly reconciliations, and allow the Company to adjust Rider CFRA rates based not only on anticipated differences but also past payments or credits. The ICC approved the proposal on January 19, 2023. If the revised CFRA tariff were in effect as of the balance sheet date, the current portion of the CMC regulatory asset balance would have increased by $117 million as of December 31, 2022, with an offsetting reduction in the noncurrent regulatory asset balance.

Excess Deferred Income Taxes

The ICC initiated a docket to accelerate and fully credit to customers TCJA unprotected property-related EDIT no later than December 31, 2025. On July 7, 2022, the ICC issued a final order on the schedule for the acceleration of EDIT amortization, adopting the proposal as submitted by several parties, including ComEd, ICC Staff, the Illinois Attorney General's Office, and the Citizens Utility Board. EDIT amortization will be credited to customers through a new rider from January 1, 2023 through December 31, 2025.

Beneficial Electrification Plan

On July 1, 2022, ComEd filed a proposed plan to promote beneficial electrification efforts in its Northern Illinois service area with the ICC as required by CEJA. ComEd's plan is designed to meaningfully reduce barriers to beneficial electrification, including those related to electric vehicles (EVs), such as upfront technology adoption costs, charging costs, and charging availability; promote equity and environmental justice; reduce carbon emissions and surface-level pollutants; and support customer education and awareness of electrification options. As proposed, ComEd could expend approximately $300 million in total over the three-year period 2023 through 2025. The beneficial electrification plan requests recovery of all those costs through a rider mechanism, under which certain of the costs would be amortized over ten years with a return on the unrecovered balance. On November 10, 2022, in responses to a Staff motion, the ICC approved an interim order dismissing from ComEd’s Beneficial Electrification Plan certain rebates (rebates to support residential customers’ purchase of EVs; and rebates to ComEd’s commercial and industrial customers to support the installation of EV chargers). However, the ICC found that building electrification measures were properly within the scope of beneficial electrification, in line with ComEd’s proposal. The ICC also adopted ComEd’s position regarding the rate impact of spending associated with EV related infrastructure. On November 21, 2022, ComEd filed an application for rehearing of the interim order, which the ICC denied. On December 9, 2022, the Office of the Illinois Attorney General (AG) also sought rehearing. On December 15, 2022, ComEd filed an appeal of the ICC’s interim order and the denial of rehearing with the Illinois Appellate Court. That appeal has been stayed pending the resolution of the balance of the case. Also on December 15, 2022, the ICC denied the AG’s application for rehearing and the AG subsequently filed an appeal. The testimony and hearing phase of this proceeding has concluded and the parties are now drafting legal briefs on the contested issues. By law the ICC must issue its decision by the end of March, therefore, a final order is expected to be issued by the ICC no later than the first quarter of 2023. At this time, ComEd cannot predict the outcome of these proceedings.

Energy Efficiency

CEJA extends ComEd’s current cumulative annual energy efficiency MWh savings goals through 2040, adds expanded electrification measures to those goals, increases low-income commitments and adds a new performance adjustment to the energy efficiency formula rate. ComEd expects its annual spend to increase in 2023 through 2040 to achieve these energy efficiency MWh savings goals, which will be deferred as a separate regulatory asset that will be recovered through the energy efficiency formula rate over the weighted average useful life, as approved by the ICC, of the related energy efficiency measures.

Energy Efficiency Formula Rate (Exelon and ComEd). FEJA allows ComEd to defer energy efficiency costs (except for any voltage optimization costs which are recovered through the electric distribution formula rate) as a separate regulatory asset that is recovered through the energy efficiency formula rate over the weighted average useful life, as approved by the ICC, of the related energy efficiency measures. ComEd earns a return on the energy efficiency regulatory asset at a rate equal to its weighted average cost of capital, which is based on a year-end capital structure and calculated using the same methodology applicable to ComEd’s electric distribution formula rate. Beginning January 1, 2018 through December 31, 2030, the ROE that ComEd earns on its energy efficiency regulatory asset is subject to a maximum downward or upward adjustment of 200 basis points if ComEd’s cumulative persisting annual MWh savings falls short of or exceeds specified percentage benchmarks of its annual incremental savings goal. ComEd is required to file an update to its energy efficiency formula rate on or before June 1st each year, with resulting rates effective in January of the following year. The annual update is based on projected current year energy efficiency costs, PJM capacity revenues, and the projected year-end regulatory asset balance less any related deferred income taxes (initial year revenue requirement). The update also reconciles any differences between the revenue requirement in effect for the prior year and actual costs incurred from the year (annual reconciliation). The approved energy efficiency formula rate also provides for revenue decoupling provisions similar to those in ComEd’s electric distribution formula rate.

