Commitments and Contingencies (All Registrants)

Commitments

Constellation Merger Commitments

In February 2012, the MDPSC issued an Order approving the Exelon and Constellation merger. As part of the MDPSC Order, Exelon agreed to provide a package of benefits to BGE customers, the City of Baltimore and the State of Maryland, resulting in an estimated direct investment in the State of Maryland of approximately $1 billion. The direct investment estimate includes $95 million to $120 million relating to the construction of a headquarters building in Baltimore for Generation’s competitive energy businesses.

The direct investment commitment also includes $450 million to $500 million relating to Exelon and Generation’s development or assistance in the development of 285 - 300 MWs of new generation in Maryland, which is expected to be completed within a period of 10 years. The MDPSC order contemplates various options for complying with the new generation development commitments, including building or acquiring generating assets, making subsidy or compliance payments, or in circumstances in which the generation build is delayed or certain specified provisions are elected, making liquidated damages payments. Exelon and Generation have incurred $454 million towards satisfying the commitment for new generation development in the state of Maryland, with approximately 220 MW of the new generation commencing with commercial operations to date. During the third quarter of 2014, the conditions associated with one of the generation development commitments changed such that the most likely outcome would involve Exelon and Generation making subsidy payments and/or liquidated damages payments rather than constructing the specified generating plant. As a result, Exelon and Generation recorded a pre-tax $44 million loss contingency in Operating and maintenance expense related to this specific commitment that is included in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2014. On December 19, 2016, Generation paid $44 million to the Maryland Energy Administration in full satisfaction of this commitment. During the fourth quarter of 2016, given continued declines in projected energy and capacity prices, Generation terminated rights to certain development projects originally intended to meet its remaining 55 MW commitment amount. The commitment will now most likely be satisfied via payment of liquidated damages or execution of a third party PPA, rather than by Generation constructing renewable generating assets. As a result, Exelon and Generation recorded a pre-tax $50 million loss contingency in Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2016.

Equity Investment Commitments

As part of Generation's recent investments in technology development, Generation enters into equity purchase agreements that include commitments to invest additional equity through incremental payments to fund the anticipated needs of the planned operations of the associated companies. The commitment includes approximately $20 million of in-kind services and 100% of 2015 ESA Investco, LLC’s equity commitment since 2015 ESA Investco, LLC is consolidated by Generation (see Note 2 - Variable Interest Entities for additional details). As of December 31, 2016, Generation’s estimated commitment relating to its equity purchase agreements, including in-kind services contributions, is anticipated to be as follows:



	Total
2017	$	34
2018	5
Total	$	39

Commercial Commitments

Exelon’s commercial commitments as of December 31, 2016, representing commitments potentially triggered by future events, were as follows:



			Expiration within
	Total		2017		2018		2019		2020		2021		2022 and beyond
Letters of credit (non-debt) ^(a)	$	1,614	$	1,355	$	246	$	—	$	13	$	—	$	—
Surety bonds^(b)	1,035		978		33		2		16		6		—
Financing trust guarantees ^(c)	628		—		—		—		—		—		628
Guaranteed lease residual values^(d)	20		—		—		—		—		—		20
Total commercial commitments	$	3,297	$	2,333	$	279	$	2	$	29	$	6	$	648

___________________________


(a)	Letters of credit (non-debt)—Exelon and certain of its subsidiaries maintain non-debt letters of credit to provide credit support for certain transactions as requested by third parties.


(b)	Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.


(c)	Includes $200 million of Trust Preferred Securities of ComEd Financing III, $178 million of Trust Preferred Securities of PECO Trust III and IV and $250 million of Trust Preferred Securities of BGE Capital Trust II.

(d)

Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $50 million, $14 million of which is a guarantee by Pepco, $17 million by DPL and $13 million by ACE. The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.

Generation’s commercial commitments as of December 31, 2016, representing commitments potentially triggered by future events, were as follows:



			Expiration within
	Total		2017		2018		2019		2020		2021		2022 and beyond
Letters of credit (non-debt) ^(a)	$	1,546	$	1,287	$	246	$	—	$	13	$	—	$	—
Surety bonds	945		918		27		—		—		—		—
Total commercial commitments	$	2,491	$	2,205	$	273	$	—	$	13	$	—	$	—

________________________


(a)	Letters of credit (non-debt)—Non-debt letters of credit maintained to provide credit support for certain transactions as requested by third parties.

ComEd’s commercial commitments as of December 31, 2016, representing commitments potentially triggered by future events, were as follows:



			Expiration within
	Total		2017		2018		2019		2020		2021		2022 and beyond
Letters of credit (non-debt) ^(a)	$	14	$	14	$	—	$	—	$	—	$	—	$	—
Surety bonds^(b)	11		9		2				—		—		—
Financing trust guarantees	200		—		—		—		—		—		200
Total commercial commitments	$	225	$	23	$	2	$	—	$	—	$	—	$	200

_________________________


(a)	Letters of credit (non-debt)—ComEd maintains non-debt letters of credit to provide credit support for certain transactions as requested by third parties.


(b)	Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.

PECO’s commercial commitments as of December 31, 2016, representing commitments potentially triggered by future events, were as follows:



			Expiration within
	Total		2017		2018		2019		2020		2021		2022 and beyond
Letters of credit (non-debt) ^(a)	$	23	$	23	$	—	$	—	$	—	$	—	$	—
Surety bonds^(b)	9		9		—		—		—		—		—
Financing trust guarantees	178		—		—		—		—		—		178
Total commercial commitments	$	210	$	32	$	—	$	—	$	—	$	—	$	178

________________________


(a)	Letters of credit (non-debt)—PECO maintains non-debt letters of credit to provide credit support for certain transactions as requested by third parties.


(b)	Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.

BGE’s commercial commitments as of December 31, 2016, representing commitments potentially triggered by future events, were as follows:



			Expiration within
	Total		2017		2018		2019		2020		2021		2022 and beyond
Letters of credit (non-debt) ^(a)	$	2	$	2	$	—	$	—	$	—	$	—	$	—
Surety bonds ^(b)	11		10		1		—		—		—		—
Financing trust guarantees	250		—		—		—		—		—		250
Total commercial commitments	$	263	$	12	$	1	$	—	$	—	$	—	$	250

________________________


(a)	Letters of credit (non-debt)—BGE maintains non-debt letters of credit to provide credit support for certain transactions as requested by third parties.


(b)	Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.

PHI commercial commitments (Successor) as of December 31, 2016, representing commitments potentially triggered by future events, were as follows:



			Expiration within
	Total		2017		2018		2019		2020		2021		2022 and beyond
Letters of credit (non-debt) ^(a)	$	1	$	1	$	—	$	—	$	—	$	—	$	—
Surety bonds ^(b)	16		14		2		—		—		—		—
Guaranteed lease residual values^(c)	20		—		—		—		—		—		20
Total commercial commitments	$	37	$	15	$	2	$	—	$	—	$	—	$	20

________________________


(a)	Letters of credit (non-debt)—PHI and certain of its subsidiaries maintain non-debt letters of credit to provide credit support for certain transactions as requested by third parties.


