EXELON CORP - Quarter Report: 2019 June (Form 10-Q)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



☒	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period Ended June 30, 2019



☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934



Commission File Number	Name of Registrant; State or Other Jurisdiction of Incorporation; Address of Principal Executive Offices; and Telephone Number	IRS Employer Identification Number

001-16169	EXELON CORPORATION	23-2990190
	(a Pennsylvania corporation) 10 South Dearborn Street P.O. Box 805379 Chicago, Illinois 60680-5379 (800) 483-3220

333-85496	EXELON GENERATION COMPANY, LLC	23-3064219
	(a Pennsylvania limited liability company) 300 Exelon Way Kennett Square, Pennsylvania 19348-2473 (610) 765-5959

001-1839	COMMONWEALTH EDISON COMPANY	36-0938600
	(an Illinois corporation) 440 South LaSalle Street Chicago, Illinois 60605-1028 (312) 394-4321

000-16844	PECO ENERGY COMPANY	23-0970240
	(a Pennsylvania corporation) P.O. Box 8699 2301 Market Street Philadelphia, Pennsylvania 19101-8699 (215) 841-4000

001-1910	BALTIMORE GAS AND ELECTRIC COMPANY	52-0280210
	(a Maryland corporation) 2 Center Plaza 110 West Fayette Street Baltimore, Maryland 21201-3708 (410) 234-5000

001-31403	PEPCO HOLDINGS LLC	52-2297449
	(a Delaware limited liability company) 701 Ninth Street, N.W. Washington, District of Columbia 20068 (202) 872-2000

001-01072	POTOMAC ELECTRIC POWER COMPANY	53-0127880
	(a District of Columbia and Virginia corporation) 701 Ninth Street, N.W. Washington, District of Columbia 20068 (202) 872-2000

001-01405	DELMARVA POWER & LIGHT COMPANY	51-0084283
	(a Delaware and Virginia corporation) 500 North Wakefield Drive Newark, Delaware 19702 (202) 872-2000

001-03559	ATLANTIC CITY ELECTRIC COMPANY	21-0398280
	(a New Jersey corporation) 500 North Wakefield Drive Newark, Delaware 19702 (202) 872-2000

Securities registered pursuant to Section 12(b) of the Act:



Title of each class	Trading Symbol(s)	Name of each exchange on which registered
EXELON CORPORATION:
Common Stock, without par value	EXC	New York Stock Exchange	and	Chicago Stock Exchange
Series A Junior Debt Subordinated Debentures	EXC22	New York Stock Exchange

PECO ENERGY COMPANY:
Trust Receipts of PECO Energy Capital Trust III, each representing a 7.38% Cumulative Preferred Security, Series D, $25 stated value, issued by PECO Energy Capital, L.P. and unconditionally guaranteed by PECO Energy Company	EXC/28	New York Stock Exchange

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.



Exelon Corporation	Large Accelerated Filer	x	Accelerated Filer	☐	Non-accelerated Filer	☐	Smaller Reporting Company	☐	Emerging Growth Company	☐
Exelon Generation Company, LLC	Large Accelerated Filer	☐	Accelerated Filer	☐	Non-accelerated Filer	x	Smaller Reporting Company	☐	Emerging Growth Company	☐
Commonwealth Edison Company	Large Accelerated Filer	☐	Accelerated Filer	☐	Non-accelerated Filer	x	Smaller Reporting Company	☐	Emerging Growth Company	☐
PECO Energy Company	Large Accelerated Filer	☐	Accelerated Filer	☐	Non-accelerated Filer	x	Smaller Reporting Company	☐	Emerging Growth Company	☐
Baltimore Gas and Electric Company	Large Accelerated Filer	☐	Accelerated Filer	☐	Non-accelerated Filer	x	Smaller Reporting Company	☐	Emerging Growth Company	☐
Pepco Holdings LLC	Large Accelerated Filer	☐	Accelerated Filer	☐	Non-accelerated Filer	x	Smaller Reporting Company	☐	Emerging Growth Company	☐
Potomac Electric Power Company	Large Accelerated Filer	☐	Accelerated Filer	☐	Non-accelerated Filer	x	Smaller Reporting Company	☐	Emerging Growth Company	☐
Delmarva Power & Light Company	Large Accelerated Filer	☐	Accelerated Filer	☐	Non-accelerated Filer	x	Smaller Reporting Company	☐	Emerging Growth Company	☐
Atlantic City Electric Company	Large Accelerated Filer	☐	Accelerated Filer	☐	Non-accelerated Filer	x	Smaller Reporting Company	☐	Emerging Growth Company	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No x

The number of shares outstanding of each registrant’s common stock as of June 30, 2019 was:



Exelon Corporation Common Stock, without par value	971,584,496
Exelon Generation Company, LLC	not applicable
Commonwealth Edison Company Common Stock, $12.50 par value	127,021,343
PECO Energy Company Common Stock, without par value	170,478,507
Baltimore Gas and Electric Company Common Stock, without par value	1,000
Pepco Holdings LLC	not applicable
Potomac Electric Power Company Common Stock, $0.01 par value	100
Delmarva Power & Light Company Common Stock, $2.25 par value	1,000
Atlantic City Electric Company Common Stock, $3.00 par value	8,546,017

TABLE OF CONTENTS



		Page No.
GLOSSARY OF TERMS AND ABBREVIATIONS		4
FILING FORMAT		8
CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION		8
WHERE TO FIND MORE INFORMATION		8
PART I.	FINANCIAL INFORMATION	9
ITEM 1.	FINANCIAL STATEMENTS	9
	Exelon Corporation
	Consolidated Statements of Operations and Comprehensive Income	10
	Consolidated Statements of Cash Flows	11
	Consolidated Balance Sheets	12
	Consolidated Statements of Changes in Shareholders’ Equity	14
	Exelon Generation Company, LLC
	Consolidated Statements of Operations and Comprehensive Income	15
	Consolidated Statements of Cash Flows	16
	Consolidated Balance Sheets	17
	Consolidated Statements of Changes in Equity	19
	Commonwealth Edison Company
	Consolidated Statements of Operations and Comprehensive Income	20
	Consolidated Statements of Cash Flows	21
	Consolidated Balance Sheets	22
	Consolidated Statements of Changes in Shareholders' Equity	24
	PECO Energy Company
	Consolidated Statements of Operations and Comprehensive Income	25
	Consolidated Statements of Cash Flows	26
	Consolidated Balance Sheets	27
	Consolidated Statements of Changes in Shareholder's Equity	29
	Baltimore Gas and Electric Company
	Statements of Operations and Comprehensive Income	30
	Statements of Cash Flows	31
	Balance Sheets	32
	Statements of Changes in Shareholder's Equity	34
	Pepco Holdings LLC
	Consolidated Statements of Operations and Comprehensive Income	35
	Consolidated Statements of Cash Flows	36
	Consolidated Balance Sheets	37
	Consolidated Statements of Changes in Equity	39



		Page No.
	Potomac Electric Power Company
	Statements of Operations and Comprehensive Income	40
	Statements of Cash Flows	41
	Balance Sheets	42
	Statements of Changes in Shareholder's Equity	44
	Delmarva Power & Light Company
	Statements of Operations and Comprehensive Income	45
	Statements of Cash Flows	46
	Balance Sheets	47
	Statements of Changes in Shareholder’s Equity	49
	Atlantic City Electric Company
	Consolidated Statements of Operations and Comprehensive Income	50
	Consolidated Statements of Cash Flows	51
	Consolidated Balance Sheets	52
	Consolidated Statements of Changes in Shareholder’s Equity	54
	Combined Notes to Consolidated Financial Statements	55
	1. Significant Accounting Policies	55
	2. Variable Interest Entities	57
	3. Mergers, Acquisitions and Dispositions	62
	4. Revenue from Contracts with Customers	63
	5. Leases	64
	6. Regulatory Matters	68
	7. Impairment of Long-Lived Assets	73
	8. Early Plant Retirements	74
	9. Fair Value of Financial Assets and Liabilities	76
	10. Derivative Financial Instruments	87
	11. Debt and Credit Agreements	94
	12. Income Taxes	96
	13. Nuclear Decommissioning	99
	14. Retirement Benefits	100
	15. Changes in Accumulated Other Comprehensive Income	103
	16. Commitments and Contingencies	106
	17. Supplemental Financial Information	114
	18. Segment Information	120



		Page No.
ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	136
	Exelon Corporation	136
	Executive Overview	136
	Financial Results of Operations	137
	Significant 2019 Transactions and Developments	140
	Other Key Business Drivers and Management Strategies	142
	Critical Accounting Policies and Estimates	145
	Results of Operations By Registrant	146
	Exelon Generation Company, LLC	147
	Commonwealth Edison Company	154
	PECO Energy Company	157
	Baltimore Gas and Electric Company	161
	Pepco Holdings LLC	164
	Potomac Electric Power Company	165
	Delmarva Power & Light Company	168
	Atlantic City Electric Company	173
	Liquidity and Capital Resources	177
	Contractual Obligations and Off-Balance Sheet Arrangements	184
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	185
ITEM 4.	CONTROLS AND PROCEDURES	190
PART II.	OTHER INFORMATION	190
ITEM 1.	LEGAL PROCEEDINGS	190
ITEM 1A.	RISK FACTORS	190
ITEM 4.	MINE SAFETY DISCLOSURES	190
ITEM 5.	OTHER INFORMATION	191
ITEM 6.	EXHIBITS	191
SIGNATURES		194
	Exelon Corporation	194
	Exelon Generation Company, LLC	195
	Commonwealth Edison Company	196
	PECO Energy Company	197
	Baltimore Gas and Electric Company	198
	Pepco Holdings LLC	199
	Potomac Electric Power Company	200
	Delmarva Power & Light Company	201
	Atlantic City Electric Company	202

Table of Contents



GLOSSARY OF TERMS AND ABBREVIATIONS
Exelon Corporation and Related Entities
Exelon		Exelon Corporation
Generation		Exelon Generation Company, LLC
ComEd		Commonwealth Edison Company
PECO		PECO Energy Company
BGE		Baltimore Gas and Electric Company
Pepco Holdings or PHI		Pepco Holdings LLC (formerly Pepco Holdings, Inc.)
Pepco		Potomac Electric Power Company
DPL		Delmarva Power & Light Company
ACE		Atlantic City Electric Company
Registrants		Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, collectively
Utility Registrants		ComEd, PECO, BGE, Pepco, DPL and ACE, collectively
ACE Funding or ATF		Atlantic City Electric Transition Funding LLC
Antelope Valley		Antelope Valley Solar Ranch One
BSC		Exelon Business Services Company, LLC
CENG		Constellation Energy Nuclear Group, LLC
Constellation		Constellation Energy Group, Inc.
EGR IV		ExGen Renewables IV, LLC
EGRP		ExGen Renewables Partners, LLC
Exelon Corporate		Exelon in its corporate capacity as a holding company
FitzPatrick		James A. FitzPatrick nuclear generating station
PCI		Potomac Capital Investment Corporation and its subsidiaries
Pepco Energy Services or PES		Pepco Energy Services, Inc. and its subsidiaries
PHI Corporate		PHI in its corporate capacity as a holding company
PHISCO		PHI Service Company
SolGen		SolGen, LLC
TMI		Three Mile Island nuclear facility

Table of Contents



GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
Note "—" of the 2018 Form 10-K		Reference to specific Combined Note to Consolidated Financial Statements within Exelon’s 2018 Annual Report on Form 10-K
AESO		Alberta Electric Systems Operator
AFUDC		Allowance for Funds Used During Construction
AMI		Advanced Metering Infrastructure
AOCI		Accumulated Other Comprehensive Income
ARC		Asset Retirement Cost
ARO		Asset Retirement Obligation
BGS		Basic Generation Service
CES		Clean Energy Standard
Clean Air Act		Clean Air Act of 1963, as amended
Clean Water Act		Federal Water Pollution Control Amendments of 1972, as amended
CODM		Chief operating decision maker(s)
D.C. Circuit Court		United States Court of Appeals for the District of Columbia Circuit
DC PLUG		District of Columbia Power Line Undergrounding Initiative
DCPSC		Public Service Commission of the District of Columbia
DOE		United States Department of Energy
DOEE		Department of Energy & Environment
DOJ		United States Department of Justice
DPSC		Delaware Public Service Commission
EDF		Electricite de France SA and its subsidiaries
EIMA		Energy Infrastructure Modernization Act (Illinois Senate Bill 1652 and Illinois House Bill 3036)
EPA		United States Environmental Protection Agency
EPSA		Electric Power Supply Association
ERCOT		Electric Reliability Council of Texas
FASB		Financial Accounting Standards Board
FEJA		Illinois Public Act 99-0906 or Future Energy Jobs Act
FERC		Federal Energy Regulatory Commission
FRCC		Florida Reliability Coordinating Council
GAAP		Generally Accepted Accounting Principles in the United States
GCR		Gas Cost Rate
GSA		Generation Supply Adjustment
ICC		Illinois Commerce Commission
ICE		Intercontinental Exchange
Illinois EPA		Illinois Environmental Protection Agency
IPA		Illinois Power Agency
IRC		Internal Revenue Code
IRS		Internal Revenue Service
ISO		Independent System Operator
ISO-NE		Independent System Operator New England Inc.

Table of Contents



GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
ISO-NY		Independent System Operator New York
LIBOR		London Interbank Offered Rate
MDE		Maryland Department of the Environment
MDPSC		Maryland Public Service Commission
MGP		Manufactured Gas Plant
MISO		Midcontinent Independent System Operator, Inc.
mmcf		Million Cubic Feet
MOPR		Minimum Offer Price Rule
MW		Megawatt
NAAQS		National Ambient Air Quality Standards
NDT		Nuclear Decommissioning Trust
NEIL		Nuclear Electric Insurance Limited
NERC		North American Electric Reliability Corporation
NJBPU		New Jersey Board of Public Utilities
Non-Regulatory Agreements Units		Nuclear generating units or portions thereof whose decommissioning-related activities are not subject to contractual elimination under regulatory accounting
NOSA		Nuclear Operating Services Agreement
NPNS		Normal Purchase Normal Sale scope exception
NRC		Nuclear Regulatory Commission
NYMEX		New York Mercantile Exchange
NYPSC		New York Public Service Commission
OCI		Other Comprehensive Income
OIESO		Ontario Independent Electricity System Operator
OPEB		Other Postretirement Employee Benefits
Oyster Creek		Oyster Creek Generating Station
PA DEP		Pennsylvania Department of Environmental Protection
PAPUC		Pennsylvania Public Utility Commission
PG&E		Pacific Gas and Electric Company
PJM		PJM Interconnection, LLC
POLR		Provider of Last Resort
PPA		Power Purchase Agreement
PPE		Property, plant and equipment
Price-Anderson Act		Price-Anderson Nuclear Industries Indemnity Act of 1957
PRP		Potentially Responsible Parties
PSDAR		Post-Shutdown Decommissioning Activities Report
PSEG		Public Service Enterprise Group Incorporated
REC		Renewable Energy Credit which is issued for each megawatt hour of generation from a qualified renewable energy source
RNF		Revenues Net of Purchased Power and Fuel Expense
Regulatory Agreement Units		Nuclear generating units or portions thereof whose decommissioning-related activities are subject to contractual elimination under regulatory accounting
Rider		Reconcilable Surcharge Recovery Mechanism

Table of Contents



GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
RMC		Risk Management Committee
ROE		Return on equity
ROU		Right-of-use
RSSA		Reliability Support Services Agreement
RTO		Regional Transmission Organization
SEC		United States Securities and Exchange Commission
SERC		SERC Reliability Corporation (formerly Southeast Electric Reliability Council)
SNF		Spent Nuclear Fuel
SOS		Standard Offer Service
TCJA		Tax Cuts and Jobs Act
Transition Bonds		Transition Bonds issued by ACE Funding
Upstream		Natural gas exploration and production activities
VIE		Variable Interest Entity
WECC		Western Electric Coordinating Council
ZEC		Zero Emission Credit, or Zero Emission Certificate
ZES		Zero Emission Standard

Table of Contents

FILING FORMAT

This combined Form 10-Q is being filed separately by Exelon Corporation, Exelon Generation Company, LLC, Commonwealth Edison Company, PECO Energy Company, Baltimore Gas and Electric Company, Pepco Holdings LLC, Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company (Registrants). Information contained herein relating to any individual Registrant is filed by such Registrant on its own behalf. No Registrant makes any representation as to information relating to any other Registrant.

CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION

This Report contains certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are subject to risks and uncertainties. The factors that could cause actual results to differ materially from the forward-looking statements made by the Registrants include those factors discussed herein, as well as the items discussed in (1) the Registrants' combined 2018 Annual Report on Form 10-K in (a) ITEM 1A. Risk Factors, (b) ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) ITEM 8. Financial Statements and Supplementary Data: Note 22, Commitments and Contingencies; (2) this Quarterly Report on Form 10-Q in (a) Part II, Other Information, ITEM 1A. Risk Factors; (b) Part 1, Financial Information, ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) Part I, Financial Information, ITEM 1. Financial Statements: Note 16, Commitments and Contingencies; and (3) other factors discussed in filings with the SEC by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this Report. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this Report.

WHERE TO FIND MORE INFORMATION

The SEC maintains an Internet site at www.sec.gov that contains reports, proxy and information statements, and other information that the Registrants file electronically with the SEC. These documents are also available to the public from commercial document retrieval services and the Registrants' website at www.exeloncorp.com. Information contained on the Registrants' website shall not be deemed incorporated into, or to be a part of, this Report.

Table of Contents

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Table of Contents

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
(In millions, except per share data)	2019			2018			2019			2018
Operating revenues
Competitive businesses revenues	$	3,959		$	4,305		$	8,938		$	9,417
Rate-regulated utility revenues	3,743			3,797			8,247			8,368
Revenues from alternative revenue programs	(13		)	(26		)	(19		)	(16		)
Total operating revenues	7,689			8,076			17,166			17,769
Operating expenses
Competitive businesses purchased power and fuel	2,289			2,277			5,493			5,566
Rate-regulated utility purchased power and fuel	936			1,038			2,285			2,476
Operating and maintenance	2,159			2,307			4,347			4,691
Depreciation and amortization	1,079			1,088			2,154			2,179
Taxes other than income	418			428			863			874
Total operating expenses	6,881			7,138			15,142			15,786
Gain on sales of assets and businesses	33			4			36			60
Operating income	841			942			2,060			2,043
Other income and (deductions)
Interest expense, net	(403		)	(367		)	(800		)	(732		)
Interest expense to affiliates	(6		)	(6		)	(13		)	(13		)
Other, net	212			44			679			17
Total other income and (deductions)	(197		)	(329		)	(134		)	(728		)
Income before income taxes	644			613			1,926			1,315
Income taxes	144			66			454			125
Equity in losses of unconsolidated affiliates	(6		)	(5		)	(12		)	(11		)
Net income	494			542			1,460			1,179
Net income attributable to noncontrolling interests	10			3			69			54
Net income attributable to common shareholders	$	484		$	539		$	1,391		$	1,125
Comprehensive income, net of income taxes
Net income	$	494		$	542		$	1,460		$	1,179
Other comprehensive (loss) income, net of income taxes
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	(16		)	(17		)	(32		)	(33		)
Actuarial loss reclassified to periodic benefit cost	36			61			74			123
Pension and non-pension postretirement benefit plan valuation adjustment	—			(1		)	(39		)	18
Unrealized gain on cash flow hedges	—			4			—			12
Unrealized (loss) gain on investments in unconsolidated affiliates	(2		)	2			(4		)	3
Unrealized gain (loss) on foreign currency translation	3			(5		)	4			(6		)
Other comprehensive income	21			44			3			117
Comprehensive income	515			586			1,463			1,296
Comprehensive income attributable to noncontrolling interests	9			4			67			56
Comprehensive income attributable to common shareholders	$	506		$	582		$	1,396		$	1,240

Average shares of common stock outstanding:
Basic	972			967			972			967
Assumed exercise and/or distributions of stock-based awards	2			2			1			1
Diluted^(a)	974			969			973			968

Earnings per average common share:
Basic	$	0.50		$	0.56		$	1.43		$	1.16
Diluted	$	0.50		$	0.56		$	1.43		$	1.16

__________


(a)	The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was immaterial for the three and six months ended June 30, 2019 and approximately 2 million and 5 million for the three and six months ended June 30, 2018, respectively.

See the Combined Notes to Consolidated Financial Statements

Table of Contents

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Six Months Ended June 30,
(In millions)	2019			2018
Cash flows from operating activities
Net income	$	1,460		$	1,179
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization	2,922			3,000
Impairment of long-lived assets	9			41
Gain on sales of assets and businesses	(33		)	(60		)
Deferred income taxes and amortization of investment tax credits	284			(2		)
Net fair value changes related to derivatives	107			151
Net realized and unrealized (gains) losses on NDT funds	(404		)	80
Other non-cash operating activities	277			479
Changes in assets and liabilities:
Accounts receivable	618			(105		)
Inventories	19			60
Accounts payable and accrued expenses	(924		)	(342		)
Option premiums received (paid), net	48			(36		)
Collateral (posted) received, net	(311		)	81
Income taxes	151			129
Pension and non-pension postretirement benefit contributions	(355		)	(345		)
Other assets and liabilities	(970		)	(441		)
Net cash flows provided by operating activities	2,898			3,869
Cash flows from investing activities
Capital expenditures	(3,572		)	(3,807		)
Proceeds from NDT fund sales	6,920			3,822
Investment in NDT funds	(6,847		)	(3,924		)
Acquisition of assets and businesses, net	—			(57		)
Proceeds from sales of assets and businesses	14			89
Other investing activities	26			31
Net cash flows used in investing activities	(3,459		)	(3,846		)
Cash flows from financing activities
Changes in short-term borrowings	470			200
Proceeds from short-term borrowings with maturities greater than 90 days	—			126
Repayments on short-term borrowings with maturities greater than 90 days	(125		)	(1		)
Issuance of long-term debt	850			1,488
Retirement of long-term debt	(574		)	(1,309		)
Dividends paid on common stock	(704		)	(666		)
Proceeds from employee stock plans	75			27
Other financing activities	(34		)	(50		)
Net cash flows used in financing activities	(42		)	(185		)
Decrease in cash, cash equivalents and restricted cash	(603		)	(162		)
Cash, cash equivalents and restricted cash at beginning of period	1,781			1,190
Cash, cash equivalents and restricted cash at end of period	$	1,178		$	1,028

Supplemental cash flow information
Decrease in capital expenditures not paid	$	(133	)	$	(283	)
Increase in PPE related to ARO update	301			47

See the Combined Notes to Consolidated Financial Statements

Table of Contents

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)



(In millions)	June 30, 2019		December 31, 2018
ASSETS
Current assets
Cash and cash equivalents	$	735	$	1,349
Restricted cash and cash equivalents	252		247
Accounts receivable, net
Customer (net of allowance for uncollectible accounts of $257 and $283 as of June 30, 2019 and December 31, 2018, respectively)	4,125		4,607
Other (net of allowance for uncollectible accounts of $40 and $36 as of June 30, 2019 and December 31, 2018, respectively)	1,008		1,256
Mark-to-market derivative assets	526		804
Unamortized energy contract assets	47		48
Inventories, net
Fossil fuel and emission allowances	258		334
Materials and supplies	1,412		1,351
Regulatory assets	1,194		1,222
Assets held for sale	880		904
Other	1,218		1,238
Total current assets	11,655		13,360
Property, plant and equipment (net of accumulated depreciation and amortization of $24,266 and $22,902 as of June 30, 2019 and December 31, 2018, respectively)	78,030		76,707
Deferred debits and other assets
Regulatory assets	8,166		8,237
Nuclear decommissioning trust funds	12,513		11,661
Investments	618		625
Goodwill	6,677		6,677
Mark-to-market derivative assets	537		452
Unamortized energy contract assets	362		372
Other	3,038		1,575
Total deferred debits and other assets	31,911		29,599
Total assets^(a)	$	121,596	$	119,666

See the Combined Notes to Consolidated Financial Statements

Table of Contents

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)



(In millions)	June 30, 2019			December 31, 2018
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings	$	1,059		$	714
Long-term debt due within one year	3,776			1,349
Accounts payable	3,248			3,800
Accrued expenses	1,706			2,112
Payables to affiliates	5			5
Regulatory liabilities	403			644
Mark-to-market derivative liabilities	163			475
Unamortized energy contract liabilities	145			149
Renewable energy credit obligation	298			344
Liabilities held for sale	764			777
Other	1,367			1,035
Total current liabilities	12,934			11,404
Long-term debt	31,909			34,075
Long-term debt to financing trusts	390			390
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	11,826			11,330
Asset retirement obligations	10,023			9,679
Pension obligations	3,720			3,988
Non-pension postretirement benefit obligations	2,007			1,928
Spent nuclear fuel obligation	1,186			1,171
Regulatory liabilities	9,793			9,559
Mark-to-market derivative liabilities	450			479
Unamortized energy contract liabilities	398			463
Other	3,053			2,130
Total deferred credits and other liabilities	42,456			40,727
Total liabilities^(a)	87,689			86,596
Commitments and contingencies
Shareholders’ equity
Common stock (No par value, 2,000 shares authorized, 972 shares and 968 shares outstanding at June 30, 2019 and December 31, 2018, respectively)	19,209			19,116
Treasury stock, at cost (2 shares at June 30, 2019 and December 31, 2018)	(123		)	(123		)
Retained earnings	15,452			14,766
Accumulated other comprehensive loss, net	(2,990		)	(2,995		)
Total shareholders’ equity	31,548			30,764
Noncontrolling interests	2,359			2,306
Total equity	33,907			33,070
Total liabilities and shareholders’ equity	$	121,596		$	119,666

__________

(a)

Exelon’s consolidated assets include $9,526 million and $9,667 million at June 30, 2019 and December 31, 2018, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $3,568 million and $3,548 million at June 30, 2019 and December 31, 2018, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 2 — Variable Interest Entities for additional information.

See the Combined Notes to Consolidated Financial Statements

Table of Contents

EXELON CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)



	Six Months Ended June 30, 2019
(In millions, shares in thousands)	Issued Shares	Common Stock			Treasury Stock			Retained Earnings			Accumulated Other Comprehensive Loss, net			Noncontrolling Interests			Total Shareholders' Equity
Balance, December 31, 2018	970,020	$	19,116		$	(123	)	$	14,766		$	(2,995	)	$	2,306		$	33,070
Net income	—	—			—			907			—			59			966
Long-term incentive plan activity	2,446	(3		)	—			—			—			—			(3		)
Employee stock purchase plan issuances	320	51			—			—			—			—			51
Changes in equity of noncontrolling interests	—	—			—			—			—			(17		)	(17		)
Sale of noncontrolling interests	—	7			—			—			—			—			7
Common stock dividends ($0.36/common share)	—	—			—			(352		)	—			—			(352		)
Other comprehensive loss, net of income taxes	—	—			—			—			(17		)	(1		)	(18		)
Balance, March 31, 2019	972,786	$	19,171		$	(123	)	$	15,321		$	(3,012	)	$	2,347		$	33,704
Net income	—	—			—			484			—			10			494
Long-term incentive plan activity	320	14			—			—			—			—			14
Employee stock purchase plan issuances	311	24			—			—			—			—			24
Changes in equity of noncontrolling interests	—	—			—			—			—			3			3
Sale of noncontrolling interests	—	—			—			—			—			—			—
Common stock dividends ($0.36/common share)	—	—			—			(353		)	—			—			(353		)
Other comprehensive income (loss), net of income taxes	—	—			—			—			22			(1		)	21
Balance, June 30, 2019	973,417	$	19,209		$	(123	)	$	15,452		$	(2,990	)	$	2,359		$	33,907



	Six Months Ended June 30, 2018
(In millions, shares in thousands)	Issued Shares	Common Stock			Treasury Stock			Retained Earnings			Accumulated Other Comprehensive Loss, net			Noncontrolling Interests			Total Shareholders' Equity
Balance, December 31, 2017	965,168	$	18,964		$	(123	)	$	14,081		$	(3,026	)	$	2,291		$	32,187
Net income	—	—			—			585			—			51			636
Long-term incentive plan activity	1,685	(3		)	—			—			—			—			(3		)
Employee stock purchase plan issuances	361	12			—			—			—			—			12
Changes in equity of noncontrolling interests	—	—			—			—			—			(9		)	(9		)
Common stock dividends ($0.35/common share)	—	—			—			(334		)	—			—			(334		)
Other comprehensive income, net of income taxes	—	—			—			—			71			1			72
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard	—	—			—			14			(10		)	—			4
Balance, March 31, 2018	967,214	$	18,973		$	(123	)	$	14,346		$	(2,965	)	$	2,334		$	32,565
Net income	—	—			—			539			—			3			542
Long-term incentive plan activity	183	20			—			—			—			—			20
Employee stock purchase plan issuances	342	15			—			—			—			—			15
Changes in equity of noncontrolling interests	—	—			—			—			—			(14		)	(14		)
Common stock dividends ($0.35/common share)	—	—			—			(334		)	—			—			(334		)
Other comprehensive income, net of income taxes	—	—			—			—			44			1			45
Balance, June 30, 2018	967,739	$	19,008		$	(123	)	$	14,551		$	(2,921	)	$	2,324		$	32,839

See the Combined Notes to Consolidated Financial Statements

Table of Contents

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2019			2018			2019			2018
Operating revenues
Operating revenues	$	3,958		$	4,306		$	8,937		$	9,419
Operating revenues from affiliates	252			273			569			671
Total operating revenues	4,210			4,579			9,506			10,090
Operating expenses
Purchased power and fuel	2,289			2,277			5,493			5,566
Purchased power and fuel from affiliates	3			3			4			7
Operating and maintenance	1,117			1,247			2,185			2,425
Operating and maintenance from affiliates	149			171			299			331
Depreciation and amortization	409			466			814			914
Taxes other than income	129			134			264			272
Total operating expenses	4,096			4,298			9,059			9,515
Gain on sales of assets and businesses	33			1			33			54
Operating income	147			282			480			629
Other income and (deductions)
Interest expense, net	(107		)	(93		)	(209		)	(184		)
Interest expense to affiliates	(9		)	(9		)	(18		)	(18		)
Other, net	171			29			601			(15		)
Total other income and (deductions)	55			(73		)	374			(217		)
Income before income taxes	202			209			854			412
Income taxes	78			23			301			32
Equity in losses of unconsolidated affiliates	(6		)	(5		)	(13		)	(12		)
Net income	118			181			540			368
Net income attributable to noncontrolling interests	10			3			68			54
Net income attributable to membership interest	$	108		$	178		$	472		$	314
Comprehensive income, net of income taxes
Net income	$	118		$	181		$	540		$	368
Other comprehensive income (loss), net of income taxes
Unrealized (loss) gain on cash flow hedges	(1		)	5			—			12
Unrealized (loss) gain on investments in unconsolidated affiliates	(2		)	2			(4		)	3
Unrealized gain (loss) on foreign currency translation	2			(5		)	4			(6		)
Other comprehensive (loss) income	(1		)	2			—			9
Comprehensive income	117			183			540			377
Comprehensive income attributable to noncontrolling interests	9			4			66			56
Comprehensive income attributable to membership interest	$	108		$	179		$	474		$	321

See the Combined Notes to Consolidated Financial Statements

Table of Contents

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Six Months Ended June 30,
(In millions)	2019			2018
Cash flows from operating activities
Net income	$	540		$	368
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization	1,580			1,735
Impairment of long-lived assets	9			41
Gain on sales of assets and businesses	(33		)	(54		)
Deferred income taxes and amortization of investment tax credits	151			(149		)
Net fair value changes related to derivatives	114			158
Net realized and unrealized (gains) losses on NDT funds	(404		)	80
Other non-cash operating activities	(50		)	85
Changes in assets and liabilities:
Accounts receivable	472			258
Receivables from and payables to affiliates, net	(18		)	7
Inventories	32			34
Accounts payable and accrued expenses	(507		)	(272		)
Option premiums received (paid), net	48			(36		)
Collateral (posted) received, net	(318		)	91
Income taxes	321			58
Pension and non-pension postretirement benefit contributions	(158		)	(129		)
Other assets and liabilities	(351		)	(212		)
Net cash flows provided by operating activities	1,428			2,063
Cash flows from investing activities
Capital expenditures	(890		)	(1,298		)
Proceeds from NDT fund sales	6,920			3,822
Investment in NDT funds	(6,847		)	(3,924		)
Acquisition of assets and businesses, net	—			(57		)
Proceeds from sales of assets and businesses	14			89
Changes in Exelon intercompany money pool	(179		)	(185		)
Other investing activities	8			4
Net cash flows used in investing activities	(974		)	(1,549		)
Cash flows from financing activities
Issuance of long-term debt	40			13
Retirement of long-term debt	(130		)	(76		)
Changes in Exelon intercompany money pool	(100		)	(54		)
Distributions to member	(449		)	(377		)
Other financing activities	(21		)	(24		)
Net cash flows used in financing activities	(660		)	(518		)
Decrease in cash, cash equivalents and restricted cash	(206		)	(4		)
Cash, cash equivalents and restricted cash at beginning of period	903			554
Cash, cash equivalents and restricted cash at end of period	$	697		$	550

Supplemental cash flow information
Decrease in capital expenditures not paid	$	(30	)	$	(310	)
Increase in PPE related to ARO update	301			47

See the Combined Notes to Consolidated Financial Statements

Table of Contents

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)



(In millions)	June 30, 2019		December 31, 2018
ASSETS
Current assets
Cash and cash equivalents	$	575	$	750
Restricted cash and cash equivalents	122		153
Accounts receivable, net
Customer (net of allowance for uncollectible accounts of $96 and $103 as of June 30, 2019 and December 31, 2018, respectively)	2,528		2,941
Other (net of allowance for uncollectible accounts of $1 as of both June 30, 2019 and December 31, 2018)	326		562
Mark-to-market derivative assets	526		804
Receivables from affiliates	159		173
Receivable from Exelon intercompany money pool	179		—
Unamortized energy contract assets	47		49
Inventories, net
Fossil fuel and emission allowances	201		251
Materials and supplies	984		963
Assets held for sale	880		904
Other	849		883
Total current assets	7,376		8,433
Property, plant and equipment (net of accumulated depreciation and amortization of $12,902 and $12,206 as of June 30, 2019 and December 31, 2018, respectively)	23,810		23,981
Deferred debits and other assets
Nuclear decommissioning trust funds	12,513		11,661
Investments	401		414
Goodwill	47		47
Mark-to-market derivative assets	533		452
Prepaid pension asset	1,506		1,421
Unamortized energy contract assets	361		371
Deferred income taxes	14		21
Other	1,841		755
Total deferred debits and other assets	17,216		15,142
Total assets^(a)	$	48,402	$	47,556

See the Combined Notes to Consolidated Financial Statements

Table of Contents

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)



(In millions)	June 30, 2019			December 31, 2018
LIABILITIES AND EQUITY
Current liabilities
Long-term debt due within one year	$	2,733		$	906
Accounts payable	1,517			1,847
Accrued expenses	767			898
Payables to affiliates	122			139
Borrowings from Exelon intercompany money pool	—			100
Mark-to-market derivative liabilities	134			449
Unamortized energy contract liabilities	26			31
Renewable energy credit obligation	298			343
Liabilities held for sale	764			777
Other	481			279
Total current liabilities	6,842			5,769
Long-term debt	5,079			6,989
Long-term debt to affiliates	892			898
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	3,534			3,383
Asset retirement obligations	9,792			9,450
Non-pension postretirement benefit obligations	889			900
Spent nuclear fuel obligation	1,186			1,171
Payables to affiliates	2,928			2,606
Mark-to-market derivative liabilities	206			252
Unamortized energy contract liabilities	13			20
Other	1,449			610
Total deferred credits and other liabilities	19,997			18,392
Total liabilities^(a)	32,810			32,048
Commitments and contingencies
Equity
Member’s equity
Membership interest	9,525			9,518
Undistributed earnings	3,746			3,724
Accumulated other comprehensive loss, net	(36		)	(38		)
Total member’s equity	13,235			13,204
Noncontrolling interests	2,357			2,304
Total equity	15,592			15,508
Total liabilities and equity	$	48,402		$	47,556

__________

(a)

Generation’s consolidated assets include $9,503 million and $9,634 million at June 30, 2019 and December 31, 2018, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $3,513 million and $3,480 million at June 30, 2019 and December 31, 2018, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 2 — Variable Interest Entities for additional information.