During 2022, the ICC approved the following total increases in ComEd's requested energy efficiency revenue requirement:

Filing Date	Requested Revenue Requirement Increase		Approved Revenue Requirement Increase(a)		Approved ROE		Approval Date	Rate Effective Date
May 25, 2022	$	50	$	50	7.85	%	October 27, 2022	January 1, 2023

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(a)ComEd’s 2023 approved revenue requirement above reflects an increase of $66 million for the initial year revenue requirement for 2023 and a decrease of $16 million related to the annual reconciliation for 2021. The revenue requirement for 2023 provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 5.94% inclusive of an allowed ROE of 7.85%, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. The revenue requirement for the 2021 reconciliation year provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 5.52% inclusive of an allowed ROE of 6.99%, which includes a downward performance adjustment that decreased the ROE. The performance adjustment can either increase or decrease the ROE based upon the achievement of energy efficiency savings goals. See table below for ComEd's regulatory assets associated with its energy efficiency formula rate.

Maryland Regulatory Matters

Maryland Revenue Decoupling (Exelon, BGE, PHI, Pepco, and DPL). In 1998, the MDPSC approved natural gas monthly rate adjustments for BGE and in 2007, the MDPSC approved electric monthly rate adjustments for BGE and BSAs for Pepco and DPL, all of which are decoupling mechanisms. As a result of the decoupling mechanisms, certain Operating revenues from electric and natural gas distribution at BGE and Operating revenues from electric distribution at Pepco Maryland (see also District of Columbia Revenue Decoupling below for Pepco District of Columbia) and DPL are not impacted by abnormal weather or usage per customer. For BGE, Pepco, and DPL, the decoupling mechanism eliminates the impacts of abnormal weather or customer usage by recognizing revenues based on an authorized distribution amount per customer by customer class. Operating revenues from electric and natural gas distribution at BGE and Operating revenues from electric distribution at Pepco Maryland and DPL are, however, impacted by changes in the number of customers.

Maryland Order Directing the Distribution of Energy Assistance Funds (Exelon, BGE, PHI, Pepco, and DPL). On June 15, 2021, the MDPSC issued an order authorizing the disbursal of funds to utilities in accordance with Maryland COVID-19 relief legislation. Under this order, BGE, Pepco, and DPL received funds of $50 million,

$12 million, and $8 million, respectively, in July 2021. The funds have been used to reduce or eliminate certain qualifying past-due residential customer receivables.

District of Columbia Regulatory Matters

District of Columbia Revenue Decoupling (Exelon, PHI, and Pepco). In 2009, the DCPSC approved a BSA, which is a decoupling mechanism. As a result of the decoupling mechanism, Operating revenues from electric distribution at Pepco District of Columbia (see also Maryland Revenue Decoupling above for Pepco Maryland) are not impacted by abnormal weather or usage per customer. The decoupling mechanism eliminates the impacts of abnormal weather or customer usage by recognizing revenues based on an authorized distribution amount per customer by customer class. Operating revenues from electric distribution at Pepco District of Columbia are, however, impacted by changes in the number of customers.

New Jersey Regulatory Matters

Conservation Incentive Program (CIP) (Exelon, PHI, and ACE). On September 25, 2020, ACE filed an application with the NJBPU as was required seeking approval to implement a portfolio of energy efficiency programs pursuant to New Jersey’s clean energy legislation. The filing included a request to implement a CIP that would eliminate the favorable and unfavorable impacts of weather and customer usage patterns on distribution revenues for most customers. 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.

On April 27, 2021, the NJBPU approved the settlement filed by ACE and the third parties to the proceeding. The approved settlement addresses all material aspects of ACE’s filing, including ACE’s ability to implement the CIP prospectively effective July 1, 2021. As a result of this decoupling mechanism, operating revenues will no longer be impacted by abnormal weather or usage for most customers. Starting in third quarter of 2021, ACE will record alternative revenue program revenues for its best estimate of the distribution revenue impacts resulting from future changes in CIP rates that it believes are probable of approval by the NJBPU in accordance with this mechanism.