(b)	Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.

(c)

Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $50 million. The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.

Pepco commercial commitments as of December 31, 2016, representing commitments potentially triggered by future events, were as follows:



			Expiration within
	Total		2017		2018		2019		2020		2021		2022 and beyond
Surety bonds ^(a)	9		9		—		—		—		—		—
Guaranteed lease residual values^(b)	6		—		—		—		—		—		6
Total commercial commitments	$	15	$	9	$	—	$	—	$	—	$	—	$	6

________________________


(a)	Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.

(b)

Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $14 million. The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.

DPL commercial commitments as of December 31, 2016, representing commitments potentially triggered by future events, were as follows:



			Expiration within
	Total		2017		2018		2019		2020		2021		2022 and beyond
Surety bonds ^(a)	4		3		1		—		—		—		—
Guaranteed lease residual values^(b)	7		—		—		—		—		—		7
Total commercial commitments	$	11	$	3	$	1	$	—	$	—	$	—	$	7

________________________


(a)	Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.

(b)

Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $17 million. The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.

ACE commercial commitments as of December 31, 2016, representing commitments potentially triggered by future events, were as follows:



			Expiration within
	Total		2017		2018		2019		2020		2021		2022 and beyond
Letters of credit (non-debt) ^(a)	$	1	$	1	$	—	$	—	$	—	$	—	$	—
Surety bonds ^(b)	3		2		1		—		—		—		—
Guaranteed lease residual values^(c)	5		—		—		—		—		—		5
Total commercial commitments	$	9	$	3	$	1	$	—	$	—	$	—	$	5

________________________


(a)	Letters of credit (non-debt)—ACE maintains non-debt letters of credit to provide credit support for certain transactions as requested by third parties.


(b)	Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.

(c)

Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $13 million. The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.

Leases

Minimum future operating lease payments, including lease payments for contracted generation, vehicles, real estate, computers, rail cars, operating equipment and office equipment, as of December 31, 2016 were:



	Exelon ^(a)		Generation^(a)		ComEd ^(b)		PECO ^(b)		BGE ^(b)(c)(d)		PHI		Pepco		DPL ^(b)		ACE
2017	$	183	$	70	$	11	$	3	$	32	$	50	$	7	$	13	$	8
2018	179		75		6		3		34		49		6		17		8
2019	123		30		6		4		34		36		5		7		7
2020	140		48		3		4		34		38		4		10		6
2021	133		47		3		4		32		34		3		9		5
Remaining years	968		644		—		—		33		211		7		54		20
Total minimum future lease payments	$	1,726	$	914	$	29	$	18	$	199	$	418	$	32	$	110	$	54

______________________


(a)	Excludes Generation’s contingent operating lease payments associated with contracted generation agreements.

(b)

Amounts related to certain real estate leases and railroad licenses effectively have indefinite payment periods. As a result, ComEd, PECO, BGE and DPL have excluded these payments from the remaining years, as such amounts would not be meaningful. ComEd’s, PECO’s, BGE’s and DPL's average annual obligation for these arrangements, included in each of the years 2017—2021, was $2 million, $4 million, $2 million and $2 million, respectively.


(c)	Includes all future lease payments on a 99 year real estate lease that expires in 2106.


(d)	The BGE column above includes minimum future lease payments associated with a 6-year lease for the Baltimore City conduit system that became effective during the fourth quarter of 2016. BGE's total commitments under the lease agreement are $21 million $25 million, $26 million , $27 million, $28 million, and $14 million related to years 2017, 2018, 2019, 2020, 2021 and thereafter, respectively.

The following table presents the Registrants’ rental expense under operating leases for the years ended December 31, 2016, 2015 and 2014:




For the Year Ended December 31,	Exelon		Generation ^(a)		ComEd		PECO		BGE		Pepco		DPL		ACE
2016	$	777	$	667	$	15	$	7	$	22	$	8	$	15	$	13
2015	922		851		12		9		32		7		14		13
2014	865		806		15		14		12		8		14		12



	Successor		Predecessor
	March 24, 2016 to December 31, 2016		January 1, 2016 to March 23, 2016	For the Year Ended December 31, 2015	For the Year Ended December 31, 2014
PHI
Rental expense under operating leases	$	49	12	60	59

________________________

(a)

Includes contingent operating lease payments associated with contracted generation agreements that are not included in the minimum future operating lease payments table above. Payments made under Generation’s contracted generation lease agreements totaled $604 million, $798 million and $755 million during 2016, 2015 and 2014, respectively. Excludes contract amortization associated with purchase accounting and contract acquisitions.

For information regarding capital lease obligations, see Note 14—Debt and Credit Agreements.

Nuclear Insurance

Generation is subject to liability, property damage and other risks associated with major incidents at any of its nuclear stations, including the CENG nuclear stations. Generation has mitigated its financial exposure to these risks through insurance and other industry risk-sharing provisions.

The Price-Anderson Act was enacted to ensure the availability of funds for public liability claims arising from an incident at any of the U.S. licensed nuclear facilities and also to limit the liability of nuclear reactor owners for such claims from any single incident. As of December 31, 2016, the current liability limit per incident is $13.4 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors at least once every five years with the last adjustment effective September 10, 2013. In accordance with the Price-Anderson Act, Generation maintains financial protection at levels equal to the amount of liability insurance available from private sources through the purchase of private nuclear energy liability insurance for public liability claims that could arise in the event of an incident. Effective January 1, 2017, the required amount of nuclear energy liability insurance purchased is $450 million for each operating site. Claims exceeding that amount are covered through mandatory participation in a financial protection pool, as required by the Price Anderson-Act, which provides the additional $13.0 billion per incident in funds available for public liability claims. Participation in this secondary financial protection pool requires the operator of each reactor to fund its proportionate share of costs for any single incident that exceeds the primary layer of financial protection. Exelon’s share of this secondary layer would be approximately $2.7 billion, including CENG's related liability, however any amounts payable under this secondary layer would be capped at $400 million per year.

In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay public liability claims exceeding the $13.4 billion limit for a single incident.

As part of the execution of the NOSA on April 1, 2014, Generation executed an Indemnity Agreement pursuant to which Generation agreed to indemnify EDF and its affiliates against third-party claims that may arise from any future nuclear incident (as defined in the Price-Anderson Act) in connection with the CENG nuclear plants or their operations. Exelon guarantees Generation’s obligations under this indemnity. See Note 5 - Investment in Constellation Energy Nuclear Group, LLC for additional information on Generation’s operations relating to CENG.

Generation is required each year to report to the NRC the current levels and sources of property insurance that demonstrates Generation possesses sufficient financial resources to stabilize and decontaminate a reactor and reactor station site in the event of an accident. The property insurance maintained for each facility is currently provided through insurance policies purchased from NEIL, an industry mutual insurance company of which Generation is a member.

NEIL may declare distributions to its members as a result of favorable operating experience. In recent years NEIL has made distributions to its members, but Generation cannot predict the level of future distributions or if they will continue at all. Generation's portion of the distribution declared by NEIL is estimated to be $21 million for 2016, and was $21 million for 2015 and $18 million for 2014. The distributions were recorded as a reduction to Operating and maintenance expense within Exelon and Generation’s Consolidated Statements of Operations and Comprehensive Income.

