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Regulatory Matters (All Registrants)

6 Months Ended

Jun. 30, 2020

As discussed in Note 3 — Regulatory Matters of the Exelon 2019 Form 10-K, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The following discusses developments in 2020 and updates to the 2019 Form 10-K.

Utility Regulatory Matters (Exelon and the Utility Registrants)

Distribution Base Rate Case Proceedings

The following tables show the completed and pending distribution base rate case proceedings in 2020.

Completed Distribution Base Rate Case Proceedings



Registrant/Jurisdiction	Filing Date	Requested Revenue Requirement (Decrease) Increase			Approved Revenue Requirement (Decrease) Increase			Approved ROE		Approval Date	Rate Effective Date
ComEd - Illinois (Electric)^(a)	April 8, 2019	$	(6	)	$	(17	)	8.91	%	December 4, 2019	January 1, 2020
DPL - Maryland (Electric)	December 5, 2019 (amended April 23, 2020)	17			12			9.60	%	July 14, 2020	July 16, 2020

__________

(a)

Reflects an increase of $51 million for the initial revenue requirement for 2019 and a decrease of $68 million related to the annual reconciliation for 2018. The revenue requirement for 2019 and annual reconciliation for 2018 provides for a weighted average debt and equity return on distribution rate base of 6.51%, inclusive of an allowed ROE of 8.91%, reflecting the average rate on 30-year treasury notes plus 580 basis points.

Pending Distribution Base Rate Case Proceedings



Registrant/Jurisdiction	Filing Date	Requested Revenue Requirement (Decrease) Increase			Requested ROE		Expected Approval Timing
ComEd - Illinois (Electric)^(a)	April 16, 2020	$	(11	)	8.38	%	Fourth quarter of 2020
BGE - Maryland (Electric and Natural Gas)^(b)	May 15, 2020	235			10.1	%	Fourth quarter of 2020
Pepco - District of Columbia (Electric)^(c)	May 30, 2019 (amended June 1, 2020)	136			9.7	%	Fourth quarter of 2020
DPL - Delaware (Natural Gas)^(d)	February 21, 2020 (amended March 17, 2020)	9			10.3	%	First quarter of 2021
DPL - Delaware (Electric)^(e)	March 6, 2020 (amended April 16, 2020)	24			10.3	%	Second quarter of 2021

__________

(a)

Reflects an increase of $51 million for the initial revenue requirement for 2020 and a decrease of $62 million related to the annual reconciliation for 2019. The revenue requirement for 2020 and annual reconciliation for 2019 provides 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 average rate on 30-year treasury notes plus 580 basis points.


(b)	Reflects a three-year cumulative multi-year plan for 2021 through 2023 and total requested revenue requirement increases in 2023 of $140 million related to electric distribution and $95 million related to natural gas distribution to recover capital investments made in late 2019 and planned capital investments from 2020 to 2023.


(c)	Pepco filed the multi-year plan enhanced proposal as an alternative to address the impacts of COVID-19. Reflects a three-year cumulative multi-year plan and requested revenue requirement increases of $73 million and $63 million for 2022 and 2023, respectively, to recover capital investments made in 2018 and 2019 and planned capital investments from 2020 to 2022.


(d)	The rates will go into effect on September 21, 2020, subject to refund.


(e)	The rates will go into effect on October 6, 2020, subject to refund.

Transmission Formula Rates

Transmission Formula Rate (Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE). ComEd’s, PECO's, BGE’s, Pepco's, DPL's and ACE's 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, BGE, DPL and ACE 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 Pepco 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, BGE, DPL and ACE 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 and Pepco also reconciles any differences between the actual costs and actual revenues for the calendar year (annual reconciliation).

For 2020, the following total increases/(decreases) were included in ComEd’s, PECO's, BGE’s, Pepco's, DPL's and ACE's electric transmission formula rate filings:



Registrant^(a)	Initial Revenue Requirement Increase (Decrease)			Annual Reconciliation Decrease			Total Revenue Requirement Increase (Decrease)^(c)			Allowed Return on Rate Base^(d)		Allowed ROE^(e)
ComEd	$	18		$	(4	)	$	14		8.17	%	11.50	%
PECO^(b)	5			(28		)	(23		)	7.47	%	10.35	%
BGE	16			(3		)	4			7.26	%	10.50	%
Pepco	2			(46		)	(44		)	7.81	%	10.50	%
DPL	(4		)	(40		)	(44		)	7.20	%	10.50	%
ACE	5			(25		)	(20		)	7.40	%	10.50	%

__________


(a)	All rates are effective June 2020, subject to review by interested parties, which is anticipated to be completed by the fourth quarter of 2020 or first quarter of 2021 for ComEd, BGE, Pepco, DPL and ACE and second quarter of 2021 for PECO.