Termination of Energy Procurement Provisions of PPAs (Exelon, PHI, and ACE). On December 22, 2021, ACE filed with the NJBPU a petition to terminate the provisions in the PPAs to purchase electricity from two coal-powered generation facilities located in the state of New Jersey. The petition was approved by the NJBPU on March 23, 2022. Upon closing of the transaction on March 31, 2022, ACE recognized a liability of $203 million for the contract termination fee, which is to be paid by the end of 2024, and recognized a corresponding regulatory asset of $203 million.

As of December 31, 2022, the $137 million liability for the contract termination fee consists of $87 million and $50 million included in Other current liabilities and Other deferred credits and other liabilities, respectively, in Exelon's Consolidated Balance Sheet. The current and noncurrent liabilities are included in PPA termination obligation and Other deferred credits and other liabilities, respectively, in PHI's and ACE's Consolidated Balance Sheets. For the year ended December 31, 2022, ACE has paid $66 million of the liability, which is recorded in Changes in Other assets and liabilities in Exelon's, PHI's, and ACE's Consolidated Statements of Cash Flows.

ACE Infrastructure Investment Program Filings (Exelon, PHI, and ACE). On February 28, 2018, ACE filed with the NJBPU the company’s IIP proposing to seek recovery of a series of investments through a new rider mechanism, totaling $338 million, between 2019-2022 to provide safe and reliable service for its customers. The IIP will allow for more timely recovery of investments made to modernize and enhance ACE’s electric system. On April 15, 2019, ACE entered into a settlement agreement with other parties, which allows for a recovery totaling $96 million of reliability related capital investments from July 1, 2019 through June 30, 2023. On April 18, 2019, the NJBPU approved the settlement agreement.

On October 31, 2022, ACE filed with the NJBPU the company’s second IIP, proposing to seek recovery through a new component of ACE’s rider mechanism, totaling $379 million, over the four-year period of July 1, 2023 to June 30, 2027. The new IIP will allow ACE to invest in projects that are designed to enhance the reliability, resiliency, and safety of the service ACE provides to its customers. ACE has requested that the NJBPU render a

decision in this matter during the first half of 2023 but cannot predict if the NJBPU will approve the application as filed.

Advanced Metering Infrastructure Filing (Exelon, PHI, and ACE). On August 26, 2020, ACE filed an application with the NJBPU as was required seeking approval to deploy a smart energy network in alignment with New Jersey’s Energy Master Plan and Clean Energy Act. The proposal consisted of estimated costs totaling $220 million with deployment taking place over a 3-year implementation period from approximately 2021 to 2024 that involves the installation of an integrated system of smart meters for all customers accompanied by the requisite communications facilities and data management systems.

On July 14, 2021, the NJBPU approved the settlement filed by ACE and the third parties to the proceeding. The approved settlement addresses all material aspects of ACE's smart energy network deployment plan, including cost recovery of the investment costs, incremental O&M expenses, and the unrecovered balance of existing infrastructure through future distribution rates.

New Jersey Clean Energy Legislation (Exelon, PHI, and ACE). On May 23, 2018, New Jersey enacted legislation that established and modified New Jersey’s clean energy and energy efficiency programs and solar and RPS. On the same day, New Jersey enacted legislation that established a ZEC program that provides compensation for nuclear plants that demonstrate to the NJBPU that they meet certain requirements. Under the legislation, the NJBPU will issue ZECs to the qualifying nuclear power plants and the electric distribution utilities in New Jersey, including ACE, will be required to purchase those ZECs. ACE began collecting from retail distribution customers, through a non-bypassable charge, all costs associated with the procurement of the ZECs effective April 18, 2019.

Other Federal Regulatory Matters

Transmission-Related Income Tax Regulatory Assets (Exelon, ComEd, BGE, PHI, Pepco, DPL, and ACE). On December 13, 2016 (and as amended on March 13, 2017), BGE filed with FERC to begin recovering certain existing and future transmission-related income tax regulatory assets through its transmission formula rate. BGE’s existing regulatory assets included (1) amounts that, if BGE’s transmission formula rate provided for recovery, would have been previously amortized and (2) amounts that would be amortized and recovered prospectively. On November 16, 2017, FERC issued an order rejecting BGE’s proposed revisions to its transmission formula rate to recover these transmission-related income tax regulatory assets. In the fourth quarter of 2017, ComEd, BGE, Pepco, DPL, and ACE fully impaired their associated transmission-related income tax regulatory assets for the portion of the income tax regulatory assets that would have been previously amortized.