Premiums paid to NEIL by its members are also subject to a potential assessment for adverse loss experience in the form of a retrospective premium obligation. NEIL has never assessed this retrospective premium since its formation in 1973, and Generation cannot predict the level of future assessments if any. The current maximum aggregate annual retrospective premium obligation for Generation is approximately $353 million. NEIL requires its members to maintain an investment grade credit rating or to ensure collectability of their annual retrospective premium obligation by providing a financial guarantee, letter of credit, deposit premium, or some other means of assurance.

NEIL provides “all risk” property damage, decontamination and premature decommissioning insurance for each station for losses resulting from damage to its nuclear plants, either due to accidents or acts of terrorism. If the decision is made to decommission the facility, a portion of the insurance proceeds will be allocated to a fund, which Generation is required by the NRC to maintain, to provide for decommissioning the facility. In the event of an insured loss, Generation is unable to predict the timing of the availability of insurance proceeds to Generation and the amount of such proceeds that would be available. In the event that one or more acts of terrorism cause accidental property damage within a twelve-month period from the first accidental property damage under one or more policies for all insured plants, the maximum recovery by Exelon will be an aggregate of $3.2 billion plus such additional amounts as the insurer may recover for all such losses from reinsurance, indemnity and any other source, applicable to such losses.

For its insured losses, Generation is self-insured to the extent that losses are within the policy deductible or exceed the amount of insurance maintained. Uninsured losses and other expenses, to the extent not recoverable from insurers or the nuclear industry, could also be borne by Generation. Any such losses could have a material adverse effect on Exelon’s and Generation’s financial condition, results of operations and liquidity.

Spent Nuclear Fuel Obligation

Under the NWPA, the DOE is responsible for the development of a geologic repository for and the disposal of SNF and high-level radioactive waste. As required by the NWPA, Generation is a party to contracts with the DOE (Standard Contracts) to provide for disposal of SNF from Generation’s nuclear generating stations. In accordance with the NWPA and the Standard Contracts, Generation historically had paid the DOE one mill ($0.001) per kWh of net nuclear generation for the cost of SNF disposal. On November 19, 2013, the D.C. Circuit Court ordered the DOE to submit to Congress a proposal to reduce the current SNF disposal fee to zero, unless and until there is a viable disposal program. On May 9, 2014, the DOE notified Generation that the SNF disposal fee remained in effect through May 15, 2014, after which time the fee was set to zero. As a result, for the year ended December 31, 2016, and December 31, 2015, Generation did not incur any expense in SNF disposal fees. For the year ended December 31, 2014, Generation incurred expense of $49 million in SNF disposal fees recorded in Purchased power and fuel expense within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income, including Exelon’s share of Salem and net of co-owner reimbursements (not including such fees incurred by CENG). Until such time as a new fee structure is in effect, Exelon and Generation will not accrue any further costs related to SNF disposal fees. This fee may be adjusted prospectively in order to ensure full cost recovery. The NWPA and the Standard Contracts required the DOE to begin taking possession of SNF generated by nuclear generating units by no later than January 31, 1998. The DOE, however, failed to meet that deadline and its performance has been, and is expected to be, delayed significantly.

The 2010 Federal budget (which became effective October 1, 2009) eliminated almost all funding for the creation of the Yucca Mountain repository while the Obama Administration devised a new strategy for long-term SNF management. A Blue Ribbon Commission (BRC) on America’s Nuclear Future, appointed by the U.S. Energy Secretary, released a report on January 26, 2012, detailing comprehensive recommendations for creating a safe, long-term solution for managing and disposing of the nation’s SNF and high-level radioactive waste.

In early 2013, the DOE issued an updated “Strategy for the Management and Disposal of Used Nuclear Fuel and High-Level Radioactive Waste” in response to the BRC recommendations. This strategy included a consolidated interim storage facility that was planned to be operational in 2025. However, due to continued delays on the part of the DOE, Generation currently assumes the DOE will begin accepting SNF in 2030. The SNF acceptance date assumption is based on management’s estimates of the amount of time required for DOE to select a site location and develop the necessary infrastructure for long-term SNF storage.

Generation uses the 2030 date as the assumed date for when the DOE will begin accepting SNF for purposes of determining nuclear decommissioning asset retirement obligations.

In August 2004, Generation and the DOJ, in close consultation with the DOE, reached a settlement under which the government agreed to reimburse Generation, subject to certain damage limitations based on the extent of the government’s breach, for costs associated with storage of SNF at Generation’s nuclear stations pending the DOE’s fulfillment of its obligations. A settlement agreement for Calvert Cliffs and Nine Mile Point was executed during 2011, pursuant to which the government agreed to reimburse the costs associated with SNF storage expended or to be expended during a term set by the agreement. The term was subsequently extended during 2014 to include SNF storage costs incurred at Calvert Cliffs and Nine Mile Point through December 31, 2016. A DOE settlement agreement for Ginna was also executed during 2011. During 2015, Ginna executed another DOE settlement agreement providing for the reimbursement of SNF storage costs incurred through December 31, 2016. Generation expects the terms for each of the settlement agreements to be extended during 2017 for another three years to cover SNF storage costs through December 31, 2019. Generation, including CENG, submits annual reimbursement requests to the DOE for costs associated with the storage of SNF. In all cases, reimbursement requests are made only after costs are incurred and only for costs resulting from DOE delays in accepting the SNF.

Under the settlement agreement, Generation has received cumulative cash reimbursements for costs incurred as follows:



	Total		Net ^(a)
Cumulative cash reimbursements ^(b)	$	1,038	$	887

_____________________________


(a)	Total after considering amounts due to co-owners of certain nuclear stations and to the former owner of Oyster Creek.


(b)	Includes $53 million and $49 million, respectively, for amounts received since April 1, 2014, for costs incurred under the CENG DOE Settlement Agreements prior to the consolidation of CENG.

As of December 31, 2016, and 2015, the amount of SNF storage costs for which reimbursement has been or will be requested from the DOE under the DOE settlement agreements is as follows:



	December 31, 2016			December 31, 2015
DOE receivable - current ^(a)	$	109		$	76
DOE receivable - noncurrent ^(b)	15			14
Amounts owed to co-owners ^(a)(c)	(13		)	(5		)

_____________________________


(a)	Recorded in Accounts receivable, other.


(b)	Recorded in Deferred debits and other assets, other


(c)	Non-CENG amounts owed to co-owners are recorded in Accounts receivable, other. CENG amounts owed to co-owners are recorded in Accounts payable. Represents amounts owed to the co-owners of Peach Bottom, Quad Cities, and Nine Mile Point Unit 2 generating facilities.