(b)	PECO posted a revised filing to the PJM website on July 17, 2020 reflecting updates to the formula rate based on the FERC order dated July 9, 2020.

(c)

The decrease in PECO's transmission revenue requirement relates to refunds from December 1, 2017, in accordance with the settlement agreement dated July 22, 2019. The change in BGE's transmission revenue requirement includes a $9 million reduction related to a FERC-approved dedicated facilities charge to recover the costs of providing transmission service to specifically designated load by BGE. ComEd, BGE, Pepco, DPL and ACE’s transmission revenue requirement include a decrease related to the April 24, 2020 settlement agreement related to excess deferred income taxes. Refer to Transmission-Related Income Tax Regulatory Assets below for additional information.


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

(e)

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

Energy Efficiency Formula Rate (Exelon and ComEd). ComEd filed its annual energy efficiency formula rate update with the ICC on May 21, 2020. The filing establishes the revenue requirement used to set the rates that will take effect in January 2021 after the ICC’s review and approval. The revenue requirement requested is based on a reconciliation of the 2019 actual costs plus projected 2020 and 2021 expenditures.



Initial Revenue Requirement Increase		Annual Reconciliation Increase		Total Revenue Requirement Increase			Requested Return on Rate Base		Requested ROE
$	45	$	3	$	48	^(a)	6.28	%	8.38	%

__________

(a)

The requested revenue requirement increase provides for a weighted average debt and equity return on rate base of 6.28% inclusive of an allowed ROE of 8.38%. The ROE reflects the average rate on 30-year treasury notes plus 580 basis points. The ROE applicable to the 2019 reconciliation year is 8.96% and the return on rate base is 6.56%, which includes a performance adjustment that can either increase or decrease the ROE.

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 asset for the portion of the income tax regulatory asset 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) 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 Court of Appeals for the D.C. Circuit. On March 27, 2020, the Court of Appeals denied BGE’s November 2, 2018 appeal.

On October 1, 2018, ComEd, BGE, Pepco, DPL, and ACE submitted filings to recover only 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. 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.

While FERC has no deadline by which it must rule on the settlement, a final order from FERC is expected in the third quarter of 2020. Exelon cannot predict the outcome of this proceeding. If FERC ultimately rules that the future, ongoing non-TCJA amortization amounts are not recoverable, Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE would record additional charges to Income tax expense, which could be up to approximately $83 million, $51 million, $19 million, $13 million, $5 million, $6 million and $2 million, respectively, as of June 30, 2020.

Regulatory Assets and Liabilities

The Utility Registrants' regulatory assets and liabilities have not changed materially since December 31, 2019, unless noted below. See Note 3 — Regulatory Matters of the Exelon 2019 Form 10-K for additional information on the specific regulatory assets and liabilities.

ComEd. Regulatory assets increased $120 million primarily due to an increase of $94 million in the Energy Efficiency Costs regulatory asset and $17 million in the Renewable Energy regulatory asset.

PECO. Regulatory assets increased $55 million primarily due to an increase of $54 million in the Deferred Income Taxes regulatory asset. Regulatory liabilities decreased $81 million primarily due to a decrease of $104 million in the Nuclear Decommissioning regulatory liability offset by a $25 million increase in the Electric Energy and Natural Gas Costs regulatory liability.

ACE. Regulatory liabilities decreased $30 million primarily due to a decrease of $44 million in the Deferred Income Taxes regulatory liability offset by a $18 million increase in Transmission FERC Formula Rate regulatory liability.

Capitalized Ratemaking Amounts Not Recognized (Exelon and the Utility Registrants)

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 Exelon's and the Utility Registrant's 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 our customers.



