
Registrant/Jurisdiction	Filing Date	Service	Requested Revenue Requirement Increase		Approved Revenue Requirement Increase		Approved ROE	Approval Date	Rate Effective Date
ComEd - Illinois	April 15, 2022(a)	Electric	$	199	$	199	7.85%	November 17, 2022	January 1, 2023
	January 17, 2023(b)	Electric	$	1,487	$	501	8.905%	December 14, 2023	January 1, 2024
	April 21, 2023(c)	Electric	$	247	$	259	8.91%	November 30, 2023	January 1, 2024
PECO - Pennsylvania	March 31, 2022	Natural Gas	$	82	$	55	N/A(d)	October 27, 2022	January 1, 2023
BGE - Maryland	May 15, 2020 (amended September 11, 2020)(e)	Electric	$	203	$	140	9.50%	December 16, 2020	January 1, 2021
		Natural Gas	$	108	$	74	9.65%
	February 17, 2023(f)	Electric	$	313	$	179	9.50%	December 14, 2023	January 1, 2024
		Natural Gas	$	289	$	229	9.45%
Pepco - Maryland(g)	October 26, 2020 (amended March 31, 2021)	Electric	$	104	$	52	9.55%	June 28, 2021	June 28, 2021
DPL - Maryland(h)	May 19, 2022	Electric	$	38	$	29	9.60%	December 14, 2022	January 1, 2023
ACE - New Jersey(i)	February 15, 2023 (amended August 21, 2023)	Electric	$	92	$	45	9.60%	November 17, 2023	December 1, 2023

(a)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. ComEd's last performance-based electric distribution formula rate update filing under EIMA was completed in 2022. See discussion of CEJA below for details on the transition away from the electric distribution formula rate.

(b)Reflects a four-year cumulative multi-year rate plan for January 1, 2024 to December 31, 2027. On December 14, 2023, the ICC approved year-over-year distribution revenue requirement increases in 2024-2027, with an amendatory order on January 10, 2024, of approximately $451 million effective January 1, 2024, $14 million effective January 1, 2025, $6 million effective January 1, 2026, and $30 million effective January 1, 2027, based on an ROE of 8.905%, an equity ratio of 50%, and year end 2022 rate base. The ICC rejected ComEd’s Grid Plan, requiring ComEd to file a revised Grid Plan by March 13, 2024, 90 days after the issuance of the December final order. The ICC also directed that the revised Grid Plan would be reviewed through further formal proceedings in that docket. On January 10, 2024, the ICC granted one portion of ComEd’s application for rehearing of the December 14, 2023 final order, and directing that a 150-day rehearing process reconsider the revenue requirements for the test years (2024-2027), absent an approved Grid Plan. On January 31,2024, the ICC further clarified the scope of the rehearing process. ComEd anticipates that the revenue requirements determined during the rehearing process will be further updated upon approval of a revised Grid Plan. On January 10, 2024, ComEd also filed with the Illinois appellate court an appeal of various aspects of the ICC’s final order on which rehearing was denied, including the 8.905% ROE, 50% equity ratio, and denial of any return on ComEd’s pension asset.

(c)On November 30, 2023, the Delivery Reconciliation Amount for 2022 defined in Rider Delivery Service Pricing Reconciliation (Rider DSPR) was approved. The delivery reconciliation amount allows for the reconciliation of the revenue requirement in effect in the final years in which formula rates are determined and until such time as new rates are established under ComEd’s approved MRP. The 2023 filing reconciled the delivery service rates in effect in 2022 with the actual delivery service costs incurred in 2022. The reconciliation revenue requirement provides for a weighted average debt and equity return on distribution rate base of 6.48%, inclusive of an allowed ROE of 8.91%, reflecting the monthly yields on 30-year treasury bonds plus 580 basis points.

(e)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.