The Standard Contracts with the DOE also required the payment to the DOE of a one-time fee applicable to nuclear generation through April 6, 1983. The fee related to the former PECO units has been paid. Pursuant to the Standard Contracts, ComEd previously elected to defer payment of the one-time fee of $277 million for its units (which are now part of Generation), with interest to the date of payment, until just prior to the first delivery of SNF to the DOE. As of December 31, 2016, the unfunded SNF liability for the one-time fee with interest was $1,024 million. Interest accrues at the 13-week Treasury Rate. The 13-week Treasury Rate in effect, for calculation of the interest accrual at December 31, 2016, was 0.355%. The liabilities for SNF disposal costs, including the one-time fee, were transferred to Generation as part of Exelon’s 2001 corporate restructuring. The outstanding one-time fee obligations for the Nine Mile Point, Ginna, Oyster Creek and TMI units remain with the former owners. The Clinton and Calvert Cliffs units have no outstanding obligation. See Note 12 — Fair Value of Financial Assets and Liabilities for additional information.

Environmental Remediation Matters

General. The Registrants’ operations have in the past, and may in the future, require substantial expenditures in order to comply with environmental laws. Additionally, under Federal and state environmental laws, the Registrants are generally liable for the costs of remediating environmental contamination of property now or formerly owned by them and of property contaminated by hazardous substances generated by them. The Registrants own or lease a number of real estate parcels, including parcels on which their operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. In addition, the Registrants are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future.

ComEd, PECO, BGE, and DPL have identified sites where former MGP activities have or may have resulted in actual site contamination. For almost all of these sites, there are additional PRPs that may share responsibility for the ultimate remediation of each location.


•	ComEd has identified 42 sites, 18 of which have been remediated and approved by the Illinois EPA or the U.S. EPA and 24 that are currently under some degree of active study and/or remediation. ComEd expects the majority of the remediation at these sites to continue through at least 2021.


•	PECO has identified 26 sites, 17 of which have been remediated in accordance with applicable PA DEP regulatory requirements. The remaining 9 sites are currently under some degree of active study and/or remediation. PECO expects the majority of the remediation at these sites to continue through at least 2022.

•

BGE has identified 13 former gas manufacturing or purification sites that it currently owns or owned at one time through a predecessor’s acquisition. Two gas manufacturing sites require some level of remediation and ongoing monitoring under the direction of the MDE. The required costs at these 2 sites are not considered material. An investigation of an additional gas purification site was completed during the first quarter of 2015 at the direction of the MDE. For more information, see the discussion of the Riverside site below.


•	DPL has identified 2 sites, all of which the remediation has been completed and approved by the MDE or the Delaware Department of Natural Resources and Environmental Control.

ComEd, pursuant to an ICC order, and PECO, pursuant to settlements of natural gas distribution rate cases with the PAPUC, are currently recovering environmental remediation costs of former MGP facility sites through customer rates. See Note 3 — Regulatory Matters for additional information regarding the associated regulatory assets. BGE is authorized to recover, and is currently recovering, environmental costs for the remediation of the former MGP facility sites from customers; however, while BGE does not have a rider for MGP clean-up costs, BGE has historically received recovery of actual clean-up costs in distribution rates. DPL has historically received recovery of actual clean-up costs in distribution rates.

As of December 31, 2016 and 2015, the Registrants had accrued the following undiscounted amounts for environmental liabilities in Other current liabilities and Other deferred credits and other liabilities within their respective Consolidated Balance Sheets:



December 31, 2016	Total environmental investigation and remediation reserve		Portion of total related to MGP investigation and remediation ^(a)
Exelon	$	429	$	325
Generation	72		—
ComEd	292		291
PECO	33		31
BGE ^(a)	2		2
PHI	30		1
Pepco	27		—
DPL	2		1
ACE	1		—



December 31, 2015	Total environmental investigation and remediation reserve		Portion of total related to MGP investigation and remediation
Exelon	$	369	$	301
Generation	63		—
ComEd	266		264
PECO	37		35
BGE	3		2
PHI (Predecessor)	33		1
Pepco	24		—
DPL	3		1
ACE	1		—

The historical nature of the MGP sites and the fact that many of the sites have been buried and built over, impacts the ability to determine a precise estimate of the ultimate costs prior to initial sampling and determination of the exact scope and method of remedial activity. Management determines its best estimate of remediation costs using all available information at the time of each study, including probabilistic and deterministic modeling for ComEd and PECO, and the remediation standards currently required by the applicable state environmental agency. Prior to completion of any significant clean up, each site remediation plan is approved by the appropriate state environmental agency.

During the third quarter of 2016, ComEd and PECO completed an annual study of their future estimated MGP remediation requirements. The results of the study resulted in a $7 million and $2 million increase to environmental liabilities and related regulatory assets for ComEd and PECO, respectively.

The Registrants cannot reasonably estimate whether they will incur other significant liabilities for additional investigation and remediation costs at these or additional sites identified by the Registrants, environmental agencies or others, or whether such costs will be recoverable from third parties, including customers.

Water Quality

Benning Road Site NPDES Permit Limit Exceedances. Pepco holds an NPDES permit issued by EPA with a July 19, 2009 effective date, which authorizes discharges from the Benning Road service facility. The 2009 permit for the first time imposed numerical limits on the allowable concentration of certain metals in storm water discharged from the site into the Anacostia River. The permit contemplated that Pepco would meet these limits over time through the use of best management practices (BMPs). The BMPs were effective in reducing metal concentrations in storm water discharges, but were not sufficient to meet all of the numerical limits for all metals.

The 2009 permit remains in effect pending EPA’s action on the Pepco renewal application, including resolution of the stormwater compliance issues. On October 30, 2015, EPA filed a Clean Water Act civil enforcement action against Pepco in federal district court, and in March 2016 the court granted a motion by the Anacostia Riverkeeper to intervene in this case as a plaintiff along with EPA. Since 2009 Pepco has installed runoff mitigation measures and implemented new operating procedures to comply with regulations. In January 2017, the parties agreed to a settlement in the form of a Consent Decree whereby Pepco will pay a civil penalty in the amount of $1.6 million, continue the BMPs to manage stormwater, construct a new stormwater treatment system, and make certain other capital improvements to the stormwater management system. The Consent Decree has been lodged with the Court and will be subject to a 30-day public comment period. It is expected that the Court will approve the Consent Decree in the first quarter of 2017. Pepco has established appropriate reserves for the liabilities under the Consent Agreement, which is included in the table above.