See the Combined Notes to Consolidated Financial Statements

Table of Contents

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(Unaudited)



	Six Months Ended June 30, 2019
	Member’s Equity
(In millions)	Membership Interest		Undistributed Earnings			Accumulated Other Comprehensive Loss, net			Noncontrolling Interests			Total Equity
Balance, December 31, 2018	$	9,518	$	3,724		$	(38	)	$	2,304		$	15,508
Net income	—		363			—			59			422
Changes in equity of noncontrolling interests	—		—			—			(17		)	(17		)
Sale of noncontrolling interests	7		—			—			—			7
Distributions to member	—		(225		)	—			—			(225		)
Other comprehensive income (loss), net of income taxes	—		—			2			(1		)	1
Balance, March 31, 2019	$	9,525	$	3,862		$	(36	)	$	2,345		$	15,696
Net income	—		108			—			10			118
Changes in equity of noncontrolling interests	—		—			—			3			3
Distributions to member	—		(224		)	—			—			(224		)
Other comprehensive loss, net of income taxes	—		—			—			(1		)	(1		)
Balance, June 30, 2019	$	9,525	$	3,746		$	(36	)	$	2,357		$	15,592



	Six Months Ended June 30, 2018
	Member’s Equity
(In millions)	Membership Interest		Undistributed Earnings			Accumulated Other Comprehensive Loss, net			Noncontrolling Interests			Total Equity
Balance, December 31, 2017	$	9,357	$	4,349		$	(37	)	$	2,290		$	15,959
Net income	—		136			—			50			186
Changes in equity of noncontrolling interests	—		—			—			(9		)	(9		)
Distributions to member	—		(188		)	—			—			(188		)
Other comprehensive income, net of income taxes	—		—			6			1			7
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard	—		6			(3		)	—			3
Balance, March 31, 2018	$	9,357	$	4,303		$	(34	)	$	2,332		$	15,958
Net income	—		178			—			3			181
Changes in equity of noncontrolling interests	—		—			—			(13		)	(13		)
Distributions to member	—		(189		)	—			—			(189		)
Other comprehensive income, net of income taxes	—		—			1			1			2
Balance, June 30, 2018	$	9,357	$	4,292		$	(33	)	$	2,323		$	15,939

See the Combined Notes to Consolidated Financial Statements

Table of Contents

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2019			2018			2019			2018
Operating revenues
Electric operating revenues	$	1,360		$	1,410		$	2,792		$	2,903
Revenues from alternative revenue programs	(14		)	(17		)	(42		)	(12		)
Operating revenues from affiliates	5			5			9			19
Total operating revenues	1,351			1,398			2,759			2,910
Operating expenses
Purchased power	316			373			705			784
Purchased power from affiliate	91			104			187			298
Operating and maintenance	245			255			504			509
Operating and maintenance from affiliate	60			69			122			129
Depreciation and amortization	257			231			508			459
Taxes other than income	71			79			148			156
Total operating expenses	1,040			1,111			2,174			2,335
Gain on sales of assets	—			1			3			5
Operating income	311			288			588			580
Other income and (deductions)
Interest expense, net	(86		)	(82		)	(171		)	(168		)
Interest expense to affiliates	(3		)	(3		)	(7		)	(7		)
Other, net	10			4			19			12
Total other income and (deductions)	(79		)	(81		)	(159		)	(163		)
Income before income taxes	232			207			429			417
Income taxes	46			43			85			88
Net income	$	186		$	164		$	344		$	329
Comprehensive income	$	186		$	164		$	344		$	329

See the Combined Notes to Consolidated Financial Statements

Table of Contents

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Six Months Ended June 30,
(In millions)	2019			2018
Cash flows from operating activities
Net income	$	344		$	329
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	508			459
Deferred income taxes and amortization of investment tax credits	64			84
Other non-cash operating activities	87			117
Changes in assets and liabilities:
Accounts receivable	56			(133		)
Receivables from and payables to affiliates, net	(16		)	15
Inventories	(5		)	5
Accounts payable and accrued expenses	(121		)	(41		)
Collateral posted, net	11			(13		)
Income taxes	43			(15		)
Pension and non-pension postretirement benefit contributions	(68		)	(39		)
Other assets and liabilities	(236		)	(166		)
Net cash flows provided by operating activities	667			602
Cash flows from investing activities
Capital expenditures	(961		)	(1,026		)
Other investing activities	17			17
Net cash flows used in investing activities	(944		)	(1,009		)
Cash flows from financing activities
Changes in short-term borrowings	303			320
Issuance of long-term debt	400			800
Retirement of long-term debt	(300		)	(700		)
Contributions from parent	124			225
Dividends paid on common stock	(254		)	(229		)
Other financing activities	(10		)	(10		)
Net cash flows provided by financing activities	263			406
Decrease in cash, cash equivalents and restricted cash	(14		)	(1		)
Cash, cash equivalents and restricted cash at beginning of period	330			144
Cash, cash equivalents and restricted cash at end of period	$	316		$	143

Supplemental cash flow information
Decrease in capital expenditures not paid	$	(77	)	$	(22	)

See the Combined Notes to Consolidated Financial Statements

Table of Contents

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)



(In millions)	June 30, 2019		December 31, 2018
ASSETS
Current assets
Cash and cash equivalents	$	65	$	135
Restricted cash	77		29
Accounts receivable, net
Customer (net of allowance for uncollectible accounts of $59 and $61 as of June 30, 2019 and December 31, 2018, respectively)	528		539
Other (net of allowance for uncollectible accounts of $18 and $20 as of June 30, 2019 and December 31, 2018, respectively)	268		320
Receivables from affiliates	20		20
Inventories, net	151		148
Regulatory assets	297		293
Other	76		86
Total current assets	1,482		1,570
Property, plant and equipment (net of accumulated depreciation and amortization of $4,949 and $4,684 as of June 30, 2019 and December 31, 2018, respectively)	22,527		22,058
Deferred debits and other assets
Regulatory assets	1,391		1,307
Investments	6		6
Goodwill	2,625		2,625
Receivables from affiliates	2,458		2,217
Prepaid pension asset	1,046		1,035
Other	354		395
Total deferred debits and other assets	7,880		7,585
Total assets	$	31,889	$	31,213

See the Combined Notes to Consolidated Financial Statements

Table of Contents

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)



(In millions)	June 30, 2019			December 31, 2018
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings	$	303		$	—
Long-term debt due within one year	—			300
Accounts payable	478			607
Accrued expenses	305			373
Payables to affiliates	91			119
Customer deposits	114			111
Regulatory liabilities	186			293
Mark-to-market derivative liability	29			26
Other	126			96
Total current liabilities	1,632			1,925
Long-term debt	8,195			7,801
Long-term debt to financing trust	205			205
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	3,929			3,813
Asset retirement obligations	119			118
Non-pension postretirement benefits obligations	191			201
Regulatory liabilities	6,322			6,050
Mark-to-market derivative liability	244			223
Other	592			630
Total deferred credits and other liabilities	11,397			11,035
Total liabilities	21,429			20,966
Commitments and contingencies
Shareholders’ equity
Common stock	1,588			1,588
Other paid-in capital	7,446			7,322
Retained deficit unappropriated	(1,639		)	(1,639		)
Retained earnings appropriated	3,065			2,976
Total shareholders’ equity	10,460			10,247
Total liabilities and shareholders’ equity	$	31,889		$	31,213

See the Combined Notes to Consolidated Financial Statements

Table of Contents

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

(Unaudited)



	Six Months Ended June 30, 2019
(In millions)	Common Stock		Other Paid-In Capital		Retained Deficit Unappropriated			Retained Earnings Appropriated			Total Shareholders’ Equity
Balance, December 31, 2018	$	1,588	$	7,322	$	(1,639	)	$	2,976		$	10,247
Net income	—		—		157			—			157
Appropriation of retained earnings for future dividends	—		—		(157		)	157			—
Common stock dividends	—		—		—			(127		)	(127		)
Contributions from parent	—		63		—			—			63
Balance, March 31, 2019	1,588		7,385		(1,639		)	3,006			10,340
Net income	—		—		186			—			186
Appropriation of retained earnings for future dividends	—		—		(186		)	186			—
Common stock dividends	—		—		—			(127		)	(127		)
Contributions from parent	—		61		—			—			61
Balance, June 30, 2019	$	1,588	$	7,446	$	(1,639	)	$	3,065		$	10,460


	Six Months Ended June 30, 2018
(In millions)	Common Stock		Other Paid-In Capital		Retained Deficit Unappropriated			Retained Earnings Appropriated			Total Shareholders’ Equity
Balance, December 31, 2017	$	1,588	$	6,822	$	(1,639	)	$	2,771		$	9,542
Net income	—		—		165			—			165
Appropriation of retained earnings for future dividends	—		—		(165		)	165			—
Common stock dividends	—		—		—			(114		)	(114		)
Contributions from parent	—		113		—			—			113
Balance, March 31, 2018	1,588		6,935		(1,639		)	2,822			9,706
Net income	—		—		164			—			164
Appropriation of retained earnings for future dividends	—		—		(164		)	164			—
Common stock dividends	—		—		—			(115		)	(115		)
Contributions from parent	—		112		—			—			112
Balance, June 30, 2018	$	1,588	$	7,047	$	(1,639	)	$	2,871		$	9,867

See the Combined Notes to Consolidated Financial Statements

Table of Contents

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2019			2018			2019			2018
Operating revenues
Electric operating revenues	$	567		$	556		$	1,188		$	1,189
Natural gas operating revenues	89			93			369			325
Revenues from alternative revenue programs	(3		)	2			(6		)	1
Operating revenues from affiliates	2			2			3			3
Total operating revenues	655			653			1,554			1,518
Operating expenses
Purchased power	124			161			275			361
Purchased fuel	32			37			166			134
Purchased power from affiliate	35			24			79			60
Operating and maintenance	162			153			349			387
Operating and maintenance from affiliates	37			38			75			79
Depreciation and amortization	83			74			164			149
Taxes other than income	37			39			79			79
Total operating expenses	510			526			1,187			1,249
Operating income	145			127			367			269
Other income and (deductions)
Interest expense, net	(30		)	(28		)	(61		)	(57		)
Interest expense to affiliates	(3		)	(4		)	(6		)	(7		)
Other, net	3			—			7			2
Total other income and (deductions)	(30		)	(32		)	(60		)	(62		)
Income before income taxes	115			95			307			207
Income taxes	13			(1		)	37			(3		)
Net income	$	102		$	96		$	270		$	210
Comprehensive income	$	102		$	96		$	270		$	210

See the Combined Notes to Consolidated Financial Statements

Table of Contents

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Six Months Ended June 30,
(In millions)	2019			2018
Cash flows from operating activities
Net income	$	270		$	210
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	164			149
Deferred income taxes and amortization of investment tax credits	8			(10		)
Other non-cash operating activities	15			22
Changes in assets and liabilities:
Accounts receivable	39			(43		)
Receivables from and payables to affiliates, net	(4		)	(4		)
Inventories	12			4
Accounts payable and accrued expenses	(31		)	(18		)
Income taxes	(11		)	19
Pension and non-pension postretirement benefit contributions	(27		)	(25		)
Other assets and liabilities	(117		)	(50		)
Net cash flows provided by operating activities	318			254
Cash flows from investing activities
Capital expenditures	(447		)	(411		)
Other investing activities	4			5
Net cash flows used in investing activities	(443		)	(406		)
Cash flows from financing activities
Changes in short-term borrowings	—			50
Issuance of long-term debt	—			375
Retirement of long-term debt	—			(500		)
Changes in Exelon intercompany money pool	52			233
Contributions from parent	145			41
Dividends paid on common stock	(180		)	(293		)
Other financing activities	(1		)	(6		)
Net cash flows provided by (used in) financing activities	16			(100		)
Decrease in cash, cash equivalents and restricted cash	(109		)	(252		)
Cash, cash equivalents and restricted cash at beginning of period	135			275
Cash, cash equivalents and restricted cash at end of period	$	26		$	23

Supplemental cash flow information
Increase (decrease) in capital expenditures not paid	$	33		$	(17	)

See the Combined Notes to Consolidated Financial Statements

Table of Contents

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)



(In millions)	June 30, 2019		December 31, 2018
ASSETS
Current assets
Cash and cash equivalents	$	20	$	130
Restricted cash and cash equivalents	6		5
Accounts receivable, net
Customer (net of allowance for uncollectible accounts of $53 and $53 as of June 30, 2019 and December 31, 2018, respectively)	302		321
Other (net of allowance for uncollectible accounts of $6 and $8 as of June 30, 2019 and December 31, 2018, respectively)	123		151
Inventories, net
Fossil fuel	26		38
Materials and supplies	37		37
Prepaid utility taxes	69		—
Regulatory assets	52		81
Other	23		19
Total current assets	658		782
Property, plant and equipment (net of accumulated depreciation and amortization of $3,636 and $3,561 as of June 30, 2019 and December 31, 2018, respectively)	8,940		8,610
Deferred debits and other assets
Regulatory assets	508		460
Investments	25		25
Receivable from affiliates	470		389
Prepaid pension asset	371		349
Other	30		27
Total deferred debits and other assets	1,404		1,250
Total assets	$	11,002	$	10,642

See the Combined Notes to Consolidated Financial Statements

Table of Contents

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)



(In millions)	June 30, 2019		December 31, 2018
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Accounts payable	375		370
Accrued expenses	102		113
Payables to affiliates	55		59
Borrowings from Exelon intercompany money pool	52		—
Customer deposits	69		68
Regulatory liabilities	91		175
Other	40		24
Total current liabilities	784		809
Long-term debt	3,085		3,084
Long-term debt to financing trusts	184		184
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	1,999		1,933
Asset retirement obligations	27		27
Non-pension postretirement benefits obligations	289		288
Regulatory liabilities	500		421
Other	79		76
Total deferred credits and other liabilities	2,894		2,745
Total liabilities	6,947		6,822
Commitments and contingencies
Shareholder’s equity
Common stock	2,723		2,578
Retained earnings	1,332		1,242
Total shareholder’s equity	4,055		3,820
Total liabilities and shareholder's equity	$	11,002	$	10,642

See the Combined Notes to Consolidated Financial Statements

Table of Contents

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER’S EQUITY

(Unaudited)



	Six months ended June 30, 2019
(In millions)	Common Stock		Retained Earnings			Accumulated Other Comprehensive Income, net			Total Shareholder's Equity
Balance, December 31, 2018	$	2,578	$	1,242		$	—		$	3,820
Net income	—		168			—			168
Common stock dividends	—		(90		)	—			(90		)
Contributions from parent	145		—			—			145
Balance, March 31, 2019	2,723		1,320			—			4,043
Net income	—		102			$	—		102
Common stock dividends	—		(90		)	—			(90		)
Balance, June 30, 2019	2,723		1,332			—			4,055


	Six months ended June 30, 2018
(In millions)	Common Stock		Retained Earnings			Accumulated Other Comprehensive Income, net			Total Shareholder's Equity
Balance, December 31, 2017	$	2,489	$	1,087		$	1		$	3,577
Net income	—		113			—			113
Common stock dividends	—		(287		)	—			(287		)
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities Standard	—		1			(1		)	—
Balance, March 31, 2018	2,489		914			—			3,403
Net income	—		96			$	—		96
Common stock dividends	—		(5		)	$	—		(5		)
Contributions from parent	41		—			$	—		41
Balance, June 30, 2018	$	2,530	$	1,005		$	—		$	3,535

See the Combined Notes to Consolidated Financial Statements

Table of Contents

BALTIMORE GAS AND ELECTRIC COMPANY

STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2019			2018			2019			2018
Operating revenues
Electric operating revenues	$	540		$	542		$	1,191		$	1,196
Natural gas operating revenues	97			118			405			448
Revenues from alternative revenue programs	6			(4		)	17			(17		)
Operating revenues from affiliates	6			6			12			12
Total operating revenues	649			662			1,625			1,639
Operating expenses
Purchased power	131			135			322			327
Purchased fuel	21			32			116			155
Purchased power from affiliate	56			62			132			127
Operating and maintenance	142			135			294			318
Operating and maintenance from affiliates	40			41			78			79
Depreciation and amortization	117			114			252			248
Taxes other than income	62			59			131			124
Total operating expenses	569			578			1,325			1,378
Gain on sales of assets	—			1			—			1
Operating income	80			85			300			262
Other income and (deductions)
Interest expense, net	(29		)	(25		)	(58		)	(51		)
Other, net	5			4			11			9
Total other income and (deductions)	(24		)	(21		)	(47		)	(42		)
Income before income taxes	56			64			253			220
Income taxes	11			13			47			41
Net income	$	45		$	51		$	206		$	179
Comprehensive income	$	45		$	51		$	206		$	179

See the Combined Notes to Consolidated Financial Statements

Table of Contents

BALTIMORE GAS AND ELECTRIC COMPANY

STATEMENTS OF CASH FLOWS

(Unaudited)



	Six Months Ended June 30,
(In millions)	2019			2018
Cash flows from operating activities
Net income	$	206		$	179
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	252			248
Deferred income taxes and amortization of investment tax credits	47			39
Other non-cash operating activities	41			27
Changes in assets and liabilities:
Accounts receivable	85			73
Receivables from and payables to affiliates, net	(14		)	(4		)
Inventories	5			5
Accounts payable and accrued expenses	(73		)	(48		)
Collateral posted, net	(5		)	—
Income taxes	(29		)	(45		)
Pension and non-pension postretirement benefit contributions	(42		)	(49		)
Other assets and liabilities	(21		)	39
Net cash flows provided by operating activities	452			464
Cash flows from investing activities
Capital expenditures	(542		)	(434		)
Other investing activities	4			6
Net cash flows used in investing activities	(538		)	(428		)
Cash flows from financing activities
Changes in short-term borrowings	194			59
Dividends paid on common stock	(112		)	(105		)
Net cash flows provided by (used in) financing activities	82			(46		)
Decrease in cash, cash equivalents and restricted cash	(4		)	(10		)
Cash, cash equivalents and restricted cash at beginning of period	13			18
Cash, cash equivalents and restricted cash at end of period	$	9		$	8

Supplemental cash flow information
Increase in capital expenditures not paid	$	24		$	10

See the Combined Notes to Consolidated Financial Statements

Table of Contents

BALTIMORE GAS AND ELECTRIC COMPANY

BALANCE SHEETS

(Unaudited)



(In millions)	June 30, 2019		December 31, 2018
ASSETS
Current assets
Cash and cash equivalents	$	8	$	7
Restricted cash and cash equivalents	1		6
Accounts receivable, net
Customer (net of allowance for uncollectible accounts of $14 and $16 as of June 30, 2019 and December 31, 2018, respectively)	278		353
Other (net of allowance for uncollectible accounts of $4 as of both June 30, 2019 and December 31, 2018)	86		90
Receivables from affiliates	—		1
Inventories, net
Fossil fuel	26		36
Materials and supplies	44		39
Prepaid utility taxes	—		74
Regulatory assets	164		177
Other	7		3
Total current assets	614		786
Property, plant and equipment (net of accumulated depreciation and amortization of $3,720 and $3,633 as of June 30, 2019 and December 31, 2018, respectively)	8,612		8,243
Deferred debits and other assets
Regulatory assets	390		398
Investments	6		5
Prepaid pension asset	289		279
Other	95		5
Total deferred debits and other assets	780		687
Total assets	$	10,006	$	9,716

See the Combined Notes to Consolidated Financial Statements

Table of Contents

BALTIMORE GAS AND ELECTRIC COMPANY

BALANCE SHEETS

(Unaudited)



(In millions)	June 30, 2019		December 31, 2018
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings	$	229	$	35
Accounts payable	279		295
Accrued expenses	103		155
Payables to affiliates	50		65
Customer deposits	120		120
Regulatory liabilities	36		77
Other	51		27
Total current liabilities	868		774
Long-term debt	2,877		2,876
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	1,301		1,222
Asset retirement obligations	24		24
Non-pension postretirement benefits obligations	198		201
Regulatory liabilities	1,162		1,192
Other	128		73
Total deferred credits and other liabilities	2,813		2,712
Total liabilities	6,558		6,362
Commitments and contingencies
Shareholder's equity
Common stock	1,714		1,714
Retained earnings	1,734		1,640
Total shareholder's equity	3,448		3,354
Total liabilities and shareholder's equity	$	10,006	$	9,716

See the Combined Notes to Consolidated Financial Statements

Table of Contents

BALTIMORE GAS AND ELECTRIC COMPANY

STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY

(Unaudited)



	Six Months Ended June 30, 2019
(In millions)	Common Stock		Retained Earnings			Total Shareholder's Equity
Balance, December 31, 2018	$	1,714	$	1,640		$	3,354
Net income	—		160			160
Common stock dividends	—		(56		)	(56		)
Balance, March 31, 2019	$	1,714	$	1,744		$	3,458
Net income	—		45			45
Common stock dividends	—		(55		)	(55		)
Balance, June 30, 2019	$	1,714	$	1,734		$	3,448

	Six Months Ended June 30, 2018
(In millions)	Common Stock		Retained Earnings			Total Shareholder's Equity
Balance, December 31, 2017	$	1,605	$	1,536		$	3,141
Net income	—		128			128
Common stock dividends	—		(52		)	(52		)
Balance, March 31, 2018	$	1,605	$	1,612		$	3,217
Net income	—		51			51
Common stock dividends	—		(53		)	(53		)
Balance, June 30, 2018	$	1,605	$	1,610		$	3,215

See the Combined Notes to Consolidated Financial Statements

Table of Contents

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2019			2018			2019			2018
Operating revenues
Electric operating revenues	$	1,067		$	1,052		$	2,205		$	2,202
Natural gas operating revenues	24			28			95			106
Revenues from alternative revenue programs	(3		)	(7		)	12			12
Operating revenues from affiliates	3			3			7			7
Total operating revenues	1,091			1,076			2,319			2,327
Operating expenses
Purchased power	303			288			658			662
Purchased fuel	9			12			43			53
Purchased power and fuel from affiliates	70			81			171			186
Operating and maintenance	213			218			452			489
Operating and maintenance from affiliates	35			37			68			74
Depreciation and amortization	188			180			369			363
Taxes other than income	108			107			220			221
Total operating expenses	926			923			1,981			2,048
Operating income	165			153			338			279
Other income and (deductions)
Interest expense, net	(67		)	(65		)	(131		)	(128		)
Other, net	14			11			27			22
Total other income and (deductions)	(53		)	(54		)	(104		)	(106		)
Income before income taxes	112			99			234			173
Income taxes	6			15			11			24
Net income	$	106		$	84		$	223		$	149
Comprehensive income	$	106		$	84		$	223		$	149

See the Combined Notes to Consolidated Financial Statements

Table of Contents

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Six Months Ended June 30,
(In millions)	2019			2018
Cash flows from operating activities
Net income	$	223		$	149
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	369			363
Deferred income taxes and amortization of investment tax credits	2			14
Other non-cash operating activities	54			71
Changes in assets and liabilities:
Accounts receivable	(34		)	(28		)
Receivables from and payables to affiliates, net	(8		)	4
Inventories	(25		)	8
Accounts payable and accrued expenses	(25		)	66
Income taxes	(12		)	13
Pension and non-pension postretirement benefit contributions	(11		)	(62		)
Other assets and liabilities	(114		)	(111		)
Net cash flows provided by operating activities	419			487
Cash flows from investing activities
Capital expenditures	(698		)	(629		)
Other investing activities	2			2
Net cash flows used in investing activities	(696		)	(627		)
Cash flows from financing activities
Changes in short-term borrowings	(27		)	(228		)
Proceeds from short-term borrowings with maturities greater than 90 days	—			125
Repayments of short-term borrowings with maturities greater than 90 days	(125		)	—
Issuance of long-term debt	410			300
Retirement of long-term debt	(125		)	(25		)
Distributions to member	(216		)	(109		)
Contributions from member	283			235
Change in Exelon intercompany money pool	3			7
Other financing activities	(4		)	(7		)
Net cash flows provided by financing activities	199			298
(Decrease) increase in cash, cash equivalents and restricted cash	(78		)	158
Cash, cash equivalents and restricted cash at beginning of period	186			95
Cash, cash equivalents and restricted cash at end of period	$	108		$	253

Supplemental cash flow information
(Decrease) increase in capital expenditures not paid	$	(74	)	$	61

See the Combined Notes to Consolidated Financial Statements

Table of Contents

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)



(In millions)	June 30, 2019		December 31, 2018
ASSETS
Current assets
Cash and cash equivalents	$	54	$	124
Restricted cash and cash equivalents	37		43
Accounts receivable, net
Customer (net of allowance for uncollectible accounts of $35 and $50 as of June 30, 2019 and December 31, 2018, respectively)	489		453
Other (net of allowance for uncollectible accounts of $11 and $3 as of June 30, 2019 and December 31, 2018, respectively)	196		177
Inventories, net
Fossil Fuel	5		9
Materials and supplies	195		163
Regulatory assets	496		489
Other	74		75
Total current assets	1,546		1,533
Property, plant and equipment, net (net of accumulated depreciation and amortization of $1,032 and $841 as of June 30, 2019 and December 31, 2018, respectively)	13,788		13,446
Deferred debits and other assets
Regulatory assets	2,163		2,312
Investments	133		130
Goodwill	4,005		4,005
Prepaid pension asset	446		486
Deferred income taxes	13		12
Other	360		60
Total deferred debits and other assets	7,120		7,005
Total assets^(a)	$	22,454	$	21,984

See the Combined Notes to Consolidated Financial Statements

Table of Contents

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)



(In millions)	June 30, 2019		December 31, 2018
LIABILITIES AND MEMBER'S EQUITY
Current liabilities
Short-term borrowings	$	27	$	179
Long-term debt due within one year	118		125
Accounts payable	426		496
Accrued expenses	224		256
Payables to affiliates	86		94
Customer deposits	117		116
Regulatory liabilities	75		84
Unamortized energy contract liabilities	119		119
Borrowings from Exelon intercompany money pool	3		—
Other	133		123
Total current liabilities	1,328		1,592
Long-term debt	6,391		6,134
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	2,219		2,146
Asset retirement obligations	53		52
Non-pension postretirement benefit obligations	100		103
Regulatory liabilities	1,789		1,864
Unamortized energy contract liabilities	385		442
Other	617		369
Total deferred credits and other liabilities	5,163		4,976
Total liabilities^(a)	12,882		12,702
Commitments and contingencies
Member's equity
Membership interest	9,503		9,220
Undistributed earnings	69		62
Total member's equity	9,572		9,282
Total liabilities and member's equity	$	22,454	$	21,984

__________

(a)

PHI’s consolidated total assets include $23 million and $33 million at June 30, 2019 and December 31, 2018, respectively, of PHI's consolidated VIE that can only be used to settle the liabilities of the VIE. PHI’s consolidated total liabilities include $55 million and $69 million at June 30, 2019 and December 31, 2018, respectively, of PHI's consolidated VIE for which the VIE creditors do not have recourse to PHI. See Note 2 — Variable Interest Entities for additional information.