On February 23, 2018 (as amended on July 9, 2018), ComEd, Pepco, DPL, and ACE each filed with FERC to revise their transmission formula rate mechanisms to permit recovery of transmission-related income tax regulatory assets, including those amounts that would have been previously amortized and recovered through rates had the transmission formula rate provided for such recovery.

On September 7, 2018, FERC issued orders rejecting (1) BGE’s rehearing request of FERC's November 16, 2017 order and (2) the February 23, 2018 (as amended on July 9, 2018) filing by ComEd, Pepco, DPL, and ACE for similar recovery.

On November 2, 2018, BGE filed an appeal of FERC's September 7, 2018 order to the U.S. Court of Appeals for the D.C. Circuit. On March 27, 2020, the U.S. Court of Appeals for the D.C. Circuit Court denied BGE’s November 2, 2018 appeal.

On October 1, 2018, ComEd, BGE, Pepco, DPL, and ACE submitted filings to recover ongoing non-TCJA amortization amounts and credit TCJA transmission-related income tax regulatory liabilities to customers for the prospective period starting on October 1, 2018. On April 26, 2019, FERC issued an order accepting ComEd's, BGE's, Pepco's, DPL's, and ACE's October 1, 2018 filings, effective October 1, 2018, subject to refund and established hearing and settlement judge procedures. On April 24, 2020, ComEd, BGE, Pepco, DPL, ACE, and other parties filed a settlement agreement with FERC, which FERC approved on September 24, 2020. The settlement agreement provides for the recovery of ongoing transmission-related income tax regulatory assets and establishes the amount and amortization period for excess deferred income taxes resulting from TCJA. The settlement resulted in a reduction to Operating revenues and an offsetting reduction to Income tax expense in the second quarter of 2020.

FERC Audit (Exelon and ComEd). The Registrants are subject to periodic audits and investigations by FERC. FERC’s Division of Audits and Accounting initiated a nonpublic audit of ComEd in May 2021 evaluating ComEd’s compliance with (1) approved terms, rates and conditions of its transmission formula rate mechanism; (2) accounting requirements of the Uniform System of Accounts; (3) reporting requirements of the FERC Form 1; and (4) the requirements for record retention. The audit covered the period from January 1, 2017 through August 31, 2022. On January 17, 2023, ComEd was provided with information on a series of potential findings, including concerning ComEd's methodology regarding the allocation of certain overhead costs to capital under FERC regulations. The final outcome and resolution of the findings or of the audit itself cannot be predicted and the results, while not reasonably estimable at this time, could be material to the Exelon and ComEd financial statements.

Regulatory Assets and Liabilities

Regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent the excess recovery of costs or accrued credits that have been deferred because it is probable such amounts will be returned to customers through future regulated rates or represent billings in advance of expenditures for approved regulatory programs.

The following tables provide information about the regulatory assets and liabilities of the Registrants as of December 31, 2022 and 2021:

December 31, 2022	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory assets
Pension and OPEB	$	1,867	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Pension and OPEB - merger related	769		—		—		—		—		—		—		—
Deferred income taxes	606		—		595		—		11		11		—		—
AMI programs - deployment costs	122		—		—		69		53		25		22		6
AMI programs - legacy meters	160		48		—		20		92		53		17		22
Electric distribution formula rate annual reconciliations	271		271		—		—		—		—		—		—
Electric distribution formula rate significant one-time events	115		115		—		—		—		—		—		—
Energy efficiency costs	1,434		1,434		—		—		—		—		—		—
Fair value of long-term debt	521		—		—		—		414		—		—		—
Fair value of PHI's unamortized energy contracts	44		—		—		—		44		—		—		—
Carbon mitigation credit	843		843		—		—		—		—		—		—
Asset retirement obligations	151		99		22		21		9		6		2		1
MGP remediation costs	318		293		13		12		—		—		—		—
Renewable energy	85		85		—		—		—		—		—		—
Electric energy and natural gas costs	241		—		15		25		201		41		26		134
Transmission formula rate annual reconciliations	37		—		16		—		21		3		5		13
Energy efficiency and demand response programs	560		—		—		286		274		187		74		13
Under-recovered revenue decoupling	106		—		—		8		98		98		—		—
Removal costs	782		—		—		171		611		144		109		359
DC PLUG charge	37		—		—		—		37		37		—		—
Deferred storm costs	90		—		—		55		35		2		2		31
COVID-19	58		20		17		8		13		10		3		—
Under-recovered credit loss expense	71		38		—		—		33		—		—		33
Other	390		196		54		29		119		55		22		12
Total regulatory assets	9,678		3,442		732		704		2,065		672		282		624
Less: current portion	1,641		775		80		177		455		235		80		130
Total noncurrent regulatory assets	$	8,037	$	2,667	$	652	$	527	$	1,610	$	437	$	202	$	494