Solid and Hazardous Waste

Cotter Corporation. The EPA has advised Cotter Corporation (Cotter), a former ComEd subsidiary, that it is potentially liable in connection with radiological contamination at a site known as the West Lake Landfill in Missouri. In 2000, ComEd sold Cotter to an unaffiliated third-party. As part of the sale, ComEd agreed to indemnify Cotter for any liability arising in connection with the West Lake Landfill. In connection with Exelon’s 2001 corporate restructuring, this responsibility to indemnify Cotter was transferred to Generation. On May 29, 2008, the EPA issued a Record of Decision approving the remediation option submitted by Cotter and the two other PRPs that required additional landfill cover. The current estimated cost of the landfill cover remediation for the site is approximately $90 million including escalation, which will be allocated among all PRPs. Generation has accrued what it believes to be an adequate amount to cover its anticipated share of such liability, which is included in the table above. By letter dated January 11, 2010, the EPA requested that the PRPs perform a supplemental feasibility study for a remediation alternative that would involve complete excavation of the radiological contamination. On September 30, 2011, the PRPs submitted the supplemental feasibility study to the EPA for review. Since June 2012, the EPA has requested that the PRPs perform a series of additional analyses and groundwater and soil sampling as part of the supplemental feasibility study. The final supplemental feasibility study was completed in December of 2016 and will enable the EPA to propose a remedy for public comment. While the EPA has not yet formally announced a change in the schedule, the PRPs believe that the EPA announcement of the proposed remedy will take place in the third quarter of 2017 at the earliest. Thereafter, the EPA will select a final remedy and enter into a Consent Decree with the PRPs to effectuate the remedy. Recent investigation has identified a number of other parties who may be PRPs and could be liable to contribute to the final remedy. Further investigation is underway. Generation believes that a partial excavation remedy is reasonably possible, and the partial excavation costs, inclusive of a landfill cover, could range from approximately $225 million to$650 million; such costs would likely be shared by the final group of identified PRPs. Generation believes the likelihood that the EPA would require a complete excavation remedy is remote. The cost of a partial or complete excavation could have a material, unfavorable impact on Generation’s and Exelon’s future results of operations and cash flows.

During December 2015, the EPA took two actions related to the West Lake Landfill designed to abate what it termed as imminent and dangerous conditions at the landfill. The first involved installation by the PRPs of a non-combustible surface cover to protect against surface fires in areas where radiological materials are believed to have been disposed. Generation has accrued what it believes to be an adequate amount to cover its anticipated liability for this interim action. The second action involved EPA's public statement that it will require the PRPs to construct a barrier wall in an adjacent landfill to prevent a subsurface fire from spreading to those areas of the West Lake Landfill where radiological materials are believed to have been disposed. At this time, EPA has not provided sufficient details related to the basis for and the requirements and design of a barrier wall to enable Generation to determine the likelihood such a remedy will ultimately be implemented, assess the degree to which Generation may have liability as a potentially responsible party, or develop a reasonable estimate of the potential incremental costs. It is reasonably possible, however, that resolution of this matter could have a material, unfavorable impact on Generation's and Exelon's future results of operations and cash flows. Finally, one of the other PRP's, the landfill owner and operator of the adjacent landfill, has indicated that it will be making a contribution claim against Cotter for costs that it has incurred to prevent the subsurface fire from spreading to those areas of the West Lake Landfill where radiological materials are believed to have been disposed. At this time, Generation and Exelon do not possess sufficient information to assess this claim and are therefore unable to determine the impact on their future results of operations and cash flows.

On February 2, 2016, the U.S. Senate passed a bill to transfer remediation authority over the West Lake Landfill from the EPA to the U.S. Army Corps of Engineers, under the Formerly Utilized Sites Remedial Action Program (FUSRAP). Such legislation would become final upon passage in the U.S. House of Representatives and the signature of the President, and be subject to annual funding appropriations in the U.S. Budget. The legislation has not passed in the House. Remediation under FUSRAP would not alter the liability of the PRPs, but could delay the determination of a final remedy and its implementation.

On August 8, 2011, Cotter was notified by the DOJ that Cotter is considered a PRP with respect to the government’s clean-up costs for contamination attributable to low level radioactive residues at a former storage and reprocessing facility named Latty Avenue near St. Louis, Missouri. The Latty Avenue site is included in ComEd’s indemnification responsibilities discussed above as part of the sale of Cotter. The radioactive residues had been generated initially in connection with the processing of uranium ores as part of the U.S. government’s Manhattan Project. Cotter purchased the residues in 1969 for initial processing at the Latty Avenue facility for the subsequent extraction of uranium and metals. In 1976, the NRC found that the Latty Avenue site had radiation levels exceeding NRC criteria for decontamination of land areas. Latty Avenue was investigated and remediated by the United States Army Corps of Engineers pursuant to funding under the FUSRAP. The DOJ has not yet formally advised the PRPs of the amount that it is seeking, but it is believed to be approximately $90 million. The DOJ and the PRPs agreed to toll the statute of limitations until August 2017 so that settlement discussions could proceed. Based on Generation’s preliminary review, it appears probable that Generation has liability to Cotter under the indemnification agreement and has established an appropriate accrual for this liability, which is included in the table above.

Commencing in February 2012, a number of lawsuits have been filed in the U.S. District Court for the Eastern District of Missouri. Among the defendants were Exelon, Generation and ComEd, all of which were subsequently dismissed from the case, as well as Cotter, which remains a defendant. The suits allege that individuals living in the North St. Louis area developed some form of cancer or other serious illness due to Cotter's negligent or reckless conduct in processing, transporting, storing, handling and/or disposing of radioactive materials. Plaintiffs are asserting public liability claims under the Price-Anderson Act. Their state law claims for negligence, strict liability, emotional distress, and medical monitoring have been dismissed. The complaints do not contain specific damage claims. In the event of a finding of liability against Cotter, it is reasonably possible that Exelon would be financially responsible due to its indemnification responsibilities of Cotter described above. The court has dismissed a number of lawsuits, and is expected to dismiss additional lawsuits based on a recent ruling. Pre-trial motions and discovery are proceeding in the remaining cases and a pre-trial scheduling order has been filed with the court. At this stage of the litigation, Generation and ComEd cannot estimate a range of loss, if any.

68th Street Dump. In 1999, the U.S. EPA proposed to add the 68th Street Dump in Baltimore, Maryland to the Superfund National Priorities List, and notified BGE and 19 others that they are PRPs at the site. In connection with BGE's 2000 corporate restructuring the responsibility for this liability was transferred to Constellation and as a result of the 2012 Exelon and CEG merger is now Generation's responsibility. In March 2004, the PRPs formed the 68th Street Coalition and entered into consent order negotiations with the U.S. EPA to investigate clean-up options for the site under the Superfund Alternative Sites Program. In May 2006, a settlement among the U.S. EPA and the PRPs with respect to investigation of the site became effective. The settlement requires the PRPs, over the course of several years, to identify contamination at the site and recommend clean-up options. The PRPs submitted their investigation of the range of clean-up options in the first quarter of 2011. Although the investigation and options provided to the U.S. EPA are still subject to U.S. EPA review and selection of a remedy, the range of estimated clean-up costs to be allocated among all of the PRPs is in the range of $50 million to $64 million. On September 30, 2013, U.S. EPA issued the Record of Decision identifying its preferred remedial alternative for the site. The estimated cost for the alternative chosen by U.S. EPA is consistent with the PRPs' estimated range of costs noted above. Based on Generation’s preliminary review, it appears probable that Generation has liability and has established an appropriate accrual for its share of the estimated clean-up costs.

Rossville Ash Site. The Rossville Ash Site is a 32-acre property located in Rosedale, Baltimore County, Maryland, which was used for the placement of fly ash from 1983-2007. The property is owned by Constellation Power Source Generation, LLC (CPSG), a wholly-owned subsidiary of Generation. In 2008, CPSG investigated and remediated the property by entering it into the Maryland Voluntary Cleanup Program (VCP) to address any historic environmental concerns and ready the site for appropriate future redevelopment. The site was accepted into the program in 2010 and is currently going through the process to remediate the site and receive closure from MDE. Exelon currently estimates the cost to close the site to be approximately $4 million, which has been fully reserved as of December 31, 2016 and is included in the table above.