See the Combined Notes to Consolidated Financial Statements

Table of Contents

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(Unaudited)



	Six Months Ended June 30, 2019
(In millions)	Membership Interest		Undistributed Earnings (Losses)			Member's Equity
Balance, December 31, 2018	$	9,220	$	62		$	9,282
Net income	—		117			117
Distributions to member	—		(128		)	(128		)
Contributions from member	19		—			19
Balance, March 31, 2019	$	9,239	$	51		$	9,290
Net income	—		106			106
Distributions to member	—		(88		)	(88		)
Contributions from member	264		—			264
Balance, June 30, 2019	$	9,503	$	69		$	9,572



	Six Months Ended June 30, 2018
(In millions)	Membership Interest		Undistributed Earnings (Losses)			Member's Equity
Balance, December 31, 2017	$	8,835	$	(10	)	$	8,825
Net income	—		65			65
Distributions to member	—		(71		)	(71		)
Balance, March 31, 2018	$	8,835	$	(16	)	$	8,819
Net income	—		84			84
Distributions to member	—		(38		)	(38		)
Contributions from member	235		—			235
Balance, June 30, 2018	$	9,070	$	30		$	9,100

See the Combined Notes to Consolidated Financial Statements

Table of Contents

POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2019			2018			2019			2018
Operating revenues
Electric operating revenues	$	531		$	531		$	1,090		$	1,067
Revenues from alternative revenue programs	(1		)	(10		)	13			10
Operating revenues from affiliates	1			2			3			3
Total operating revenues	531			523			1,106			1,080
Operating expenses
Purchased power	92			94			209			224
Purchased power from affiliates	52			46			122			98
Operating and maintenance	59			60			123			133
Operating and maintenance from affiliates	52			56			107			113
Depreciation and amortization	93			92			186			188
Taxes other than income	90			90			182			183
Total operating expenses	438			438			929			939
Operating income	93			85			177			141
Other income and (deductions)
Interest expense, net	(34		)	(32		)	(68		)	(63		)
Other, net	7			8			14			16
Total other income and (deductions)	(27		)	(24		)	(54		)	(47		)
Income before income taxes	66			61			123			94
Income taxes	2			7			4			9
Net income	$	64		$	54		$	119		$	85
Comprehensive income	$	64		$	54		$	119		$	85

See the Combined Notes to Consolidated Financial Statements

Table of Contents

POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF CASH FLOWS

(Unaudited)



	Six Months Ended June 30,
(In millions)	2019			2018
Cash flows from operating activities
Net income	$	119		$	85
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	186			188
Deferred income taxes and amortization of investment tax credits	10			(8		)
Other non-cash operating activities	8			24
Changes in assets and liabilities:
Accounts receivable	(36		)	(31		)
Receivables from and payables to affiliates, net	4			(11		)
Inventories	(20		)	2
Accounts payable and accrued expenses	(25		)	77
Income taxes	(23		)	3
Pension and non-pension postretirement benefit contributions	(6		)	(11		)
Other assets and liabilities	(40		)	(91		)
Net cash flows provided by operating activities	177			227
Cash flows from investing activities
Capital expenditures	(298		)	(287		)
Changes in PHI intercompany money pool	(38		)	—
Other investing activities	1			2
Net cash flows used in investing activities	(335		)	(285		)
Cash flows from financing activities
Changes in short-term borrowings	(40		)	(26		)
Issuance of long-term debt	260			100
Retirement of long-term debt	(117		)	(7		)
Dividends paid on common stock	(72		)	(50		)
Contributions from parent	129			85
Other financing activities	(3		)	(4		)
Net cash flows provided by financing activities	157			98
(Decrease) increase in cash, cash equivalents and restricted cash	(1		)	40
Cash, cash equivalents and restricted cash at beginning of period	53			40
Cash, cash equivalents and restricted cash at end of period	$	52		$	80

Supplemental cash flow information
(Decrease) increase in capital expenditures not paid	$	(18	)	$	28

See the Combined Notes to Consolidated Financial Statements

Table of Contents

POTOMAC ELECTRIC POWER COMPANY

BALANCE SHEETS

(Unaudited)



(In millions)	June 30, 2019		December 31, 2018
ASSETS
Current assets
Cash and cash equivalents	$	18	$	16
Restricted cash and cash equivalents	34		37
Accounts receivable, net
Customer (net of allowance for uncollectible accounts of $13 and $20 as of June 30, 2019 and December 31, 2018, respectively)	254		225
Other (net of allowance for uncollectible accounts of $6 and $1 as of June 30, 2019 and December 31, 2018, respectively)	110		81
Receivables from affiliates	—		1
Receivable from PHI intercompany money pool	38		—
Inventories, net	115		93
Regulatory assets	262		270
Other	10		37
Total current assets	841		760
Property, plant and equipment, net (net of accumulated depreciation and amortization of $3,431 and $3,354 as of June 30, 2019 and December 31, 2018, respectively)	6,623		6,460
Deferred debits and other assets
Regulatory assets	601		643
Investments	108		105
Prepaid pension asset	306		316
Other	77		15
Total deferred debits and other assets	1,092		1,079
Total assets	$	8,556	$	8,299

See the Combined Notes to Consolidated Financial Statements

Table of Contents

POTOMAC ELECTRIC POWER COMPANY

BALANCE SHEETS

(Unaudited)



(In millions)	June 30, 2019		December 31, 2018
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings	$	—	$	40
Long-term debt due within one year	8		15
Accounts payable	175		214
Accrued expenses	114		126
Payables to affiliates	67		62
Customer deposits	55		54
Regulatory liabilities	7		7
Merger related obligation	38		38
Current portion of DC PLUG obligation	30		30
Other	23		42
Total current liabilities	517		628
Long-term debt	2,852		2,704
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	1,114		1,064
Asset retirement obligations	37		37
Non-pension postretirement benefit obligations	25		29
Regulatory liabilities	782		822
Other	313		275
Total deferred credits and other liabilities	2,271		2,227
Total liabilities	5,640		5,559
Commitments and contingencies
Shareholder's equity
Common stock	1,765		1,636
Retained earnings	1,151		1,104
Total shareholder's equity	2,916		2,740
Total liabilities and shareholder's equity	$	8,556	$	8,299

See the Combined Notes to Consolidated Financial Statements

Table of Contents

POTOMAC ELECTRIC POWER COMPANY

STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY

(Unaudited)



	Six Months Ended June 30, 2019
(In millions)	Common Stock		Retained Earnings			Total Shareholder's Equity
Balance, December 31, 2018	$	1,636	$	1,104		$	2,740
Net income	—		55			55
Common stock dividends	—		(24		)	(24		)
Contributions from parent	14		—			14
Balance, March 31, 2019	1,650		1,135			2,785
Net income	—		64			64
Common stock dividends	—		(48		)	(48		)
Contributions from parent	115		—			115
Balance, June 30, 2019	$	1,765	$	1,151		$	2,916

	Six Months Ended June 30, 2018
(In millions)	Common Stock		Retained Earnings			Total Shareholder's Equity
Balance, December 31, 2017	$	1,470	$	1,063		$	2,533
Net income	—		31			31
Common stock dividends	—		(25		)	(25		)
Balance, March 31, 2018	1,470		1,069			2,539
Net income	—		54			54
Common stock dividends	—		(25		)	(25		)
Contributions from parent	85		—			85
Balance, June 30, 2018	$	1,555	$	1,098		$	2,653

See the Combined Notes to Consolidated Financial Statements

Table of Contents

DELMARVA POWER & LIGHT COMPANY

STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2019			2018			2019			2018
Operating revenues
Electric operating revenues	$	261		$	255		$	568		$	558
Natural gas operating revenues	24			28			95			106
Revenues from alternative revenue programs	—			4			1			5
Operating revenues from affiliates	2			2			3			4
Total operating revenues	287			289			667			673
Operating expenses
Purchased power	86			72			193			162
Purchased fuel	9			12			43			53
Purchased power from affiliate	12			30			35			76
Operating and maintenance	39			36			84			94
Operating and maintenance from affiliates	38			41			76			81
Depreciation and amortization	45			43			91			88
Taxes other than income	14			13			28			28
Total operating expenses	243			247			550			582
Operating income	44			42			117			91
Other income and (deductions)
Interest expense, net	(15		)	(14		)	(30		)	(27		)
Other, net	5			3			7			5
Total other income and (deductions)	(10		)	(11		)	(23		)	(22		)
Income before income taxes	34			31			94			69
Income taxes	4			5			11			12
Net income	$	30		$	26		$	83		$	57
Comprehensive income	$	30		$	26		$	83		$	57

See the Combined Notes to Consolidated Financial Statements

Table of Contents

DELMARVA POWER & LIGHT COMPANY

STATEMENTS OF CASH FLOWS

(Unaudited)



	Six Months Ended June 30,
(In millions)	2019			2018
Cash flows from operating activities
Net income	$	83		$	57
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	91			88
Deferred income taxes and amortization of investment tax credits	(5		)	9
Other non-cash operating activities	11			14
Changes in assets and liabilities:
Accounts receivable	15			18
Receivables from and payables to affiliates, net	(11		)	(22		)
Inventories	(3		)	4
Accounts payable and accrued expenses	6			10
Income taxes	11			16
Pension and non-pension postretirement benefit contributions	(1		)	—
Other assets and liabilities	(26		)	22
Net cash flows provided by operating activities	171			216
Cash flows from investing activities
Capital expenditures	(160		)	(166		)
Other investing activities	1			1
Net cash flows used in investing activities	(159		)	(165		)
Cash flows from financing activities
Changes in short-term borrowings	—			(216		)
Issuance of long-term debt	—			200
Retirement of long-term debt	—			(4		)
Dividends paid on common stock	(70		)	(40		)
Contributions from parent	—			150
Changes in PHI intercompany money pool	38			—
Other financing activities	—			(2		)
Net cash flows (used in) provided by financing activities	(32		)	88
(Decrease) increase in cash, cash equivalents and restricted cash	(20		)	139
Cash, cash equivalents and restricted cash at beginning of period	24			2
Cash, cash equivalents and restricted cash at end of period	$	4		$	141

Supplemental cash flow information
(Decrease) increase in capital expenditures not paid	$	(17	)	$	17

See the Combined Notes to Consolidated Financial Statements

Table of Contents

DELMARVA POWER & LIGHT COMPANY

BALANCE SHEETS

(Unaudited)



(In millions)	June 30, 2019		December 31, 2018
ASSETS
Current assets
Cash and cash equivalents	$	3	$	23
Restricted cash and cash equivalents	1		1
Accounts receivable, net
Customer (net of allowance for uncollectible accounts of $10 and $12 as of June 30, 2019 and December 31, 2018, respectively)	123		134
Other (net of allowance for uncollectible accounts of $2 and $1 as of June 30, 2019 and December 31, 2018, respectively)	43		46
Inventories, net
Fossil Fuel	5		9
Materials and supplies	46		37
Renewable energy credits	18		8
Regulatory assets	59		59
Other	2		19
Total current assets	300		336
Property, plant and equipment, net (net of accumulated depreciation and amortization of $1,380 and $1,329 as of June 30, 2019 and December 31, 2018, respectively)	3,893		3,821
Deferred debits and other assets
Regulatory assets	224		231
Goodwill	8		8
Prepaid pension asset	178		186
Other	80		6
Total deferred debits and other assets	490		431
Total assets	$	4,683	$	4,588

See the Combined Notes to Consolidated Financial Statements

Table of Contents

DELMARVA POWER & LIGHT COMPANY

BALANCE SHEETS

(Unaudited)



(In millions)	June 30, 2019		December 31, 2018
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Long-term debt due within one year	$	91	$	91
Accounts payable	106		111
Accrued expenses	43		39
Payables to affiliates	25		33
Customer deposits	36		35
Regulatory liabilities	43		59
Borrowings from PHI intercompany money pool	38		—
Other	16		7
Total current liabilities	398		375
Long-term debt	1,404		1,403
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	644		628
Non-pension postretirement benefits obligations	16		17
Regulatory liabilities	586		606
Other	113		50
Total deferred credits and other liabilities	1,359		1,301
Total liabilities	3,161		3,079
Commitments and contingencies
Shareholder's equity
Common stock	914		914
Retained earnings	608		595
Total shareholder's equity	1,522		1,509
Total liabilities and shareholder's equity	$	4,683	$	4,588

See the Combined Notes to Consolidated Financial Statements

Table of Contents

DELMARVA POWER & LIGHT COMPANY

STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY

(Unaudited)



	Six Months Ended June 30, 2019
(In millions)	Common Stock		Retained Earnings			Total Shareholder's Equity
Balance, December 31, 2018	$	914	$	595		$	1,509
Net income	—		53			53
Common stock dividends	—		(41		)	(41		)
Balance, March 31, 2019	914		607			1,521
Net income	—		30			30
Common stock dividends	—		(29		)	(29		)
Balance, June 30, 2019	$	914	$	608		$	1,522



	Six Months Ended June 30, 2018
(In millions)	Common Stock		Retained Earnings			Total Shareholder's Equity
Balance, December 31, 2017	$	764	$	571		$	1,335
Net income	—		31			31
Common stock dividends	—		(36		)	(36		)
Balance, March 31, 2018	764		566			1,330
Net income	—		26			26
Common stock dividends	—		(4		)	(4		)
Contributions from parent	150		—			150
Balance, June 30, 2018	$	914	$	588		$	1,502

See the Combined Notes to Consolidated Financial Statements

Table of Contents

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME

(Unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2019			2018			2019			2018
Operating revenues
Electric operating revenues	$	275		$	265		$	547		$	576
Revenues from alternative revenue programs	(2		)	(1		)	(1		)	(3		)
Operating revenues from affiliates	1			1			1			2
Total operating revenues	274			265			547			575
Operating expenses
Purchased power	125			122			257			277
Purchased power from affiliates	6			6			13			12
Operating and maintenance	41			40			88			95
Operating and maintenance from affiliates	33			35			67			70
Depreciation and amortization	40			36			71			69
Taxes other than income	1			1			2			3
Total operating expenses	246			240			498			526
Operating income	28			25			49			49
Other income and (deductions)
Interest expense, net	(15		)	(16		)	(28		)	(32		)
Other, net	1			1			4			1
Total other income and (deductions)	(14		)	(15		)	(24		)	(31		)
Income before income taxes	14			10			25			18
Income taxes	—			2			1			3
Net income	$	14		$	8		$	24		$	15
Comprehensive income	$	14		$	8		$	24		$	15

See the Combined Notes to Consolidated Financial Statements

Table of Contents

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Six Months Ended June 30,
(In millions)	2019			2018
Cash flows from operating activities
Net income	$	24		$	15
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization	71			69
Deferred income taxes and amortization of investment tax credits	2			6
Other non-cash operating activities	7			12
Changes in assets and liabilities:
Accounts receivable	(11		)	(13		)
Receivables from and payables to affiliates, net	(9		)	(4		)
Inventories	(1		)	4
Accounts payable and accrued expenses	16			14
Income taxes	6			3
Pension and non-pension postretirement benefit contributions	—			(6		)
Other assets and liabilities	(44		)	(33		)
Net cash flows provided by operating activities	61			67
Cash flows from investing activities
Capital expenditures	(227		)	(170		)
Other investing activities	—			(2		)
Net cash flows used in investing activities	(227		)	(172		)
Cash flows from financing activities
Changes in short-term borrowings	13			14
Proceeds from short-term borrowings with maturities greater than 90 days	—			125
Repayments of short-term borrowings with maturities greater than 90 days	(125		)	—
Issuance of long-term debt	150			—
Retirement of long-term debt	(9		)	(15		)
Dividends paid on common stock	(24		)	(19		)
Contributions from parent	155			—
Other financing activities	(1		)	—
Net cash flows provided by financing activities	159			105
(Decrease) increase in cash, cash equivalents and restricted cash	(7		)	—
Cash, cash equivalents and restricted cash at beginning of period	30			31
Cash, cash equivalents and restricted cash at end of period	$	23		$	31

Supplemental cash flow information
(Decrease) increase in capital expenditures not paid	$	(35	)	$	14

See the Combined Notes to Consolidated Financial Statements

Table of Contents

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)



(In millions)	June 30, 2019		December 31, 2018
ASSETS
Current assets
Cash and cash equivalents	$	4	$	7
Restricted cash and cash equivalents	2		4
Accounts receivable, net
Customer (net of allowance for uncollectible accounts of $11 and $18 as of June 30, 2019 and December 31, 2018, respectively)	112		95
Other (net of allowance for uncollectible accounts of $3 and $1 as of June 30, 2019 and December 31, 2018, respectively)	50		55
Receivables from affiliates	—		1
Inventories, net	34		33
Prepaid utility taxes	33		—
Regulatory assets	57		40
Other	7		5
Total current assets	299		240
Property, plant and equipment, net (net of accumulated depreciation and amortization of $1,179 and $1,137 as of June 30, 2019 and December 31, 2018, respectively)	3,093		2,966
Deferred debits and other assets
Regulatory assets	374		386
Prepaid pension asset	60		67
Other	60		40
Total deferred debits and other assets	494		493
Total assets^(a)	$	3,886	$	3,699

See the Combined Notes to Consolidated Financial Statements

Table of Contents

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)



(In millions)	June 30, 2019		December 31, 2018
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings	$	27	$	139
Long-term debt due within one year	19		18
Accounts payable	135		154
Accrued expenses	36		35
Payables to affiliates	21		28
Customer deposits	26		26
Regulatory liabilities	25		18
Other	10		4
Total current liabilities	299		422
Long-term debt	1,310		1,170
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	546		535
Non-pension postretirement benefit obligations	18		17
Regulatory liabilities	388		402
Other	44		27
Total deferred credits and other liabilities	996		981
Total liabilities^(a)	2,605		2,573
Commitments and contingencies
Shareholder's equity
Common stock	1,134		979
Retained earnings	147		147
Total shareholder's equity	1,281		1,126
Total liabilities and shareholder's equity	$	3,886	$	3,699

__________

(a)

ACE’s consolidated total assets include $19 million and $23 million at June 30, 2019 and December 31, 2018, respectively, of ACE's consolidated VIE that can only be used to settle the liabilities of the VIE. ACE’s consolidated total liabilities include $51 million and $59 million at June 30, 2019 and December 31, 2018, respectively, of ACE's consolidated VIE for which the VIE creditors do not have recourse to ACE. See Note 2 — Variable Interest Entities for additional information.

See the Combined Notes to Consolidated Financial Statements

Table of Contents

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY

(Unaudited)



	Six Months Ended June 30, 2019
(In millions)	Common Stock		Retained Earnings			Total Shareholder's Equity
Balance, December 31, 2018	$	979	$	147		$	1,126
Net income	—		10			10
Common stock dividends	—		(12		)	(12		)
Contributions from parent	5		—			5
Balance, March 31, 2019	984		145			1,129
Net income	—		14			14
Common stock dividends	—		(12		)	(12		)
Contributions from parent	150		—			150
Balance, June 30, 2019	$	1,134	$	147		$	1,281



	Six Months Ended June 30, 2018
(In millions)	Common Stock		Retained Earnings			Total Shareholder's Equity
Balance, December 31, 2017	$	912	$	131		$	1,043
Net income	—		7			7
Common stock dividends	—		(9		)	(9		)
Balance, March 31, 2018	912		129			1,041
Net income	—		8			8
Common stock dividends	—		(10		)	(10		)
Balance, June 30, 2018	$	912	$	127		$	1,039

See the Combined Notes to Consolidated Financial Statements

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in millions, except per share data, unless otherwise noted)

1. Significant Accounting Policies (All Registrants)

Description of Business (All Registrants)

Exelon is a utility services holding company engaged in the generation, delivery and marketing of energy through Generation and the energy distribution and transmission businesses through ComEd, PECO, BGE, Pepco, DPL and ACE.



Name of Registrant	Business	Service Territories
Exelon Generation Company, LLC	Generation, physical delivery and marketing of power across multiple geographical regions through its customer-facing business, Constellation, which sells electricity to both wholesale and retail customers. Generation also sells natural gas, renewable energy and other energy-related products and services.	Five reportable segments: Mid-Atlantic, Midwest, New York, ERCOT and Other Power Regions

Commonwealth Edison Company	Purchase and regulated retail sale of electricity	Northern Illinois, including the City of Chicago
	Transmission and distribution of electricity to retail customers
PECO Energy Company	Purchase and regulated retail sale of electricity and natural gas	Southeastern Pennsylvania, including the City of Philadelphia (electricity)
	Transmission and distribution of electricity and distribution of natural gas to retail customers	Pennsylvania counties surrounding the City of Philadelphia (natural gas)
Baltimore Gas and Electric Company	Purchase and regulated retail sale of electricity and natural gas	Central Maryland, including the City of Baltimore (electricity and natural gas)
	Transmission and distribution of electricity and distribution of natural gas to retail customers
Pepco Holdings LLC	Utility services holding company engaged, through its reportable segments Pepco, DPL and ACE	Service Territories of Pepco, DPL and ACE

Potomac Electric Power Company	Purchase and regulated retail sale of electricity	District of Columbia, and major portions of Montgomery and Prince George’s Counties, Maryland
	Transmission and distribution of electricity to retail customers
Delmarva Power & Light Company	Purchase and regulated retail sale of electricity and natural gas	Portions of Delaware and Maryland (electricity)
	Transmission and distribution of electricity and distribution of natural gas to retail customers	Portions of New Castle County, Delaware (natural gas)
Atlantic City Electric Company	Purchase and regulated retail sale of electricity	Portions of Southern New Jersey
	Transmission and distribution of electricity to retail customers

Basis of Presentation (All Registrants)

Each of the Registrant’s Consolidated Financial Statements includes the accounts of its subsidiaries. All intercompany transactions have been eliminated.

Through its business services subsidiary, BSC, Exelon provides its subsidiaries with a variety of support services

at cost, including legal, human resources, financial, information technology and supply management services. PHI also has a business services subsidiary, PHISCO, which provides a variety of support services at cost, including legal, accounting, engineering, customer operations, distribution and transmission planning, asset management, system operations, and power procurement, to PHI operating companies. The costs of BSC and PHISCO are directly charged or allocated to the applicable subsidiaries. The results of Exelon’s corporate operations are presented as “Other” within the consolidated financial statements and include intercompany eliminations unless otherwise disclosed.

The accompanying consolidated financial statements as of June 30, 2019 and 2018 and for the three and six months then ended are unaudited but, in the opinion of the management of each Registrant include all adjustments that are considered necessary for a fair statement of the Registrants’ respective financial statements in accordance with GAAP. All adjustments are of a normal, recurring nature, except as otherwise disclosed. The December 31, 2018 Consolidated Balance Sheets were derived from audited financial statements. Financial results for interim periods are not necessarily indicative of results that may be expected for any other interim period or for the fiscal year ending

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

December 31, 2019. These Combined Notes to Consolidated Financial Statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations.

New Accounting Standards (All Registrants)

New Accounting Standards Adopted in 2019: In 2019, the Registrants have adopted the following new authoritative accounting guidance issued by the FASB.

Leases. The Registrants applied the new guidance with the following transition practical expedients:


•	a "package of three" expedients that must be taken together and allow entities to (1) not reassess whether existing contracts contain leases, (2) carryforward the existing lease classification, and (3) not reassess initial direct costs associated with existing leases,


•	an implementation expedient which allows the requirements of the standard in the period of adoption with no restatement of prior periods, and


•	a land easement expedient which allows entities to not evaluate land easements under the new standard at adoption if they were not previously accounted for as leases.

The standard materially impacted the Registrants' Consolidated Balance Sheets but did not have a material impact in the Registrants' Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and Consolidated Statements of Changes in Shareholders' Equity. The most significant impact was the recognition of the ROU assets and lease liabilities for operating leases. The operating ROU assets and lease liabilities recognized upon adoption are materially consistent with the balances presented in the Combined Notes to the Consolidated Financial Statements. See Note 5 - Leases for additional information.

See Note 1 — Significant Accounting Policies of the Exelon 2018 Form 10-K for additional information on new accounting standards issued and adopted as of January 1, 2019.

New Accounting Standards Issued and Not Yet Adopted as of June 30, 2019: The following new authoritative accounting guidance issued by the FASB has not yet been adopted and reflected by the Registrants in their consolidated financial statements as of June 30, 2019. Unless otherwise indicated, the Registrants are currently assessing the impacts such guidance may have (which could be material) in their financial statements. The Registrants have assessed other FASB issuances of new standards which are not listed below as the Registrants do not expect such standards to have a material impact to their financial statements.

Goodwill Impairment (Issued January 2017). Simplifies the accounting for goodwill impairment by removing Step 2 of the current test, which requires calculation of a hypothetical purchase price allocation. Under the revised guidance, goodwill impairment will be measured as the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill (currently Step 1 of the two-step impairment test). Entities will continue to have the option to perform a qualitative assessment to determine if a quantitative impairment test is necessary. Exelon, Generation, ComEd, PHI and DPL do not expect the updated guidance to have a material impact to their financial statements. The standard is effective January 1, 2020, with early adoption permitted, and must be applied on a prospective basis.

Impairment of Financial Instruments (Issued June 2016). Provides for a new Current Expected Credit Loss (CECL) impairment model for specified financial instruments including loans, trade receivables, debt securities classified as held-to-maturity investments and net investments in leases recognized by a lessor. Under the new guidance, on initial recognition and at each reporting period, an entity is required to recognize an allowance that reflects the entity’s current estimate of credit losses expected to be incurred over the life of the financial instrument. The standard does not make changes to the existing impairment models for non-financial assets such as fixed assets, intangibles and goodwill. The standard will be effective January 1, 2020 (with early adoption as of January 1, 2019 permitted) and requires a modified retrospective transition approach through a cumulative-effect adjustment to retained earnings as of the beginning of the period of adoption. The Registrants are currently assessing the impacts of this standard.

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(Dollars in millions, except per share data, unless otherwise noted)

Leases (All Registrants)

The Registrants recognize a ROU asset and lease liability for operating leases with a term of greater than one year. The ROU asset is included in Other deferred debits and other assets and the lease liability is included in Other current liabilities and Other deferred credits and other liabilities on the Consolidated Balance Sheets. The ROU asset is measured as the sum of (1) the present value of all remaining fixed and in-substance fixed payments using each Registrant’s incremental borrowing rate, (2) any lease payments made at or before the commencement date (less any lease incentives received) and (3) any initial direct costs incurred. The lease liability is measured the same as the ROU asset, but excludes any payments made before the commencement date and initial direct costs incurred. Lease terms include options to extend or terminate the lease if it is reasonably certain they will be exercised. The Registrants include non-lease components, which are service-related costs that are not integral to the use of the asset, in the measurement of the ROU asset and lease liability.

Expense for operating leases and leases with a term of one year or less is recognized on a straight-line basis over the term of the lease, unless another systematic and rational basis is more representative of the derivation of benefit from use of the leased property. Variable lease payments are recognized in the period in which the related obligation is incurred and consist primarily of payments for purchases of electricity under contracted generation and are based on the electricity produced by those generating assets. Operating lease expense and variable lease payments are recorded to Purchased power and fuel expense for contracted generation or Operating and maintenance expense for all other lease agreements on the Registrants’ Statements of Operations and Comprehensive Income.

Income from operating leases, including subleases, is recognized on a straight-line basis over the term of the lease, unless another systematic and rational basis is more representative of the pattern in which income is earned over the term of the lease. Variable lease payments are recognized in the period in which the related obligation is performed and consist primarily of payments received from sales of electricity under contracted generation and are based on the electricity produced by those generating assets. Operating lease income and variable lease payments are recorded to Operating revenues on the Registrants’ Statements of Operations and Comprehensive Income.

The Registrants’ operating leases consist primarily of contracted generation, real estate including office buildings, and vehicles and equipment. The Registrants generally account for contracted generation in which the generating asset is not renewable as a lease if the customer has dispatch rights and obtains substantially all of the economic benefits. For new agreements entered after January 1, 2019, the Registrants will generally not account for contracted generation in which the generating asset is renewable as a lease if the customer does not design the generating asset. The Registrants account for land right arrangements that provide for exclusive use as leases while shared use land arrangements are generally not leases. The Registrants do not account for secondary use pole attachments as leases.

See Note 5 —Leases for additional information.

2. Variable Interest Entities (All Registrants)

A VIE is a legal entity that possesses any of the following characteristics: an insufficient amount of equity at risk to finance its activities, equity owners who do not have the power to direct the significant activities of the entity (or have voting rights that are disproportionate to their ownership interest) or equity owners who do not have the obligation to absorb expected losses or the right to receive the expected residual returns of the entity. Companies are required to consolidate a VIE if they are its primary beneficiary, which is the enterprise that has the power to direct the activities that most significantly affect the entity’s economic performance.

At June 30, 2019 and December 31, 2018, Exelon, Generation, PHI and ACE collectively consolidated five VIEs or VIE groups for which the applicable Registrant was the primary beneficiary (see Consolidated Variable Interest Entities below). As of June 30, 2019 and December 31, 2018, Exelon and Generation collectively had significant interests in eight and seven, respectively, other VIEs for which the applicable Registrant does not have the power to direct the entities’ activities and, accordingly, was not the primary beneficiary (see Unconsolidated Variable Interest Entities below).

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(Dollars in millions, except per share data, unless otherwise noted)

Consolidated Variable Interest Entities

As of June 30, 2019 and December 31, 2018, Exelon's and Generation's consolidated VIEs consist of:


•	energy related companies involved in distributed generation, backup generation and energy development


•	renewable energy project companies formed by Generation to build, own and operate renewable power facilities


•	certain retail power and gas companies for which Generation is the sole supplier of energy, and


•	CENG.

As of June 30, 2019 and December 31, 2018, Exelon's, PHI's and ACE's consolidated VIE consist of:


•	ACE Transition Funding (ATF), a special purpose entity formed by ACE for the purpose of securitizing authorized portions of ACE’s recoverable stranded costs through the issuance and sale of transition bonds.

As of June 30, 2019 and December 31, 2018, ComEd, PECO, BGE, Pepco and DPL did not have any material consolidated VIEs.

Exelon and Generation provided the following support to their respective consolidated VIEs:


•	Operating and capital funding to the renewable energy project companies and there is limited recourse to Generation related to certain renewable energy project companies;


•	Approximately $6 million and $34 million as of June 30, 2019 and December 31, 2018, respectively, in credit support for the retail power and gas companies for which Generation is the sole supplier of energy.


•	Exelon and Generation, where indicated, provide the following support to CENG:


•	under PPAs with CENG, Generation purchased or will purchase 50.01% of the available output generated by the CENG nuclear plants not subject to other contractual agreements from January 2015 through the end of the operating life of each respective plant.


•	Generation provided a $400 million loan to CENG. The loan balance was fully repaid by CENG in January 2019.

•

Generation executed an Indemnity Agreement pursuant to which Generation agreed to indemnify EDF 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 Agreement. (See Note 16 — Commitments and Contingencies for additional information),


•	Generation and EDF share in the $688 million of contingent payment obligations for the payment of contingent retrospective premium adjustments for the nuclear liability insurance, and


•	Exelon has executed an agreement to provide up to $245 million to support the operations of CENG as well as a $165 million guarantee of CENG’s cash pooling agreement with its subsidiaries.

As of June 30, 2019 and December 31, 2018, Exelon, PHI and ACE provided the following support to their respective consolidated VIE:

•

In the case of ATF, proceeds from the sale of each series of transition bonds by ATF were transferred to ACE in exchange for the transfer by ACE to ATF of the right to collect a non-bypassable Transition Bond Charge from ACE customers pursuant to bondable stranded costs rate orders issued by the NJBPU in an amount sufficient to fund the principal and interest payments on transition bonds and related taxes, expenses and fees. During the three and six months ended June 30, 2019, ACE

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(Dollars in millions, except per share data, unless otherwise noted)

transferred $3 million and $7 million to ATF, respectively. During the three and six months ended June 30, 2018, ACE transferred $6 million and $14 million to ATF, respectively.

For each of the consolidated VIEs, except as otherwise noted:


•	the assets of the VIEs are restricted and can only be used to settle obligations of the respective VIE;


•	Exelon, Generation, PHI and ACE did not provide any additional material financial support to the VIEs;


•	Exelon, Generation, PHI and ACE did not have any material contractual commitments or obligations to provide financial support to the VIEs; and


•	the creditors of the VIEs did not have recourse to Exelon’s, Generation’s, PHI's or ACE's general credit.

The carrying amounts and classification of the consolidated VIEs’ assets and liabilities included in the Registrants' consolidated financial statements at June 30, 2019 and December 31, 2018 are as follows:



	June 30, 2019								December 31, 2018
	Exelon^(a)		Generation		PHI^(a)		ACE		Exelon^(a)		Generation		PHI^(a)		ACE
Current assets	$	649	$	646	$	3	$	2	$	938	$	931	$	7	$	4
Noncurrent assets	9,204		9,184		20		17		9,071		9,045		26		19
Total assets	$	9,853	$	9,830	$	23	$	19	$	10,009	$	9,976	$	33	$	23
Current liabilities	715		694		21		20		$	274	$	252	$	22	$	19
Noncurrent liabilities	2,861		2,827		34		31		3,280		3,233		47		40
Total liabilities	$	3,576	$	3,521	$	55	$	51	$	3,554	$	3,485	$	69	$	59

_________


(a)	Includes certain purchase accounting adjustments not pushed down to the ACE standalone entity.

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(Dollars in millions, except per share data, unless otherwise noted)

Assets and Liabilities of Consolidated VIEs

Included within the balances above are assets and liabilities of certain consolidated VIEs for which the assets can only be used to settle obligations of those VIEs, and liabilities that creditors or beneficiaries do not have recourse to the general credit of the Registrants. As of June 30, 2019 and December 31, 2018, these assets and liabilities primarily consisted of the following:



	June 30, 2019								December 31, 2018
	Exelon^(a)		Generation		PHI^(a)		ACE		Exelon^(a)		Generation		PHI^(a)		ACE
Cash and cash equivalents	$	106	$	106	$	—	$	—	$	414	$	414	$	—	$	—
Restricted cash and cash equivalents	75		73		2		2		66		62		4		4
Accounts receivable, net
Customer	161		161		—		—		146		146		—		—
Other	39		39		—		—		23		23		—		—
Inventory, net
Materials and supplies	217		217		—		—		212		212		—		—
Other current assets	28		27		1		—		52		49		3		—
Total current assets	626		623		3		2		913		906		7		4
Property, plant and equipment, net	6,084		6,084		—		—		6,145		6,145		—		—
NDT funds	2,589		2,589		—		—		2,351		2,351		—		—
Other noncurrent assets	227		207		20		17		258		232		26		19
Total noncurrent assets	8,900		8,880		20		17		8,754		8,728		26		19
Total assets	$	9,526	$	9,503	$	23	$	19	$	9,667	$	9,634	$	33	$	23
Long-term debt due within one year	$	560	$	540	$	20	$	19	$	87	$	66	$	21	$	18
Accounts payable	89		89		—		—		96		96		—		—
Accrued expenses	52		51		1		1		72		72		1		1
Unamortized energy contract liabilities	11		11		—		—		15		15		—		—
Other current liabilities	3		3		—		—		3		3		—		—
Total current liabilities	715		694		21		20		273		252		22		19
Long-term debt	558		524		34		31		1,072		1,025		47		40
Asset retirement obligations	2,218		2,218		—		—		2,160		2,160		—		—
Unamortized energy contract liabilities	—		—		—		—		1		1		—		—
Other noncurrent liabilities	77		77		—		—		42		42		—		—
Total noncurrent liabilities	2,853		2,819		34		31		3,275		3,228		47		40
Total liabilities	$	3,568	$	3,513	$	55	$	51	$	3,548	$	3,480	$	69	$	59

_________


(a)	Includes certain purchase accounting adjustments not pushed down to the ACE standalone entity.

Unconsolidated Variable Interest Entities

Exelon’s and Generation’s variable interests in unconsolidated VIEs generally include equity investments and energy purchase and sale contracts. For the equity investments, the carrying amount of the investments is reflected in Exelon’s and Generation’s Consolidated Balance Sheets in Investments. For the energy purchase and sale contracts

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(Dollars in millions, except per share data, unless otherwise noted)

(commercial agreements), the carrying amount of assets and liabilities in Exelon’s and Generation’s Consolidated Balance Sheets that relate to their involvement with the VIEs are predominately related to working capital accounts and generally represent the amounts owed by, or owed to, Exelon and Generation for the deliveries associated with the current billing cycles under the commercial agreements. Further, Exelon and Generation have not provided material debt or equity support, liquidity arrangements or performance guarantees associated with these commercial agreements.

As of June 30, 2019 and December 31, 2018, Exelon's and Generation's unconsolidated VIEs consist of:


•	Energy purchase and sale agreements with VIEs for which Generation has concluded that consolidation is not required.


•	Asset sale agreement with ZionSolutions, LLC and EnergySolutions, Inc. in which Generation has a variable interest but has concluded that consolidation is not required.


•	Equity investments in distributed energy companies for which Generation has concluded that consolidation is not required.

As of June 30, 2019 and December 31, 2018, the Utility Registrants did not have any material unconsolidated VIEs.