December 31, 2022	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory liabilities
Deferred income taxes	$	3,546	$	2,010	$	—	$	682	$	854	$	402	$	304	$	148
Decommissioning the Regulatory Agreement Units	2,897		2,660		237		—		—		—		—		—
Removal costs	1,750		1,604		—		35		111		20		91		—
Electric energy and natural gas costs	87		11		65		4		7		—		7		—
Transmission formula rate annual reconciliations	31		3		—		18		10		9		1		—
Renewable portfolio standards costs	810		810		—		—		—		—		—		—
Stranded costs	9		—		—		—		9		—		—		9
Energy efficiency and demand response programs	15		—		15		—		—		—		—		—
Over-recovered revenue decoupling	19		—		—		4		15		—		6		9
Dedicated facilities charge	110		—		—		110		—		—		—		—
Other	275		41		28		10		81		30		15		16
Total regulatory liabilities	9,549		7,139		345		863		1,087		461		424		182
Less: current portion	437		226		75		47		76		6		44		26
Total noncurrent regulatory liabilities	$	9,112	$	6,913	$	270	$	816	$	1,011	$	455	$	380	$	156

December 31, 2021	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory assets
Pension and OPEB	$	2,409	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Pension and OPEB - merger related	893		—		—		—		—		—		—		—
Deferred income taxes	883		—		873		—		10		10		—		—
AMI programs - deployment costs	145		—		—		89		56		30		26		—
AMI programs - legacy meters	186		69		—		29		88		60		21		7
Electric distribution formula rate annual reconciliations	44		44		—		—		—		—		—		—
Electric distribution formula rate significant one-time events	104		104		—		—		—		—		—		—
Energy efficiency costs	1,181		1,181		—		—		—		—		—		—
Fair value of long-term debt	557		—		—		—		443		—		—		—
Fair value of PHI's unamortized energy contracts	236		—		—		—		236		—		—		—
Asset retirement obligations	145		99		21		19		6		5		—		1
MGP remediation costs	283		266		8		9		—		—		—		—
Renewable energy	219		219		—		—		—		—		—		—
Electric energy and natural gas costs	96		—		—		49		47		29		13		5
Transmission formula rate annual reconciliations	43		—		14		1		28		—		8		20
Energy efficiency and demand response programs	564		—		—		283		281		199		79		3
Under-recovered revenue decoupling	157		—		—		32		125		125		—		—
Removal costs	758		—		—		143		615		147		109		360
DC PLUG charge	70		—		—		—		70		70		—		—
Deferred storm costs	49		—		—		—		49		3		3		43
COVID-19	82		28		33		8		13		10		3		—
Under-recovered credit loss expense	89		60		—		—		29		—		—		29
Other	327		135		42		30		130		57		18		23
Total regulatory assets	9,520		2,205		991		692		2,226		745		280		491
Less: current portion	1,296		335		48		215		432		213		68		61
Total noncurrent regulatory assets	$	8,224	$	1,870	$	943	$	477	$	1,794	$	532	$	212	$	430

December 31, 2021	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory liabilities
Deferred income taxes	$	4,005	$	2,105	$	—	$	819	$	1,081	$	525	$	354	$	202
Decommissioning the Regulatory Agreement Units	3,357		2,760		597		—		—		—		—		—
Removal costs	1,694		1,541		—		39		114		20		94		—
Electric energy and natural gas costs	113		25		71		—		17		9		3		5
Transmission formula rate annual reconciliations	8		7		—		—		1		1		—		—
Renewable portfolio standards costs	500		500		—		—		—		—		—		—
Stranded costs	35		—		—		—		35		—		—		24
Other	292		6		61		102		58		8		15		11
Total regulatory liabilities	10,004		6,944		729		960		1,306		563		466		242
Less: current portion	376		185		94		26		68		14		25		28
Total noncurrent regulatory liabilities	$	9,628	$	6,759	$	635	$	934	$	1,238	$	549	$	441	$	214

Descriptions of the regulatory assets and liabilities included in the tables above are summarized below, including their recovery and amortization periods.