	Exelon		ComEd^(a)		PECO		BGE^(b)		PHI		Pepco^(c)		DPL^(c)		ACE
June 30, 2020	$	57	$	1	$	—	$	49	$	7	$	4	$	3	$	—
December 31, 2019	63		3		—		53		7		4		3		—

_________


(a)	Reflects ComEd's unrecognized equity returns earned 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.

Generation Regulatory Matters (Exelon and Generation)

New Jersey Regulatory Matters

New Jersey Clean Energy Legislation. On May 23, 2018, 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, including that they make a significant contribution to air quality in the state and that their revenues are insufficient to cover their costs and risks. Under the legislation, the NJBPU will issue ZECs to qualifying nuclear power plants and the electric distribution utilities in New Jersey, including ACE, will be required to purchase those ZECs. On April 18, 2019, the NJBPU approved the award of ZECs to Salem 1 and Salem 2. Upon approval, Generation began recognizing revenue for the sale of New Jersey ZECs in the month they are generated and has recognized $17 million and $35 million for the three and six months ended June 30, 2020 and $10 million for the three and six months ended June 30, 2019. On May 15, 2019, New Jersey Rate Counsel appealed the NJBPU's decision to the New Jersey Superior Court. Exelon and Generation cannot predict the outcome of the appeal. See Note 6 — Early Plant Retirements for additional information related to Salem.

New York Regulatory Matters

New York Clean Energy Standard. On August 1, 2016, the NYPSC issued an order establishing the New York CES, a component of which is a Tier 3 ZEC program targeted at preserving the environmental attributes of zero-emissions nuclear-powered generating facilities that meet the criteria demonstrating public necessity as determined by the NYPSC to be Generation's FitzPatrick, Ginna and Nine Mile Point nuclear facilities.

On November 30, 2016 (as amended on January 13, 2017), a group of parties filed a Petition in New York State court seeking to invalidate the ZEC program, which argued that the NYPSC did not have authority to establish the program, that it violated state environmental law and that it violated certain technical provisions of the State Administrative Procedures Act when adopting the ZEC program. On January 22, 2018, the court dismissed the environmental claims and the majority of the plaintiffs from the case but denied the motions to dismiss with respect to the remaining five plaintiffs and claims, without commenting on the merits of the case. On October 8, 2019, the court dismissed all remaining claims. The petitioners filed a notice of appeal on November 4, 2019 and originally had until May 4, 2020 to file their brief. Due to COVID-19 related restrictions, the court extended the deadline to July 29, 2020 and, as of August 4, 2020, no brief has been received.

See Note 6 — Early Plant Retirements for additional information related to Ginna and Nine Mile Point.

Federal Regulatory Matters

PJM and NYISO MOPR Proceedings. PJM and NYISO capacity markets include a Minimum Offer Price Rule (MOPR). If a resource is subjected to a MOPR, its offer is adjusted to effectively remove the revenues it receives through a state government-provided financial support program - resulting in a higher offer that may not clear the capacity market. Prior to December 19, 2019, the MOPR in PJM applied only to certain new gas-fired resources. Currently, the MOPR in NYISO applies only to certain resources in downstate New York.

For Generation’s facilities in PJM and NYISO that are currently receiving ZEC compensation, an expanded MOPR would require exclusion of ZEC compensation when bidding into future capacity auctions, resulting in an increased risk of these facilities not receiving capacity revenues in future auctions. While FERC issued a set of orders on MOPR in NYISO on February 20, 2020, it did not expand mitigation to include Generation's nuclear assets in upstate New York. However, FERC has taken action to expand the MOPR in PJM.

On December 19, 2019, FERC required PJM to broadly apply the MOPR to all new and existing resources including nuclear, renewables, demand response, energy efficiency, storage and all resources owned by vertically-integrated utilities. This greatly expands the breadth and scope of PJM’s MOPR, which is effective as of PJM’s next capacity auction. While FERC included some limited exemptions, no exemptions were available to state-supported nuclear resources.

FERC provided no new mechanism for accommodating state-supported resources other than the existing FRR mechanism (under which an entire utility zone would be removed from PJM’s capacity auction along with sufficient resources to support the load in such zone). In response to FERC’s order PJM submitted a compliance filing on March 18, 2020 wherein PJM proposes tariff language interpreting and implementing FERC's directives and proposes a schedule for resuming capacity auctions that is contingent on the timing of FERC's action on the compliance filing. FERC has no deadline for such action, and FERC could accept, reject or direct further revisions to all or part of PJM's proposed tariff revisions and auction schedule.