As of June 30, 2019 and December 31, 2018, Exelon and Generation had significant unconsolidated variable interests in eight and seven VIEs, respectively, for which Exelon or Generation, as applicable, was not the primary beneficiary; including certain equity investments and certain commercial agreements. Exelon and Generation only include unconsolidated VIEs that are individually material in the tables below. However, Exelon and Generation have several individually immaterial VIEs that in aggregate represent a total investment of $16 million and $12 million, as of June 30, 2019, and $15 million and $13 million as of December 31, 2018, respectively. These immaterial VIEs are equity and debt securities in energy development companies. As of June 30, 2019 and December 31, 2018, the maximum exposure to loss related to these securities included in Investments in Exelon’s and Generation’s Consolidated Balance Sheets is limited to $16 million and $12 million, and $15 million and $13 million, respectively. The risk of a loss was assessed to be remote and, accordingly, Exelon and Generation have not recognized a liability associated with any portion of the maximum exposure to loss.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

The following tables present summary information about Exelon's and Generation’s significant unconsolidated VIE entities:



June 30, 2019	Commercial Agreement VIEs		Equity Investment VIEs		Total
Total assets^(a)	$	603	$	453	$	1,056
Total liabilities^(a)	33		225		258
Exelon's ownership interest in VIE^(a)	—		203		203
Other ownership interests in VIE^(a)	571		25		596
Registrants’ maximum exposure to loss:
Carrying amount of equity method investments	—		203		203
Contract intangible asset	7		—		7



December 31, 2018	Commercial Agreement VIEs		Equity Investment VIEs		Total
Total assets^(a)	$	597	$	472	$	1,069
Total liabilities^(a)	37		222		259
Exelon's ownership interest in VIE^(a)	—		223		223
Other ownership interests in VIE^(a)	560		27		587
Registrants’ maximum exposure to loss:
Carrying amount of equity method investments	—		223		223
Contract intangible asset	7		—		7

_________


(a)	These items represent amounts in the unconsolidated VIE balance sheets, not in Exelon’s or Generation’s Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs.

For each of the unconsolidated VIEs, Exelon and Generation have assessed the risk of a loss equal to their maximum exposure to be remote and, accordingly, Exelon and Generation have not recognized a liability associated with any portion of the maximum exposure to loss. In addition, there are no material agreements with, or commitments by, third parties that would affect the fair value or risk of their variable interests in these VIEs.

3. Mergers, Acquisitions and Dispositions (Exelon and Generation)

Acquisition of Handley Generating Station

On November 7, 2017, ExGen Texas Power, LLC (EGTP), and all of its wholly owned subsidiaries filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Code in the United States Bankruptcy Court for the District of Delaware, which resulted in Exelon and Generation deconsolidating EGTP's assets and liabilities from their consolidated financial statements. Concurrently with the Chapter 11 filings, Generation entered into an asset purchase agreement to acquire one of EGTP's generating plants, the Handley Generating Station, which closed on April 4, 2018 for a purchase price of $62 million.

Disposition of Oyster Creek

On July 31, 2018, Generation entered into an agreement with Holtec International (Holtec) and its indirect wholly owned subsidiary, Oyster Creek Environmental Protection, LLC (OCEP), for the sale and decommissioning of Oyster Creek located in Forked River, New Jersey, which permanently ceased generation operations on September 17, 2018. Completion of the transaction contemplated by the sale agreement was subject to the satisfaction of several closing conditions, including approval of the license transfer from the NRC and other regulatory approvals, and a private letter ruling from the IRS, which were satisfied in the second quarter 2019. The sale was completed on July 1, 2019. Exelon and Generation expect the loss on the sale, which will be recognized in the third quarter, to be immaterial.

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(Dollars in millions, except per share data, unless otherwise noted)

Under the terms of the transaction, Generation transferred to OCEP substantially all the assets associated with Oyster Creek, including assets held in NDT funds, along with the assumption of liability for all responsibility for the site, including full decommissioning and ongoing management of spent fuel until the spent fuel is moved offsite. The terms of the transaction also include various forms of performance assurance for the obligations of OCEP to timely complete the required decommissioning, including a parental guaranty from Holtec for all performance and payment obligations of OCEP, and a requirement for Holtec to deliver a letter of credit to Generation upon the occurrence of specified events.

As a result of the transaction, in the third quarter of 2018, Exelon and Generation reclassified certain Oyster Creek assets and liabilities in Exelon’s and Generation’s Consolidated Balance Sheets as held for sale at their respective fair values. Exelon and Generation had $863 million and $759 million of Assets and Liabilities held for sale, respectively, at June 30, 2019 and $897 million and $777 million of Assets and Liabilities held for sale, respectively, at December 31, 2018. Upon remeasurement of the Oyster Creek ARO, Exelon and Generation recognized an $84 million and a $9 million pre-tax charge to Operating and maintenance expense in the third quarter of 2018 and in the second quarter of 2019, respectively. See Note 13 - Nuclear Decommissioning for additional information.

Other Asset Disposition

On February 28, 2018, Generation completed the sale of its interest in an electrical contracting business that primarily installs, maintains and repairs underground and high-voltage cable transmission and distribution systems for $87 million, resulting in a pre-tax gain which is included within Gain on sales of assets and businesses in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income for the six months ended June 30, 2018. In June 2018, additional proceeds were received, and a pre-tax gain was recorded within Gain on sales of assets and businesses in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.

4. Revenue from Contracts with Customers (All Registrants)

The Registrants recognize revenue from contracts with customers to depict the transfer of goods or services to customers at an amount that the entities expect to be entitled to in exchange for those goods or services. Generation’s primary sources of revenue include competitive sales of power, natural gas, and other energy-related products and services. The Utility Registrants’ primary sources of revenue include regulated electric and gas tariff sales, distribution and transmission services.

See Note 3 — Revenue from Contracts with Customers of the Exelon 2018 Form 10-K for additional information regarding the primary sources of revenue for the Registrants.

Contract Balances (All Registrants)

Contract Assets and Liabilities

Generation records contract assets for the revenue recognized on the construction and installation of energy efficiency assets and new power generating facilities before Generation has an unconditional right to bill for and receive the consideration from the customer. These contract assets are subsequently reclassified to receivables when the right to payment becomes unconditional. Generation records contract assets and contract receivables within Other current assets and Accounts receivable, net - Customer, respectively, within Exelon’s and Generation’s Consolidated Balance Sheets.

Generation records contract liabilities when consideration is received or due prior to the satisfaction of the performance obligations. These contract liabilities primarily relate to upfront consideration received or due for equipment service plans, solar panel leases and the Illinois ZEC program that introduces a cap on the total consideration to be received by Generation. Generation records contract liabilities within Other current liabilities and Other noncurrent liabilities within Exelon's and Generation's Consolidated Balance Sheets.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

The following table provides a rollforward of the contract assets and liabilities reflected in Exelon's and Generation's Consolidated Balance Sheets from January 1, 2018 to June 30, 2019:



	Contract Assets						Contract Liabilities
	Exelon			Generation			Exelon			Generation
Balance as of January 1, 2018	$	283		$	283		$	35		$	35
Consideration received or due	(146		)	(146		)	179			465
Revenues recognized	50			50			(187		)	(458		)
Balance at December 31, 2018	187			187			27			42
Consideration received or due	(44		)	(44		)	38			115
Revenues recognized	53			53			(44		)	(131		)
Balance at June 30, 2019	$	196		$	196		$	21		$	26

The Utility Registrants do not have any contract assets. The Utility Registrants also record contract liabilities when consideration is received prior to the satisfaction of the performance obligations. As of June 30, 2019 and December 31, 2018, the Utility Registrants' contract liabilities were immaterial.

Transaction Price Allocated to Remaining Performance Obligations (All Registrants)

The following table shows the amounts of future revenues expected to be recorded in each year for performance obligations that are unsatisfied or partially unsatisfied as of June 30, 2019. This disclosure only includes contracts for which the total consideration is fixed and determinable at contract inception. The average contract term varies by customer type and commodity but ranges from one month to several years.

This disclosure excludes Generation's power and gas sales contracts as they contain variable volumes and/or variable pricing. This disclosure also excludes the Utility Registrants' gas and electric tariff sales contracts and transmission revenue contracts as they generally have an original expected duration of one year or less and, therefore, do not contain any future, unsatisfied performance obligations to be included in this disclosure.



	2019		2020		2021		2022		2023 and thereafter		Total
Exelon	$	274	$	275	$	93	$	68	$	248	$	958
Generation	355		343		118		72		248		1,136

Revenue Disaggregation (All Registrants)

The Registrants disaggregate revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. See Note 18 — Segment Information for the presentation of the Registrant's revenue disaggregation.

5. Leases (All Registrants)

Lessee

The Registrants have operating leases for which they are the lessees. The following tables outline the significant types of operating leases at each registrant and other terms and conditions of the lease agreements. The Registrants do not have material finance leases.

Exelon

Generation

ComEd

PECO

BGE

PHI

Pepco

DPL

ACE

Contracted generation

●

Real estate

●

Vehicles and equipment

●

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(Dollars in millions, except per share data, unless otherwise noted)



(in years)	Exelon	Generation	ComEd	PECO	BGE	PHI	Pepco	DPL	ACE
Remaining lease terms	1-87	1-37	1-6	1-15	1-87	1-13	1-13	1-13	1-8
Options to extend the term	3-30	3-30	5	N/A	N/A	3-30	5	3-30	N/A
Options to terminate within	1-4	2	4	N/A	3	N/A	N/A	N/A	N/A

The components of lease costs for the three months ended June 30, 2019 were as follows:



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Operating lease costs	$	87	$	61	$	1	$	—	$	9	$	13	$	3	$	4	$	3
Variable lease costs	77		72		1		—		1		2		1		—		1
Short-term lease costs	3		3		—		—		—		—		—		—		—
Total lease costs ^(a)	$	167	$	136	$	2	$	—	$	10	$	15	$	4	$	4	$	4

__________


(a)	Excludes $16 million, $12 million, $4 million and $4 million of sublease income recorded at Exelon, Generation, PHI and DPL.

The components of lease costs for the six months ended June 30, 2019 were as follows:



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Operating lease costs	$	155	$	107	$	2	$	—	$	17	$	23	$	6	$	7	$	4
Variable lease costs	150		140		1		—		1		4		1		1		1
Short-term lease costs	11		11		—		—		—		—		—		—		—
Total lease costs ^(a)	$	316	$	258	$	3	$	—	$	18	$	27	$	7	$	8	$	5

__________


(a)	Excludes $19 million, $14 million, $5 million and $5 million of sublease income recorded at Exelon, Generation, PHI and DPL.

The following table provides additional information regarding the presentation of operating lease ROU assets and lease liabilities within the Registrants’ Consolidated Balance Sheets as of June 30, 2019:



	Exelon^(a)		Generation^(a)		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Operating lease ROU assets
Other deferred debits and other assets	$	1,412	$	982	$	11	$	2	$	91	$	309	$	67	$	74	$	24

Operating lease liabilities
Other current liabilities	250		173		3		1		32		36		8		11		6
Other deferred credits and other liabilities	1,353		981		9		1		65		280		60		72		19
Total operating lease liabilities	$	1,603	$	1,154	$	12	$	2	$	97	$	316	$	68	$	83	$	25

__________


(a)	Exelon's and Generation's operating ROU assets and lease liabilities include $595 million and $744 million, respectively, related to contracted generation.

The weighted average remaining lease terms, in years, and discount rates for operating leases as of June 30, 2019 were as follows:



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Remaining lease term	9.9		10.6		4.9		4.4		5.4		9.2		9.7		9.6		5.2
Discount rate	4.6	%	4.8	%	3.1	%	3.4	%	3.6	%	4.1	%	3.8	%	3.9	%	3.5	%

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Future minimum lease payments for operating leases as of June 30, 2019 were as follows:



Year	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
2019	$	149	$	104	$	2	$	1	$	17	$	23	$	6	$	5	$	4
2020	291		202		3		1		34		44		9		12		5
2021	246		161		3		—		31		42		9		12		5
2022	177		112		2		—		16		41		8		11		4
2023	141		99		1		—		—		39		8		10		3
Remaining years	1,051		834		2		—		19		196		43		52		6
Total	2,055		1,512		13		2		117		385		83		102		27
Interest	452		358		1		—		20		69		15		19		2
Total operating lease liabilities	$	1,603	$	1,154	$	12	$	2	$	97	$	316	$	68	$	83	$	25

Future minimum lease payments for operating leases under the prior lease accounting guidance as of December 31, 2018 were as follows:



Year	Exelon^(a)(b)		Generation^(a)(b)		ComEd^(a)(c)		PECO^(a)(c)		BGE^(a)(c)(d)(e)		PHI^(a)		Pepco^(a)		DPL^(a)(c)		ACE^(a)
2019	$	140	$	33	$	7	$	5	$	35	$	48	$	11	$	14	$	7
2020	149		46		5		5		35		46		10		13		6
2021	143		46		4		5		33		43		9		12		5
2022	126		47		4		5		18		42		8		12		5
2023	97		46		3		5		3		39		8		10		4
Remaining years	723		545		—		—		19		159		40		35		5
Total minimum future lease payments	$	1,378	$	763	$	23	$	25	$	143	$	377	$	86	$	96	$	32

__________


(a)	Includes amounts related to shared use land arrangements.


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

(c)

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 2019 - 2023, was $3 million, $5 million, $1 million and $1 million respectively. Also includes amounts related to shared use land arrangements.


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


(e)	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 $26 million, $28 million, $28 million and $14 million related to years 2019 - 2022, respectively.

Cash paid for amounts included in the measurement of lease liabilities for the six months ended June 30, 2019 were as follows:



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Operating cash flows from operating leases	$	142	$	101	$	2	$	—	$	16	$	19	$	5	$	4	$	3

ROU assets obtained in exchange for lease obligations for the six months ended June 30, 2019 were as follows:



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Operating leases	$	30	$	7	$	6	$	—	$	1	$	15	$	6	$	6	$	3

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(Dollars in millions, except per share data, unless otherwise noted)

Lessor

The Registrants have operating leases for which they are the lessors. The following tables outline the significant types of leases at each registrant and other terms and conditions of their lease agreements.

Exelon

Generation

ComEd

PECO

BGE

PHI

Pepco

DPL

ACE

Contracted generation

●

Real estate

●



(in years)	Exelon	Generation	ComEd	PECO	BGE	PHI	Pepco	DPL	ACE
Remaining lease terms	1-84	1-33	1-18	1-84	24	1-14	2-7	13-14	1-3
Options to extend the term	1-79	1-5	5-79	5-50	N/A	5	N/A	N/A	N/A

The components of lease income for the three months ended June 30, 2019 were as follows:



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Operating lease income	$	14	$	12	$	—	$	—	$	—	$	1	$	—	$	1	$	—
Variable lease income	77		74		—		—		—		3		—		3		—

The components of lease income for the six months ended June 30, 2019 were as follows:



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Operating lease income	$	18	$	15	$	—	$	—	$	—	$	2	$	—	$	2	$	—
Variable lease income	129		126		—		—		—		3		—		3		—

Future minimum lease payments to be recovered under operating leases as of June 30, 2019 were as follows:



Year	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
2019	$	33	$	31	$	—	$	—	$	—	$	2	$	—	$	2	—
2020	51		46		—		—		—		4		—		3		—
2021	51		46		—		—		—		4		1		3		—
2022	50		45		—		—		—		5		—		4		—
2023	49		45		—		—		—		4		—		3		—
Remaining years	314		271		1		3		1		38		—		38		—
Total	$	548	$	484	$	1	$	3	$	1	$	57	$	1	$	53	$	—

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

6. Regulatory Matters (All Registrants)

As discussed in Note 4 — Regulatory Matters of the Exelon 2018 Form 10-K, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The following discusses developments in 2019 and updates to the 2018 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 2019.

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)	April 16, 2018	$	(23	)		$	(24	)		8.69%		December 4, 2018	January 1, 2019
PECO - Pennsylvania (Electric)	March 29, 2018	$	82			$	25			N/A	^(a)	December 20, 2018	January 1, 2019
BGE - Maryland (Natural Gas)	June 8, 2018 (amended October 12, 2018)	$	61			$	43			9.8%		January 4, 2019	January 4, 2019
ACE - New Jersey (Electric)	August 21, 2018 (amended November 19, 2018)	$	122		^(b)	$	70		^(b)	9.6%		March 13, 2019	April 1, 2019

__________


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


(b)	Requested and approved increases are before New Jersey sales and use tax.

Pending Distribution Base Rate Case Proceedings



Registrant/Jurisdiction	Filing Date	Requested Revenue Requirement Increase (Decrease)			Requested ROE		Expected Approval Timing
Pepco - Maryland (Electric)	January 15, 2019 (amended May 16, 2019)	$	27		10.3	%	Third quarter of 2019
ComEd - Illinois (Electric)^(a)	April 8, 2019	$	(6	)	8.91	%	December 2019
BGE - Maryland (Electric)	May 24, 2019	$	74		10.3	%	December 2019
BGE - Maryland (Natural Gas)	May 24, 2019	$	59		10.3	%	December 2019
Pepco - District of Columbia (Electric)^(b)	May 30, 2019	$	162		10.3	%	Second quarter of 2020

__________

(a)

Reflects an increase of $57 million for the initial revenue requirement for 2019 and a decrease of $63 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 6.53%. See Note 4 — Regulatory Matters of the Exelon 2018 Form 10-K for additional information on ComEd's distribution formula rate filings.


(b)	Reflects a three-year cumulative multi-year plan and total requested revenue requirement increases of $85 million, $40 million and $37 million for years 2020, 2021, and 2022, respectively, to recover capital investments made in 2018 and 2019 and planned capital investments from 2020 to 2022.

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(Dollars in millions, except per share data, unless otherwise noted)

Transmission Formula Rates

Transmission Formula Rate (Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE). ComEd’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, with the resulting rates effective on June 1 of the same year. The annual formula rate update is based on prior year actual costs and current year projected capital additions (initial year revenue requirement). The update also reconciles any differences between the revenue requirement in effect beginning June 1 of the prior year and actual costs incurred for that year (annual reconciliation).

For 2019, the following total increases/(decreases) were included in ComEd’s, BGE’s, Pepco's, DPL's and ACE's electric transmission formula rate filings:



Registrant^(a)	Initial Revenue Requirement Increase (Decrease)			Annual Reconciliation Increase (Decrease)			Total Revenue Requirement Increase (Decrease)				Allowed Return on Rate Base^(c)		Allowed ROE^(d)
ComEd	$	21		$	(16	)	$	5			8.21	%	11.50	%
BGE	(10		)	(23		)	(19		)	^(b)	7.35	%	10.50	%
Pepco	15			11			26				7.75	%	10.50	%
DPL	17			(1		)	16				7.14	%	10.50	%
ACE	11			(2		)	9				7.79	%	10.50	%

__________


(a)	All rates are effective June 2019, subject to review by the FERC and other parties, which is due by the fourth quarter of 2019.


(b)	The change in BGE's transmission revenue requirement includes a FERC approved dedicated facilities charge of $14 million to recover the costs of providing transmission service to specifically designated load by BGE.


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

(d)

As part of the FERC-approved settlement of ComEd’s 2007 transmission rate case, the rate of return on common equity is 11.50%, 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%. 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.

Pending Transmission Formula Rate (Exelon and PECO). On May 1, 2017, PECO filed a request with FERC seeking approval to update its transmission rates and change the manner in which PECO’s transmission rate is determined from a fixed rate to a formula rate. The formula rate will be updated annually to ensure that under this rate customers pay the actual costs of providing transmission services. PECO’s initial formula rate filing included a requested increase of $22 million to PECO’s annual transmission revenue requirement, which reflected a ROE of 11%, inclusive of a 50 basis point adder for being a member of a RTO. On June 27, 2017, FERC issued an Order accepting the filing and suspending the proposed rates until December 1, 2017, subject to refund, and set the matter for hearing and settlement judge procedures.

Pursuant to the transmission formula rate request discussed above, PECO made its annual formula rate updates in May 2018 and 2019, which included a decrease of $6 million and an increase of $8 million, respectively, to the annual transmission revenue requirement. The updated transmission formula rates were effective on June 1, 2018 and 2019, respectively, subject to refund.

On July 22, 2019, PECO and other parties filed with FERC a settlement agreement, which includes a ROE of 10.35%, inclusive of a 50 basis point adder for being a member of a RTO. The settlement is not expected to have a material impact on PECO’s 2017, 2018, or 2019 annual transmission revenue requirements. A final order from FERC is not expected prior to the fourth quarter of 2019. PECO cannot predict the outcome of this proceeding, or the transmission formula FERC may approve.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Other State Regulatory Matters

Energy Efficiency Formula Rate. ComEd filed its annual energy efficiency formula rate update with the ICC on May 23, 2019. The filing establishes the revenue requirement used to set the rates that will take effect in January 2020 after the ICC’s review and approval. The revenue requirement requested is based on a reconciliation of the 2018 actual costs plus projected 2019 and 2020 expenditures.



Registrant	Initial Revenue Requirement Increase (Decrease)		Annual Reconciliation Increase (Decrease)			Total Revenue Requirement Increase (Decrease)			Requested Return on Rate Base		Requested ROE
ComEd	$	53	$	(2	)	$	51	^(a)	6.53	%	8.91	%

__________

(a)

The requested revenue requirement increase provides for a weighted average debt and equity return on rate base of 6.53% inclusive of an allowed ROE of 8.91%. The ROE reflects the average rate on 30-year treasury notes plus 580 basis points. The ROE applicable to the 2018 reconciliation year is 10.91% and the return on rate base is 7.49%, which include the Performance Adjustment, which can either increase or decrease the ROE by up to a maximum of 200 basis points.

New Jersey Regulatory Matters

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

New Jersey Clean Energy Legislation (Exelon, PHI and ACE). On May 23, 2018, New Jersey enacted legislation that established and modified New Jersey’s clean energy and energy efficiency programs and solar and renewable energy portfolio standards. On the same day, New Jersey enacted legislation that established a ZEC program that provides compensation for nuclear plants that demonstrate to the NJBPU that they meet certain requirements, 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. Electric distribution utilities in New Jersey, including ACE, began collecting from retail distribution customers, through a non-bypassable charge, all costs associated with the utility’s procurement of the ZECs effective April 18, 2019. See Generation Regulatory Matters below for additional information.

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. ComEd, Pepco, DPL and ACE had similar transmission-related income tax regulatory liabilities and assets also requiring FERC approval. 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. As a result of the FERC’s order, ComEd, BGE, Pepco, DPL and ACE took a charge to Income tax expense within their Consolidated Statements of Operations and Comprehensive Income in the fourth quarter of 2017 reducing their associated transmission-related income tax regulatory assets for the portion of the total transmission-related income tax regulatory assets that would have been previously amortized and recovered through rates. Similar regulatory assets and liabilities at PECO are not subject to the same FERC transmission rate recovery formula. See above for additional information regarding PECO's transmission formula rate filing.

On December 18, 2017, BGE filed for clarification and rehearing of FERC’s November 16, 2017 order and 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.

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(Dollars in millions, except per share data, unless otherwise noted)

On September 7, 2018, FERC issued orders rejecting BGE’s December 18, 2017 request for rehearing and clarification and ComEd's, Pepco's, DPL's and ACE's February 23, 2018 (as amended on July 9, 2018) filings, citing the lack of timeliness of the requests to recover amounts that would have been previously amortized, but indicating that ongoing recovery of certain transmission-related income tax regulatory assets would provide for a more accurate revenue requirement, consistent with its November 16, 2017 order.

On October 1, 2018, ComEd, BGE, Pepco, DPL, and ACE submitted filings to recover ongoing non-TCJA amortization amounts and refund TCJA transmission-related income tax regulatory liabilities for the prospective period starting on October 1, 2018. In addition, on October 9, 2018, ComEd, Pepco, DPL, and ACE sought rehearing of FERC's September 7, 2018 order. 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 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. ComEd, BGE, Pepco, DPL, and ACE cannot predict the outcome of these proceedings.

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 $78 million, $52 million, $16 million, $10 million, $3 million, $5 million and $2 million, respectively, as of June 30, 2019.

Regulatory Assets and Liabilities

The Utility Registrants' regulatory assets and liabilities have not changed materially since December 31, 2018, unless noted below. See Note 4 — Regulatory Matters of the Exelon 2018 Form 10-K for additional information on the specific regulatory assets and liabilities.

ComEd. Regulatory assets increased $88 million primarily due to an increase of $117 million in Energy Efficiency Costs, partially offset by a decrease of $38 million in Electric Distribution Formula Rate Annual Reconciliations.

BGE. Regulatory liabilities decreased $71 million primarily due to a decrease of $31 million in Deferred Income Taxes and $29 million in Removal Costs.

Pepco. Regulatory assets decreased $50 million primarily due to a decrease of $21 million in Electric Energy and Natural Gas Costs and $16 million in DC PLUG charge.

DPL. Regulatory liabilities decreased $36 million primarily due to a decrease of $21 million in Deferred Income Taxes.

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, 2019	$	61	$	5	$	—	$	48	$	8	$	5	$	3	$	—
December 31, 2018	$	65	$	8	$	—	$	49	$	8	$	5	$	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.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Generation Regulatory Matters (Exelon and Generation)

Illinois Regulatory Matters

Zero Emission Standard. Pursuant to FEJA, on January 25, 2018, the ICC announced that Generation’s Clinton Unit 1, Quad Cities Unit 1 and Quad Cities Unit 2 nuclear plants were selected as the winning bidders through the IPA's ZEC procurement event. Generation executed the ZEC procurement contracts with Illinois utilities, including ComEd, effective January 26, 2018 and began recognizing revenue with compensation for the sale of ZECs retroactive to the June 1, 2017 effective date of FEJA. During the first quarter of 2018, Generation recognized $150 million of revenue related to ZECs generated from June 1, 2017 through December 31, 2017.

On February 14, 2017, two lawsuits were filed in the Northern District of Illinois against the IPA alleging that the state’s ZEC program violates certain provisions of the U.S. Constitution. Both lawsuits argued that the Illinois ZEC program would distort PJM's FERC-approved energy and capacity market auction system of setting wholesale prices and sought a permanent injunction preventing the implementation of the program. The lawsuits were dismissed by the district court on July 14, 2017. On September 13, 2018, the U.S. Circuit Court of Appeals for the Seventh Circuit affirmed the lower court's dismissal of both lawsuits. On January 7, 2019, plaintiffs filed a petition seeking U.S. Supreme Court review of the case, which was denied on April 15, 2019.

New Jersey Regulatory Matters

New Jersey Clean Energy Legislation. On May 23, 2018, New Jersey enacted legislation that established a ZEC program that will provide 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 November 19, 2018, NJBPU issued an order providing for the method and application process for determining the eligibility of nuclear power plants, a draft method and process for ranking and selecting eligible nuclear power plants, and the establishment of a mechanism for each regulated utility to purchase ZECs from selected nuclear power plants. On December 19, 2018, PSEG filed complete applications seeking NJBPU approval for Salem 1 and Salem 2, of which Generation owns a 42.59% ownership interest, to participate in the ZEC program. 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 $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. The appeal does not prevent implementation of the ZEC program. Exelon and Generation cannot predict the outcome of the appeal. See Note 8 — 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.

On October 19, 2016, a coalition of fossil-generation companies filed a complaint in federal district court against the NYPSC alleging that the ZEC program violates certain provisions of the U.S. Constitution; specifically, that the ZEC program interferes with FERC’s jurisdiction over wholesale rates and that it discriminates against out of state competitors, which was dismissed by the district court on July 25, 2017. On September 27, 2018, the U.S. Court of Appeals for the Second Circuit affirmed the lower court's dismissal of the complaint against the ZEC program. On January 7, 2019, the fossil-generation companies filed a petition seeking U.S. Supreme Court review of the case which was denied on April 15, 2019.

In addition, 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. Subsequently, Generation, CENG and the NYPSC filed motions to dismiss the state court action, which were later opposed by the plaintiffs. On January 22,

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(Dollars in millions, except per share data, unless otherwise noted)

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. Generation, CENG and the state’s answers and briefs were filed on March 30, 2018. On December 17, 2018, plaintiffs filed a reply brief introducing new arguments and new evidence. The State of New York filed a motion to strike on December 28, 2018. On January 4, 2019, Generation and CENG filed a motion to strike the new arguments and new evidence. The court must now decide whether or not to set the case for hearing.

See Note 8 — Early Plant Retirements for additional information related to Ginna and Nine Mile Point.

Federal Regulatory Matters

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) with MDE for Conowingo, Generation continues to work with MDE and other stakeholders to resolve water quality licensing issues, including: (1) water quality, (2) fish habitat, and (3) sediment.

On April 27, 2018, the MDE issued its 401 Certification for Conowingo. As issued, the 401 Certification contains numerous conditions, including those relating to reduction of nutrients from upstream sources, removal of all visible trash and debris from upstream sources, and implementation of measures relating to fish passage, which could have a material, unfavorable impact in Exelon’s and Generation’s financial statements through an increase in capital expenditures and operating costs if implemented. On May 25, 2018, Generation filed complaints in federal and state court, along with a petition for reconsideration with MDE, alleging that the conditions are unfair and onerous violating MDE regulations, state, federal, and constitutional law. Generation also requested that FERC defer the issuance of the federal license while these significant state and federal law issues are pending. On February 28, 2019, Generation filed a Petition for Declaratory Order with FERC requesting that FERC issue an order declaring that MDE waived its right to issue a 401 Certification for Conowingo because it failed to timely act on Conowingo's 401 Certification application and requesting that FERC decline to include the conditions proposed by MDE in April 2018. Exelon also continues to challenge the 401 Certification through the administrative process and in state and federal court. Exelon and Generation cannot predict the final outcome or its financial impact, if any, on Exelon or Generation.

As of June 30, 2019, $40 million of direct costs associated with Conowingo licensing efforts have been capitalized. See Note 4 — Regulatory Matters of the Exelon 2018 Form 10-K for additional information on Generation's operating license renewal efforts.

7. Impairment of Long-Lived Assets (Exelon and Generation)

Registrants evaluate long-lived assets for recoverability whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. The fair value analysis is primarily based on the income approach using significant unobservable inputs (Level 3) including revenue and generation forecasts, projected capital and maintenance expenditures and discount rates. Changes in those inputs could potentially result in material future impairments of the Registrants' long-lived assets.

Generation’s Antelope Valley, a 242 MW solar facility in Lancaster, CA, sells all of its output to PG&E through a PPA. As of June 30, 2019, Generation had approximately $740 million of net long-lived assets related to Antelope Valley. As a result of the PG&E bankruptcy filing in the first quarter of 2019, Generation completed a comprehensive review of Antelope Valley's estimated undiscounted future cash flows and no impairment charge was recorded. Significant changes in assumptions such as the likelihood of the PPA being rejected as part of the bankruptcy proceedings could potentially result in future impairments of Antelope Valley’s net long-lived assets, which could be material.

Antelope Valley is a wholly owned indirect subsidiary of EGR IV, which had approximately $1,950 million of additional net long-lived assets as of June 30, 2019. EGR IV is a wholly owned indirect subsidiary of Exelon and Generation and includes Generation's interest in EGRP and other projects with non-controlling interests. To date, there have been no indicators to suggest that the carrying amount of other net long-lived assets of EGR IV may not be recoverable.

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(Dollars in millions, except per share data, unless otherwise noted)

Generation will continue to monitor the bankruptcy proceedings for any changes in circumstances that may indicate the carrying amount of the net long-lived assets of Antelope Valley or other long-lived assets of EGR IV may not be recoverable.

See Note 11 - Debt and Credit Agreements for additional information on the PG&E bankruptcy.

8. Early Plant Retirements (Exelon and Generation)

Exelon and Generation continuously evaluate factors that affect the current and expected economic value of Generation’s plants, including, but not limited to: market power prices, results of capacity auctions, potential legislative and regulatory solutions to ensure plants are fairly compensated for benefits they provide through their carbon-free emissions, reliability, or fuel security, and the impact of potential rules from the EPA requiring reduction of carbon and other emissions and the efforts of states to implement those final rules. The precise timing of an early retirement date for any plant, and the resulting financial statement impacts, may be affected by many factors, including the status of potential regulatory or legislative solutions, results of any transmission system reliability study assessments, the nature of any co-owner requirements and stipulations, and NDT fund requirements for nuclear plants, among other factors. However, the earliest retirement date for any plant would usually be the first year in which the unit does not have capacity or other obligations, and where applicable, just prior to its next scheduled nuclear refueling outage.

Nuclear Generation

In 2015 and 2016, Generation identified the Clinton and Quad Cities nuclear plants in Illinois, Ginna and Nine Mile Point nuclear plants in New York and Three Mile Island nuclear plant in Pennsylvania as having the greatest risk of early retirement based on economic valuation and other factors. In 2017, PSEG made public similar financial challenges facing its New Jersey nuclear plants, including Salem, of which Generation owns a 42.59% ownership interest. PSEG is the operator of Salem and also has the decision making authority to retire Salem.

Assuming the continued effectiveness of the Illinois ZES, New Jersey ZEC program and the New York CES, Generation and CENG, through its ownership of Ginna and Nine Mile Point, no longer consider Clinton, Quad Cities, Salem, Ginna or Nine Mile Point to be at heightened risk for early retirement. However, to the extent the Illinois ZES, New Jersey ZEC program or the New York CES programs do not operate as expected over their full terms, each of these plants could again be at heightened risk for early retirement, which could have a material impact on Exelon’s and Generation’s future financial statements. See Note 6 — Regulatory Matters for additional information on the Illinois ZES, New Jersey ZEC program and New York CES.