Sauer Dump. On May 30, 2012, BGE was notified by the U.S. EPA that it is considered a PRP at the Sauer Dump Superfund site in Dundalk, Maryland. The U.S. EPA offered BGE and three other PRPs the opportunity to conduct an environmental investigation and present cleanup recommendations at the site. In addition, the U.S. EPA is seeking recovery from the PRPs of $1.7 million for past cleanup and investigation costs at the site. On March 11, 2013, BGE and three other PRPs signed an Administrative Settlement Agreement and Order on Consent with the U.S. EPA which requires the PRPs to conduct a remedial investigation and feasibility study at the site to determine what, if any, are the appropriate and recommended cleanup activities for the site. The ultimate outcome of this proceeding is uncertain. Since the U.S. EPA has not selected a cleanup remedy and the allocation of the cleanup costs among the PRPs has not been determined, an estimate of the range of BGE’s reasonably possible loss, if any, cannot be determined. It is possible, however, that resolution of this matter could have a material, unfavorable impact on Exelon's and BGE’s future results of operations and cash flows.

Riverside. In 2013, the MDE, at the request of EPA, conducted a site inspection and limited environmental sampling of certain portions of the 170 acre Riverside property owned by BGE. The site consists of several different parcels with different current and historical uses. The sampling included soil and groundwater samples for a number of potential environmental contaminants. The sampling confirmed the existence of contaminants consistent with the known historical uses of the various portions of the site. In March 2014, the MDE requested that BGE conduct an investigation which included a site-wide investigation of soils, sediment, groundwater, and surface water to complement the MDE sampling. The field investigation was completed in January 2015, and a final report was provided to MDE on June 2, 2015. On November 3, 2015, MDE provided BGE with its comments and recommendations on the report which require BGE to conduct further investigation and sampling at the site to better delineate the nature and extent of historic contamination, including off-site sediment and soil sampling. MDE did not request any interim remediation at this time and BGE anticipates completing the additional work requested by the end of the first quarter of 2017. BGE has established what it believes is an appropriate reserve based upon the investigation to date. The established reserve is included in the table above. As the investigation and potential remediation proceed, it is possible that resolution of this matter could have a material, unfavorable impact on Exelon's and BGE’s future results of operations and cash flows.

Benning Road Site. In September 2010, PHI received a letter from EPA identifying the Benning Road site as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. A portion of the site was formerly the location of a Pepco Energy Services electric generating facility. That generating facility was deactivated in June 2012 and plant structure demolition was completed in July 2015. The remaining portion of the site consists of a Pepco transmission and distribution service center that remains in operation. In December 2011, the U.S. District Court for the District of Columbia approved a consent decree entered into by Pepco and Pepco Energy Services with the DOEE, which requires Pepco and Pepco Energy Services to conduct a RI/FS for the Benning Road site and an approximately 10 to 15 acre portion of the adjacent Anacostia River. The RI/FS will form the basis for the remedial actions for the Benning Road site and for the Anacostia River sediment associated with the site. The consent decree does not obligate Pepco or Pepco Energy Services to pay for or perform any remediation work, but it is anticipated that DOEE will look to Pepco and Pepco Energy Services to assume responsibility for cleanup of any conditions in the river that are determined to be attributable to past activities at the Benning Road site.

The initial RI field work began in January 2013 and was completed in December 2014. In April 2015, Pepco and Pepco Energy Services submitted a draft RI Report to DOEE. After review, DOEE determined that additional field investigation and data analysis was required to complete the RI process (much of which was beyond the scope of the original DOEE-approved RI work plan). In the meantime, Pepco and Pepco Energy Services revised the draft RI Report to address DOEE’s comments and DOEE released the draft RI Report for public review in February 2016. Once the additional RI work has been completed, Pepco and Pepco Energy Services will issue a draft “final” RI report for review and comment by DOEE and the public. Pepco and Pepco Energy Services will then proceed to develop an FS to evaluate possible remedial alternatives for submission to DOEE.

Upon DOEE’s approval of the final remedial investigation and feasibility study Reports, Pepco and Pepco Energy Services will have satisfied their obligations under the consent decree. At that point, DOEE will prepare a Proposed Plan regarding further response actions. After considering public comment on the Proposed Plan, DOEE will issue a Record of Decision identifying any further response actions determined to be necessary.

PHI, Pepco and Pepco Energy Services have determined that a loss associated with this matter for PHI, Pepco and Pepco Energy Services is probable and an estimated liability for this issue has been accrued, which is included in the table above. As the remedial investigation proceeds and potential remedies are identified, it is possible that additional reserves could be established in amounts that could be material to PHI, Pepco and Pepco Energy Services. Pursuant to Exelon's March 2016 acquisition of PHI, Pepco Energy Services was transferred to Generation. The ultimate resolution of this matter is currently not expected to have any significant financial impact on Generation.

Anacostia River Tidal Reach. Contemporaneous with the Benning RI/FS being performed by Pepco and Pepco Energy Services, DOEE and certain federal agencies have been conducting a separate RI/FS focused on the entire tidal reach of the Anacostia River extending from just north of the Maryland-D.C. boundary line to the confluence of the Anacostia and Potomac Rivers. In March 2016, DOEE released a draft of the river-wide RI Report for public review and comment. The river-wide RI incorporated the results of the river sampling performed by Pepco and Pepco Energy Services as part of the Benning RI/FS, as well as similar sampling efforts conducted by owners of other sites adjacent to this segment of the river and supplemental river sampling conducted by DOEE’s contractor. DOEE asked Pepco, along with parties responsible for other sites along the river, to participate in a “Consultative Working Group” to provide input into the process for future remedial actions addressing the entire tidal reach of the river and to ensure proper coordination with the other river cleanup efforts currently underway, including cleanup of the river segment adjacent to the Benning Road site resulting from the Benning Road RI/FS. Pepco responded that it will participate in the Consultative Working Group but its participation is not an acceptance of any financial responsibility beyond the work that will be performed at the Benning Road site described above. DOEE has advised the Consultative Working Group that the federal and DOEE authorities are conducting phase 2 of a remedial investigation. DOEE has targeted June 2018 as the date for remedy selection for clean-up of sediments in this section of the river. The Consultative Working Group and the other possible PRPs have provided input into the proposed clean-up process and schedule. At this time, it is not possible to predict the extent of Pepco’s participation in the river-wide RI/FS process, and Pepco cannot estimate the reasonably possible range of loss for response costs beyond those associated with the Benning RI/FS component of the river-wide initiative. It is possible, however, that resolution of this matter could have a material, unfavorable impact on Exelon's and Pepco’s future results of operations and cash flows.