(f)Reflects a three-year cumulative multi-year plan for January 1, 2024 through December 31, 2026. The MDPSC awarded BGE electric revenue requirement increases of $41 million, $113 million, and $25 million in 2024, 2025, and 2026, respectively, and natural gas revenue requirement increases of $126 million, $62 million, and $41 million in 2024, 2025, and 2026, respectively. Requested revenue requirement increases will be used to recover capital investments designed to increase the resilience of the electric and gas distribution systems and support Maryland's climate and regulatory initiatives. The MDPSC also approved a portion of the requested 2021 and 2022 reconciliation amounts, which will be recovered through separate electric and gas riders starting in 2024. As such, the reconciliation amounts are not included in the approved revenue requirement increases. The 2021 reconciliation amounts are $13 million and $7 million for electric and gas, respectively, and the 2022 reconciliation amounts are $39 million and $15 million for electric and gas, respectively.

(g)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. In 2021, the MDPSC deferred a decision on whether to use certain tax benefits to offset the revenue requirement increases for the 12-month period ending March 31, 2024. In December 2022 Pepco proposed that tax benefits not be used to offset the revenue requirement increases for this period. On January 25, 2023, the MDPSC accepted Pepco’s recommendations not to use tax benefits to offset revenue requirement increases for the 12-month period ending March 31, 2024.

(b)Reflects a three-year cumulative multi-year plan for April 1, 2024 through March 31, 2027 submitted to the MDPSC. Pepco requested total electric revenue requirement increases of $69 million, $54 million and $51 million effective April 1, 2024, April 1, 2025, and April 1, 2026, respectively through its rebuttal filing made on January 26, 2024. The plan contains a proposed nine-month extension period with a requested revenue requirement increase of $14 million effective April 1, 2027 through December 31, 2027. Requested revenue requirement increases will be used to recover capital investments designed to advance system-readiness and support Maryland's climate and clean energy goals. On August 7, 2023, the MDPSC issued an order approving a settlement agreement which allows Pepco to establish a revenue deferral mechanism to recover its full Commission-authorized year 1 increase between July 1, 2024 through March 31, 2025 and extend the procedural schedule to address intervenor resource constraints.

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).

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) requirements that ComEd and the ICC initiate and conduct various regulatory proceedings on subjects including ethics, spending, grid investments, and performance metrics.

On February 3, 2022, the ICC approved a tariff that establishes the process under which ComEd reconciled its 2022 and will reconcile its 2023 rate year revenue requirements with actual costs. Those reconciliation amounts are determined using the same process 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. In April 2023, ComEd filed its first petition with the ICC to reconcile its 2022 actual costs with the approved revenue requirement that was in effect in 2022; the final order was issued on November 30, 2023, for rates beginning January 2024. In 2024, ComEd will file with the ICC its 2023 actual costs with the approved revenue requirement that was in effect in 2023.

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 MRP 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. On May 22, 2023, direct testimony was filed by ICC staff and more than a dozen intervenors and intervenor groups. The testimonies addressed a wide variety of topics, including rate of return on equity, capital structure, grid planning, various distribution grid and information technology investments, and affordability and customer service. ComEd also made voluntary adjustments and, per the ICC’s final beneficial electrification order requiring ComEd to recover beneficial electrification costs through the MRP, increased its total revenue requirement request from $1.472 billion to $1.545 billion. ComEd filed its reply brief on September 27, 2023, to adjust its total requested revenue requirement increase to $1.487 billion.

On December 14, 2023, the ICC issued a final order. The ICC rejected ComEd’s Grid Plan as non-compliant with certain requirements of CEJA, and required ComEd to file a revised Grid Plan by March 13, 2024, 90 days after the issuance of the final order. In the absence of an approved Grid Plan, the ICC set ComEd’s forecast revenue requirements for 2024-2027 based on ComEd's approved year-end 2022 rate base. This results in a total cumulative revenue requirement increase of $501 million, a $986 million total revenue reduction from the requested cumulative revenue requirement increase but remains subject to annual reconciliation in accordance with CEJA. The final order approved the process and formulas associated with the MRP reconciliation mechanisms. The ICC did not approve a previously proposed phase-in of the ICC's approved year-over-year revenue increases, and it also denied ComEd's ability to earn a return on its pension asset.