In Pennsylvania, the TMI nuclear plant did not clear in the May 2017 PJM capacity auction for the 2020-2021 planning year, the third consecutive year that TMI failed to clear the PJM base residual capacity auction and on May 30, 2017, based on these capacity auction results, prolonged periods of low wholesale power prices, and the absence of federal or state policies that place a value on nuclear energy for its ability to produce electricity without air pollution, Generation announced that it would permanently cease generation operations at TMI on or about September 30, 2019. Generation filed the required market and regulatory notifications to shut down the plant and PJM approved the deactivation. On April 5, 2019, Generation filed the PSDAR with the NRC detailing the plans for TMI after its final shutdown.

On February 2, 2018, Generation announced that it would permanently cease generation operations at the Oyster Creek nuclear plant at the end of its current operating cycle and permanently ceased generation operations in September 2018.

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(Dollars in millions, except per share data, unless otherwise noted)

As a result of these early nuclear plant retirement decisions, Exelon and Generation recognized incremental non-cash charges to earnings stemming from shortening the expected economic useful lives primarily related to accelerated depreciation of plant assets (including any ARC) and accelerated amortization of nuclear fuel, as well as operating and maintenance expenses. See Note 13 — Nuclear Decommissioning for additional information on changes to the nuclear decommissioning ARO balance. The total impact for the three and six months ended June 30, 2019 and 2018 are summarized in the table below.



	Three Months Ended June 30,				Six Months Ended June 30,
Income statement expense (pre-tax)	2019		2018		2019			2018
Depreciation and amortization^(a)
Accelerated depreciation	$	71	$	152	$	145		$	289
Accelerated nuclear fuel amortization	4		19		9			34
Operating and maintenance^(b)	—		2		(83		)	28
Total	$	75	$	173	$	71		$	351

_________


(a)	Reflects incremental accelerated depreciation and amortization for TMI for the three and six months ended June 30, 2019. Reflects incremental accelerated depreciation for TMI and Oyster Creek for the three and six months ended June 30, 2018. The Oyster Creek amounts are from February 2, 2018 through June 30, 2018.


(b)	In 2019, primarily reflects decrease to estimated decommissioning costs for TMI. See Note 13 — Nuclear Decommissioning for additional information on the first quarter 2019 TMI ARO update. In 2018, primarily reflects materials and supplies inventory reserve adjustments, employee related costs and CWIP impairments associated with the early retirement decisions for TMI and Oyster Creek.

Generation’s Dresden, Byron and Braidwood nuclear plants in Illinois are also showing increased signs of economic distress, which could lead to an early retirement, in a market that does not currently compensate them for their unique contribution to grid resiliency and their ability to produce large amounts of energy without carbon and air pollution. The May 2018 PJM capacity auction for the 2021-2022 planning year resulted in the largest volume of nuclear capacity ever not selected in the auction, including all of Dresden, and portions of Byron and Braidwood. Exelon continues to work with stakeholders on state policy solutions, while also advocating for broader market reforms at the regional and federal level.

Other Generation

On March 29, 2018, Generation notified grid operator ISO-NE of its plans to early retire its Mystic Generating Station assets absent regulatory reforms on June 1, 2022, at the end of the then-current capacity commitment for Mystic Units 7 and 8. Mystic Unit 9 was then committed through May 2021.

On May 16, 2018, Generation made a filing with FERC to establish cost-of-service compensation and terms and conditions of service for Mystic Units 8 and 9 for the period between June 1, 2022 - May 31, 2024. On December 20, 2018, FERC issued an order accepting the cost of service agreement reflecting a number of adjustments to the annual fixed revenue requirement and allowing for recovery of a substantial portion of the costs associated with the Everett Marine Terminal. Those adjustments were reflected in a compliance filing filed March 1, 2019. In the December 20, 2018 order, FERC also directed a paper hearing on ROE using a new methodology. Initial briefs in the ROE proceeding were filed on April 19, 2019 and reply briefs were filed on July 18, 2019. On January 4, 2019, Generation notified ISO-NE that it will participate in the Forward Capacity Market auction for the 2022 - 2023 capacity commitment period. In addition, on January 22, 2019, Exelon and several other parties filed requests for rehearing of certain findings of the December 20, 2018 order, which does not alter Generation's commitment to participate in the Forward Capacity Auction for the 2022-2023 capacity commitment period. On June 10, 2019, ISO-NE announced that it has determined that Mystic 8 and 9 are needed for fuel security for the 2023-2024 capacity commitment period.

On March 25, 2019, ISO-NE filed the Inventoried Energy Program, which is intended to provide an interim fuel security program pending conclusion of the stakeholder process to develop a long-term, market-based solution to address fuel security. Exelon filed comments on the Inventoried Energy Program proposal on April 15, 2019. FERC has ordered ISO-NE to file long-term, market-based fuel security rules by October 15, 2019. On May 8, 2019, FERC issued a deficiency letter to ISO-NE seeking additional information on the Inventoried Energy Program proposal,

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(Dollars in millions, except per share data, unless otherwise noted)

and ISO-NE filed a response on June 6, 2019. On July 15, 2019, FERC held a staff-led public meeting on the long-term, market-based fuel security proposal.

The following table provides the balance sheet amounts as of June 30, 2019 for Exelon's and Generation’s significant assets and liabilities associated with the Mystic Units 8 and 9 and Everett Marine Terminal assets that would potentially be impacted by a decision to permanently cease generation operations in the absence of long-term market rule changes.



	June 30, 2019
Asset Balances
Materials and supplies inventory	$	30
Fuel inventory	11
Completed plant, net	896
Construction work in progress	4
Liability Balances
Asset retirement obligation	(1		)

9. Fair Value of Financial Assets and Liabilities (All Registrants)

Exelon measures and classifies fair value measurements in accordance with the hierarchy as defined by GAAP. The hierarchy prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:


•	Level 1 - quoted prices (unadjusted) in active markets for identical assets or liabilities that the Registrants have the ability to liquidate as of the reporting date.


•	Level 2 - inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data.


•	Level 3 - unobservable inputs, such as internally developed pricing models or third-party valuations for the asset or liability due to little or no market activity for the asset or liability.

Exelon’s valuation techniques used to measure the fair value of the assets and liabilities shown in the tables below are in accordance with the policies discussed in Note 11 — Fair Value of Financial Assets and Liabilities of the Exelon 2018 Form 10-K, unless otherwise noted below.

Fair Value of Financial Liabilities Recorded at Amortized Cost

The following tables present the carrying amounts and fair values of the Registrants’ short-term liabilities, long-term debt, SNF obligation and trust preferred securities (long-term debt to financing trusts or junior subordinated debentures) as of June 30, 2019 and December 31, 2018. The Registrants have no financial liabilities classified as Level 1.

The carrying amounts of the Registrants’ short-term liabilities as presented on their Consolidated Balance Sheets are representative of their fair value (Level 2) because of the short-term nature of these instruments.

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(Dollars in millions, except per share data, unless otherwise noted)



	June 30, 2019								December 31, 2018
	Carrying Amount		Fair Value						Carrying Amount		Fair Value
	Carrying Amount		Level 2		Level 3		Total		Carrying Amount		Level 2		Level 3		Total
Long-Term Debt, including amounts due within one year^(a)
Exelon	$	35,685	$	36,248	$	2,569	$	38,817	$	35,424	$	33,711	$	2,158	$	35,869
Generation	8,704		7,822		1,472		9,294		8,793		7,467		1,443		8,910
ComEd	8,195		9,222		—		9,222		8,101		8,390		—		8,390
PECO	3,085		3,415		50		3,465		3,084		3,157		50		3,207
BGE	2,877		3,197		—		3,197		2,876		2,950		—		2,950
PHI	6,509		5,823		1,047		6,870		6,259		5,436		665		6,101
Pepco	2,860		3,134		377		3,511		2,719		2,901		196		3,097
DPL	1,495		1,396		218		1,614		1,494		1,303		193		1,496
ACE	1,329		1,025		451		1,476		1,188		987		275		1,262
Long-Term Debt to Financing Trusts^(a)
Exelon	$	390	$	—	$	415	$	415	$	390	$	—	$	400	$	400
ComEd	205		—		209		209		205		—		209		209
PECO	184		—		206		206		184		—		191		191
SNF Obligation
Exelon	$	1,186	$	1,025	$	—	$	1,025	$	1,171	$	949	$	—	$	949
Generation	1,186		1,025		—		1,025		1,171		949		—		949

____


(a)	Includes unamortized debt issuance costs which are not fair valued.

Recurring Fair Value Measurements

The following tables present assets and liabilities measured and recorded at fair value in the Registrants' Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of June 30, 2019 and December 31, 2018:



	Exelon										Generation
As of June 30, 2019	Level 1		Level 2		Level 3		Not subject to leveling		Total		Level 1		Level 2		Level 3		Not subject to leveling		Total
Assets
Cash equivalents^(a)	$	648	$	—	$	—	$	—	$	648	$	323	$	—	$	—	$	—	$	323
NDT fund investments
Cash equivalents^(b)	1,241		90		—		—		1,331		1,241		90		—		—		1,331
Equities	3,123		1,638		—		1,328		6,089		3,123		1,638		—		1,328		6,089
Fixed income
Corporate debt	—		1,453		247		—		1,700		—		1,453		247		—		1,700
U.S. Treasury and agencies	1,589		134		—		—		1,723		1,589		134		—		—		1,723
Foreign governments	—		58		—		—		58		—		58		—		—		58
State and municipal debt	—		81		—		—		81		—		81		—		—		81
Other^(c)	—		19		—		955		974		—		19		—		955		974
Fixed income subtotal	1,589		1,745		247		955		4,536		1,589		1,745		247		955		4,536

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(Dollars in millions, except per share data, unless otherwise noted)



	Exelon														Generation
As of June 30, 2019	Level 1			Level 2			Level 3			Not subject to leveling		Total			Level 1			Level 2			Level 3			Not subject to leveling		Total
Middle market lending	—			—			292			455		747			—			—			292			455		747
Private equity	—			—			—			379		379			—			—			—			379		379
Real estate	—			—			—			557		557			—			—			—			557		557
NDT fund investments subtotal^(d)	5,953			3,473			539			3,674		13,639			5,953			3,473			539			3,674		13,639
Rabbi trust investments
Cash equivalents	49			—			—			—		49			4			—			—			—		4
Mutual funds	73			—			—			—		73			23			—			—			—		23
Fixed income	—			13			—			—		13			—			—			—			—		—
Life insurance contracts	—			72			40			—		112			—			23			—			—		23
Rabbi trust investments subtotal	122			85			40			—		247			27			23			—			—		50
Commodity derivative assets
Economic hedges	505			2,148			1,875			—		4,528			505			2,148			1,875			—		4,528
Proprietary trading	—			44			139			—		183			—			44			139			—		183
Effect of netting and allocation of collateral^(e)(f)	(646		)	(2,042		)	(965		)	—		(3,653		)	(646		)	(2,042		)	(965		)	—		(3,653		)
Commodity derivative assets subtotal	(141		)	150			1,049			—		1,058			(141		)	150			1,049			—		1,058
Total assets	6,582			3,708			1,628			3,674		15,592			6,162			3,646			1,588			3,674		15,070
Liabilities
Commodity derivative liabilities
Economic hedges	(743		)	(2,539		)	(1,606		)	—		(4,888		)	(743		)	(2,539		)	(1,333		)	—		(4,615		)
Proprietary trading	—			(44		)	(71		)	—		(115		)	—			(44		)	(71		)	—		(115		)
Effect of netting and allocation of collateral^(e)(f)	743			2,438			1,228			—		4,409			743			2,438			1,228			—		4,409
Commodity derivative liabilities subtotal	—			(145		)	(449		)	—		(594		)	—			(145		)	(176		)	—		(321		)
Deferred compensation obligation	—			(137		)	—			—		(137		)	—			(36		)	—			—		(36		)
Total liabilities	—			(282		)	(449		)	—		(731		)	—			(181		)	(176		)	—		(357		)
Total net assets	$	6,582		$	3,426		$	1,179		$	3,674	$	14,861		$	6,162		$	3,465		$	1,412		$	3,674	$	14,713

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(Dollars in millions, except per share data, unless otherwise noted)



	Exelon														Generation
As of December 31, 2018	Level 1			Level 2			Level 3			Not subject to leveling		Total			Level 1			Level 2			Level 3			Not subject to leveling		Total
Assets
Cash equivalents^(a)	$	1,243		$	—		$	—		$	—	$	1,243		$	581		$	—		$	—		$	—	$	581
NDT fund investments
Cash equivalents^(b)	252			86			—			—		338			252			86			—			—		338
Equities	2,918			1,591			—			1,381		5,890			2,918			1,591			—			1,381		5,890
Fixed income
Corporate debt	—			1,593			230			—		1,823			—			1,593			230			—		1,823
U.S. Treasury and agencies	2,081			99			—			—		2,180			2,081			99			—			—		2,180
Foreign governments	—			50			—			—		50			—			50			—			—		50
State and municipal debt	—			149			—			—		149			—			149			—			—		149
Other^(c)	—			30			—			846		876			—			30			—			846		876
Fixed income subtotal	2,081			1,921			230			846		5,078			2,081			1,921			230			846		5,078
Middle market lending	—			—			313			367		680			—			—			313			367		680
Private equity	—			—			—			329		329			—			—			—			329		329
Real estate	—			—			—			510		510			—			—			—			510		510
NDT fund investments subtotal^(d)	5,251			3,598			543			3,433		12,825			5,251			3,598			543			3,433		12,825
Rabbi trust investments
Cash equivalents	48			—			—			—		48			5			—			—			—		5
Mutual funds	72			—			—			—		72			24			—			—			—		24
Fixed income	—			15			—			—		15			—			—			—			—		—
Life insurance contracts	—			70			38			—		108			—			22			—			—		22
Rabbi trust investments subtotal	120			85			38			—		243			29			22			—			—		51
Commodity derivative assets
Economic hedges	541			2,760			1,470			—		4,771			541			2,760			1,470			—		4,771
Proprietary trading	—			69			77			—		146			—			69			77			—		146
Effect of netting and allocation of collateral^(e)(f)	(582		)	(2,357		)	(732		)	—		(3,671		)	(582		)	(2,357		)	(732		)	—		(3,671		)
Commodity derivative assets subtotal	(41		)	472			815			—		1,246			(41		)	472			815			—		1,246
Total assets	6,573			4,155			1,396			3,433		15,557			5,820			4,092			1,358			3,433		14,703

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(Dollars in millions, except per share data, unless otherwise noted)



	Exelon														Generation
As of December 31, 2018	Level 1			Level 2			Level 3			Not subject to leveling		Total			Level 1			Level 2			Level 3			Not subject to leveling		Total
Liabilities
Commodity derivative liabilities
Economic hedges	(642		)	(2,963		)	(1,276		)	—		(4,881		)	(642		)	(2,963		)	(1,027		)	—		(4,632		)
Proprietary trading	—			(73		)	(21		)	—		(94		)	—			(73		)	(21		)	—		(94		)
Effect of netting and allocation of collateral^(e)(f)	639			2,581			808			—		4,028			639			2,581			808			—		4,028
Commodity derivative liabilities subtotal	(3		)	(455		)	(489		)	—		(947		)	(3		)	(455		)	(240		)	—		(698		)
Deferred compensation obligation	—			(137		)	—			—		(137		)	—			(35		)	—			—		(35		)
Total liabilities	(3		)	(592		)	(489		)	—		(1,084		)	(3		)	(490		)	(240		)	—		(733		)
Total net assets	$	6,570		$	3,563		$	907		$	3,433	$	14,473		$	5,817		$	3,602		$	1,118		$	3,433	$	13,970

_________

(a)

Exelon excludes cash of $447 million and $458 million at June 30, 2019 and December 31, 2018, respectively, and restricted cash of $83 million and $80 million at June 30, 2019 and December 31, 2018, respectively, and includes long-term restricted cash of $191 million and $185 million at June 30, 2019 and December 31, 2018, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. Generation excludes cash of $329 million and $283 million at June 30, 2019 and December 31, 2018, respectively, and restricted cash of $45 million and $39 million at June 30, 2019 and December 31, 2018, respectively.


(b)	Includes $75 million and $50 million of cash received from outstanding repurchase agreements at June 30, 2019 and December 31, 2018, respectively, and is offset by an obligation to repay upon settlement of the agreement as discussed in (d) below.

(c)

Includes a derivative liability of $2 million and a derivative asset of $44 million, which have total notional amounts of $827 million and $1,432 million at June 30, 2019 and December 31, 2018, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do not represent the amount of Exelon and Generation's exposure to credit or market loss.

(d)

Excludes net liabilities of $141 million and $130 million at June 30, 2019 and December 31, 2018, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, repurchase agreement obligations, and payables related to pending securities purchases. The repurchase agreements are generally short-term in nature with durations generally of 30 days or less.

(e)

Collateral posted/(received) from counterparties totaled $97 million, $396 million and $263 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of June 30, 2019. Collateral posted/(received) from counterparties, net of collateral paid to counterparties, totaled $57 million, $224 million and $76 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2018.


(f)	Of the collateral posted/(received), $358 million and $(94) million represents variation margin on the exchanges as of June 30, 2019 and December 31, 2018, respectively.

As of June 30, 2019, Exelon and Generation have outstanding commitments to invest in fixed income, middle market lending, private equity and real estate investments of approximately $121 million, $84 million, $396 million, and $252 million, respectively. These commitments will be funded by Generation’s existing NDT funds.

Exelon and Generation hold investments without readily determinable fair values with carrying amounts of $75 million as of June 30, 2019. Changes were immaterial in fair value, cumulative adjustments and impairments for the three and six months ended June 30, 2019.

Valuation Techniques Used to Determine Net Asset Value

Certain NDT Fund Investments are not classified within the fair value hierarchy and are included under the heading “Not subject to leveling” in the table above. These investments are measured at fair value using NAV per share as a practical expedient and include commingled funds, mutual funds which are not publicly quoted, managed middle market funds, private equity and real estate funds.

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(Dollars in millions, except per share data, unless otherwise noted)

For commingled funds and mutual funds, which are not publicly quoted, the fair value is primarily derived from the quoted prices in active markets on the underlying securities and can typically be redeemed monthly with 30 or less days of notice and without further restrictions. For managed middle market funds, the fair value is determined using a combination of valuation models including cost models, market models, and income models and typically cannot be redeemed until maturity of the term loan. Private equity and real estate investments include those in limited partnerships that invest in operating companies and real estate holding companies that are not publicly traded on a stock exchange, such as, leveraged buyouts, growth capital, venture capital, distressed investments, investments in natural resources, and direct investments in pools of real estate properties. These investments typically cannot be redeemed and are generally liquidated over a period of 8 to 10 years from the initial investment date, which is based on Exelon’s understanding of the investment funds. Private equity and real estate valuations are reported by the fund manager and are based on the valuation of the underlying investments, which include inputs such as cost, operating results, discounted future cash flows, market based comparable data, and independent appraisals from sources with professional qualifications. These valuation inputs are unobservable.

ComEd, PECO and BGE



	ComEd											PECO										BGE
As of June 30, 2019	Level 1		Level 2			Level 3			Total			Level 1		Level 2			Level 3		Total			Level 1		Level 2			Level 3		Total
Assets
Cash equivalents^(a)	$	222	$	—		$	—		$	222		$	9	$	—		$	—	$	9		$	1	$	—		$	—	$	1
Rabbi trust investments
Mutual funds	—		—			—			—			7		—			—		7			7		—			—		7
Life insurance contracts	—		—			—			—			—		10			—		10			—		—			—		—
Rabbi trust investments subtotal	—		—			—			—			7		10			—		17			7		—			—		7
Total assets	222		—			—			222			16		10			—		26			8		—			—		8
Liabilities
Deferred compensation obligation	—		(7		)	—			(7		)	—		(8		)	—		(8		)	—		(5		)	—		(5		)
Mark-to-market derivative liabilities^(b)	—		—			(273		)	(273		)	—		—			—		—			—		—			—		—
Total liabilities	—		(7		)	(273		)	(280		)	—		(8		)	—		(8		)	—		(5		)	—		(5		)
Total net assets (liabilities)	$	222	$	(7	)	$	(273	)	$	(58	)	$	16	$	2		$	—	$	18		$	8	$	(5	)	$	—	$	3



	ComEd											PECO										BGE
As of December 31, 2018	Level 1		Level 2			Level 3			Total			Level 1		Level 2			Level 3		Total			Level 1		Level 2			Level 3		Total
Assets
Cash equivalents^(a)	$	209	$	—		$	—		$	209		$	111	$	—		$	—	$	111		$	4	$	—		$	—	$	4
Rabbi trust investments
Mutual funds	—		—			—			—			7		—			—		7			6		—			—		6
Life insurance contracts	—		—			—			—			—		10			—		10			—		—			—		—
Rabbi trust investments subtotal	—		—			—			—			7		10			—		17			6		—			—		6
Total assets	209		—			—			209			118		10			—		128			10		—			—		10
Liabilities
Deferred compensation obligation	—		(6		)	—			(6		)	—		(10		)	—		(10		)	—		(5		)	—		(5		)
Mark-to-market derivative liabilities^(b)	—		—			(249		)	(249		)	—		—			—		—			—		—			—		—
Total liabilities	—		(6		)	(249		)	(255		)	—		(10		)	—		(10		)	—		(5		)	—		(5		)
Total net assets (liabilities)	$	209	$	(6	)	$	(249	)	$	(46	)	$	118	$	—		$	—	$	118		$	10	$	(5	)	$	—	$	5

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

_________

(a)

ComEd excludes cash of $65 million and $93 million at June 30, 2019 and December 31, 2018, respectively, and restricted cash of $29 million and $28 million at June 30, 2019 and December 31, 2018, respectively, and includes long-term restricted cash of $174 million and $166 million at June 30, 2019 and December 31, 2018, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. PECO excludes cash of $17 million and $24 million at June 30, 2019 and December 31, 2018, respectively. BGE excludes cash of $7 million at both June 30, 2019 and December 31, 2018, and restricted cash of $1 million and $2 million at June 30, 2019 and December 31, 2018, respectively.


(b)	The Level 3 balance consists of the current and noncurrent liability of $29 million and $244 million, respectively, at June 30, 2019, and $26 million and $223 million, respectively, at December 31, 2018, related to floating-to-fixed energy swap contracts with unaffiliated suppliers.

PHI, Pepco, DPL and ACE



	As of June 30, 2019										As of December 31, 2018
PHI	Level 1		Level 2			Level 3		Total			Level 1		Level 2			Level 3		Total
Assets
Cash equivalents^(a)	$	87	$	—		$	—	$	87		$	147	$	—		$	—	$	147
Rabbi trust investments
Cash equivalents	44		—			—		44			42		—			—		42
Mutual funds	13		—			—		13			13		—			—		13
Fixed income	—		13			—		13			—		15			—		15
Life insurance contracts	—		23			40		63			—		22			38		60
Rabbi trust investments subtotal	57		36			40		133			55		37			38		130
Total assets	144		36			40		220			202		37			38		277
Liabilities
Deferred compensation obligation	—		(19		)	—		(19		)	—		(21		)	—		(21		)
Total liabilities	—		(19		)	—		(19		)	—		(21		)	—		(21		)
Total net assets	$	144	$	17		$	40	$	201		$	202	$	16		$	38	$	256



	Pepco										DPL								ACE
As of June 30, 2019	Level 1		Level 2			Level 3		Total			Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Cash equivalents^(a)	$	40	$	—		$	—	$	40		$	1	$	—	$	—	$	1	$	19	$	—	$	—	$	19
Rabbi trust investments
Cash equivalents	43		—			—		43			—		—		—		—		—		—		—		—
Fixed income	—		3			—		3			—		—		—		—		—		—		—		—
Life insurance contracts	—		23			39		62			—		—		—		—		—		—		—		—
Rabbi trust investments subtotal	43		26			39		108			—		—		—		—		—		—		—		—
Total assets	83		26			39		148			1		—		—		1		19		—		—		19
Liabilities
Deferred compensation obligation	—		(2		)	—		(2		)	—		—		—		—		—		—		—		—
Total liabilities	—		(2		)	—		(2		)	—		—		—		—		—		—		—		—
Total net assets	$	83	$	24		$	39	$	146		$	1	$	—	$	—	$	1	$	19	$	—	$	—	$	19

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)



	Pepco										DPL										ACE
As of December 31, 2018	Level 1		Level 2			Level 3		Total			Level 1		Level 2			Level 3		Total			Level 1		Level 2		Level 3		Total
Assets
Cash equivalents^(a)	$	38	$	—		$	—	$	38		$	16	$	—		$	—	$	16		$	23	$	—	$	—	$	23
Rabbi trust investments
Cash equivalents	41		—			—		41			—		—			—		—			—		—		—		—
Fixed income	—		5			—		5			—		—			—		—			—		—		—		—
Life insurance contracts	—		22			37		59			—		—			—		—			—		—		—		—
Rabbi trust investments subtotal	41		27			37		105			—		—			—		—			—		—		—		—
Total assets	79		27			37		143			16		—			—		16			23		—		—		23
Liabilities
Deferred compensation obligation	—		(3		)	—		(3		)	—		(1		)	—		(1		)	—		—		—		—
Total liabilities	—		(3		)	—		(3		)	—		(1		)	—		(1		)	—		—		—		—
Total net assets (liabilities)	$	79	$	24		$	37	$	140		$	16	$	(1	)	$	—	$	15		$	23	$	—	$	—	$	23

_________

(a)

PHI excludes cash of $21 million and $39 million at June 30, 2019 and December 31, 2018, respectively, and includes long-term restricted cash of $17 million and $19 million at June 30, 2019 and December 31, 2018, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. Pepco excludes cash of $12 million and $15 million at June 30, 2019 and December 31, 2018, respectively. DPL excludes cash of $3 million and $8 million at June 30, 2019 and December 31, 2018, respectively. ACE excludes cash of $4 million and $7 million at June 30, 2019 and December 31, 2018, respectively, and includes long-term restricted cash of $17 million and $19 million at June 30, 2019 and December 31, 2018, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets.

The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the three and six months ended June 30, 2019 and 2018:



	Exelon			Generation										ComEd				PHI and Pepco
Three Months Ended June 30, 2019	Total			NDT Fund Investments			Mark-to-Market Derivatives				Total Generation			Mark-to-Market Derivatives				Life Insurance Contracts		Eliminated in Consolidation
Balance as of March 31, 2019	$	838		$	540		$	499			$	1,039		$	(240	)		$	39	$	—
Total realized / unrealized gains (losses)
Included in net income	275			2			272			^(a)	274			—				1		—
Included in noncurrent payables to affiliates	—			10			—				10			—				—		(10		)
Included in regulatory assets/liabilities	(23		)	—			—				—			(33		)	^(b)	—		10
Change in collateral	106			—			106				106			—				—		—
Purchases, sales, issuances and settlements
Purchases	51			40			11				51			—				—		—
Sales	(1		)	—			(1		)		(1		)	—				—		—
Settlements	(53		)	(53		)	—				(53		)	—				—		—
Transfers into Level 3	3			—			3			^(c)	3			—				—		—
Transfers out of Level 3	(17		)	—			(17		)	^(c)	(17		)	—				—		—
Balance at June 30, 2019	$	1,179		$	539		$	873			$	1,412		$	(273	)		$	40	$	—
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of June 30, 2019	$	339		$	1		$	337			$	338		$	—			$	1	$	—

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)



	Exelon			Generation										ComEd				PHI and Pepco
Six Months Ended June 30, 2019	Total			NDT Fund Investments			Mark-to-Market Derivatives				Total Generation			Mark-to-Market Derivatives				Life Insurance Contracts		Eliminated in Consolidation
Balance as of December 31, 2018	$	907		$	543		$	575			$	1,118		$	(249	)		$	38	$	—
Total realized / unrealized gains (losses)
Included in net income	46			3			41			^(a)	44			—				2		—
Included in noncurrent payables to affiliates	—			21			—				21			—				—		(21		)
Included in regulatory assets	(3		)	—			—				—			(24		)	^(b)	—		21
Change in collateral	187			—			187				187			—				—		—
Purchases, sales, issuances and settlements
Purchases	110			42			68				110			—				—		—
Sales	(1		)	—			(1		)		(1		)	—				—		—
Settlements	(70		)	(70		)	—				(70		)	—				—		—
Transfers into Level 3	3			—			3			^(c)	3			—				—		—
Transfers out of Level 3	—			—			—			^(c)	—			—				—		—
Balance as of June 30, 2019	$	1,179		$	539		$	873			$	1,412		$	(273	)		$	40	$	—
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of June 30, 2019	$	191		$	3		$	186			$	189		$	—			$	2	$	—

__________


(a)	Includes a reduction for the reclassification of $65 million and $145 million of realized gains due to the settlement of derivative contracts for the three and six months ended June 30, 2019, respectively.

(b)

Includes $41 million of decreases in fair value and an increase for realized losses due to settlements of $8 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended June 30, 2019. Includes $37 million of increases in fair value and an increase for realized losses due to settlements of $13 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the six months ended June 30, 2019.


(c)	Transfers into and out of Level 3 generally occur when the contract tenor becomes less and more observable respectively, primarily due to changes in market liquidity or assumptions for certain commodity contracts.

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)



	Exelon			Generation										ComEd				PHI and Pepco
Three Months Ended June 30, 2018	Total			NDT Fund Investments			Mark-to-Market Derivatives				Total Generation			Mark-to-Market Derivatives				Life Insurance Contracts		Eliminated in Consolidation
Balance as of March 31, 2018	$	1,283		$	609		$	918			$	1,527		$	(267	)		$	23	$	—
Total realized / unrealized gains (losses)
Included in net income	(112		)	—			(113		)	^(a)	(113		)	—				1		—
Included in noncurrent payables to affiliates	—			(3		)	—				(3		)	—				—		3
Included in regulatory assets	12			—			—				—			15			^(b)	—		(3		)
Change in collateral	(49		)	—			(49		)		(49		)	—				—		—
Purchases, sales, issuances and settlements
Purchases	30			17			13				30			—				—		—
Sales	(1		)	—			(1		)		(1		)	—				—		—
Settlements	(26		)	(38		)	—				(38		)	—				12		—
Transfers into Level 3	(15		)	—			(15		)	^(c)	(15		)	—				—		—
Transfers out of Level 3	(16		)	—			(16		)	^(c)	(16		)	—				—		—
Balance as of June 30, 2018	$	1,106		$	585		$	737			$	1,322		$	(252	)		$	36	$	—
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of June 30, 2018	$	3		$	(4	)	$	7			$	3		$	—			$	—	$	—



	Exelon			Generation										ComEd				PHI and Pepco
Six Months Ended June 30, 2018	Total			NDT Fund Investments			Mark-to-Market Derivatives				Total Generation			Mark-to-Market Derivatives				Life Insurance Contracts		Eliminated in Consolidation
Balance as of December 31, 2017	$	966		$	648		$	552			$	1,200		$	(256	)		$	22	$	—
Total realized / unrealized gains (losses)
Included in net income	74			1			71			^(a)	72			—				2		—
Included in noncurrent payables to affiliates	—			3			—				3			—				—		(3		)
Included in regulatory assets	7			—			—				—			4			^(b)	—		3
Change in collateral	57			—			57				57			—				—		—
Purchases, sales, issuances and settlements
Purchases	119			19			100				119			—				—		—
Sales	(4		)	—			(4		)		(4		)	—				—		—
Settlements	(74		)	(86		)	—				(86		)	—				12		—
Transfers into Level 3	(23		)	—			(23		)	^(c)	(23		)	—				—		—
Transfers out of Level 3	(16		)	—			(16		)	^(c)	(16		)	—				—		—
Balance as of June 30, 2018	$	1,106		$	585		$	737			$	1,322		$	(252	)		$	36	$	—
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of June 30, 2018	$	259		$	(4	)	$	263			$	259		$	—			$	—	$	—

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

__________


(a)	Includes a reduction for the reclassification of $120 million and $192 million of realized gains due to the settlement of derivative contracts for the three and six months ended June 30, 2018, respectively.

(b)

Includes $11 million of decreases in fair value and an increase for realized losses due to settlements of $4 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended June 30, 2018. Includes $6 million of increases in fair value and an increase for realized losses due to settlements of $10 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the six months ended June 30, 2018.


(c)	Transfers into and out of Level 3 generally occur when the contract tenor becomes less and more observable respectively, primarily due to changes in market liquidity or assumptions for certain commodity contracts.

The following tables present the income statement classification of the total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis during the three and six months ended June 30, 2019 and 2018:



	Exelon									Generation							PHI and Pepco
	Operating Revenues		Purchased Power and Fuel			Operating and Maintenance		Other, net		Operating Revenues		Purchased Power and Fuel			Other, net		Operating and Maintenance
Total realized gains (losses) for the three months ended June 30, 2019	$	275	$	(3	)	$	1	$	2	$	275	$	(3	)	$	2	$	1
Total realized (losses) gains for the six months ended June 30, 2019	147		(106		)	2		3		147		(106		)	3		2
Total unrealized gains (losses) for the three months ended June 30, 2019	360		(23		)	1		1		360		(23		)	1		1
Total unrealized gains (losses) for the six months ended June 30, 2019	269		(83		)	2		3		269		(83		)	3		2



	Exelon											Generation									PHI and Pepco
	Operating Revenues			Purchased Power and Fuel			Operating and Maintenance		Other, net			Operating Revenues			Purchased Power and Fuel			Other, net			Operating and Maintenance
Total realized (losses) gains for the three months ended June 30, 2018	$	(191	)	$	78		$	1	$	—		$	(191	)	$	78		$	—		$	1
Total realized gains (losses) for the six months ended June 30, 2018	144			(73		)	2		2			144			(73		)	2			2
Total unrealized (losses) gains for the three months ended June 30, 2018	(71		)	78			—		(4		)	(71		)	78			(4		)	—
Total unrealized gains (losses) for the six months ended June 30, 2018	238			25			—		(3		)	238			25			(3		)	—

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

The table below discloses the significant inputs to the forward curve used to value these positions.