Line Item	Description	End Date of Remaining Recovery/Refund Period	Return
Pension and OPEB	Primarily reflects the Utility Registrants' and PHI's portion of deferred costs, including unamortized actuarial losses (gains) and prior service costs (credits), associated with Exelon's pension and OPEB plans, which are recovered through customer rates once amortized through net periodic benefit cost. Also, includes the Utility Registrants' and PHI's non–service cost components capitalized in Property, plant and equipment, net on their Consolidated Balance Sheets.	The deferred costs are amortized over the plan participants' average remaining service periods subject to applicable pension and OPEB cost recognition policies. See Note 14 — Retirement Benefits for additional information. The capitalized non–service cost components are amortized over the lives of the underlying assets.	No
Pension and OPEB - merger related	The deferred costs established at the date of the Constellation and PHI mergers are amortized over the plan participants' average remaining service periods subject to applicable pension and OPEB cost recognition policies. The costs are recovered through customer rates once amortized through net periodic benefit cost. See Note 14 — Retirement Benefits for additional information. The capitalized non–service cost components are amortized over the lives of the underlying assets.	Legacy BGE - 2038 Legacy PHI - 2032	No

Line Item	Description	End Date of Remaining Recovery/Refund Period	Return
Deferred income taxes	Represents deferred income taxes that are recoverable or refundable through customer rates, primarily associated with accelerated depreciation, the equity component of AFUDC, and the effects of income tax rate changes, including those resulting from the TCJA. These amounts include transmission-related regulatory liabilities that require FERC approval separate from the transmission formula rate. See Transmission-Related Income Tax Regulatory Assets section above for additional information.	Amounts are recoverable over the period in which the related deferred income taxes reverse, which is generally based on the expected life of the underlying assets. For TCJA, generally refunded over the remaining depreciable life of the underlying assets, except in certain jurisdictions where the commissions have approved a shorter refund period for certain assets not subject to IRS normalization rules.	No
AMI programs - deployment costs	Represents installation and ongoing incremental costs of new smart meters, including implementation costs at Pepco and DPL of dynamic pricing for energy usage resulting from smart meters.	BGE - 2026 Pepco - 2029 DPL - 2030 ACE - To be determined in next distribution rate case filed with NJBPU	BGE, Pepco, DPL - Yes ACE - Yes, on incremental costs of new smart meters
AMI programs - legacy meters	Represents early retirement costs of legacy meters.	ComEd - 2028 BGE - 2026 Pepco - 2029 DPL - 2030 ACE - To be determined in next distribution rate case filed with NJBPU	ComEd, Pepco (District of Columbia), DPL (Delaware), ACE - Yes BGE, Pepco (Maryland), DPL (Maryland) - No
Electric distribution formula rate annual reconciliations	Represents under/(over)-recoveries related to electric distribution service costs recoverable through ComEd's performance-based formula rate, which is updated annually with rates effective on January 1st.	2024	Yes
Electric distribution formula rate significant one-time events	Represents deferred distribution service costs related to ComEd's significant one-time events (e.g., storm costs), which are recovered over 5 years from date of the event.	2026	Yes

Line Item	Description	End Date of Remaining Recovery/Refund Period	Return
Energy efficiency costs	Represents ComEd's costs recovered through the energy efficiency formula rate tariff and the reconciliation of the difference of the revenue requirement in effect for the prior year and the revenue requirement based on actual prior year costs. Deferred energy efficiency costs are recovered over the weighted average useful life of the related energy measure.	2034	Yes
Fair value of long-term debt	Represents the difference between the carrying value and fair value of long-term debt of BGE and PHI of $107 million and $414 million, respectively, as of December 31, 2022, and $114 million and $443 million, respectively, as of December 31, 2021, as of the PHI and Constellation merger dates.	BGE - 2036 PHI - 2045	No
Fair value of PHI’s unamortized energy contracts	Represents the regulatory assets recorded at Exelon and PHI offsetting the fair value adjustment related to Pepco's, DPL's, and ACE's electricity and natural gas energy supply contracts recorded at PHI as of the PHI merger date.	2036	No
Carbon mitigation credit	Represents CMC procurement costs and credits as well as reasonable costs ComEd has incurred to implement and comply with the CMC procurement process.	Over 9 months starting with the September billing period and ending with the following May billing period	No
Asset retirement obligations	Represents future legally required removal costs associated with existing AROs.	Over the life of the related assets	Yes, once the removal activities have been performed
MGP remediation costs	Represents environmental remediation costs for MGP sites recorded at ComEd, PECO, and BGE.	ComEd and PECO - Over the expected remediation period. See Note 18 — Commitments and Contingencies for additional information. BGE - 10 years from when the remediation spend is approved by the MDPSC.	ComEd and PECO - No BGE - Yes
Renewable energy	Represents the change in fair value of ComEd‘s 20-year floating-to-fixed long-term renewable energy swap contracts.	2032	No