On December 22, 2023, ComEd filed an application for rehearing on several findings in the final order including the use of the 2022 year-end rate base to establish forecast revenue requirements for 2024-2027, ROE, pension asset return, and capital structure. On January 10, 2024, ComEd’s application for rehearing was denied on all issues except for the order’s use of the 2022 year-end rate base. On January 31, 2024, the ICC granted ComEd's motion seeking additional clarification on the scope on rehearing, generally accepting ComEd's proposal and confirming that the rehearing will determine if the forecasted year-end 2023 rate base should be used to set rates for 2024 through 2027 until a refiled Grid Plan is approved. A final rehearing order on that topic is statutorily required by early June 2024. On January 10, 2024, ComEd also filed an appeal in the Illinois Appellate Court of the issues on which rehearing was denied, including but not limited to the allowed ROE and denial of a return on ComEd’s pension asset. There is no deadline by when the appellate court must rule. On February 8, 2024, the ICC denied ComEd's request to provide clarification on other issues including the schedule for review of the refiled Grid Plan. ComEd has completed and placed in service additional utility plant assets in 2023 and will continue to complete and place in service additional utility plant assets prior to the approval of the new Grid Plan. There are still significant unknowns, but ComEd does not currently believe that it is probable that the initially uncollected depreciation or return on the recently completed plant will ultimately be disallowed.

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. On April 5, 2023, the ICC issued its final order on rehearing for the performance and tracking metrics proceeding, in which the ICC declined to adopt ComEd's proposed modifications to the reliability and peak load reduction performance metrics. Efforts are underway to implement the performance metrics, which took effect on January 1, 2024. 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.

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. In the June 2022 billing period. ComEd began issuing credits to its retail customers under its new CMC rider. A regulatory asset is recorded for the difference between customer credits issued and the credit to be received from the participating nuclear-powered generating facilities. The balance as of December 31, 2023 is $673 million.

Under CEJA, the costs of procuring CMCs, including carrying costs, are recovered through a rider, the Rider Carbon-Free Resource Adjustment (Rider CFRA). As originally approved by the ICC, 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 an amendment to Rider CFRA proposing that it recover costs or provide credits faster than the tariff allows, implement monthly reconciliations, and allow ComEd to adjust Rider CFRA rates based not only on anticipated differences but also past payments or credits, and implement monthly reconciliations beginning with the June 2023 delivery period. The ICC approved the proposal on January 19, 2023. In addition, on March 24, 2023, ComEd submitted revisions to Rider CFRA which clarified the methodology for calculating interest to be included in the annual reconciliation associated with the June 2022 through May 2023 delivery year. The ICC approved the proposal on April 20, 2023. On February 2, 2024, ComEd filed a petition with the ICC to initiate the reconciliation proceeding for the costs incurred in connection with the procurement of CMCs during the delivery year beginning June 1, 2022 and extending through May 31, 2023.

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.

On March 23, 2023, the ICC issued its final order approving the beneficial electrification plan for ComEd. The ICC rejected ComEd's request to treat a large portion of beneficial electrification costs as a regulatory asset and ordered ComEd to seek cost recovery through the multi-year rate plan filing for 2024 and 2025, and the final formula rate reconciliation docket for 2023, rather than through a separate charge. The order also authorized an overall annual budget of $77 million per year for the three year plan period (2023 through 2025), with flexibility to roll forward unused funds to future years within the same plan period. On April 18, 2023, ComEd filed an application for rehearing in the beneficial electrification plan docket. The Chicago Transit Authority and City of Chicago, jointly, and the Office of the Illinois Attorney General (ILAG) also filed applications for rehearing. On April 27, 2023, ICC staff filed a motion for clarification, seeking clarification from the ICC on the precise budget described in the final order. On May 8, 2023, the ICC denied all applications for rehearing, and entered an amendatory order regarding the annual beneficial electrification plan budgets. ComEd has been directed to use good faith efforts to spend $77 million annually. ComEd subsequently filed its compliance filing in May 2023, detailing project related spending, clarifying the procedure that will be used to seek stakeholder feedback related to beneficial electrification pilot programs, and including the timeline for tariff changes required to implement the programs. ComEd and the ILAG both filed appeals of the ICC’s interim order that addressed the permissible scope of utility beneficial electrification programs outside of transportation and the rate impact cap. The ILAG also filed an appeal seeking reversal of portions of the ICC’s final decision. The final order partly mooted ComEd’s appeal of the interim order and ComEd has decided not to pursue the other issues. As such, ComEd moved to voluntarily dismiss its appeal and the appellate court granted that request. The ILAG consolidated their appeals. Any ruling on the appeals, even a negative ruling removing programs from the BE Plan or lowering the overall budget of the BE Plan, will only impact forward-looking costs.