Type of trade	Fair Value at June 30, 2019			Fair Value at December 31, 2018			Valuation Technique	Unobservable Input	2019 Range			2018 Range
Mark-to-market derivatives — Economic Hedges (Exelon and Generation)^(a)(b)	$	542		$	443		Discounted Cash Flow	Forward power price	$10	-	$118	$12	-	$174
								Forward gas price	$1.54	-	$11.26	$0.78	-	$12.38
							Option Model	Volatility percentage	8%	-	384%	10%	-	277%

Mark-to-market derivatives — Proprietary trading (Exelon and Generation)^(a)(b)	$	68		$	56		Discounted Cash Flow	Forward power price	$10	-	$118	$14	-	$174

Mark-to-market derivatives (Exelon and ComEd)	$	(273	)	$	(249	)	Discounted Cash Flow	Forward heat rate^(c)	9x	-	10x	10x	-	11x
								Marketability reserve	4%	-	7%	4%	-	8%
								Renewable factor	88%	-	119%	86%	-	120%

_________


(a)	The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions.


(b)	The fair values do not include cash collateral posted on level three positions of $263 million and $76 million as of June 30, 2019 and December 31, 2018, respectively.


(c)	Quoted forward natural gas rates are utilized to project the forward power curve for the delivery of energy at specified future dates. The natural gas curve is extrapolated beyond its observable period to the end of the contract’s delivery.

The inputs listed above, which are as of the balance sheet date, would have a direct impact on the fair values of the above instruments if they were adjusted. The significant unobservable inputs used in the fair value measurement of Generation’s commodity derivatives are forward commodity prices and for options is price volatility. Increases (decreases) in the forward commodity price in isolation would result in significantly higher (lower) fair values for long positions (contracts that give Generation the obligation or option to purchase a commodity), with offsetting impacts to short positions (contracts that give Generation the obligation or right to sell a commodity). Increases (decreases) in volatility would increase (decrease) the value for the holder of the option (writer of the option). Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of volatility of prices. An increase to the reserves listed above would decrease the fair value of the positions. An increase to the heat rate or renewable factors would increase the fair value accordingly. Generally, interrelationships exist between market prices of natural gas and power. As such, an increase in natural gas pricing would potentially have a similar impact on forward power markets.

10. Derivative Financial Instruments (All Registrants)

The Registrants use derivative instruments to manage commodity price risk, interest rate risk and foreign exchange risk related to ongoing business operations.

Authoritative guidance requires that derivative instruments be recognized as either assets or liabilities at fair value, with changes in fair value of the derivative recognized in earnings immediately. Other accounting treatments are available through special election and designation, provided they meet specific, restrictive criteria both at the time of designation and on an ongoing basis. These alternative permissible accounting treatments include NPNS, cash flow hedges and fair value hedges. All derivative economic hedges related to commodities, referred to as economic hedges, are recorded at fair value through earnings at Generation and offset by a corresponding regulatory asset or liability at ComEd. For all NPNS derivative instruments, accounts receivable or accounts payable are recorded when derivative settles and revenue or expense is recognized in earnings as the underlying physical commodity is sold or consumed.

Table of Contents

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Authoritative guidance about offsetting assets and liabilities requires the fair value of derivative instruments to be shown in the Combined Notes to Consolidated Financial Statements on a gross basis, even when the derivative instruments are subject to legally enforceable master netting agreements and qualify for net presentation in the Consolidated Balance Sheets. A master netting agreement is an agreement between two counterparties that may have derivative and non-derivative contracts with each other providing for the net settlement of all referencing contracts via one payment stream, which takes place as the contracts deliver, when collateral is requested or in the event of default. In the tables below that present fair value balances, Generation’s energy-related economic hedges and proprietary trading derivatives are shown gross. The impact of the netting of fair value balances with the same counterparty that are subject to legally enforceable master netting agreements, as well as netting of cash collateral, including margin on exchange positions, is aggregated in the collateral and netting columns.

Generation’s and ComEd’s use of cash collateral is generally unrestricted unless Generation or ComEd are downgraded below investment grade. Cash collateral held by PECO, BGE, Pepco, DPL and ACE must be deposited in an unaffiliated major U.S. commercial bank or foreign bank with a U.S. branch office that meet certain qualifications.

Commodity Price Risk (All Registrants)

Each of the Registrants employ established policies and procedures to manage their risks associated with market fluctuations in commodity prices by entering into physical and financial derivative contracts, including swaps, futures, forwards, options and short-term and long-term commitments to purchase and sell energy and commodity products. The Registrants believe these instruments, which are either determined to be non-derivative or classified as economic hedges, mitigate exposure to fluctuations in commodity prices.

Generation. To the extent the amount of energy Generation produces differs from the amount of energy it has contracted to sell, Exelon and Generation are exposed to market fluctuations in the prices of electricity, fossil fuels and other commodities. Within Exelon, Generation has the most exposure to commodity price risk. As such, Generation uses a variety of derivative and non-derivative instruments to manage the commodity price risk of its electric generation facilities, including power and gas sales, fuel and power purchases, natural gas transportation and pipeline capacity agreements and other energy-related products marketed and purchased. To manage these risks, Generation may enter into fixed-price derivative or non-derivative contracts to hedge the variability in future cash flows from expected sales of power and gas and purchases of power and fuel. The objectives for executing such hedges include fixing the price for a portion of anticipated future electricity sales at a level that provides an acceptable return. Generation is also exposed to differences between the locational settlement prices of certain economic hedges and the hedged generating units. This price difference is actively managed through other instruments which include derivative congestion products, whose changes in fair value are recognized in earnings each period, and auction revenue rights, which are accounted for on an accrual basis.

Additionally, Generation is exposed to certain market risks through its proprietary trading activities. The proprietary trading activities are a complement to Generation’s energy marketing portfolio but represent a small portion of Generation’s overall energy marketing activities and are subject to limits established by Exelon’s RMC.

Utility Registrants. The Utility Registrants procure electric and natural gas supply through a competitive procurement process approved by each of the respective state utility commissions. The Utility Registrants’ hedging programs are intended to reduce exposure to energy and natural gas price volatility and have no direct earnings impact as the costs are fully recovered from customers through regulatory-approved recovery mechanisms. The following table provides a summary of the Utility Registrants’ primary derivative hedging instruments, listed by commodity and accounting treatment.

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(Dollars in millions, except per share data, unless otherwise noted)



Registrant	Commodity	Accounting Treatment	Hedging instrument
ComEd	Electricity	NPNS	Fixed price contracts based on all requirements in the IPA procurement plans.
ComEd	Electricity	Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability^(a)	20-year floating-to-fixed energy swap contracts beginning June 2012 based on the renewable energy resource procurement requirements in the Illinois Settlement Legislation of approximately 1.3 million MWhs per year.
PECO^(b)	Gas	NPNS	Fixed price contracts to cover about 20% of planned natural gas purchases in support of projected firm sales.
BGE	Electricity	NPNS	Fixed price contracts for all SOS requirements through full requirements contracts.
BGE	Gas	NPNS	Fixed price contracts for between 10-20% of forecasted system supply requirements for flowing (i.e., non-storage) gas for the November through March period.
Pepco	Electricity	NPNS	Fixed price contracts for all SOS requirements through full requirements contracts.
DPL	Electricity	NPNS	Fixed price contracts for all SOS requirements through full requirements contracts.
	Gas	NPNS	Fixed price contracts through full requirements contracts.
	Gas	Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability ^(c)	Exchange traded future contracts for 50% of estimated monthly purchase requirements each month, including purchases for storage injections.
ACE	Electricity	NPNS	Fixed price contracts for all BGS requirements through full requirements contracts.

__________


(a)	See Note 4 - Regulatory Matters for additional information.


(b)	As part of its hedging program, PECO enters into electric supply procurement contracts that do not meet the definition of a derivative instrument.


(c)	The fair value of the DPL economic hedge is not material as of June 30, 2019 and December 31, 2018 and is not presented in the fair value tables below.

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(Dollars in millions, except per share data, unless otherwise noted)

The following table provides a summary of the derivative fair value balances recorded by Generation, ComEd and Exelon as of June 30, 2019 and December 31, 2018:



June 30, 2019	Exelon			Generation														ComEd
Derivatives	Total Derivatives			Economic Hedges			Proprietary Trading			Collateral ^(a)(b)		Netting ^(a)			Subtotal			Economic Hedges
Mark-to-market derivative assets (current assets)	$	526		$	2,910		$	122		$	218	$	(2,724	)	$	526		$	—
Mark-to-market derivative assets (noncurrent assets)	532			1,618			61			122		(1,269		)	532			—
Total mark-to-market derivative assets	1,058			4,528			183			340		(3,993		)	1,058			—
Mark-to-market derivative liabilities (current liabilities)	(157		)	(3,039		)	(78		)	265		2,724			(128		)	(29		)
Mark-to-market derivative liabilities (noncurrent liabilities)	(437		)	(1,576		)	(37		)	151		1,269			(193		)	(244		)
Total mark-to-market derivative liabilities	(594		)	(4,615		)	(115		)	416		3,993			(321		)	(273		)
Total mark-to-market derivative net assets (liabilities)	$	464		$	(87	)	$	68		$	756	$	—		$	737		$	(273	)



December 31, 2018	Exelon			Generation														ComEd
Description	Total Derivatives			Economic Hedges			Proprietary Trading			Collateral (a)(b)		Netting (a)			Subtotal			Economic Hedges
Mark-to-market derivative assets (current assets)	$	801		$	3,505		$	105		$	121	$	(2,930	)	$	801		$	—
Mark-to-market derivative assets (noncurrent assets)	445			1,266			41			51		(913		)	445			—
Total mark-to-market derivative assets	1,246			4,771			146			172		(3,843		)	1,246			—
Mark-to-market derivative liabilities (current liabilities)	(473		)	(3,429		)	(74		)	125		2,931			(447		)	(26		)
Mark-to-market derivative liabilities (noncurrent liabilities)	(474		)	(1,203		)	(20		)	60		912			(251		)	(223		)
Total mark-to-market derivative liabilities	(947		)	(4,632		)	(94		)	185		3,843			(698		)	(249		)
Total mark-to-market derivative net assets (liabilities)	$	299		$	139		$	52		$	357	$	—		$	548		$	(249	)

_________

(a)

Exelon and Generation net all available amounts allowed under the derivative authoritative guidance in the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, letters of credit and other forms of non-cash collateral. These amounts are immaterial and not reflected in the table above.


(b)	Of the collateral posted/(received), $358 million and $(94) million represents variation margin on the exchanges at June 30, 2019 and December 31, 2018 respectively.

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(Dollars in millions, except per share data, unless otherwise noted)

Economic Hedges (Commodity Price Risk)

Generation. For the three and six months ended June 30, 2019 and 2018, Exelon and Generation recognized the following net pre-tax commodity mark-to-market gains (losses) which are also located in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows.



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
Income Statement Location	Gain (Loss)						Gain (Loss)
Operating revenues	$	40		$	(7	)	$	(10	)	$	(107	)
Purchased power and fuel	(114		)	96			(84		)	(70		)
Total Exelon and Generation	$	(74	)	$	89		$	(94	)	$	(177	)

In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on Generation’s owned and contracted generation positions that have not been hedged. Generation hedges commodity price risk on a ratable basis over three-year periods. As of June 30, 2019, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York and ERCOT reportable segments is 92%-95%, 70%-73% and 40%-43% for 2019, 2020 and 2021, respectively.

Proprietary Trading (Commodity Price Risk)

Generation also executes commodity derivatives for proprietary trading purposes. Proprietary trading includes all contracts executed with the intent of benefiting from shifts or changes in market prices as opposed to those executed with the intent of hedging or managing risk. Gains and losses associated with proprietary trading are reported as Operating revenues in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income and are included in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows. For the three and six months ended June 30, 2019 and 2018, net pre-tax commodity mark-to-market gains (losses) for Exelon and Generation were not material. The Utility Registrants do not execute derivatives for proprietary trading purposes.

Interest Rate and Foreign Exchange Risk (Exelon and Generation)

Exelon and Generation utilize interest rate swaps, which are treated as economic hedges, to manage their interest rate exposure. On July 1, 2018, Exelon de-designated its fair value hedges related to interest rate risk and Generation de-designated its cash flow hedges related to interest rate risk. The notional amounts were $1,373 million and $1,420 million at June 30, 2019 and December 31, 2018, respectively, for Exelon and $573 million and $620 million at June 30, 2019 and December 31, 2018, respectively, for Generation.

Generation utilizes foreign currency derivatives to manage foreign exchange rate exposure associated with international commodity purchases in currencies other than U.S. dollars, which are treated as economic hedges. The notional amounts were $219 million and $268 million at June 30, 2019 and December 31, 2018, respectively.

The mark-to-market derivative assets and liabilities as of June 30, 2019 and December 31, 2018 and the mark-to-market gains and losses for the three and six months ended June 30, 2019 and 2018 were not material for Exelon and Generation.

Credit Risk (All Registrants)

The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties on executed derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date.

Generation. For commodity derivatives, Generation enters into enabling agreements that allow for payment netting with its counterparties, which reduces Generation’s exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. Typically, each enabling agreement is for a specific commodity and so, with respect to each individual counterparty, netting is limited to transactions involving that specific commodity product, except where master netting agreements exist with a

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(Dollars in millions, except per share data, unless otherwise noted)

counterparty that allow for cross product netting. In addition to payment netting language in the enabling agreement, Generation’s credit department establishes credit limits, margining thresholds and collateral requirements for each counterparty, which are defined in the derivative contracts. Counterparty credit limits are based on an internal credit review process that considers a variety of factors, including the results of a scoring model, leverage, liquidity, profitability, credit ratings by credit rating agencies, and risk management capabilities. To the extent that a counterparty’s margining thresholds are exceeded, the counterparty is required to post collateral with Generation as specified in each enabling agreement. Generation’s credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis.

The following tables provide information on Generation’s credit exposure for all derivative instruments, NPNS and applicable payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of June 30, 2019. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties. The figures in the tables below exclude credit risk exposure from individual retail counterparties, nuclear fuel procurement contracts and exposure through RTOs, ISOs, NYMEX, ICE, NASDAQ, NGX and Nodal commodity exchanges. Additionally, the figures in the tables below exclude exposures with affiliates, including net receivables with ComEd, PECO, BGE, Pepco, DPL and ACE of $70 million, $30 million, $32 million, $39 million, $15 million and $8 million as of June 30, 2019, respectively.



Rating as of June 30, 2019	Total Exposure Before Credit Collateral		Credit Collateral^(a)		Net Exposure		Number of Counterparties Greater than 10% of Net Exposure	Net Exposure of Counterparties Greater than 10% of Net Exposure
Investment grade	$	859	$	12	$	847	2	$	249
Non-investment grade	30		11		19
No external ratings
Internally rated — investment grade	204		1		203
Internally rated — non-investment grade	117		11		106
Total	$	1,210	$	35	$	1,175	2	$	249



Net Credit Exposure by Type of Counterparty	As of June 30, 2019
Financial institutions	$	3
Investor-owned utilities, marketers, power producers	810
Energy cooperatives and municipalities	302
Other	60
Total	$	1,175

_________


(a)	As of June 30, 2019, credit collateral held from counterparties where Generation had credit exposure included $25 million of cash and $9 million of letters of credit. The credit collateral does not include non-liquid collateral.

Utility Registrants. The Utility Registrants have contracts to procure electric and natural gas supply that provide suppliers with a certain amount of unsecured credit. If the exposure on the supply contract exceeds the amount of unsecured credit, the suppliers may be required to post collateral. The net credit exposure is mitigated primarily by the ability to recover procurement costs through customer rates. As of June 30, 2019, the Utility Registrants’ counterparty credit risk with suppliers was immaterial.

Credit-Risk-Related Contingent Features (All Registrants)

Generation. As part of the normal course of business, Generation routinely enters into physically or financially settled contracts for the purchase and sale of electric capacity, electricity, fuels, emissions allowances and other energy-related products. Certain of Generation’s derivative instruments contain provisions that require Generation to post collateral. Generation also enters into commodity transactions on exchanges where the exchanges act as the counterparty to each trade. Transactions on the exchanges must adhere to comprehensive collateral and

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(Dollars in millions, except per share data, unless otherwise noted)

margining requirements. This collateral may be posted in the form of cash or credit support with thresholds contingent upon Generation’s credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. These credit-risk-related contingent features stipulate that if Generation were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. This incremental collateral requirement allows for the offsetting of derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master netting agreements. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. In this case, Generation believes an amount of several months of future payments (i.e., capacity payments) rather than a calculation of fair value is the best estimate for the contingent collateral obligation, which has been factored into the disclosure below.

The aggregate fair value of all derivative instruments with credit-risk related contingent features in a liability position that are not fully collateralized (excluding transactions on the exchanges that are fully collateralized) is detailed in the table below:



Credit-Risk Related Contingent Features	June 30, 2019			December 31, 2018
Gross fair value of derivative contracts containing this feature^(a)	$	(1,119	)	$	(1,723	)
Offsetting fair value of in-the-money contracts under master netting arrangements^(b)	824			1,105
Net fair value of derivative contracts containing this feature^(c)	$	(295	)	$	(618	)

_________


(a)	Amount represents the gross fair value of out-of-the-money derivative contracts containing credit-risk related contingent features ignoring the effects of master netting agreements.


(b)	Amount represents the offsetting fair value of in-the-money derivative contracts under legally enforceable master netting agreements with the same counterparty, which reduces the amount of any liability for which a Registrant could potentially be required to post collateral.


(c)	Amount represents the net fair value of out-of-the-money derivative contracts containing credit-risk related contingent features after considering the mitigating effects of offsetting positions under master netting arrangements and reflects the actual net liability upon which any potential contingent collateral obligations would be based.

As of June 30, 2019 and December 31, 2018, Exelon and Generation posted or held the following amounts of cash collateral and letters of credit on derivative contracts with external counterparties, after giving consideration to offsetting derivative and non-derivative positions under master netting agreements.



	June 30, 2019		December 31, 2018
Cash collateral posted	$	781	$	418
Letters of credit posted	228		367
Cash collateral held	64		47
Letters of credit held	21		44
Additional collateral required in the event of a credit downgrade below investment grade	1,513		2,104

Generation entered into supply forward contracts with certain utilities, including PECO and BGE, with one-sided collateral postings only from Generation. If market prices fall below the benchmark price levels in these contracts, the utilities are not required to post collateral. However, when market prices rise above the benchmark price levels, counterparty suppliers, including Generation, are required to post collateral once certain unsecured credit limits are exceeded.

Utility Registrants

The Utility Registrants’ electric supply procurement contracts do not contain provisions that would require them to post collateral.

PECO’s, BGE’s, and DPL’s natural gas procurement contracts contain provisions that could require PECO, BGE, and DPL to post collateral in the form of cash or credit support, which vary by contract and counterparty, with

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(Dollars in millions, except per share data, unless otherwise noted)

thresholds contingent upon PECO’s, BGE, and DPL’s credit rating. As of June 30, 2019, PECO, BGE, and DPL were not required to post collateral for any of these agreements. If PECO, BGE or DPL lost their investment grade credit ratings as of June 30, 2019, they could have been required to post incremental collateral to its counterparties of $31 million, $31 million and $12 million, respectively.

11. Debt and Credit Agreements (All Registrants)

Short-Term Borrowings

Exelon Corporate, ComEd, BGE, Pepco, DPL and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper. Generation and PECO meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the Exelon intercompany money pool. PHI Corporate meets its short-term liquidity requirements primarily through the issuance of short-term notes and the Exelon intercompany money pool. The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit.

Commercial Paper

The following table reflects the Registrants' commercial paper programs as of June 30, 2019 and December 31, 2018. Generation and PECO had no commercial paper borrowings as of both June 30, 2019 and December 31, 2018.



	Outstanding Commercial Paper as of				Average Interest Rate on Commercial Paper Borrowings as of
Commercial Paper Issuer	June 30, 2019		December 31, 2018		June 30, 2019		December 31, 2018
Exelon	$	559	$	89	2.60	%	2.15	%
ComEd	303		—		2.59	%	2.14	%
BGE	229		35		2.58	%	2.18	%
PHI	27		54		2.61	%	2.15	%
PEPCO	—		40		2.62	%	2.24	%
DPL	—		—		2.55	%	2.07	%
ACE	27		14		2.61	%	2.21	%

See Note 13— Debt and Credit Agreements of the Exelon 2018 Form 10-K for additional information on the Registrants’ credit facilities.

Short-Term Loan Agreements

On March 23, 2017, Exelon Corporate entered into a term loan agreement for $500 million, which was renewed on March 22, 2018 with an expiration of March 21, 2019. The loan agreement was renewed on March 20, 2019 and will expire on March 19, 2020. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.95% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Exelon's Consolidated Balance Sheet within Short-Term borrowings.

Credit Agreements

On February 21, 2019, Generation entered into a credit agreement establishing a $100 million bilateral credit facility. The facility will mature in March 2021. This facility will solely be used by Generation to issue letters of credit.

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(Dollars in millions, except per share data, unless otherwise noted)

Long-Term Debt

Issuance of Long-Term Debt

During the six months ended June 30, 2019, the following long-term debt was issued:



Company	Type	Interest Rate		Maturity	Amount		Use of Proceeds
Generation	Energy Efficiency Project Financing	3.95	%	August 31, 2020	$	2	Funding to install energy conservation measures for the Fort Meade project.
Generation	Energy Efficiency Project Financing	3.46	%	May 1, 2020	$	39	Funding to install energy conservation measures for the Marine Corps. Logistics Project.
ComEd	First Mortgage Bonds, Series 126	4.00	%	March 1, 2049	$	400	Repay a portion of ComEd’s outstanding commercial paper obligations and fund other general corporate purposes.
Pepco	First Mortgage Bonds	3.45	%	June 13, 2029	$	150	Repay existing indebtedness and for general corporate purposes
Pepco	Unsecured Tax-Exempt Bonds	1.70	%	September 1, 2022	$	110	Repay existing indebtedness and for general corporate purposes
ACE	First Mortgage Bonds	3.50	%	May 21, 2029	$	100	Repay existing indebtedness and for general corporate purposes
ACE	First Mortgage Bonds	4.14	%	May 21, 2049	$	50	Repay existing indebtedness and for general corporate purposes

Debt Covenants

As of June 30, 2019, the Registrants are in compliance with debt covenants, except for Antelope Valley's nonrecourse debt event of default as discussed below.

Nonrecourse Debt

Exelon and Generation have issued nonrecourse debt financing. Borrowings under these agreements are secured by the assets and equity of each respective project. The lenders do not have recourse against Exelon or Generation in the event of a default.

Antelope Valley Solar Ranch One. In December 2011, the DOE Loan Programs Office issued a guarantee for up to $646 million for a nonrecourse loan from the Federal Financing Bank to support the financing of the construction of the Antelope Valley facility. The project became fully operational in 2014. The loan will mature on January 5, 2037. As of June 30, 2019, approximately $500 million was outstanding. In 2017, Generation’s interests in Antelope Valley were also contributed to and are pledged as collateral for the EGR IV financing structure referenced below.

Antelope Valley sells all of its output to PG&E through a PPA. On January 29, 2019, PG&E filed for protection under Chapter 11 of the U.S. Bankruptcy Code, which created an event of default for Antelope Valley’s nonrecourse debt that provides the lender with a right to accelerate amounts outstanding under the loan such that they would become immediately due and payable. As a result of the ongoing event of default and the absence of a waiver from the lender foregoing their acceleration rights, the debt was reclassified as current in Exelon’s and Generation’s Consolidated Balance Sheets in the first quarter of 2019 and continues to be classified as current as of June 30, 2019. Further, distributions from Antelope Valley to EGR IV are currently suspended.

ExGen Renewables IV. In November 2017, EGR IV, an indirect subsidiary of Exelon and Generation, entered into an $850 million nonrecourse senior secured term loan credit facility agreement. Generation’s interests in EGRP, Antelope Valley, SolGen, and Albany Green Energy were all contributed to and are pledged as collateral for this financing. The loan is scheduled to mature on November 28, 2024. As of June 30, 2019, $796 million was outstanding.

Although Antelope Valley’s debt is in default, it is nonrecourse to EGR IV. However, if in the future Antelope Valley were to file for bankruptcy protection as a result of events culminating from PG&E’s bankruptcy proceedings this

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(Dollars in millions, except per share data, unless otherwise noted)

would represent an event of default for EGR IV’s debt that would provide the lender with an opportunity to accelerate EGR IV’s debt.

See Note 13— Debt and Credit Agreements of the Exelon 2018 Form 10-K for additional information on nonrecourse debt.

12. Income Taxes (All Registrants)

Rate Reconciliation

The effective income tax rate from continuing operations varies from the U.S. Federal statutory rate principally due to the following:



	Three Months Ended June 30, 2019
	Exelon	Generation	ComEd	PECO	BGE	PHI	Pepco	DPL	ACE
U.S. Federal statutory rate	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	5.4	5.5	8.2	(1.2)	6.5	4.8	2.0	7.0	7.0
Qualified NDT fund income	5.1	16.2	—	—	—	—	—	—	—
Amortization of investment tax credit, including deferred taxes on basis difference	(0.7)	(1.9)	(0.2)	—	(0.1)	(0.2)	(0.1)	(0.2)	(0.3)
Plant basis differences	(1.7)	—	(0.6)	(5.9)	(1.5)	(1.7)	(2.1)	(0.3)	(2.2)
Production tax credits and other credits	(0.9)	(2.8)	—	—	(0.1)	—	—	—	—
Noncontrolling interests	0.1	0.4	—	—	—	—	—	—	—
Excess deferred tax amortization	(7.8)	—	(9.0)	(2.7)	(7.9)	(19.4)	(18.3)	(15.7)	(23.1)
Other	1.9	0.2	0.4	0.1	1.7	0.9	0.5	—	(2.4)
Effective income tax rate	22.4%	38.6%	19.8%	11.3%	19.6%	5.4%	3.0%	11.8%	—%

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(Dollars in millions, except per share data, unless otherwise noted)



	Three Months Ended June 30, 2018
	Exelon	Generation	ComEd	PECO	BGE	PHI	Pepco	DPL	ACE
U.S. Federal statutory rate	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	3.4	4.3	8.1	(3.4)	6.5	6.2	4.7	6.5	7.6
Qualified NDT fund income	0.2	0.5	—	—	—	—	—	—	—
Amortization of investment tax credit, including deferred taxes on basis difference	(0.9)	(2.4)	(0.2)	(0.1)	(0.2)	(0.2)	(0.1)	(0.3)	(0.3)
Plant basis differences	(3.0)	—	(0.1)	(17.2)	(0.7)	(1.2)	(2.0)	—	(0.2)
Production tax credits and other credits	(1.7)	(4.9)	(0.1)	—	—	—	—	—	—
Noncontrolling interests	(1.5)	(4.5)	—	—	—	—	—	—	—
Excess deferred tax amortization	(5.2)	—	(7.6)	(0.3)	(7.2)	(11.3)	(11.7)	(11.2)	(8.8)
Tax Cuts and Jobs Act of 2017	(1.3)	(1.7)	(0.7)	—	0.1	0.8	—	—	—
Other	(0.2)	(1.3)	0.4	(1.1)	0.8	(0.1)	(0.4)	0.1	0.7
Effective income tax rate	10.8%	11.0%	20.8%	(1.1)%	20.3%	15.2%	11.5%	16.1%	20.0%




	Six Months Ended June 30, 2019
	Exelon	Generation	ComEd	PECO	BGE	PHI	Pepco	DPL	ACE
U.S. Federal statutory rate	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	4.4	3.6	8.2	0.2	6.4	4.7	2.0	6.7	6.9
Qualified NDT fund income	6.5	14.7	—	—	—	—	—	—	—
Amortization of investment tax credit, including deferred taxes on basis difference	(0.6)	(1.1)	(0.2)	—	(0.1)	(0.2)	(0.1)	(0.2)	(0.3)
Plant basis differences	(1.5)	—	(0.6)	(6.4)	(1.0)	(1.7)	(2.0)	(0.6)	(2.2)
Production tax credits and other credits	(0.8)	(1.8)	—	—	—	—	—	—	—
Noncontrolling interests	(0.3)	(0.8)	—	—	—	—	—	—	—
Excess deferred tax amortization	(5.8)	—	(8.8)	(2.6)	(7.9)	(19.4)	(18.1)	(15.6)	(23.4)
Other	0.7	(0.4)	0.2	(0.1)	0.2	0.3	0.5	0.4	2.0
Effective income tax rate	23.6%	35.2%	19.8%	12.1%	18.6%	4.7%	3.3%	11.7%	4.0%

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(Dollars in millions, except per share data, unless otherwise noted)



	Six Months Ended June 30, 2018
	Exelon	Generation	ComEd	PECO	BGE	PHI	Pepco	DPL	ACE
U.S. Federal statutory rate	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%	21.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	3.8	3.4	8.1	(3.6)	6.4	5.5	3.7	6.4	7.2
Qualified NDT fund income	(0.1)	(0.4)	—	—	—	—	—	—	—
Amortization of investment tax credit, including deferred taxes on basis difference	(1.1)	(3.3)	(0.2)	(0.1)	(0.1)	(0.2)	(0.1)	(0.3)	(0.3)
Plant basis differences	(2.8)	—	—	(15.6)	(0.7)	(1.8)	(2.5)	(0.7)	(1.3)
Production tax credits and other credits	(2.3)	(7.2)	(0.1)	—	—	—	—	—	—
Noncontrolling interests	(1.1)	(3.5)	—	—	—	—	—	—	—
Excess deferred tax amortization	(5.6)	—	(7.5)	(2.7)	(8.2)	(11.0)	(12.1)	(9.4)	(8.8)
Tax Cuts and Jobs Act of 2017	(0.6)	(0.9)	(0.3)	—	—	0.5	—	—	—
Other	(1.7)	(1.3)	0.1	(0.4)	0.2	(0.1)	(0.4)	0.4	(1.1)
Effective income tax rate	9.5%	7.8%	21.1%	(1.4)%	18.6%	13.9%	9.6%	17.4%	16.7%

Accounting for Uncertainty in Income Taxes

The Registrants have the following unrecognized tax benefits as of June 30, 2019 and December 31, 2018:



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
June 30, 2019	$	448	$	411	$	—	$	—	$	—	$	45	$	—	$	—	$	14
December 31, 2018	$	477	$	408	$	2	$	—	$	—	$	45	$	—	$	—	$	14

In 2016, the Tax Court held that Exelon was not entitled to defer a gain on its 1999 like-kind exchange transaction. In addition to the tax and interest related to the gain deferral, the Tax Court also ruled that Exelon was liable for penalties and interest on the penalties. Exelon had fully paid the amounts assessed resulting from the Tax Court decision in 2017. In September 2017, Exelon appealed the Tax Court decision to the U.S. Court of Appeals for the Seventh Circuit. In October 2018, the U.S. Court of Appeals for the Seventh Circuit affirmed the Tax Court’s decision. Exelon filed a petition seeking rehearing of the Seventh Circuit’s decision, but the Seventh Circuit denied that petition in December 2018.

In the first quarter of 2019, Exelon elected not to seek a further review by the U.S. Supreme Court. As a result, Exelon's and ComEd's unrecognized tax benefits decreased by approximately $33 million and $2 million, respectively, in the first quarter of 2019.

Reasonably possible the total amount of unrecognized tax benefits could significantly increase or decrease within 12 months after the reporting date

Settlement of Income Tax Audits, Refund Claims, and Litigation

As of June 30, 2019, Exelon, Generation, PHI and ACE have approximately $425 million, $411 million, $14 million and $14 million, respectively, of unrecognized federal and state tax benefits that could significantly decrease within the 12 months after the reporting date as a result of completing audits, potential settlements, and the outcomes of pending court cases. Of the above unrecognized tax benefits, Exelon and Generation have $411 million that, if recognized, would decrease the effective tax rate. The unrecognized tax benefits related to PHI and ACE, if

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recognized, may be included in future regulated base rates and that portion would have no impact to the effective tax rate.

State Income Tax Law Changes

On June 5, 2019, the Governor of Illinois signed a tax bill which would increase the Illinois corporate income tax rate from 9.50% to 10.49% effective for tax years beginning on or after January 1, 2021. The tax rate is contingent upon ratification of state constitutional amendments in November 2020. The effect of the rate change will be recognized in the period in which the new legislation is enacted. Exelon, Generation and ComEd do not expect a material impact to their financial statements as a result of the rate change.

13. Nuclear Decommissioning (Exelon and Generation)

Nuclear Decommissioning Asset Retirement Obligations (Exelon and Generation)

Generation has a legal obligation to decommission its nuclear power plants following the expiration of their operating licenses. To estimate its decommissioning obligation related to its nuclear generating stations for financial accounting and reporting purposes, Generation uses a probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models and discount rates. Generation updates its ARO annually, unless circumstances warrant more frequent updates, based on its review of updated cost studies and its annual evaluation of cost escalation factors and probabilities assigned to various scenarios.