Line Item	Description	End Date of Remaining Recovery/Refund Period	Return
Electric energy and natural gas costs	Represents under (over)-recoveries related to energy and gas supply related costs recoverable (refundable) under approved rate riders.	2025	DPL (Delaware), ACE - Yes ComEd, PECO, BGE, Pepco, DPL (Maryland) - No
Transmission formula rate annual reconciliations	Represents under (over)-recoveries related to transmission service costs recoverable through the Utility Registrants’ FERC formula rates, which are updated annually with rates effective each June 1st.	2024	Yes
Energy efficiency and demand response programs	Includes under (over)-recoveries of costs incurred related to energy efficiency programs and demand response programs and recoverable costs associated with customer direct load control and energy efficiency and conservation programs that are being recovered from customers.	PECO - 2025 BGE - 2027 Pepco, DPL - 2037 ACE - 2032	BGE, Pepco (Maryland), DPL (Maryland), ACE - Yes DPL (Delaware), Pepco (District of Columbia) - No PECO - Yes on capital investment recovered through this mechanism
Under (over) -recovered revenue decoupling	Represents electric and / or gas distribution costs recoverable from or refundable to customers under decoupling mechanisms.	BGE - 2023 Pepco (Maryland) - $11 million - 2023 Pepco (District of Columbia) - $87 million: $49 million to be recovered via monthly surcharge by 2024; $38 million to be recovered via the monthly surcharge, the timing of which will be impacted by the next multi-year plan filed with DCPSC DPL - 2023 ACE - 2024	BGE, Pepco, DPL, ACE - No
Stranded costs	The regulatory asset represents certain stranded costs associated with ACE's former electricity generation business. The regulatory liability represents overcollection of a customer surcharge collected by ACE to fund principal and interest payments on Transition Bonds of ACE Transition Funding that securitized such costs.	Stranded costs - 2022 Overcollection - 2024	Stranded costs - Yes Overcollection - No

Line Item	Description	End Date of Remaining Recovery/Refund Period	Return
Removal costs	For BGE, Pepco, DPL, and ACE, the regulatory asset represents costs incurred to remove property, plant and equipment in excess of amounts received from customers through depreciation rates. For ComEd, BGE, Pepco, and DPL, the regulatory liability represents amounts received from customers through depreciation rates to cover the future non–legally required cost to remove property, plant and equipment, which reduces rate base for ratemaking purposes.	BGE, Pepco, DPL, and ACE - Asset is generally recovered over the life of the underlying assets. ComEd, BGE, Pepco, and DPL - Liability is reduced as costs are incurred.	Yes
DC PLUG charge	Represents costs associated with DC PLUG, which is a projected six-year, $500 million project to place underground some of the District of Columbia’s most outage-prone power lines with $250 million of the project costs funded by Pepco and $250 million funded by the District of Columbia. Rates for the DC PLUG initiative went into effect on February 7, 2018.	2024	Portion of asset funded by Pepco-Yes
Deferred storm costs	For Pepco, DPL, ACE, and BGE, amounts represent total incremental storm restoration costs incurred due to major storm events recoverable from customers in the Maryland and New Jersey jurisdictions.	Pepco - 2024 DPL - 2027 ACE - $24 million - 2024; $7 million to be determined in next distribution rate case filed with NJBPU BGE - $55 million to be determined in next multi-year plan filed with MDPSC	Pepco, DPL, BGE - Yes ACE - No
Decommissioning the Regulatory Units	Represents estimated excess funds at the end of decommissioning the Regulatory Agreement Units. See below regarding Decommissioning the Regulatory Agreement Units for additional information.	Not currently being refunded	No