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, 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.

(a)ComEd's 2024 approved revenue requirement above reflects an increase of $71 million for the initial year revenue requirement for 2024 and a increase of $47 million related to the annual reconciliation for 2022. The revenue requirement for 2024 provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 6.48% inclusive of an allowed ROE of 8.91%, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. The revenue requirement for the 2022 reconciliation year provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 7.47% inclusive of an allowed ROE of 10.89%, which includes an upward performance adjustment that increased 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 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.

EmPOWER Maryland Cost Recovery (Exelon, BGE, PHI, Pepco and DPL). On December 29, 2023, the MDPSC issued an order authorizing the next three-year program cycle for EmPOWER Maryland and approved various proposals by the program administrators to implement new energy efficiency programs for the 2024-2026 program cycle, as well as continue operating core programs. Historically, BGE, Pepco, and DPL deferred most of their energy efficiency program costs to a regulatory asset and either deferred most of their demand response program costs to a regulatory asset or capitalized them. Beginning in 2024, BGE, Pepco, and DPL will begin deferring less energy efficiency and demand response program costs to a regulatory asset. Additionally, as part of the order, the MDPSC directed BGE, Pepco, and DPL to extend the amortization of unamortized costs as of December 31, 2023 from 5 to 7 years to mitigate customer bill impacts.

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.

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 has recorded 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, 2023, the $49 million liability for the contract termination fee is included in Other current liabilities in Exelon's Consolidated Balance Sheet and PPA termination obligation in PHI's and ACE's Consolidated Balance Sheets. For the year ended December 31, 2023 and 2022, ACE has paid $88 million and $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 Registrants' 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 a second IIP, called “Powering the Future”, 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. On June 15, 2023, ACE entered into a settlement agreement with other parties, which allows for a recovery totaling $93 million of reliability related capital investments from July 1, 2023, through June 30, 2027. ACE will have the option of seeking approval from the NJBPU to extend the end date of the IIP beyond June 30, 2027, if ACE determines an extension is necessary. On June 29, 2023, the NJBPU adopted the settlement agreement and issued an order approving the program.

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.

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.

FERC Audit (Exelon and ComEd). The Utility Registrants are subject to periodic audits and investigations by FERC. FERC’s Division of Audits and Accounting initiated a nonpublic audit of ComEd in 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 period extends back to January 1, 2017. 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 in the first quarter of 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, including a suggestion that refunds may be due to customers for amounts collected in previous years. On August 28, 2023, ComEd filed a formal notice of the issues it will contest. On December 14, 2023, FERC appointed a settlement judge for the contested overhead allocation findings. 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.


December 31, 2023	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory assets
AMI programs - deployment costs	$	109	$	—	$	—	$	49	$	60	$	18	$	17	$	25
AMI programs - legacy meters	127		28		—		12		87		41		14		32
Asset retirement obligations	159		104		22		23		10		6		2		2
Carbon mitigation credit	673		673		—		—		—		—		—		—
COVID-19	41		11		11		6		13		10		3		—
DC PLUG charge	3		—		—		—		3		3		—		—
Deferred income taxes	759		—		748		—		11		11		—		—
Deferred storm costs	114		—		—		84		30		9		2		19
Electric distribution formula rate annual reconciliations	787		787		—		—		—		—		—		—
Electric distribution formula rate significant one-time events	89		89		—		—		—		—		—		—
Electric energy and natural gas costs	98		—		1		25		72		11		2		59
Energy efficiency and demand response programs	631		—		23		316		292		187		73		32
Energy efficiency costs	1,691		1,691		—		—		—		—		—		—
Fair value of long-term debt	486		—		—		—		385		—		—		—
Fair value of PHI's unamortized energy contracts	35		—		—		—		35		—		—		—
MGP remediation costs	315		286		15		14		—		—		—		—
Multi-year plan reconciliations	112		—		—		112		—		—		—		—
Pension and OPEB	2,254		—		—		—		—		—		—		—
Pension and OPEB - merger related	637		—		—		—		—		—		—		—
Removal costs	827		—		—		219		608		137		118		354
Renewable energy	134		134		—		—		—		—		—		—
Transmission formula rate annual reconciliations	75		—		9		5		61		15		22		24
Under-recovered credit loss expense	112		78		—		—		34		—		—		34
Under-recovered revenue decoupling	176		—		—		64		112		100		—		12
Universal service fund charge under-recovery - Electric	59		—		59		—		—		—		—		—
Zero emission credit	58		58		—		—		—		—		—		—
Other	352		190		32		27		111		52		19		15
Total regulatory assets	10,913		4,129		920		956		1,924		600		272		608
Less: current portion	2,215		1,335		127		229		337		150		54		125
Total noncurrent regulatory assets	$	8,698	$	2,794	$	793	$	727	$	1,587	$	450	$	218	$	483


