Regulatory Matters (All Registrants)

12 Months Ended

Dec. 31, 2021

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 2021.

Completed Distribution Base Rate Case Proceedings

Registrant/Jurisdiction	Filing Date	Service	Requested Revenue Requirement (Decrease) Increase		Approved Revenue Requirement (Decrease) Increase		Approved ROE		Approval Date	Rate Effective Date
ComEd - Illinois(a)	April 16, 2020	Electric	$	(11)	$	(14)	8.38	%	December 9, 2020	January 1, 2021
	April 16, 2021	Electric	51		46		7.36	%	December 1, 2021	January 1, 2022
PECO - Pennsylvania	September 30, 2020	Natural Gas	69		29		10.24	%	June 22, 2021	July 1, 2021
	March 30, 2021	Electric	246		132		N/A(b)		November 18, 2021	January 1, 2022
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 - Delaware	March 6, 2020 (amended February 2, 2021)	Electric	23		14		9.60	%	September 15, 2021	October 6, 2020
ACE - New Jersey(f)	December 9, 2020 (amended February 26, 2021)	Electric	67		41		9.60	%	July 14, 2021	January 1, 2022

__________

(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 the Clean Energy Law 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. ComEd is required to file an annual update 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 2021 approved revenue requirement reflects an increase of $50 million for the initial year revenue requirement for 2021 and a decrease of $64 million related to the annual reconciliation for 2019. The revenue requirement for 2021 and the revenue requirement for 2019 provide for a weighted average debt and equity return on distribution rate base of 6.28% inclusive of an allowed ROE of 8.38%, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points.

ComEd’s 2022 approved revenue requirement above 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.

(b)The PECO electric base rate case proceeding was resolved through a settlement agreement, which did not specify an approved ROE.

(c)Reflects a three-year cumulative multi-year plan for 2021 through 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. BGE proposed to use certain tax benefits to fully offset the increases in 2021 and 2022 and partially offset the increase in 2023. 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. Whether certain tax benefits will be used to offset the customer rate increases in 2023 has not been decided, and BGE cannot predict the outcome.

(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 the remainder of 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 the remainder of 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)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
DPL - Delaware	January 14, 2022	Natural Gas	$	14	10.30	%	First quarter of 2023
DPL - Maryland(a)	September 1, 2021 (amended December 23, 2021)	Electric	27		10.10	%	First quarter of 2022

__________

(a)On January 24, 2022, DPL filed a settlement agreement with the MDPSC. The settlement provides for a revenue requirement increase of $13 million. The 9.60% ROE in the agreement is solely for the purposes of calculating AFUDC and regulatory asset carrying costs. On February 15, 2021, the Chief Public Utility Law Judge issued a proposed order approving the settlement agreement without modification. The proposed order will become a final order of the MDPSC on March 2, 2022, subject to modification or reversal by the MDPSC.

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 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 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 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 2021, the following total increases/(decreases) were included in the Utility Registrants' electric transmission formula rate updates:

Registrant(a)	Initial Revenue Requirement Increase (Decrease)		Annual Reconciliation Increase		Total Revenue Requirement Increase(b)		Allowed Return on Rate Base(c)		Allowed ROE(d)
ComEd	$	33	$	12	$	45	8.20	%	11.50	%
PECO	(2)		26		24		7.37	%	10.35	%
BGE	38		27		65		7.35	%	10.50	%
Pepco	(9)		21		12		7.68	%	10.50	%
DPL	19		33		52		7.20	%	10.50	%
ACE	27		24		51		7.45	%	10.50	%

__________

(a)All rates are effective June 1, 2021 - May 31, 2022, subject to review by interested parties pursuant to review protocols of each Utility Registrant's tariff.

(b)In 2020, ComEd, BGE, Pepco, DPL, and ACE's transmission revenue requirement included a one-time decrease in accordance with the April 24, 2020 settlement agreement related to excess deferred income taxes which now completed has resulted in an increase to the 2021 transmission revenue requirement. In 2020, PECO's transmission revenue requirement included a one-time decrease in accordance with the December 5, 2019 settlement agreement related to refunds which now completed has resulted in an increase to the 2021 transmission revenue requirement.