On April 16, 2020, FERC issued an order largely denying requests for rehearing of FERC's December 2019 order but granting a few clarifications that required an additional PJM compliance filing that could also delay the timing for FERC to issue its compliance order(s) which PJM submitted on June 1, 2020. PJM cannot resume activities related to its capacity auctions until FERC acts on these compliance filings.

FERC issued an order on May 21, 2020 involving reforms to PJM’s day-ahead and real-time reserves markets that may require further changes to the MOPR levels pending before FERC in the PJM MOPR Proceeding. In approving reforms to PJM’s reserves markets, FERC also directed PJM to develop a new methodology for estimating revenues that resources will receive for sales of energy and related services (referred to as the Energy and Ancillary Services Offset) and to use that new methodology in calculating a number of parameters and assumptions used in the capacity market, including MOPR levels. FERC directed PJM to submit its new Energy and Ancillary Services Offset revenue projection methodology no later than August 5, 2020. On review of this compliance filing, FERC will address how these additional reforms will impact MOPR levels and the timeline for implementing the new revenue projection methodology, including any potential impacts on auction timing.

Unless Illinois and New Jersey can implement an FRR program in their PJM zones, the MOPR will apply in the next capacity auction to Generation's owned or jointly owned nuclear plants in those states receiving a benefit under the Illinois ZES or the New Jersey ZEC program, as applicable, increasing the risk that those units may not clear the capacity market.

Exelon is currently working with PJM and other stakeholders to pursue the FRR option prior to the next capacity auction in PJM. If Illinois implements the FRR option, Generation’s Illinois nuclear plants could be removed from PJM’s capacity auction and instead supply capacity and be compensated under the FRR program, which has the potential to mitigate the current economic distress being experienced by Generation's nuclear plants in Illinois, as discussed in Note 6 - Early Plant Retirements. Implementing the FRR program in Illinois will require both legislative and regulatory changes. Legislation may be introduced in New Jersey as well. Exelon cannot predict whether or when such legislative and regulatory changes can be implemented.

If Generation’s state-supported nuclear plants in PJM are subjected to the MOPR or equivalent without compensation under an FRR or similar program, it could have a material adverse impact on Exelon's and Generation's financial statements, which Exelon and Generation cannot reasonably estimate at this time.

Operating License Renewals

Conowingo Hydroelectric Project. On August 29, 2012, Generation submitted a hydroelectric license application to FERC for a new license for the Conowingo Hydroelectric Project (Conowingo). In connection with Generation’s efforts to obtain a water quality certification pursuant to Section 401 of the Clean Water Act (401 Certification) from MDE for Conowingo, Generation has been working with MDE and other stakeholders to resolve water quality licensing issues, including: (1) water quality, (2) fish habitat, and (3) sediment.

On October 29, 2019, Generation and MDE filed with FERC a Joint Offer of Settlement (Offer of Settlement) that would resolve all outstanding issues relating to the 401 Certification. Pursuant to the Offer of Settlement, the parties submitted Proposed License Articles to FERC to be incorporated by FERC into the new license in accordance with FERC’s discretionary authority under the Federal Power Act. Among the Proposed License Articles are modifications to river flows to improve aquatic habitat, eel passage improvements and initiatives to support rare, threatened and endangered wildlife. If FERC approves the Offer of Settlement and incorporates the Proposed License Articles into the new license without modification, then MDE would waive its rights to issue a 401 Certification and Generation would agree, pursuant to a separate agreement with MDE (MDE Settlement), to implement additional environmental protection, mitigation and enhancement measures over the anticipated 50-year term of the new license. These measures address mussel restoration and other ecological and water quality matters, among other commitments. Exelon’s commitments under the various provisions of the Offer of Settlement and MDE Settlement are not effective unless and until FERC approves the Offer of Settlement and issues the new license with the Proposed License Articles. Generation cannot currently predict when FERC will issue the new license.

Peach Bottom Units 2 and 3. On July 10, 2018, Generation submitted a second 20-year license renewal application with the NRC for Peach Bottom Units 2 and 3, which was approved on March 6, 2020. Peach Bottom Units 2 and 3 are now licensed to operate through 2053 and 2054, respectively.