December 31, 2023	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory liabilities
Decommissioning the Regulatory Agreement Units	$	3,232	$	2,954	$	278	$	—	$	—	$	—	$	—	$	—
Dedicated facilities charge	129		—		—		129		—		—		—		—
Deferred income taxes	3,284		1,900		—		634		750		338		274		138
Electric energy and natural gas costs	121		4		93		—		24		9		15		—
Energy efficiency and demand response programs	1		—		1		—		—		—		—		—
Multi-year plan reconciliations	23		—		—		—		23		16		7		—
Over-recovered revenue decoupling	2		—		—		—		2		—		2		—
Removal costs	1,845		1,701		—		28		116		20		96		—
Renewable portfolio standards costs	1,102		1,102		—		—		—		—		—		—


Other	226		23		34		9		60		14		21		8
Total regulatory liabilities	9,965		7,684		406		800		975		397		415		146
Less: current portion	389		191		92		27		71		15		50		6
Total noncurrent regulatory liabilities	$	9,576	$	7,493	$	314	$	773	$	904	$	382	$	365	$	140


December 31, 2022	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory assets
AMI programs - deployment costs	$	122	$	—	$	—	$	69	$	53	$	25	$	22	$	6
AMI programs - legacy meters	160		48		—		20		92		53		17		22
Asset retirement obligations	151		99		22		21		9		6		2		1
Carbon mitigation credit	843		843		—		—		—		—		—		—
COVID-19	58		20		17		8		13		10		3		—
DC PLUG charge	37		—		—		—		37		37		—		—
Deferred income taxes	606		—		595		—		11		11		—		—
Deferred storm costs	90		—		—		55		35		2		2		31
Electric distribution formula rate annual reconciliations	271		271		—		—		—		—		—		—
Electric distribution formula rate significant one-time events	115		115		—		—		—		—		—		—
Electric energy and natural gas costs	241		—		15		25		201		41		26		134
Energy efficiency and demand response programs	560		—		—		286		274		187		74		13
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		—		—		—
MGP remediation costs	318		293		13		12		—		—		—		—

Pension and OPEB	1,867		—		—		—		—		—		—		—
Pension and OPEB - merger related	769		—		—		—		—		—		—		—
Removal costs	782		—		—		171		611		144		109		359
Renewable energy	85		85		—		—		—		—		—		—
Transmission formula rate annual reconciliations	37		—		16		—		21		3		5		13
Under-recovered credit loss expense	71		38		—		—		33		—		—		33
Under-recovered revenue decoupling	106		—		—		8		98		98		—		—
Universal service fund charge under-recovery - Electric	19		—		19		—		—		—		—		—

Other	371		196		35		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
Decommissioning the Regulatory Agreement Units	$	2,897	$	2,660	$	237	$	—	$	—	$	—	$	—	$	—
Dedicated facilities charge	110		—		—		110		—		—		—		—
Deferred income taxes	3,546		2,010		—		682		854		402		304		148
Electric energy and natural gas costs	87		11		65		4		7		—		7		—
Energy efficiency and demand response programs	15		—		15		—		—		—		—		—
Multi-year plan reconciliations	14		—		—		—		14		14		—		—
Over-recovered revenue decoupling	19		—		—		4		15		—		6		9
Removal costs	1,750		1,604		—		35		111		20		91		—
Renewable portfolio standards costs	810		810		—		—		—		—		—		—
Stranded costs	9		—		—		—		9		—		—		9
Transmission formula rate annual reconciliations	31		3		—		18		10		9		1		—
Other	261		41		28		10		67		16		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