Line Item	Description	End Date of Remaining Recovery/Refund Period	Return
COVID-19	Represents incremental credit losses and direct costs related to COVID-19 incurred primarily in 2020 at the Utility Registrants, partially offset by a decrease in travel costs at BGE, Pepco and DPL. Direct costs consisted 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.	ComEd - 2025 BGE - $4 million - 2025; $4 million to be determined in the next multi-year plan filed with MDPSC PECO - 2024 Pepco (District of Columbia) - $8 million to be determined in the next multi-year plan filed with DCPSC Pepco (Maryland) - $1 million - 2026; $1 million to be determined in the next multi-year plan filed with MDPSC DPL (Maryland) - $1 million - 2027 DPL (Delaware) - $2 million to be determined in pending distribution rate case filed with DEPSC	ComEd and BGE - Yes PECO, Pepco, and DPL - No
Under-recovered credit loss expense	For ComEd and ACE, amounts represent the difference between annual credit loss expense and revenues collected in rates through ICC and NJBPU-approved riders. The difference between net credit loss expense and revenues collected through the rider each calendar year for ComEd is recovered over a twelve-month period beginning in June of the following calendar year. ACE intends to recover from June through May of each respective year, subject to approval of the NJBPU.	ComEd - 2024 ACE - To be determined in next Societal Benefits Rider filing with NJBPU	No

Line Item	Description	End Date of Remaining Recovery/Refund Period	Return
Renewable portfolio standards costs	Represents an overcollection of funds from both ComEd customers and alternative retail electricity suppliers to be spent on future renewable energy procurements.	$743 million to be determined in the ICC annual reconciliation for 2023 $67 million to be determined based on the LTRRPP developed by the IPA	No
Dedicated facilities charge	Represents the timing difference between the recovery of certain transmission-related assets and their depreciable life.	Depreciable life of the related assets	Yes

Decommissioning the Regulatory Agreement Units

The regulatory agreements with the ICC and PAPUC dictate obligations related to the shortfall or excess of NDT funds necessary for decommissioning the former ComEd units on a unit-by-unit basis and the former PECO units in total.

For the former PECO units, given the symmetric settlement provisions that allow for continued recovery of decommissioning costs from PECO customers in the event of a shortfall and the obligation for Constellation to ultimately return excess funds to PECO customers (on an aggregate basis for all seven units), decommissioning-related activities prior to separation on February 1, 2022 were generally offset in Exelon’s Consolidated Statements of Operations and Comprehensive Income with an offsetting adjustment to the regulatory liabilities or regulatory assets and an equal noncurrent affiliate receivable from or payable to Generation at PECO. Following the separation, decommissioning-related activities result in an adjustment to the Receivable related to Regulatory Agreement Units and an equal adjustment to the regulatory liabilities or regulatory assets at PECO.

For the former ComEd units, given no further recovery from ComEd customers is permitted and Constellation retains an obligation to ultimately return excess funds to ComEd customers (on a unit-by-unit basis), to the extent excess funds are expected for each unit, decommissioning-related activities prior to separation on February 1, 2022 were offset in the Consolidated Statements of Operations and Comprehensive Income with an offsetting adjustment to regulatory liabilities and noncurrent affiliate receivable from Generation at ComEd. Following the separation, decommissioning-related activities result in an adjustment to the Receivable related to Regulatory Agreement Units and an equal adjustment to the regulatory liabilities at ComEd. However, given the asymmetric settlement provision that does not allow for continued recovery from ComEd customers in the event of a shortfall, recognition of a regulatory asset at ComEd is not permissible.

Capitalized Ratemaking Amounts Not Recognized

The following table presents authorized amounts capitalized for ratemaking purposes related to earnings on shareholders’ investment that are not recognized for financial reporting purposes in the Registrants' Consolidated Balance Sheets. These amounts will be recognized as revenues in the related Consolidated Statements of Operations and Comprehensive Income in the periods they are billable to the Utility Registrants' customers.

	Exelon		ComEd(a)		PECO		BGE(b)		PHI		Pepco(c)		DPL(c)		ACE(b)
December 31, 2022	$	57	$	8	$	—	$	28	$	21	$	18	$	2	$	1
December 31, 2021	43		1		—		37		5		3		2		—

__________

(a)Reflects ComEd's unrecognized equity returns earned for ratemaking purposes on its electric distribution formula rate regulatory assets.

(b)BGE's and ACE's authorized amounts capitalized for ratemaking purposes primarily relate to earnings on shareholders' investment on their respective AMI programs.

(c)Pepco's and DPL's authorized amounts capitalized for ratemaking purposes relate to earnings on shareholders' investment on their respective AMI Programs and Energy Efficiency and Demand Response Programs, and for Pepco District of Columbia revenue decoupling program. The earnings on energy efficiency are on Pepco District of Columbia and DPL Delaware programs only.