Conectiv Energy Wholesale Power Generation Sites. In July 2010, PHI sold the wholesale power generation business of Conectiv Energy Holdings, Inc. and substantially all of its subsidiaries (Conectiv Energy) to Calpine Corporation (Calpine). Under New Jersey’s Industrial Site Recovery Act (ISRA), the transfer of ownership triggered an obligation on the part of Conectiv Energy to remediate any environmental contamination at each of the nine Conectiv Energy generating facility sites located in New Jersey. Under the terms of the sale, Calpine has assumed responsibility for performing the ISRA-required remediation and for the payment of all related ISRA compliance costs up to $10 million. PHI is obligated to indemnify Calpine for any ISRA compliance remediation costs in excess of $10 million. According to PHI’s estimates, the costs of ISRA-required remediation activities at the nine generating facility sites located in New Jersey are in the range of approximately $7 million to $18 million, and PHI has established an appropriate accrual for its share of the estimated clean-up costs, which is included in the table above. Pursuant to Exelon’s March 2016 acquisition of PHI, Conectiv Energy was transferred to Generation, however, the responsibility to indemnify Calpine remained at PHI. The ultimate resolution of this matter is currently not expected to have any significant financial impact on PHI.

Rock Creek Mineral Oil Release. In late August 2015, a Pepco underground transmission line in the District of Columbia suffered a breach, resulting in the release of non-toxic mineral oil surrounding the transmission line into the surrounding soil, and a small amount reached Rock Creek through a storm drain. Pepco notified regulatory authorities, and Pepco and its spill response contractors placed booms in Rock Creek, blocked the storm drain to prevent the release of mineral oil into the creek and commenced remediation of soil around the transmission line and the Rock Creek shoreline. Pepco estimates that approximately 6,100 gallons of mineral oil were released and that its remediation efforts recovered approximately 80% of the amount released. Pepco’s remediation efforts are ongoing under the direction of the DOEE, including the requirements of a February 29, 2016 compliance order which requires Pepco to prepare a full incident investigation report and prepare a removal action work plan to remove all impacted soils in the vicinity of the storm drain outfall, and in collaboration with the National Park Service, the Smithsonian Institution/National Zoo and EPA. Pepco’s investigation presently indicates that the damage to Pepco’s facilities occurred prior to the release of mineral oil when third-party excavators struck the Pepco underground transmission line while installing cable for another utility.

To the extent recovery is available against any party who contributed to this loss, PHI and Pepco will pursue such action. Exelon, PHI and Pepco continue to investigate the cause of the incident, the parties involved, and legal responsibility under District of Columbia law, but do not believe that the remediation costs to resolve this matter will have a material adverse effect on their respective financial condition, results of operations or cash flows.

Brandywine Fly Ash Disposal Site. In February 2013, Pepco received a letter from the MDE requesting that Pepco investigate the extent of waste on a Pepco right-of-way that traverses the Brandywine fly ash disposal site in Brandywine, Prince George’s County, Maryland, owned by NRG Energy, Inc. (as successor to GenOn MD Ash Management, LLC) (NRG). In July 2013, while reserving its rights and related defenses under a 2000 agreement covering the sale of this site, Pepco indicated its willingness to investigate the extent of, and propose an appropriate closure plan to address, ash on the right-of-way. Pepco submitted a schedule for development of a closure plan to MDE on September 30, 2013 and, by letter dated October 18, 2013, MDE approved the schedule.

Exelon, PHI and Pepco have determined that a loss associated with this matter is probable and have estimated that the costs for implementation of a closure plan and cap on the site are in the range of approximately $3 million to $6 million, for which an appropriate reserve has been established and is included in the table above. Exelon, PHI and Pepco believe that the costs incurred in this matter will be recoverable from NRG under the 2000 sale agreement.

Litigation and Regulatory Matters

Asbestos Personal Injury Claims (Exelon, Generation, ComEd, PECO and BGE).

Exelon and Generation. Generation maintains a reserve for claims associated with asbestos-related personal injury actions in certain facilities that are currently owned by Generation or were previously owned by ComEd and PECO. The reserve is recorded on an undiscounted basis and excludes the estimated legal costs associated with handling these matters, which could be material.

At December 31, 2016 and 2015, Generation had reserved approximately $83 million and $95 million, respectively, in total for asbestos-related bodily injury claims. As of December 31, 2016, approximately $22 million of this amount related to 230 open claims presented to Generation, while the remaining $61 million of the reserve is for estimated future asbestos-related bodily injury claims anticipated to arise through 2050, based on actuarial assumptions and analyses, which are updated on an annual basis. On a quarterly basis, Generation monitors actual experience against the number of forecasted claims to be received and expected claim payments and evaluates whether an adjustment to the reserve is necessary.

On November 22, 2013, the Supreme Court of Pennsylvania held that the Pennsylvania Workers Compensation Act does not apply to an employee’s disability or death resulting from occupational disease, such as diseases related to asbestos exposure, which manifests more than 300 weeks after the employee’s last employment-based exposure, and that therefore the exclusivity provision of the Act does not preclude such employee from suing his or her employer in court. The Supreme Court’s ruling reverses previous rulings by the Pennsylvania Superior Court precluding current and former employees from suing their employers in court, despite the fact that the same employee was not eligible for workers compensation benefits for diseases that manifest more than 300 weeks after the employee’s last employment-based exposure to asbestos. Since the Pennsylvania Supreme Court’s ruling in November 2013, Exelon, Generation, and PECO have experienced an increase in asbestos-related personal injury claims brought by former PECO employees, all of which have been reserved against on a claim by claim basis. Those additional claims are taken into account in projecting estimated future asbestos-related bodily injury claims.

On November 4, 2015, the Illinois Supreme Court found that the provisions of the Illinois’ Workers’ Compensation Act and the Workers’ Occupational Diseases Act barred an employee from bringing a direct civil action against an employer for latent diseases, including asbestos-related diseases that fall outside the 25-year limit of the statute of repose. The Illinois Supreme Court’s ruling reversed previous rulings by the Illinois Court of Appeals, which initially ruled that the Illinois Worker’s Compensation law should not apply in cases where the diagnosis of an asbestos related disease occurred after the 25-year maximum time period for filing a Worker’s Compensation claim. As a result of this ruling, Exelon, Generation, and ComEd have not recorded an increase to the asbestos-related bodily injury liability as of December 31, 2016.

There is a reasonable possibility that Exelon may have additional exposure to estimated future asbestos-related bodily injury claims in excess of the amount accrued and the increases could have a material adverse effect on Exelon’s, Generation’s and PECO’s future results of operations and cash flows.

BGE. Since 1993, BGE and certain Constellation (now Generation) subsidiaries have been involved in several actions concerning asbestos. The actions are based upon the theory of “premises liability,” alleging that BGE and Generation knew of and exposed individuals to an asbestos hazard. In addition to BGE and Generation, numerous other parties are defendants in these cases.

To date, most asbestos claims which have been resolved relating to BGE and certain Constellation subsidiaries

have been dismissed or resolved without any payment and a small minority of these cases has been resolved for amounts that were not material to BGE or Generation’s financial results. Presently, there are an immaterial number of asbestos cases pending against BGE and certain Constellation subsidiaries.