The following table provides a rollforward of the nuclear decommissioning ARO reflected in Exelon’s and Generation’s Consolidated Balance Sheets from December 31, 2018 to June 30, 2019:



Nuclear decommissioning ARO at December 31, 2018 ^(a)(b)	$	10,005
Accretion expense	243
Net increase due to changes in, and timing of, estimated future cash flows	232
Costs incurred related to decommissioning plants	(43		)
Nuclear decommissioning ARO at June 30, 2019 ^(a)(b)	$	10,437

_________


(a)	Includes $99 million and $22 million as the current portion of the ARO at June 30, 2019 and December 31, 2018, respectively, which is included in Other current liabilities in Exelon’s and Generation’s Consolidated Balance Sheets.


(b)	Includes $755 million and $772 million of ARO related to Oyster Creek which is classified as Liabilities held for sale in Exelon's and Generation's Consolidated Balance Sheets at June 30, 2019 and December 31, 2018, respectively. See Note 3 — Mergers, Acquisitions and Dispositions for additional information.

During the six months ended June 30, 2019, Exelon's and Generation’s total nuclear ARO increased by approximately $432 million, primarily reflecting the accretion of the ARO liability due to the passage of time and the impacts of ARO updates completed during first quarter 2019. The first quarter 2019 ARO update includes an increase of approximately $330 million for a change in the assumed retirement timing probabilities for certain economically challenged nuclear plants and a $110 million decrease for the impacts of revised decommissioning cost estimates for TMI which incorporate site specific decommissioning planning activities in anticipation of its September 2019 shutdown date. Approximately $85 million of the TMI ARO adjustment resulted in a decrease in Operating and maintenance expense within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. See Note 8 — Early Plant Retirements for additional information.

NDT Funds (Exelon and Generation)

Exelon and Generation had NDT funds totaling $13,498 million and $12,695 million at June 30, 2019 and December 31, 2018, respectively. The NDT funds include $857 million and $890 million at June 30, 2019 and December 31, 2018, respectively, related to Oyster Creek NDT funds which are classified as Assets held for sale in Exelon's and Generation's Consolidated Balance Sheets. See Note 3 — Mergers, Acquisitions and Dispositions for additional information regarding the sale of Oyster Creek. The NDT funds also include $127 million and $144 million for the current portion of the NDT funds at June 30, 2019 and December 31, 2018, respectively, which are

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included in Other current assets in Exelon's and Generation's Consolidated Balance Sheets. See Note 17 — Supplemental Financial Information for additional information on activities of the NDT funds.

NRC Minimum Funding Requirements (Exelon and Generation)

NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts to decommission the facility at the end of its life.

Generation filed its biennial decommissioning funding status report with the NRC on April 1, 2019 for all units except for Zion Station which is included in a separate report to the NRC submitted by ZionSolutions, LLC. The status report demonstrated adequate decommissioning funding assurance as of December 31, 2018 for all units except for Clinton and Peach Bottom Unit 1. As of February 28, 2019, Clinton demonstrated adequate minimum funding assurance due to market recovery and no further action is required. This demonstration was also included in the April 1, 2019 submittal. As a former PECO plant, financial assurance for decommissioning Peach Bottom Unit 1 is provided by the NDT fund, collections from PECO ratepayers, and the ability to adjust those collections in accordance with the approved PAPUC tariff. No additional actions are required aside from the PAPUC filing in accordance with the tariff. See Note 15 — Asset Retirement Obligations of the Exelon 2018 Form 10-K for information regarding the amount collected from PECO ratepayers for decommissioning cost.

14. Retirement Benefits (All Registrants)

Exelon sponsors defined benefit pension plans and other postretirement benefit plans for essentially all current employees. Substantially all non-union employees and electing union employees hired on or after January 1, 2001 participate in cash balance pension plans. Effective January 1, 2009, substantially all newly-hired union-represented employees participate in cash balance pension plans. Effective February 1, 2018, most newly-hired Generation and BSC non-represented employees are not eligible for pension benefits and will instead be eligible to receive an enhanced non-discretionary employer contribution in an Exelon defined contribution savings plan. Effective January 1, 2018, most newly-hired non-represented employees are not eligible for OPEB benefits and employees represented by Local 614 are not eligible for retiree health care benefits.

Effective January 1, 2019, Exelon merged the Exelon Corporation Cash Balance Pension Plan (CBPP) into the Exelon Corporation Retirement Program (ECRP). The merging of the plans is not changing the benefits offered to the plan participants and, thus, has no impact on Exelon's pension obligation. However, beginning in 2019, actuarial losses and gains related to the CBPP and ECRP are being amortized over participants’ average remaining service period of the merged ECRP rather than each individual plan.

Defined Benefit Pension and Other Postretirement Benefits

During the first quarter of 2019, Exelon received an updated valuation of its pension and OPEB to reflect actual census data as of January 1, 2019. This valuation resulted in an increase to the pension and OPEB obligations of $75 million and $36 million, respectively. Additionally, accumulated other comprehensive loss increased by $39 million (after-tax) and regulatory assets and liabilities increased by $53 million and decreased by $5 million, respectively.

The majority of the 2019 pension benefit cost for Exelon-sponsored plans is calculated using an expected long-term rate of return on plan assets of 7.00% and a discount rate of 4.31%. The majority of the 2019 other postretirement benefit cost is calculated using an expected long-term rate of return on plan assets of 6.67% for funded plans and a discount rate of 4.30%.

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A portion of the net periodic benefit cost for all plans is capitalized within the Consolidated Balance Sheets. The following table presents the components of Exelon's net periodic benefit costs, prior to capitalization, for the three and six months ended June 30, 2019 and 2018.



	Pension Benefits Three Months Ended June 30,						Other Postretirement Benefits Three Months Ended June 30,
	2019			2018			2019			2018
Components of net periodic benefit cost:
Service cost	$	89		$	102		$	24		$	28
Interest cost	221			200			47			44
Expected return on assets	(306		)	(313		)	(38		)	(43		)
Amortization of:
Prior service benefit	—			—			(44		)	(47		)
Actuarial loss	103			157			10			16
Settlement charges	—			1			—			—
Net periodic benefit cost	$	107		$	147		$	(1	)	$	(2	)




	Pension Benefits Six Months Ended June 30,						Other Postretirement Benefits Six Months Ended June 30,
	2019			2018			2019			2018
Components of net periodic benefit cost:
Service cost	$	178		$	202		$	47		$	56
Interest cost	442			401			94			88
Expected return on assets	(612		)	(626		)	(77		)	(87		)
Amortization of:
Prior service cost (benefit)	—			1			(89		)	(93		)
Actuarial loss	206			314			23			33
Settlement charges	—			1			—			—
Net periodic benefit cost	$	214		$	293		$	(2	)	$	(3	)

The amounts below represent Exelon's, Generation's, ComEd's, PECO's, BGE's, PHI's, Pepco's, DPL's, and ACE's pension and postretirement benefit plan costs. For Exelon, the service cost component is included in Operating and maintenance expense and Property, plant and equipment, net, for the three and six months ended June 30, 2019 and 2018, while the non-service cost components are included in Other, net and Regulatory assets for the three and six months ended June 30, 2019 and 2018. For the Registrants other than Exelon, the service cost and non-service cost components are included in Operating and maintenance expense and Property, plant and equipment, net in their consolidated financial statements for the three and six months ended June 30, 2019 and 2018.

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	Three Months Ended June 30,				Six Months Ended June 30,
Pension and Other Postretirement Benefit Costs	2019		2018		2019		2018
Exelon	$	106	$	145	$	212	$	290
Generation	31		51		62		100
ComEd	23		44		47		88
PECO	3		5		5		10
BGE	16		15		30		30
PHI	24		17		48		34
Pepco	6		3		12		8
DPL	4		2		8		3
ACE	4		3		8		6

Defined Contribution Savings Plans

The Registrants participate in various 401(k) defined contribution savings plans that are sponsored by Exelon. The plans are qualified under applicable sections of the IRC and allow employees to contribute a portion of their pre-tax and/or after-tax income in accordance with specified guidelines. All Registrants match a percentage of the employee contributions up to certain limits. The following table presents the matching contributions to the savings plans during the three and six months ended June 30, 2019 and 2018, respectively.



	Three Months Ended June 30,				Six Months Ended June 30,
Savings Plan Matching Contributions	2019		2018		2019		2018
Exelon	$	33	$	50	$	64	$	82
Generation	14		28		28		43
ComEd	9		8		16		15
PECO	2		2		5		4
BGE	2		2		4		4
PHI	3		3		6		6
Pepco	1		1		2		2
DPL	1		1		1		1
ACE	—		—		1		1

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15. Changes in Accumulated Other Comprehensive Income (Exelon and Generation)

The following tables present changes in accumulated other comprehensive income (loss) (AOCI) by component for the six months ended June 30, 2019 and 2018:



Six Months Ended June 30, 2019	Losses on Cash Flow Hedges			Pension and Non-Pension Postretirement Benefit Plan Items			Foreign Currency Items			AOCI of Investments in Unconsolidated Affiliates			Total
Exelon^(a)
Beginning balance	$	(2	)	$	(2,960	)	$	(33	)	$	—		$	(2,995	)
OCI before reclassifications	—			(39		)	4			(2		)	(37		)
Amounts reclassified from AOCI^(b)	—			42			—			—			42
Net current-period OCI	—			3			4			(2		)	5
Ending balance	$	(2	)	$	(2,957	)	$	(29	)	$	(2	)	$	(2,990	)
Generation^(a)
Beginning balance	$	(4	)	$	—		$	(33	)	$	(1	)	$	(38	)
OCI before reclassifications	—			—			4			(2		)	2
Amounts reclassified from AOCI	—			—			—			—			—
Net current-period OCI	—			—			4			(2		)	2
Ending balance	$	(4	)	$	—		$	(29	)	$	(3	)	$	(36	)

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Six Months Ended June 30, 2018	Gains (Losses) on Cash Flow Hedges			Unrealized gains (losses) on Marketable Securities			Pension and Non-Pension Postretirement Benefit Plan Items				Foreign Currency Items			AOCI of Investments in Unconsolidated Affiliates			Total
Exelon^(a)
Beginning balance	$	(14	)	$	10		$	(2,998	)	^(d)	$	(23	)	$	(1	)	$	(3,026	)
OCI before reclassifications	13			—			20				(6		)	1			28
Amounts reclassified from AOCI^(b)	(1		)	—			88				—			—			87
Net current-period OCI	12			—			108				(6		)	1			115
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard^(c)	—			(10		)	—				—			—			(10		)
Ending balance	$	(2	)	$	—		$	(2,890	)		$	(29	)	$	—		$	(2,921	)
Generation^(a)
Beginning balance	$	(16	)	$	3		$	—			$	(23	)	$	(1	)	$	(37	)
OCI before reclassifications	13			—			—				(6		)	1			8
Amounts reclassified from AOCI	(1		)	—			—				—			—			(1		)
Net current-period OCI	12			—			—				(6		)	1			7
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard^(c)	—			(3		)	—				—			—			(3		)
Ending balance	$	(4	)	$	—		$	—			$	(29	)	$	—		$	(33	)

_________


(a)	All amounts are net of tax and noncontrolling interests. Amounts in parenthesis represent a decrease in AOCI.


(b)	See next tables for details about these reclassifications.

(c)

Exelon prospectively adopted the new standard Recognition and Measurement of Financial Assets and Liabilities. The standard was adopted as of January 1, 2018, which resulted in an increase to Retained earnings and Accumulated other comprehensive loss of $10 million and $3 million for Exelon and Generation, respectively. The amounts reclassified related to Rabbi Trusts. See Note 1 — Significant Accounting Policies of the Exelon 2018 Form 10-K for additional information.

(d)

Exelon early adopted the new standard Reclassification of Certain Tax Effects from AOCI. The standard was adopted retrospectively as of December 31, 2017, which resulted in an increase to Exelon’s Retained earnings and Accumulated other comprehensive loss of $539 million, primarily related to deferred income taxes associated with Exelon’s pension and OPEB obligations. See Note 1 — Significant Accounting Policies of the Exelon 2018 Form 10-K for additional information.

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ComEd, PECO, BGE, PHI, Pepco, DPL and ACE did not have any reclassifications out of AOCI to Net income during the three and six months ended June 30, 2019 and 2018. The following tables present amounts reclassified out of AOCI to Net income for Exelon during the three and six months ended June 30, 2019 and 2018.

Three Months Ended June 30, 2019



Details about AOCI components	Items reclassified out of AOCI^(a)			Affected line item in the Statement of Operations and Comprehensive Income
	Exelon
Amortization of pension and other postretirement benefit plan items
Prior service costs^(b)	$	22
Actuarial losses^(b)	(49		)
	(27		)	Total before tax
	7			Tax benefit
	$	(20	)	Net of tax

Six Months Ended June 30, 2019



Details about AOCI components	Items reclassified out of AOCI^(a)			Affected line item in the Statement of Operations and Comprehensive Income
	Exelon
Amortization of pension and other postretirement benefit plan items
Prior service costs^(b)	$	44
Actuarial losses^(b)	(100		)
	(56		)	Total before tax
	14			Tax benefit
	$	(42	)	Net of tax

Three Months Ended June 30, 2018



Details about AOCI components	Items reclassified out of AOCI^(a)			Affected line item in the Statement of Operations and Comprehensive Income
	Exelon
Amortization of pension and other postretirement benefit plan items
Prior service costs^(b)	$	23
Actuarial losses^(b)	(83		)
	(60		)	Total before tax
	16			Tax benefit
	$	(44	)	Net of tax

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Six Months Ended June 30, 2018



Details about AOCI components	Items reclassified out of AOCI^(a)			Affected line item in the Statement of Operations and Comprehensive Income
	Exelon
Amortization of pension and other postretirement benefit plan items
Prior service costs^(b)	$	46
Actuarial losses^(b)	(166		)
	(120		)	Total before tax
	32			Tax benefit
	$	(88	)	Net of tax

_________


(a)	Amounts in parenthesis represent a decrease in net income.


(b)	This AOCI component is included in the computation of net periodic pension and OPEB cost. See Note 14 — Retirement Benefits for additional information.

The following table presents income tax benefit (expense) allocated to each component of other comprehensive income (loss) during the three and six months ended June 30, 2019 and 2018:



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
Exelon
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	$	6		$	6		$	12		$	12
Actuarial loss reclassified to periodic benefit cost	(13		)	(22		)	(26		)	(44		)
Pension and non-pension postretirement benefit plans valuation adjustment	—			1			14			(6		)
Change in unrealized loss on cash flow hedges	—			(1		)	—			(4		)
Change in unrealized gain (loss) on investments in unconsolidated affiliates	1			—			1			(1		)
Total	$	(6	)	$	(16	)	$	1		$	(43	)

Generation
Change in unrealized gain (loss) on cash flow hedges	$	—		$	(1	)	$	—		$	(4	)
Change in unrealized gain (loss) on investments in unconsolidated affiliates	1			—			1			(1		)
Total	$	1		$	(1	)	$	1		$	(5	)

16. Commitments and Contingencies (All Registrants)

The following is an update to the current status of commitments and contingencies set forth in Note 22 of the Exelon 2018 Form 10-K. See Note 5 — Mergers, Acquisitions and Dispositions of the Exelon 2018 Form 10-K for additional information on the PHI Merger commitments.

Commitments

PHI Merger Commitments (Exelon, PHI, Pepco, DPL and ACE). The merger of Exelon and PHI was approved in Delaware, New Jersey, Maryland and the District of Columbia. Exelon and PHI agreed to certain commitments including where applicable: customer rate credits, funding for energy efficiency and delivery system modernization programs, a green sustainability fund, workforce development initiatives, charitable contributions, renewable

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generation and other required commitments. In addition, the orders approving the merger in Delaware, New Jersey, and Maryland include a “most favored nation” provision which, generally, requires allocation of merger benefits proportionally across all the jurisdictions.

The following amounts represent total commitment costs for Exelon, PHI, Pepco, DPL and ACE that have been recorded since the acquisition date and the remaining obligations as of June 30, 2019:



Description	Expected Payment Period	Exelon		PHI		Pepco		DPL		ACE
Rate credits	2016 - 2021	$	264	$	264	$	91	$	72	$	101
Energy efficiency	2016 - 2021	117		—		—		—		—
Charitable contributions	2016 - 2026	50		50		28		12		10
Delivery system modernization	Q2 2017	22		—		—		—		—
Green sustainability fund	Q2 2017	14		—		—		—		—
Workforce development	2016 - 2020	17		—		—		—		—
Other		29		6		1		5		—
Total commitments		$	513	$	320	$	120	$	89	$	111
Remaining commitments		$	116	$	86	$	69	$	11	$	6

In addition, Exelon is committed to develop or to assist in the commercial development of approximately 37 MWs of new solar generation in Maryland, District of Columbia, and Delaware at an estimated cost of approximately $127 million, which will generate future earnings at Exelon and Generation. Investment costs, which are expected to be primarily capital in nature, are recognized as incurred and recorded in Exelon's and Generation's financial statements. As of June 30, 2019, 27 MWs of new generation were developed and Exelon and Generation have incurred costs of $102 million. Exelon has also committed to purchase 100 MWs of wind energy in PJM. DPL has committed to conducting three RFPs to procure up to a total of 120 MWs of wind RECs for the purpose of meeting Delaware's renewable portfolio standards. DPL has conducted two of the three wind REC RFPs. The first 40 MW wind REC tranche was conducted in 2017 and did not result in a purchase agreement. The second 40 MW wind REC tranche was conducted in 2018 and resulted in a proposed REC purchase agreement that was approved by the DPSC in March 2019. The third and final 40 MW wind REC tranche will be conducted in 2022.

Pursuant to the various jurisdictions' merger approval conditions, over specified periods Pepco, DPL and ACE are not permitted to reduce employment levels due to involuntary attrition associated with the merger integration process and have made other commitments regarding hiring and relocation of positions.

Commercial Commitments (All Registrants). The Registrants’ commercial commitments as of June 30, 2019, representing commitments potentially triggered by future events were as follows:



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Letters of credit	$	1,315	$	1,283	$	7	$	—	$	9	$	10	$	10	$	—	$	—
Surety bonds^(a)	1,492		1,271		52		9		17		39		31		4		3
Financing trust guarantees	378		—		200		178		—		—		—		—		—
Guaranteed lease residual values^(b)	26		—		—		—		—		26		9		11		7
Total commercial commitments	$	3,211	$	2,554	$	259	$	187	$	26	$	75	$	50	$	15	$	10

_________


(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 lease term associated with these assets ranges from 1 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $68 million, $23 million of which is a guarantee by Pepco, $28 million by DPL and $17 million by ACE. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.

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(Dollars in millions, except per share data, unless otherwise noted)

Nuclear Insurance (Exelon and Generation). Generation is subject to liability, property damage and other risks associated with major incidents at any of its 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 June 30, 2019, the current liability limit per incident is $13.9 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors. Changes to account for the effects of inflation occur at least once every five years with the last adjustment effective November 1, 2018. 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 $13.5 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 $2.9 billion, however any amounts payable under this secondary layer would be capped at $434 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 $13.9 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 2 — Variable Interest Entities of the Exelon 2018 Form 10-K 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.

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 $334 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.

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(Dollars in millions, except per share data, unless otherwise noted)

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 cash flows.

Environmental Remediation Matters

General (All Registrants). The Registrants’ operations have in the past, and may in the future, require substantial expenditures 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. Unless otherwise disclosed, the Registrants cannot reasonably estimate whether they will incur 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. Additional costs could have a material, unfavorable impact in the Registrants' financial statements.

MGP Sites (Exelon, ComEd, PECO, BGE, PHI and DPL). ComEd, PECO, BGE and DPL have identified sites where former MGP or gas purification 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, 21 of which have been remediated and approved by the Illinois EPA or the U.S. EPA and 21 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 2023.


•	PECO has identified 26 sites, 17 of which have been remediated in accordance with applicable PA DEP regulatory requirements and 9 that 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 sites, 9 of which have been remediated and approved by the MDE and 4 that require some level of remediation and/or ongoing activity. BGE expects the majority of the remediation at these sites to continue through at least 2019.


•	DPL has identified 3 sites, for 2 of which remediation has been completed and approved by the MDE or the Delaware Department of Natural Resources and Environmental Control. The remaining site is under study and the required cost at the site is not expected to be material.

The historical nature of the MGP and gas purification 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.

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 6 — Regulatory Matters for additional information regarding the associated regulatory assets. While BGE and DPL do not have riders for MGP clean-up costs, they have historically received recovery of actual clean-up costs in distribution rates.

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(Dollars in millions, except per share data, unless otherwise noted)

As of June 30, 2019 and December 31, 2018, 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:



June 30, 2019	Total environmental investigation and remediation reserve		Portion of total related to MGP investigation and remediation
Exelon	$	482	$	345
Generation	107		—
ComEd	318		318
PECO	25		24
BGE	5		3
PHI	27		—
Pepco	24		—
DPL	1		—
ACE	1		—



December 31, 2018	Total environmental investigation and remediation reserve		Portion of total related to MGP investigation and remediation
Exelon	$	496	$	356
Generation	108		—
ComEd	329		327
PECO	27		25
BGE	5		4
PHI	27		—
Pepco	25		—
DPL	1		—
ACE	1		—

Cotter Corporation (Exelon and Generation). 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. Including Cotter, there are three PRPs participating in the West Lake Landfill remediation proceeding. Investigation by Generation has identified a number of other parties who also may be PRPs and could be liable to contribute to the final remedy. Further investigation is ongoing.

In September 2018 the EPA issued its Record of Decision (ROD) Amendment for the selection of the final remedy. The ROD modified the EPA’s previously proposed plan for partial excavation of the radiological materials by reducing the depths of the excavation. The ROD also allows for variation in depths of excavation depending on radiological concentrations. The EPA and the PRPs have entered into a Consent Agreement to perform the Remedial Design, which is expected to be completed in the 2020 - 2021 time frame. In March 2019 the PRPs received Special Notice Letters from the EPA to perform the Remedial Action work. The EPA has established a deadline of October 2019 for the PRPs to provide a good faith offer to conduct, or finance, the Remedial Action work. This schedule can be extended by the EPA pending completion of the Remedial Design. The estimated cost of the remedy, taking into account the current EPA technical requirements and the total costs expected to be incurred by the PRPs in fully executing the remedy, is approximately $280 million, including cost escalation on an undiscounted basis, which would be allocated among the final group of PRPs. Generation has determined that a loss associated with the EPA’s partial excavation and enhanced landfill cover remedy is probable and has recorded a liability included in the table above, that reflects management’s best estimate of Cotter’s allocable share of the ultimate cost. Given the joint and several nature of this liability, the magnitude of Generation’s ultimate liability will depend on the actual costs incurred

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(Dollars in millions, except per share data, unless otherwise noted)

to implement the required remediation remedy as well as on the nature and terms of any cost-sharing arrangements with the final group of PRPs. Therefore, it is reasonably possible that the ultimate cost and Generation’s associated allocable share could differ significantly once these uncertainties are resolved, which could have a material impact on Exelon's and Generation's future financial statements.

One of the other PRPs has indicated 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, Exelon and Generation do not possess sufficient information to assess this claim and therefore are unable to estimate a range of loss, if any. As such, no liability has been recorded for the potential contribution claim. It is reasonably possible, however, that resolution of this matter could have a material, unfavorable impact on Exelon’s and Generation's financial statements.

In January 2018, the PRPs were advised by the EPA that it will begin an additional investigation and evaluation of groundwater conditions at the West Lake Landfill. In September 2018, the PRPs agreed to an Administrative Settlement Agreement and Order on Consent for the performance by the PRPs of the groundwater RI/FS. The purpose of this RI/FS is to define the nature and extent of any groundwater contamination from the West Lake Landfill site and evaluate remedial alternatives. Generation estimates the undiscounted cost for the groundwater RI/FS to be approximately $20 million. Generation determined a loss associated with the RI/FS is probable and has recorded a liability included in the table above that reflects management’s best estimate of Cotter’s allocable share of the cost among the PRPs. At this time Generation cannot predict the likelihood or the extent to which, if any, remediation activities may be required and therefore cannot estimate a reasonably possible range of loss for response costs beyond those associated with the RI/FS component. It is reasonably possible, however, that resolution of this matter could have a material, unfavorable impact on Exelon’s and Generation’s future financial statements.

In August, 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 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 from all PRPs. Pursuant to a series of annual agreements since 2011, the DOJ and the PRPs have tolled the statute of limitations until August 2019 so that settlement discussions could proceed. Generation has determined that a loss associated with this matter is probable under its indemnification agreement with Cotter and has recorded an estimated 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. In the event of a finding of liability against Cotter, it is probable that Generation would be financially responsible due to its indemnification responsibilities of Cotter described above. The court has dismissed a number of the lawsuits as untimely, which has been upheld on appeal. Cotter and the remaining plaintiffs have engaged in settlement discussions pursuant to court-ordered mediation. During the second quarter of 2018, Generation determined a loss was probable based on the advancement of settlement proceedings and recorded an immaterial liability.

Benning Road Site (Exelon, Generation, PHI and Pepco). 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

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(Dollars in millions, except per share data, unless otherwise noted)

conduct a Remediation Investigation (RI)/ Feasibility Study (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. Pursuant to Exelon's March 23, 2016 acquisition of PHI, Pepco Energy Services was transferred to Generation.

Since 2013, Pepco and Pepco Energy Services (now Generation) have been performing RI work and have submitted multiple draft RI reports to the DOEE. Once the RI work is completed, Pepco and Generation will issue a draft “final” RI report for review and comment by DOEE and the public. Pepco and Generation will then proceed to develop an FS to evaluate possible remedial alternatives for submission to DOEE. The Court has established a schedule for completion of the RI and FS, and approval by the DOEE, by September 16, 2021.

Upon DOEE’s approval of the final RI and FS Reports, Pepco and Generation 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 Generation have determined that a loss associated with this matter is probable and have accrued an estimated liability, which is included in the table above.

Anacostia River Tidal Reach (Exelon, PHI and Pepco). Contemporaneous with the Benning RI/FS being performed by Pepco and Generation, 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 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. In April 2018, DOEE released a draft remedial investigation report for public review and comment. Pepco submitted written comments to the draft RI and participated in a public hearing. Pepco continues outreach efforts as appropriate to the agencies, governmental officials, community organizations and other key stakeholders. In May 2018 the District of Columbia Council extended the deadline for completion of the Record of Decision from June 30, 2018 until December 31, 2019. An appropriate liability for Pepco’s share of investigation costs has been accrued and is included in the table above. Although Pepco has determined that it is probable that costs for remediation will be incurred, Pepco cannot estimate the reasonably possible range of loss at this time and no liability has been accrued for those future costs. A draft Feasibility Study of potential remedies and their estimated costs is being prepared by the agencies and is expected later in 2019, at which time Pepco will likely be in a better position to estimate the range of loss.

In addition to the activities associated with the remedial process outlined above, there is a complementary statutory program that requires an assessment to determine if any natural resources have been damaged as a result of the contamination that is being remediated, and, if so, that a plan be developed by the federal, state and local Trustees responsible for those resources to restore them to their condition before injury from the environmental contaminants. If natural resources are not restored, then compensation for the injury can be sought from the party responsible for the release of the contaminants. The assessment of Natural Resource Damages (NRD) typically takes place following cleanup because cleanups sometimes also effectively restore habitat. During the second quarter of 2018, Pepco became aware that the Trustees are in the beginning stages of this process that often takes many years beyond the remedial decision to complete. Pepco has concluded that a loss associated with the eventual NRD assessment is reasonably possible. Due to the very early stage of the assessment process it cannot reasonably estimate the range of loss.

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(Dollars in millions, except per share data, unless otherwise noted)

Litigation and Regulatory Matters

Asbestos Personal Injury Claims (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 estimated liabilities are recorded on an undiscounted basis and exclude the estimated legal costs associated with handling these matters, which could be material.

At June 30, 2019 and December 31, 2018, Generation had recorded estimated liabilities of approximately $84 million and $79 million, respectively, in total for asbestos-related bodily injury claims. As of June 30, 2019, approximately $24 million of this amount related to 244 open claims presented to Generation, while the remaining $60 million is for estimated future asbestos-related bodily injury claims anticipated to arise through 2055, 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 adjustments to the estimated liabilities are necessary.

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 unfavorable impact on Exelon's and Generation's financial statements.

City of Everett Tax Increment Financing Agreement (Exelon and Generation). On April 10, 2017, the City of Everett petitioned the Massachusetts Economic Assistance Coordinating Council (EACC) to revoke the 1999 tax increment financing agreement (TIF Agreement) relating to Mystic Units 8 and 9 on the grounds that the total investment in Mystic Units 8 and 9 materially deviates from the investment set forth in the TIF Agreement. On October 31, 2017, a three-member panel of the EACC conducted an administrative hearing on the City’s petition. On November 30, 2017, the hearing panel issued a tentative decision denying the City’s petition, finding that there was no material misrepresentation that would justify revocation of the TIF Agreement. On December 13, 2017, the tentative decision was adopted by the full EACC. On January 12, 2018, the City filed a complaint in Massachusetts Superior Court requesting, among other things, that the court set aside the EACC’s decision, grant the City’s request to decertify the Project and the TIF Agreement, and award the City damages for alleged underpaid taxes over the period of the TIF Agreement. Generation vigorously contested the City’s claims before the EACC and will continue to do so in the Massachusetts Superior Court proceeding. Generation continues to believe that the City’s claim lacks merit. Accordingly, Generation has not recorded a liability for payment resulting from such a revocation, nor can Generation estimate a reasonably possible range of loss, if any, associated with any such revocation. Further, it is reasonably possible that property taxes assessed in future periods, including those following the expiration of the current TIF Agreement in 2019, could be material to Generation’s results of operations and cash flows.

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 reasonably possible, 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.

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(Dollars in millions, except per share data, unless otherwise noted)

17. Supplemental Financial Information (All Registrants)

Supplemental Statement of Operations Information

The following tables provide additional information about material items recorded in the Registrants' Consolidated Statements of Operations and Comprehensive Income.



	Taxes other than income
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Three Months Ended June 30, 2019
Utility taxes^(a)	$	209	$	32	$	55	$	30	$	21	$	71	$	67	$	4	$	—
Property	148		68		9		4		37		30		21		8		1
Payroll	61		30		7		4		4		7		2		1		1

Three Months Ended June 30, 2018
Utility taxes^(a)	$	218	$	29	$	60	$	30	$	21	$	78	$	73	$	5	$	—
Property	135		65		8		4		34		24		15		8		1
Payroll	65		34		7		4		4		6		2		1		1

Six Months Ended June 30, 2019
Utility taxes^(a)	$	432	$	58	$	118	$	63	$	48	$	145	$	136	$	9	$	—
Property	296		138		15		8		75		60		43		16		1
Payroll	127		64		14		7		8		14		3		2		2

Six Months Ended June 30, 2018
Utility taxes^(a)	$	452	$	60	$	121	$	63	$	47	$	161	$	151	$	10	$	—
Property	271		134		15		7		69		46		29		16		1
Payroll	133		68		14		8		8		14		3		2		2

_________

(a)

Generation’s utility tax represents gross receipts tax related to its retail operations, and the Utility Registrants' utility taxes represents municipal and state utility taxes and gross receipts taxes related to their operating revenues. The offsetting collection of utility taxes from customers is recorded in revenues in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.

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(Dollars in millions, except per share data, unless otherwise noted)



	Other, Net
	Exelon			Generation			ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Three Months Ended June 30, 2019
Decommissioning-related activities:
Net realized income on NDT funds^(a)
Regulatory agreement units	$	77		$	77		$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-regulatory agreement units	230			230			—		—		—		—		—		—		—
Net unrealized (losses) gains on NDT funds
Regulatory agreement units	98			98			—		—		—		—		—		—		—
Non-regulatory agreement units	(98		)	(98		)	—		—		—		—		—		—		—
Regulatory offset to NDT fund-related activities^(b)	(141		)	(141		)	—		—		—		—		—		—		—
Decommissioning-related activities	166			166			—		—		—		—		—		—		—
AFUDC — Equity	21			—			4		3		5		9		6		1		2
Non-service net periodic benefit cost	5			—			—		—		—		—		—		—		—

Three Months Ended June 30, 2018
Decommissioning-related activities:
Net realized income on NDT funds^(a)
Regulatory agreement units	$	216		$	216		$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-regulatory agreement units	143			143			—		—		—		—		—		—		—
Net unrealized losses on NDT funds
Regulatory agreement units	(194		)	(194		)	—		—		—		—		—		—		—
Non-regulatory agreement units	(120		)	(120		)	—		—		—		—		—		—		—
Regulatory offset to NDT fund-related activities^(b)	(23		)	(23		)	—		—		—		—		—		—		—
Decommissioning-related activities	22			22			—		—		—		—		—		—		—
AFUDC — Equity	13			—			2		—		4		7		6		1		—
Non-service net periodic benefit cost	(11		)	—			—		—		—		—		—		—		—

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(Dollars in millions, except per share data, unless otherwise noted)



	Other, Net
	Exelon			Generation			ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Six Months Ended June 30, 2019
Decommissioning-related activities:
Net realized income on NDT funds^(a)
Regulatory agreement units	$	131		$	131		$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-regulatory agreement units	283			283			—		—		—		—		—		—		—
Net unrealized gains on NDT funds
Regulatory agreement units	476			476			—		—		—		—		—		—		—
Non-regulatory agreement units	182			182			—		—		—		—		—		—		—
Regulatory offset to NDT fund-related activities^(b)	(487		)	(487		)	—		—		—		—		—		—		—
Decommissioning-related activities	585			585			—		—		—		—		—		—		—
AFUDC — Equity	43			—			9		6		10		18		12		2		4
Non-service net periodic benefit cost	10			—			—		—		—		—		—		—		—

Six Months Ended June 30, 2018
Decommissioning-related activities:
Net realized income on NDT funds^(a)
Regulatory agreement units	$	262		$	262		$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-regulatory agreement units	199			199			—		—		—		—		—		—		—
Net unrealized losses on NDT funds
Regulatory agreement units	(268		)	(268		)	—		—		—		—		—		—		—
Non-regulatory agreement units	(215		)	(215		)	—		—		—		—		—		—		—
Regulatory offset to NDT fund-related activities^(b)	(1		)	(1		)	—		—		—		—		—		—		—
Decommissioning-related activities	(23		)	(23		)	—		—		—		—		—		—		—
AFUDC — Equity	31			—			8		2		8		13		12		1		—
Non-service net periodic benefit cost	(21		)	—			—		—		—		—		—		—		—

_________


(a)	Realized income includes interest, dividends and realized gains and losses on sales of NDT fund investments.