(c)Represents the weighted average debt and equity return on transmission rate bases.

(d)As part of the FERC-approved settlements of ComEd’s 2007 and PECO's 2017 transmission rate cases, the rate of return on common equity is 11.50% and 10.35%, respectively, inclusive of a 50-basis-point incentive adder for being a member of a RTO, and the common equity component of the ratio used to calculate the weighted average debt and equity return for the transmission formula rate is currently capped at 55% and 55.75%, respectively. As part of the FERC-approved settlement of the ROE complaint against BGE, Pepco, DPL, and ACE, the rate of return on common equity is 10.50%, inclusive of a 50-basis-point incentive adder for being a member of a RTO.

Other State Regulatory Matters

Illinois Regulatory Matters

Clean Energy Law (Exelon and ComEd). On September 15, 2021, the Illinois Public Act 102-0662 was signed into law by the Governor of Illinois (“Clean Energy Law”). The Clean Energy Law 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 multi-year plan 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 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 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 the Clean Energy Law are possible and Exelon and ComEd cannot reasonably predict the outcome of any such challenges.

Carbon Mitigation Credit

The Clean Energy Law establishes decarbonization requirements for Illinois as well as programs to support the retention and development of emissions-free sources of electricity. Among other things, the Clean Energy Law authorized the IPA to procure up to 54.5 million CMCs from qualifying nuclear plants for a five-year period beginning on June 1, 2022 through May 31, 2027. CMCs are credits for the carbon-free attributes of eligible nuclear power plants in PJM. ComEd will procure CMCs based upon the number of MWhs produced annually by each plant, subject to minimum performance requirements. 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 the new law 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 is required to purchase CMCs and all its costs of doing so will be recovered through a new rider. That rider will provide for an annual reconciliation and true-up to actual costs incurred by ComEd to purchase CMCs, with any difference to be credited to or collected from ComEd’s retail customers in subsequent periods.

The provisions do not impact ComEd’s consolidated financial statements until 2022.

ComEd Electric Distribution Rates

The Clean Energy Law contains requirements associated with ComEd’s transition away from the performance-based electric distribution formula rate. The law authorizing that rate setting process sunsets at the end of 2022. The Clean Energy Law, and tariffs adopted under it, governs both the remaining reconciliations of rates set under that formula process and requires ComEd to file in 2023 its choice of either a general rate case or a four-year multi-year plan to set rates that take effect in 2024.

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 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 United States Treasury bonds plus 580 basis points.

If ComEd elects to file a multi-year plan, that plan would set rates for 2024 – 2027, based on forecasted revenue requirements and an ICC determined rate of return on rate base, including the cost of common equity. Each year of the multi-year plan is subject to after the fact ICC review and reconciliation of the plan’s revenue requirement for that year with the actual costs that the ICC determines are prudently and reasonably incurred for that year. That reconciliation is subject to adjustment for certain expenses and, unless the plan is modified, to a 5% cap on increases in certain costs over the costs in the previously approved multi-year rate plan revenue requirement. ComEd would make its initial reconciliation filing in 2025, and 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. The ICC must also approve certain annual performance metrics, which can impose symmetrical performance adjustments in the total range of 20 to 60 basis points to ComEd’s rate of return on common equity based on the extent to which ComEd achieved the annual performance goals. ComEd will recover from retail customers, subject to certain exceptions, the costs it incurs pursuant to the Clean Energy Law either through its electric distribution rate or other recovery mechanisms.

The Clean Energy Law, among other things, also requires ComEd’s rates to include a decoupling mechanism to eliminate any impacts of weather or load from ComEd’s electric distribution rate revenues. The Clean Energy Law also requires the ICC to initiate a docket to accelerate and fully credit to customers unprotected property related TCJA excess deferred income taxes no later than December 31, 2025.

Energy Efficiency

The Clean Energy Law 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 2022 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 2021, 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
June 1, 2021	$	54	$	54	7.36	%	November 18, 2021	January 1, 2022

_________

(a)ComEd’s 2022 approved revenue requirement above reflects an increase of $55 million for the initial year revenue requirement for 2022 and a decrease of $1 million related to the annual reconciliation for 2020. The revenue requirement for 2022 provides for a weighted average debt and equity return on the energy efficiency regulatory asset and 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 revenue requirement for the 2020 reconciliation year provides for a weighted average debt and equity return on the energy efficiency asset and rate base of 6.26% inclusive of an allowed ROE of 8.46%, 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 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.