Continuous Power Interruption (Exelon and ComEd)

Section 16-125 of the Illinois Public Utilities Act provides that in the event an electric utility, such as ComEd, experiences a continuous power interruption of four hours or more that affects (in ComEd’s case) more than 30,000 customers, the utility may be liable for actual damages suffered by customers as a result of the interruption and may be responsible for reimbursement of local governmental emergency and contingency expenses incurred in connection with the interruption. Recovery of consequential damages is barred. The affected utility may seek from the ICC a waiver of these liabilities when the utility can show that the cause of the interruption was unpreventable damage due to weather events or conditions, customer tampering, or certain other causes enumerated in the law. As of December 31, 2016 and 2015, ComEd did not have any material liabilities recorded for these storm events.

Fund Transfer Restrictions (Exelon, Generation, ComEd, PECO, BGE, PEPCO, DPL and ACE)

Under applicable law, Exelon may borrow or receive an extension of credit from its subsidiaries. Under the terms of Exelon’s intercompany money pool agreement, Exelon can lend to, but not borrow from the money pool.

The Federal Power Act declares it to be unlawful for any officer or director of any public utility “to participate in the making or paying of any dividends of such public utility from any funds properly included in capital account.” What constitutes “funds properly included in capital account” is undefined in the Federal Power Act or the related regulations; however, FERC has consistently interpreted the provision to allow dividends to be paid as long as: (1) the source of the dividends is clearly disclosed; (2) the dividend is not excessive; and (3) there is no self-dealing on the part of corporate officials. While these restrictions may limit the absolute amount of dividends that a particular subsidiary may pay, Exelon does not believe these limitations are materially limiting because, under these limitations, the subsidiaries are allowed to pay dividends sufficient to meet Exelon’s actual cash needs.

Under Illinois law, ComEd may not pay any dividend on its stock unless, among other things, “[its] earnings and earned surplus are sufficient to declare and pay same after provision is made for reasonable and proper reserves,” or unless it has specific authorization from the ICC. ComEd has also agreed in connection with financings arranged through ComEd Financing III that it will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debt securities issued to ComEd Financing III; (2) it defaults on its guarantee of the payment of distributions on the preferred trust securities of ComEd Financing III; or (3) an event of default occurs under the Indenture under which the subordinated debt securities are issued.

PECO’s Articles of Incorporation prohibit payment of any dividend on, or other distribution to the holders of, common stock if, after giving effect thereto, the capital of PECO represented by its common stock together with its retained earnings is, in the aggregate, less than the involuntary liquidating value of its then outstanding preferred securities. On May 1, 2013, PECO redeemed all outstanding preferred securities. As a result, the above ratio calculation is no longer applicable. Additionally, PECO may not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debentures, which were issued to PEC L.P. or PECO Trust IV; (2) it defaults on its guarantee of the payment of distributions on the Series D Preferred Securities of PEC L.P. or the preferred trust securities of PECO Trust IV; or (3) an event of default occurs under the Indenture under which the subordinated debentures are issued.

BGE is subject to certain dividend restrictions established by the MDPSC. First, BGE was prohibited from paying a dividend on its common shares through the end of 2014. Second, BGE is prohibited from paying a dividend on its common shares if (a) after the dividend payment, BGE’s equity ratio would be below 48% as calculated pursuant to the MDPSC’s ratemaking precedents or (b) BGE’s senior unsecured credit rating is rated by two of the three major credit rating agencies below investment grade. Finally, BGE must notify the MDPSC that it intends to declare a dividend on its common shares at least 30 days before such a dividend is paid. There are no other limitations on BGE paying common stock dividends unless BGE elects to defer interest payments on the 6.20% Deferrable Interest Subordinated Debentures due 2043, and any deferred interest remains unpaid.

PEPCO is subject to certain dividend restrictions established by settlements approved in Maryland and the District of Columbia. PEPCO is prohibited from paying a dividend on its common shares if (a) after the dividend payment, PEPCO's equity ratio would be 48% as equity levels are calculated under the ratemaking precedents of the commissions and the Board or (b) Pepco’s senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade.

DPL is subject to certain dividend restrictions established by settlements approved in Delaware and Maryland. DPL is prohibited from paying a dividend on its common shares if (a) after the dividend payment, DPL's equity ratio would be 48% as equity levels are calculated under the ratemaking precedents of the commissions and the Board or (b) DPL’s senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade.

ACE is subject to certain dividend restrictions established by settlements approved in New Jersey. ACE is prohibited from paying a dividend on its common shares if (a) after the dividend payment, ACE's equity ratio would be 48% as equity levels are calculated under the ratemaking precedents of the commissions and the Board or (b) ACE’s senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade.

Baltimore City Franchise Taxes (BGE)

The City of Baltimore claims that BGE has maintained electric facilities in the City’s public right-of-ways for over one hundred years without the proper franchise rights from the City. BGE has reviewed the City's claim and believes that it lacks merit. BGE has not recorded an accrual for payment of franchise fees for past periods as a range of loss, if any, cannot be reasonably estimated at this time. Franchise fees assessed in future periods may be material to BGE’s results of operations and cash flows.

Conduit Lease with City of Baltimore (Exelon and BGE)

On September 23, 2015, the Baltimore City Board of Estimates approved an increase in annual rental fees for access to the Baltimore City underground conduit system effective November 1, 2015, from $12 million to $42 million, subject to an annual increase thereafter based on the Consumer Price Index. BGE subsequently entered into litigation with the City regarding the amount of and basis for establishing the conduit fee. On November 30, 2016, the Baltimore City Board of Estimates approved a settlement agreement entered into between BGE and the City to resolve the disputes and pending litigation related to BGE's use of and payment for the underground conduit system. As a result of the settlement, the parties have entered into a six-year lease that reduces the annual expense to $25 million in the first three years and caps the annual expense in the last three years to not more than $29 million. BGE recorded a credit to Operating and maintenance expense in the fourth quarter of approximately $28 million for the reversal of the previously higher fees accrued in the current year as well as the settlement of prior year disputed fee true-up amounts.

Deere Wind Energy Assets (Exelon and Generation)

In 2013, Deere & Company (“Deere”) filed a lawsuit against Generation in the Delaware Superior Court relating to Generation’s acquisition of the Deere wind energy assets. Under the purchase agreement, Deere was entitled to receive earn-out payments if certain specific wind projects already under development in Michigan met certain development and construction milestones following the sale. In the complaint, Deere seeks to recover a $14 million earn-out payment associated with one such project, which was never completed. Generation has filed counterclaims against Deere for breach of contract, with a right of recoupment and set off. On June 2, 2016, the Delaware Superior Court entered summary judgment in favor of Deere. On January 17, 2017, Generation filed an appeal with the Supreme Court of Delaware. Generation has accrued an amount to cover its potential liability.

General (All Registrants)

The Registrants are involved in various other litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. The Registrants maintain accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of reasonably possible loss, particularly where (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.

Income Taxes (Exelon, Generation, ComEd, PECO and BGE)

See Note 15 — Income Taxes for information regarding the Registrants’ income tax refund claims and certain tax positions, including the 1999 sale of fossil generating assets.