Line Item	Description	End Date of Remaining Recovery/Refund Period	Return
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 - 2029	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
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


Line Item	Description	End Date of Remaining Recovery/Refund Period	Return
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.	2024	No
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 - 2028 PECO - 2024 Pepco (District of Columbia) - $8 million to be determined in pending multi-year plan filed with DCPSC. Pepco (Maryland) - $2 million to be determined in pending 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, BGE, and DPL (Maryland) - Yes PECO, Pepco, and DPL (Delaware) - No
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
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
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
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.	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
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 - $1 million - 2024; $8 million to be determined in a future multi-year plan filed with MDPSC. DPL - 2027 ACE - 2026 BGE - $57 million - 2028; $27 million to be determined in the next multi-year plan filed with MDPSC.	Pepco, DPL, BGE - Yes ACE - 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.	2025	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.	2027	Yes


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
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 - 2030 Pepco, DPL - 2030 ACE - 2032	BGE, Pepco (Maryland), DPL (Maryland) - See above regarding EmPOWER Maryland Cost Recovery for additional information DPL (Delaware), Pepco (District of Columbia) - No ACE - Yes PECO - Yes on capital investment recovered through this mechanism
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.	2035	Yes


Line Item	Description	End Date of Remaining Recovery/Refund Period	Return
Fair value of long-term debt	Represents the difference between the carrying value and fair value of long-term debt of BGE, recorded at Exelon, and PHI of $101 million and $385 million, respectively, as of December 31, 2023, and $107 million and $414 million, respectively, as of December 31, 2022, as of the 2016 PHI and 2012 Constellation merger dates.	Exelon - 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
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 occurs.	ComEd and PECO - No BGE - Yes
Multi-year plan reconciliations	Represents under (over)-recoveries related to electric and gas distribution multi-year plans.	BGE - $60 million related to 2021 and 2022 reconciliations - 2025. $52 million related to 2023 reconciliations - to be determined in a future MDPSC order. Pepco (District of Columbia) - $16 million which has been reviewed by the DCPSC and will be finalized upon receipt of the DCPSC order in the pending multi-year plan filing. DPL (Maryland) - $7 million to be determined in next multi-year plan filed with MDPSC.	BGE - No Pepco (District of Columbia) - Yes DPL (Maryland) - Yes


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


Line Item	Description	End Date of Remaining Recovery/Refund Period	Return
Pension and OPEB - merger related	The deferred costs established at the date of the 2012 Constellation and 2016 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
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
Renewable energy	Represents the change in fair value of ComEd‘s 20-year floating-to-fixed long-term renewable energy swap contracts.	2032	No
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.	$1,033 million to be determined in pending ICC annual reconciliation for the Renewable Energy Adjustment rider. $69 million to be determined based on the LTRRPP developed by the IPA.	No
Stranded costs	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.	2023	No


Line Item	Description	End Date of Remaining Recovery/Refund Period	Return
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.	2025	Yes
Under (over) -recovered revenue decoupling	Represents electric and / or gas distribution costs recoverable from or refundable to customers under decoupling mechanisms.	BGE - 2025 Pepco (Maryland) - $10 million - 2024 Pepco (District of Columbia) - $90 million to be determined in the next multi-year plan filed with DCPSC. DPL - 2024 ACE - 2024	BGE, Pepco, DPL, ACE - 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 pending Societal Benefits Rider filing with NJBPU.	No
Universal service fund charge under-recovery - Electric	Represents under-recovery of electric supply and distribution revenue shortfalls net of base rate recovery related to PECO’s Universal Service programs, which are designed to provide affordable bills for electric service to low-income, residential customers based on individual household needs.	PECO - To be determined in the annual adjustment and reconciliation as approved by the PAPUC.	No
Zero emission credit	Represents ZEC procurement costs and any reasonable costs ComEd has incurred to implement and comply with the ZEC procurement process.	ComEd - Over 9 months starting with the September billing period and ending with the following May billing period.	ComEd - No

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.

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. PECO had no related amounts at December 31, 2023 and December 31, 2022