ACE Infrastructure Investment Program Filing (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.

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.

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, 2021 and 2020:

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		—		—		35
Other	292		6		61		102		58		8		15		10
Total regulatory liabilities	10,004		6,944		729		960		1,306		563		466		252
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	$	224

December 31, 2020	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory assets
Pension and OPEB	$	3,010	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Pension and OPEB - merger related	1,014		—		—		—		—		—		—		—
Deferred income taxes	715		—		705		—		10		10		—		—
AMI programs - deployment costs	174		—		—		109		65		35		30		—
AMI programs - legacy meters	219		90		—		37		92		68		24		—
Electric distribution formula rate annual reconciliations	(14)		(14)		—		—		—		—		—		—
Electric distribution formula rate significant one-time events	117		117		—		—		—		—		—		—
Energy efficiency costs	982		982		—		—		—		—		—		—
Fair value of long-term debt	598		—		—		—		478		—		—		—
Fair value of PHI's unamortized energy contracts	328		—		—		—		328		—		—		—
Asset retirement obligations	135		92		21		18		4		3		—		1
MGP remediation costs	285		271		10		4		—		—		—		—
Renewable energy	301		301		—		—		—		—		—		—
Electric energy and natural gas costs	95		—		—		23		72		37		5		30
Transmission formula rate annual reconciliations	5		—		—		2		3		—		2		1
Energy efficiency and demand response programs	572		—		—		289		283		203		80		—
Under-recovered revenue decoupling	113		—		—		20		93		93		—		—
Stranded costs	25		—		—		—		25		—		—		25
Removal costs	701		—		—		107		594		151		105		339
DC PLUG charge	100		—		—		—		100		100		—		—
Deferred storm costs	50		—		—		—		50		5		4		41
COVID-19	81		22		38		10		11		7		4		—
Under-recovered credit loss expense	107		89		—		—		18		—		—		18
Other	274		78		27		30		147		72		26		15
Total regulatory assets	9,987		2,028		801		649		2,373		784		280		470
Less: current portion	1,228		279		25		168		440		214		58		75
Total noncurrent regulatory assets	$	8,759	$	1,749	$	776	$	481	$	1,933	$	570	$	222	$	395

December 31, 2020	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory liabilities
Deferred income taxes	$	4,502	$	2,205	$	—	$	1,001	$	1,296	$	621	$	404	$	271
Decommissioning the Regulatory Units	3,016		2,541		475		—		—		—		—		—
Removal costs	1,649		1,482		—		47		120		20		100		—
Electric energy and natural gas costs	175		34		97		6		38		24		10		4
Transmission formula rate annual reconciliations	52		2		12		—		38		23		9		6
Renewable portfolio standards costs	427		427		—		—		—		—		—		—
Stranded costs	24		—		—		—		24		—		—		24
Other	221		1		40		85		59		2		17		13
Total regulatory liabilities	10,066		6,692		624		1,139		1,575		690		540		318
Less: current portion	581		289		121		30		137		46		47		44
Total noncurrent regulatory liabilities	$	9,485	$	6,403	$	503	$	1,109	$	1,438	$	644	$	493	$	274

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 13 — 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 13 — 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	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.	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	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 - 2027 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	Early retirement costs of legacy meters.	ComEd - 2028 BGE - 2026 Pepco - 2027 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	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.	2023	Yes
Electric distribution formula rate significant one-time events	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.	2025	Yes

Line Item	Description	End Date of Remaining Recovery/Refund Period	Return
Energy efficiency costs	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.	2032	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 $114 million and $443 million, respectively, as of December 31, 2021, and $120 million and $478 million, respectively, as of December 31, 2020, 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
Asset retirement obligations	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	Environmental remediation costs for MGP sites recorded at ComEd, PECO, and BGE.	Over the expected remediation period. See Note 17 — Commitments and Contingencies for additional information.	No
Renewable energy	Represents the change in fair value of ComEd‘s 20-year floating-to-fixed long-term renewable energy swap contracts.	2032	No
Electric energy and natural gas costs	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	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.	2023	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 - 2026 Pepco, DPL - 2036 ACE - 2031	BGE, Pepco, DPL, ACE - Yes PECO - Yes on capital investment recovered through this mechanism

Line Item	Description	End Date of Remaining Recovery/Refund Period	Return
Under-recovered revenue decoupling	Electric and / or gas distribution costs recoverable from customers under decoupling mechanisms.	BGE - 2022 Pepco (Maryland) - $22 million - 2022 Pepco (District of Columbia) - $103 million: $66 million to be recovered via monthly surcharge by 2024; $37 million to be recovered via monthly surcharge, estimated to be fully recovered by 2028	BGE and Pepco - 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 - To be determined by refund mechanism filing with NJBPU	Stranded costs - Yes Overcollection - 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
DC PLUG charge	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

Line Item	Description	End Date of Remaining Recovery/Refund Period	Return
Deferred storm costs	For Pepco, DPL, and ACE 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 - $1 million - 2025; $2 million to be determined in pending distribution rate case filed with MDPSC ACE - $36 million - 2024; $7 million to be determined in next distribution rate case filed with NJBPU	Pepco, DPL - Yes ACE - No
Decommissioning the Regulatory Units	Estimated future decommissioning costs for the Regulatory Agreement Units that are less than the associated NDT fund assets. See below regarding Decommissioning the Regulatory Agreement Units for additional information.	Not currently being refunded.	No
COVID-19	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 - 2025 PECO - 2024 Pepco (District of Columbia) - $8 million to be determined in next distribution rate case filed with DCPSC Pepco (Maryland) - $1 million - 2026; $1 million to be determined in next distribution rate case filed with MDPSC DPL (Maryland) - $1 million to be determined in pending distribution rate case filed with MDPSC DPL (Delaware) - $2 million to be determined in next distribution rate case filed with DEPSC	ComEd and BGE - Yes PECO, Pepco, and DPL - No

Line Item	Description	End Date of Remaining Recovery/Refund Period	Return
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
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.	$432 million to be determined in the ICC annual reconciliation for 2023 $68 million to be determined based on the LTRRPP developed by the IPA	No

Decommissioning the Regulatory Agreement Units

Based on the regulatory agreements with the ICC and PAPUC that dictate Generation’s 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, decommissioning-related activities net of applicable taxes, including realized and unrealized gains and losses on the NDT funds, depreciation of the ARC, and accretion of the decommissioning obligation, are generally offset in Exelon’s Consolidated Statements of Operations and Comprehensive Income and are recorded by the corresponding regulated utility as a component of the intercompany and regulatory balances in the balance sheet.

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 Generation to ultimately return excess funds to PECO customers (on an aggregate basis for all seven units), decommissioning-related activities are generally offset in Exelon’s Consolidated Statements of Operations and Comprehensive Income regardless of whether the NDT funds are expected to exceed or fall short of the total estimated decommissioning obligation. The offset of decommissioning-related activities in the Consolidated Statement of Operations and Comprehensive Income results in an adjustment to the regulatory liabilities or regulatory assets and an equal noncurrent affiliate receivable from or payable to Generation at PECO.

For the former ComEd units, given no further recovery from ComEd customers is permitted and Generation retains an obligation to ultimately return any unused NDTs to ComEd customers (on a unit-by-unit basis), to the extent the related NDT investment balances are expected to exceed the total estimated decommissioning obligation for each unit, decommissioning-related activities are offset in the Consolidated Statements of Operations and Comprehensive Income which results in an adjustment to the regulatory liabilities and noncurrent receivables from Generation 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
December 31, 2021	$	43	$	1	$	—	$	37	$	5	$	3	$	2	$	—
December 31, 2020	51		(1)		—		45		7		4		3		—

__________

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

(b)BGE's authorized amounts capitalized for ratemaking purposes primarily relate to earnings on shareholders' investment on its 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. The earnings on energy efficiency are on Pepco DC and DPL DE programs only.