(b)	Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units, including the elimination of income taxes related to all NDT fund activity for those units. See Note 15 — Asset Retirement Obligations of the Exelon 2018 Form 10-K for additional information regarding the accounting for nuclear decommissioning.

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(Dollars in millions, except per share data, unless otherwise noted)

Supplemental Cash Flow Information

The following tables provide additional information about material items recorded in the Registrants' Consolidated Statements of Cash Flows.



	Depreciation, amortization and accretion
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Six Months Ended June 30, 2019
Property, plant and equipment^(a)	$	1,859	$	789	$	439	$	149	$	173	$	266	$	117	$	71	$	57
Amortization of regulatory assets^(a)	266		—		69		15		79		103		69		20		14
Amortization of intangible assets, net^(a)	29		25		—		—		—		—		—		—		—
Amortization of energy contract assets and liabilities^(b)	5		5		—		—		—		—		—		—		—
Nuclear fuel^(c)	513		513		—		—		—		—		—		—		—
ARO accretion^(d)	250		248		—		—		—		—		—		—		—
Total depreciation, amortization and accretion	$	2,922	$	1,580	$	508	$	164	$	252	$	369	$	186	$	91	$	71

Six Months Ended June 30, 2018
Property, plant and equipment^(a)	$	1,873	$	890	$	406	$	135	$	164	$	236	$	107	$	64	$	47
Amortization of regulatory assets^(a)	278		—		53		14		84		127		81		24		22
Amortization of intangible assets, net^(a)	28		24		—		—		—		—		—		—		—
Amortization of energy contract assets and liabilities^(b)	10		10		—		—		—		—		—		—		—
Nuclear fuel^(c)	569		569		—		—		—		—		—		—		—
ARO accretion^(d)	242		242		—		—		—		—		—		—		—
Total depreciation, amortization and accretion	$	3,000	$	1,735	$	459	$	149	$	248	$	363	$	188	$	88	$	69

_________


(a)	Included in Depreciation and amortization in the Registrants' Consolidated Statements of Operations and Comprehensive Income.


(b)	Included in Operating revenues or Purchased power and fuel expense in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.


(c)	Included in Purchased power and fuel expense in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.


(d)	Included in Operating and maintenance expense in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.

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(Dollars in millions, except per share data, unless otherwise noted)



	Other non-cash operating activities
	Exelon			Generation			ComEd		PECO		BGE		PHI			Pepco			DPL			ACE
Six Months Ended June 30, 2019
Pension and non-pension postretirement benefit costs	$	212		$	62		$	47	$	5	$	29	$	48		$	12		$	8		$	8
Provision for uncollectible accounts	45			12			16		10		4		3			2			1			—
Other decommissioning-related activity^(a)	(260		)	(261		)	—		—		—		—			—			—			—
Energy-related options^(b)	43			43			—		—		—		—			—			—			—
Amortization of rate stabilization deferral	(10		)	—			—		—		—		(10		)	(8		)	(2		)	—
Discrete impacts from EIMA and FEJA^(c)	24			—			24		—		—		—			—			—			—
Long-term incentive plan	35			—			—		—		—		—			—			—			—
Amortization of operating ROU asset	115			78			1		—		15		17			4			5			2

Six Months Ended June 30, 2018
Pension and non-pension postretirement benefit costs	$	290		$	100		$	88	$	10	$	29	$	34		$	8		$	3		$	6
Provision for uncollectible accounts	77			28			18		11		5		15			7			2			5
Other decommissioning-related activity^(a)	(61		)	(61		)	—		—		—		—			—			—			—
Energy-related options^(b)	(7		)	(7		)	—		—		—		—			—			—			—
Amortization of rate stabilization deferral	13			—			—		—		—		13			10			3			—
Discrete impacts from EIMA and FEJA^(c)	14			—			14		—		—		—			—			—			—
Long-term incentive plan	51			—			—		—		—		—			—			—			—

_______

(a)

Includes the elimination of decommissioning-related activity for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income and income taxes related to all NDT fund activity for these units. See Note 15 — Asset Retirement Obligations of the Exelon 2018 Form 10-K for additional information regarding the accounting for nuclear decommissioning.


(b)	Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded in Operating revenues and expenses.


(c)	Reflects the change in ComEd's distribution and energy efficiency formula rates. See Note 6 — Regulatory Matters for additional information.

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(Dollars in millions, except per share data, unless otherwise noted)

The following tables provide a reconciliation of cash, cash equivalents and restricted cash reported within the Registrants’ Consolidated Balance Sheets that sum to the total of the same amounts in their Consolidated Statements of Cash Flows.



	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
June 30, 2019
Cash and cash equivalents	$	735	$	575	$	65	$	20	$	8	$	54	$	18	$	3	$	4
Restricted cash	252		122		77		6		1		37		34		1		2
Restricted cash included in other long-term assets	191		—		174		—		—		17		—		—		17
Total cash, cash equivalents and restricted cash	$	1,178	$	697	$	316	$	26	$	9	$	108	$	52	$	4	$	23

December 31, 2018
Cash and cash equivalents	$	1,349	$	750	$	135	$	130	$	7	$	124	$	16	$	23	$	7
Restricted cash	247		153		29		5		6		43		37		1		4
Restricted cash included in other long-term assets	185		—		166		—		—		19		—		—		19
Total cash, cash equivalents and restricted cash	$	1,781	$	903	$	330	$	135	$	13	$	186	$	53	$	24	$	30

June 30, 2018
Cash and cash equivalents	$	694	$	420	$	30	$	18	$	7	$	195	$	47	$	141	$	6
Restricted cash	206		130		5		5		1		38		33		—		5
Restricted cash included in other long-term assets	128		—		108		—		—		20		—		—		20
Total cash, cash equivalents and restricted cash	$	1,028	$	550	$	143	$	23	$	8	$	253	$	80	$	141	$	31

December 31, 2017
Cash and cash equivalents	$	898	$	416	$	76	$	271	$	17	$	30	$	5	$	2	$	2
Restricted cash	207		138		5		4		1		42		35		—		6
Restricted cash included in other long-term assets	85		—		63		—		—		23		—		—		23
Total cash, cash equivalents and restricted cash	$	1,190	$	554	$	144	$	275	$	18	$	95	$	40	$	2	$	31

For additional information on restricted cash see Note 1 — Significant Accounting Policies of the Exelon 2018 Form 10-K.

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(Dollars in millions, except per share data, unless otherwise noted)

Supplemental Balance Sheet Information

The following tables provide additional information about material items recorded in the Registrants' Consolidated Balance Sheets.



	Unbilled customer revenues
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
June 30, 2019	$	1,352	$	703	$	218	$	121	$	115	$	195	$	107	$	47	$	41
December 31, 2018	1,656		965		223		114		168		186		97		59		30



	Accrued expenses
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
June 30, 2019
Compensation-related accruals^(a)	$	767	$	292	$	117	$	52	$	41	$	72	$	23	$	15	$	10
Taxes accrued	446		304		65		14		21		75		54		13		9
Interest accrued	340		76		109		33		40		50		24		8		13

December 31, 2018
Compensation-related accruals^(a)	$	1,191	$	479	$	187	$	49	$	68	$	99	$	29	$	19	$	12
Taxes accrued	412		226		71		28		46		74		58		4		5
Interest accrued	334		77		105		33		39		50		25		8		12

_________


(a)	Primarily includes accrued payroll, bonuses and other incentives, vacation and benefits.

18. Segment Information (All Registrants)

Operating segments for each of the Registrants are determined based on information used by the CODM in deciding how to evaluate performance and allocate resources at each of the Registrants.

Exelon has eleven reportable segments, which include Generation's five reportable segments consisting of the Mid-Atlantic, Midwest, New York, ERCOT and all other power regions referred to collectively as “Other Power Regions” and ComEd, PECO, BGE, and PHI's three reportable segments consisting of Pepco, DPL and ACE. ComEd, PECO, BGE, Pepco, DPL and ACE each represent a single reportable segment, and as such, no separate segment information is provided for these Registrants. Exelon, ComEd, PECO, BGE, Pepco, DPL and ACE's CODMs evaluate the performance of and allocate resources to ComEd, PECO, BGE, Pepco, DPL and ACE based on net income.

The basis for Generation's reportable segments is the integrated management of its electricity business that is located in different geographic regions, and largely representative of the footprints of ISO/RTO and/or NERC regions, which utilize multiple supply sources to provide electricity through various distribution channels (wholesale and retail). Generation's hedging strategies and risk metrics are also aligned to these same geographic regions. Descriptions of each of Generation’s five reportable segments are as follows:


•	Mid-Atlantic represents operations in the eastern half of PJM, which includes New Jersey, Maryland, Virginia, West Virginia, Delaware, the District of Columbia and parts of Pennsylvania and North Carolina.


•	Midwest represents operations in the western half of PJM and the United States footprint of MISO, excluding MISO’s Southern Region.


•	New York represents operations within ISO-NY.


•	ERCOT represents operations within Electric Reliability Council of Texas.

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(Dollars in millions, except per share data, unless otherwise noted)


•	Other Power Regions:


•	New England represents the operations within ISO-NE.


•	South represents operations in the FRCC, MISO’s Southern Region, and the remaining portions of the SERC not included within MISO or PJM.


•	West represents operations in the WECC, which includes California ISO.


•	Canada represents operations across the entire country of Canada and includes AESO, OIESO and the Canadian portion of MISO.

The CODMs for Exelon and Generation evaluate the performance of Generation’s electric business activities and allocate resources based on RNF. Generation believes that RNF is a useful measurement of operational performance. RNF is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report. Generation’s operating revenues include all sales to third parties and affiliated sales to the Utility Registrants. Purchased power costs include all costs associated with the procurement and supply of electricity including capacity, energy and ancillary services. Fuel expense includes the fuel costs for Generation’s owned generation and fuel costs associated with tolling agreements. The results of Generation's other business activities are not regularly reviewed by the CODM and are therefore not classified as operating segments or included in the regional reportable segment amounts. These activities include natural gas, as well as other miscellaneous business activities that are not significant to Generation's overall operating revenues or results of operations. Further, Generation’s unrealized mark-to-market gains and losses on economic hedging activities and its amortization of certain intangible assets and liabilities relating to commodity contracts recorded at fair value from mergers and acquisitions are also excluded from the regional reportable segment amounts. Exelon and Generation do not use a measure of total assets in making decisions regarding allocating resources to or assessing the performance of these reportable segments.

During the first quarter of 2019, due to a change in economics in our New England region, Generation changed the way that information is reviewed by the CODM. The New England region is no longer regularly reviewed as a separate region by the CODM nor is it presented separately in any external information presented to third parties. Information for the New England region is reviewed by the CODM as part of Other Power Regions. Exelon and Generation retrospectively applied this change.

An analysis and reconciliation of the Registrants’ reportable segment information to the respective information in the consolidated financial statements for the three and six months ended June 30, 2019 and 2018 is as follows:

Three Months Ended June 30, 2019 and 2018



	Generation^(a)		ComEd		PECO		BGE		PHI		Other^(b)		Intersegment Eliminations			Exelon
Operating revenues^(c):
2019
Competitive businesses electric revenues	$	3,718	$	—	$	—	$	—	$	—	$	—	$	(250	)	$	3,468
Competitive businesses natural gas revenues	333		—		—		—		—		—		—			333
Competitive businesses other revenues	159		—		—		—		—		—		(1		)	158
Rate-regulated electric revenues	—		1,351		566		540		1,063		—		(8		)	3,512
Rate-regulated natural gas revenues	—		—		89		109		24		—		(4		)	218
Shared service and other revenues	—		—		—		—		4		484		(488		)	—
Total operating revenues	$	4,210	$	1,351	$	655	$	649	$	1,091	$	484	$	(751	)	$	7,689

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(Dollars in millions, except per share data, unless otherwise noted)



	Generation^(a)		ComEd		PECO			BGE		PHI		Other^(b)			Intersegment Eliminations			Exelon
2018
Competitive businesses electric revenues	$	3,939	$	—	$	—		$	—	$	—	$	—		$	(270	)	$	3,669
Competitive businesses natural gas revenues	489		—		—			—		—		—			—			489
Competitive businesses other revenues	151		—		—			—		—		—			(4		)	147
Rate-regulated electric revenues	—		1,398		560			548		1,045		—			(9		)	3,542
Rate-regulated natural gas revenues	—		—		93			114		28		—			(5		)	230
Shared service and other revenues	—		—		—			—		3		487			(491		)	(1		)
Total operating revenues	$	4,579	$	1,398	$	653		$	662	$	1,076	$	487		$	(779	)	$	8,076
Intersegment revenues^(d):
2019	$	252	$	5	$	2		$	6	$	3	$	482		$	(750	)	$	—
2018	273		5		2			6		3		487			(776		)	—
Depreciation and amortization:
2019	$	409	$	257	$	83		$	117	$	188	$	25		$	—		$	1,079
2018	466		231		74			114		180		23			—			1,088
Operating expenses:
2019	$	4,096	$	1,040	$	510		$	569	$	926	$	484		$	(744	)	$	6,881
2018	4,298		1,111		526			578		923		492			(790		)	7,138
Interest expense, net:
2019	$	116	$	89	$	33		$	29	$	67	$	75		$	—		$	409
2018	102		85		32			25		65		64			—			373
Income (loss) before income taxes:
2019	$	202	$	232	$	115		$	56	$	112	$	(73	)	$	—		$	644
2018	209		207		95			64		99		(61		)	—			613
Income Taxes:
2019	$	78	$	46	$	13		$	11	$	6	$	(10	)	$	—		$	144
2018	23		43		(1		)	13		15		(27		)	—			66
Net income (loss):
2019	$	118	$	186	$	102		$	45	$	106	$	(63	)	$	—		$	494
2018	181		164		96			51		84		(34		)	—			542
Capital Expenditures
2019	$	383	$	459	$	225		$	284	$	340	$	11		$	—		$	1,702
2018	670		495		194			210		371		(13		)	—			1,927

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(Dollars in millions, except per share data, unless otherwise noted)

__________

(a)

Intersegment revenues for Generation in 2019 include revenue from sales to PECO of $35 million, sales to BGE of $57 million, sales to Pepco of $52 million, sales to DPL of $12 million and sales to ACE of $5 million in the Mid-Atlantic region, and sales to ComEd of $89 million in the Midwest region, which eliminate upon consolidation. Intersegment revenues for Generation in 2018 include revenue from sales to PECO of $25 million, sales to BGE of $63 million, sales to Pepco of $46 million, sales to DPL of $30 million and sales to ACE of $6 million in the Mid-Atlantic region, and sales to ComEd of $103 million in the Midwest region, which eliminate upon consolidation.


(b)	Other primarily includes Exelon’s corporate operations, shared service entities and other financing and investment activities.


(c)	Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 17 — Supplemental Financial Information for additional information on total utility taxes.

(d)

Intersegment revenues exclude sales to unconsolidated affiliates. The intersegment profit associated with Generation’s sale of certain products and services by and between Exelon’s segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income.

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(Dollars in millions, except per share data, unless otherwise noted)

PHI:



	Pepco		DPL		ACE		Other^(b)			Intersegment Eliminations			PHI
Operating revenues^(a):
2019
Rate-regulated electric revenues	$	531	$	261	$	274	$	—		$	(3	)	$	1,063
Rate-regulated natural gas revenues	—		24		—		—			—			24
Shared service and other revenues	—		2		—		97			(95		)	4
Total operating revenues	$	531	$	287	$	274	$	97		$	(98	)	$	1,091
2018
Rate-regulated electric revenues	$	523	$	261	$	265	$	—		$	(4	)	$	1,045
Rate-regulated natural gas revenues	—		28		—		—			—			28
Shared service and other revenues	—		—		—		108			(105		)	3
Total operating revenues	$	523	$	289	$	265	$	108		$	(109	)	$	1,076
Intersegment revenues:
2019	$	1	$	2	$	1	$	98		$	(99	)	$	3
2018	2		2		1		107			(109		)	3
Depreciation and amortization:
2019	$	93	$	45	$	40	$	10		$	—		$	188
2018	92		43		36		9			—			180
Operating expenses:
2019	$	438	$	243	$	246	$	100		$	(101	)	$	926
2018	438		247		240		110			(112		)	923
Interest expense, net:
2019	$	34	$	15	$	15	$	3		$	—		$	67
2018	32		14		16		3			—			65
Income (loss) before income taxes:
2019	$	66	$	34	$	14	$	106		$	(108	)	$	112
2018	61		31		10		85			(88		)	99
Income Taxes:
2019	$	2	$	4	$	—	$	—		$	—		$	6
2018	7		5		2		1			—			15
Net income (loss):
2019	$	64	$	30	$	14	$	(5	)	$	3		$	106
2018	54		26		8		(7		)	3			84
Capital Expenditures
2019	$	154	$	82	$	99	$	5		$	—		$	340
2018	160		101		107		3			—			371

__________


(a)	Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 17 — Supplemental Financial Information for additional information on total utility taxes.


(b)	Other primarily includes PHI’s corporate operations, shared service entities and other financing and investment activities.

The following tables disaggregate the Registrants' revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. For Generation, the disaggregation of revenues reflects Generation’s two primary products of power sales and natural gas sales, with further disaggregation of power sales provided by geographic region. For the Utility Registrants, the disaggregation of revenues reflects the two primary utility services of rate-regulated electric sales and rate-regulated natural gas sales (where applicable), with further disaggregation of these tariff sales provided

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(Dollars in millions, except per share data, unless otherwise noted)

by major customer groups. Exelon’s disaggregated revenues are consistent with Generation and the Utility Registrants, but exclude any intercompany revenues.

Competitive Business Revenues (Generation):



	Three Months Ended June 30, 2019
	Revenues from external parties^(a)						Intersegment revenues			Total Revenues
	Contracts with customers		Other^(b)		Total		Intersegment revenues			Total Revenues
Mid-Atlantic	$	1,162	$	21	$	1,183	$	6		$	1,189
Midwest	974		68		1,042		(8		)	1,034
New York	373		17		390		—			390
ERCOT	178		47		225		4			229
Other Power Regions	814		64		878		(17		)	861
Total Competitive Businesses Electric Revenues	3,501		217		3,718		(15		)	3,703
Competitive Businesses Natural Gas Revenues	177		156		333		15			348
Competitive Businesses Other Revenues^(c)	108		51		159		—			159
Total Generation Consolidated Operating Revenues	$	3,786	$	424	$	4,210	$	—		$	4,210



	Three Months Ended June 30, 2018
	Revenues from external customers(a)							Intersegment revenues			Total Revenues
	Contracts with customers		Other(b)			Total		Intersegment revenues			Total Revenues
Mid-Atlantic	$	1,220	$	58		$	1,278	$	4		$	1,282
Midwest	1,062		73			1,135		(5		)	1,130
New York	392		(2		)	390		2			392
ERCOT	165		111			276		1			277
Other Power Regions	761		99			860		(39		)	821
Total Competitive Businesses Electric Revenues	3,600		339			3,939		(37		)	3,902
Competitive Businesses Natural Gas Revenues	295		194			489		37			526
Competitive Businesses Other Revenues^(c)	125		26			151		—			151
Total Generation Consolidated Operating Revenues	$	4,020	$	559		$	4,579	$	—		$	4,579

__________


(a)	Includes all wholesale and retail electric sales to third parties and affiliated sales to the Utility Registrants.


(b)	Includes revenues from derivatives and leases.


(c)	Other represents activities not allocated to a region. See text above for a description of included activities. Includes unrealized mark-to-market gains of $38 million and losses of $5 million in 2019 and 2018, respectively, and elimination of intersegment revenues.

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(Dollars in millions, except per share data, unless otherwise noted)

Revenues net of purchased power and fuel expense (Generation):



	Three Months Ended June 30, 2019							Three Months Ended June 30, 2018
	RNF from external customers^(a)		Intersegment RNF			Total RNF		RNF from external customers^(a)		Intersegment RNF			Total RNF
Mid-Atlantic	$	644	$	8		$	652	$	722	$	13		$	735
Midwest	738		(8		)	730		770		2			772
New York	250		3			253		259		7			266
ERCOT	80		(1		)	79		129		(47		)	82
Other Power Regions	154		(20		)	134		229		(43		)	186
Total Revenues net of purchased power and fuel for Reportable Segments	1,866		(18		)	1,848		2,109		(68		)	2,041
Other^(b)	52		18			70		190		68			258
Total Generation Revenues net of purchased power and fuel expense	$	1,918	$	—		$	1,918	$	2,299	$	—		$	2,299

__________


(a)	Includes purchases and sales from/to third parties and affiliated sales to the Utility Registrants.

(b)

Other represents activities not allocated to a region. See text above for a description of included activities. Includes unrealized mark-to-market losses of $74 million and gains of $90 million in 2019 and 2018, respectively, accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 8 — Early Plant Retirements of $5 million decrease and $20 million decrease to RNF in 2019 and 2018, respectively, and the elimination of intersegment RNF.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Electric and Gas Revenue by Customer Class (Utility Registrants):



	Three Months Ended June 30, 2019
Revenues from contracts with customers	ComEd			PECO			BGE		PHI			Pepco			DPL		ACE
Rate-regulated electric revenues
Residential	$	647		$	343		$	282	$	494		$	224		$	135	$	135
Small commercial & industrial	349			99			59		120			35			44		41
Large commercial & industrial	127			52			109		278			207			25		46
Public authorities & electric railroads	10			7			6		16			8			4		4
Other^(a)	227			62			82		159			56			54		50
Total rate-regulated electric revenues^(b)	$	1,360		$	563		$	538	$	1,067		$	530		$	262	$	276
Rate-regulated natural gas revenues
Residential	$	—		$	49		$	60	$	11		$	—		$	11	$	—
Small commercial & industrial	—			33			11		7			—			7		—
Large commercial & industrial	—			—			23		2			—			2		—
Transportation	—			6			—		3			—			3		—
Other^(c)	—			1			7		1			—			1		—
Total rate-regulated natural gas revenues^(d)	$	—		$	89		$	101	$	24		$	—		$	24	$	—
Total rate-regulated revenues from contracts with customers	$	1,360		$	652		$	639	$	1,091		$	530		$	286	$	276

Other revenues
Revenues from alternative revenue programs	$	(14	)	$	(3	)	$	6	$	(3	)	$	(1	)	$	—	$	(2	)
Other rate-regulated electric revenues^(e)	5			6			3		3			2			1		—
Other rate-regulated natural gas revenues^(e)	—			—			1		—			—			—		—
Total other revenues	$	(9	)	$	3		$	10	$	—		$	1		$	1	$	(2	)
Total rate-regulated revenues for reportable segments	$	1,351		$	655		$	649	$	1,091		$	531		$	287	$	274

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)



	Three Months Ended June 30, 2018
Revenues from contracts with customers	ComEd			PECO		BGE			PHI			Pepco			DPL		ACE
Rate-regulated electric revenues
Residential	$	699		$	338	$	295		$	505		$	228		$	142	$	135
Small commercial & industrial	357			97		60			115			33			44		38
Large commercial & industrial	127			52		101			282			212			25		45
Public authorities & electric railroads	12			6		7			16			9			3		4
Other^(a)	213			60		78			133			49			41		44
Total rate-regulated electric revenues^(b)	$	1,408		$	553	$	541		$	1,051		$	531		$	255	$	266
Rate-regulated natural gas revenues
Residential	$	—		$	62	$	74		$	13		$	—		$	13	$	—
Small commercial & industrial	—			25		13			8			—			8		—
Large commercial & industrial	—			—		23			1			—			1		—
Transportation	—			5		—			4			—			4		—
Other^(c)	—			1		12			2			—			2		—
Total rate-regulated natural gas revenues^(d)	$	—		$	93	$	122		$	28		$	—		$	28	$	—
Total rate-regulated revenues from contracts with customers	$	1,408		$	646	$	663		$	1,079		$	531		$	283	$	266

Other revenues
Revenues from alternative revenue programs	$	(17	)	$	2	$	(4	)	$	(7	)	$	(10	)	$	4	$	(1	)
Other rate-regulated electric revenues^(e)	7			5		3			4			2			2		—
Other rate-regulated natural gas revenues^(e)	—			—		—			—			—			—		—
Total other revenues	$	(10	)	$	7	$	(1	)	$	(3	)	$	(8	)	$	6	$	(1	)
Total rate-regulated revenues for reportable segments	$	1,398		$	653	$	662		$	1,076		$	523		$	289	$	265

__________


(a)	Includes revenues from transmission revenue from PJM, wholesale electric revenue and mutual assistance revenue.


(b)	Includes operating revenues from affiliates of $5 million, $1 million, $1 million, $3 million, $1 million, $2 million and $1 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2019 and $5 million, $2 million, $2 million, $3 million $2 million, $2 million and $1 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2018.


(c)	Includes revenues from off-system natural gas sales.


(d)	Includes operating revenues from affiliates of less than $1 million and $4 million at PECO and BGE, respectively, in 2019 and 2018.


(e)	Includes late payment charge revenues.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Six Months Ended June 30, 2019 and 2018



	Generation^(a)		ComEd		PECO		BGE		PHI		Other^(b)		Intersegment Eliminations			Exelon
Operating revenues^(c):
2019
Competitive businesses electric revenues	$	8,052	$	—	$	—	$	—	$	—	$	—	$	(565	)	$	7,487
Competitive businesses natural gas revenues	1,214		—		—		—		—		—		(1		)	1,213
Competitive businesses other revenues	240		—		—		—		—		—		(2		)	238
Rate-regulated electric revenues	—		2,759		1,185		1,198		2,218		—		(17		)	7,343
Rate-regulated natural gas revenues	—		—		369		427		95		—		(8		)	883
Shared service and other revenues	—		—		—		—		6		940		(944		)	2
Total operating revenues	$	9,506	$	2,759	$	1,554	$	1,625	$	2,319	$	940	$	(1,537	)	$	17,166
2018
Competitive businesses electric revenues	$	8,448	$	—	$	—	$	—	$	—	$	—	$	(663	)	$	7,785
Competitive businesses natural gas revenues	1,444		—		—		—		—		—		(8		)	1,436
Competitive businesses other revenues	198		—		—		—		—		—		(2		)	196
Rate-regulated electric revenues	—		2,910		1,193		1,206		2,214		—		(27		)	7,496
Rate-regulated natural gas revenues	—		—		325		433		106		—		(9		)	855
Shared service and other revenues	—		—		—		—		7		940		(946		)	1
Total operating revenues	$	10,090	$	2,910	$	1,518	$	1,639	$	2,327	$	940	$	(1,655	)	$	17,769
Shared service and other revenues
Intersegment revenues^(d):
2019	$	568	$	9	$	3	$	12	$	7	$	935	$	(1,534	)	$	—
2018	672		19		3		12		7		937		(1,650		)	—
Depreciation and amortization:
2019	$	814	$	508	$	164	$	252	$	369	$	47	$	—		$	2,154
2018	914		459		149		248		363		46		—			2,179
Operating expenses:
2019	$	9,059	$	2,174	$	1,187	$	1,325	$	1,981	$	942	$	(1,526	)	$	15,142
2018	9,515		2,335		1,249		1,378		2,048		936		(1,675		)	15,786
Interest expense, net:
2019	$	227	$	178	$	67	$	58	$	131	$	152	$	—		$	813
2018	202		175		64		51		128		125		—			745

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)



	Generation^(a)		ComEd		PECO			BGE		PHI		Other^(b)			Intersegment Eliminations			Exelon
Income (loss) before income taxes:
2019	$	854	$	429	$	307		$	253	$	234	$	(151	)	$	—		$	1,926
2018	412		417		207			220		173		(114		)	—			1,315
Income Taxes:
2019	$	301	$	85	$	37		$	47	$	11	$	(27	)	$	—		$	454
2018	32		88		(3		)	41		24		(57		)	—			125
Net income (loss):
2019	$	540	$	344	$	270		$	206	$	223	$	(123	)	$	—		$	1,460
2018	368		329		210			179		149		(56		)	—			1,179
Capital Expenditures
2019	$	890	$	961	$	447		$	542	$	698	$	34		$	—		$	3,572
2018	1,298		1,026		411			434		629		9			—			3,807
Total assets:
June 30, 2019	$	48,402	$	31,889	$	11,002		$	10,006	$	22,454	$	8,142		$	(10,299	)	$	121,596
December 31, 2018	47,556		31,213		10,642			9,716		21,984		8,355			(9,800		)	119,666

__________

(a)

Intersegment revenues for Generation in 2019 include revenue from sales to PECO of $80 million, sales to BGE of $133 million, sales to Pepco of $122 million, sales to DPL of $35 million and sales to ACE of $13 million in the Mid-Atlantic region, and sales to ComEd of $183 million in the Midwest region, which eliminate upon consolidation. Intersegment revenues for Generation in 2018 include revenue from sales to PECO of $61 million, sales to BGE of $128 million, sales to Pepco of $98 million, sales to DPL of $76 million and sales to ACE of $12 million in the Mid-Atlantic region, and sales to ComEd of $297 million in the Midwest region, which eliminate upon consolidation.


(b)	Other primarily includes Exelon’s corporate operations, shared service entities and other financing and investment activities.


(c)	Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 17 — Supplemental Financial Information for additional information on total utility taxes.

(d)

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

PHI:



	Pepco		DPL		ACE		Other^(b)			Intersegment Eliminations			PHI
Operating revenues^(a):
2019
Rate-regulated electric revenues	$	1,106	$	572	$	547	$	—		$	(7	)	$	2,218
Rate-regulated natural gas revenues	—		95		—		—			—			95
Shared service and other revenues	—		—		—		205			(199		)	6
Total operating revenues	$	1,106	$	667	$	547	$	205		$	(206	)	$	2,319
2018
Rate-regulated electric revenues	$	1,080	$	567	$	575	$	—		$	(8	)	$	2,214
Rate-regulated natural gas revenues	—		106		—		—			—			106
Shared service and other revenues	—		—		—		221			(214		)	7
Total operating revenues	$	1,080	$	673	$	575	$	221		$	(222	)	$	2,327
Intersegment revenues:
2019	$	3	$	3	$	1	$	205		$	(205	)	$	7
2018	3		4		2		220			(222		)	7
Depreciation and amortization:
2019	$	186	$	91	$	71	$	20		$	1		$	369
2018	188		88		69		19			(1		)	363
Operating expenses:
2019	$	929	$	550	$	498	$	208		$	(204	)	$	1,981
2018	939		582		526		224			(223		)	2,048
Interest expense, net:
2019	$	68	$	30	$	28	$	5		$	—		$	131
2018	63		27		32		5			1			128
Income (loss) before income taxes:
2019	$	123	$	94	$	25	$	219		$	(227	)	$	234
2018	94		69		18		149			(157		)	173
Income Taxes:
2019	$	4	$	11	$	1	$	(4	)	$	(1	)	$	11
2018	9		12		3		—			—			24
Net income (loss):
2019	$	119	$	83	$	24	$	(10	)	$	7		$	223
2018	85		57		15		(15		)	7			149
Capital Expenditures
2019	$	298	$	160	$	227	$	13		$	—		$	698
2018	287		166		170		6			—			629
Total assets:
June 30, 2019	$	8,556	$	4,683	$	3,886	$	11,168		$	(5,839	)	$	22,454
December 31, 2018	8,299		4,588		3,699		10,819			(5,421		)	21,984

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

__________


(a)	Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 17 — Supplemental Financial Information for additional information on total utility taxes.


(b)	Other primarily includes PHI’s corporate operations, shared service entities and other financing and investment activities.

Competitive Business Revenues (Generation):



	Six Months Ended June 30, 2019
	Revenues from external parties^(a)							Intersegment Revenues			Total Revenues
	Contracts with customers		Other^(b)			Total		Intersegment Revenues			Total Revenues
Mid-Atlantic	$	2,448	$	(2	)	$	2,446	$	(1	)	$	2,445
Midwest	2,030		126			2,156		(14		)	2,142
New York	781		1			782		—			782
ERCOT	307		126			433		8			441
Other Power Regions	1,976		259			2,235		(21		)	2,214
Total Competitive Businesses Electric Revenues	7,542		510			8,052		(28		)	8,024
Competitive Businesses Natural Gas Revenues	763		451			1,214		28			1,242
Competitive Businesses Other Revenues^(c)	230		10			240		—			240
Total Generation Consolidated Operating Revenues	$	8,535	$	971		$	9,506	$	—		$	9,506



	Six Months Ended June 30, 2018
	Revenues from external customers^(a)							Intersegment revenues			Total Revenues
	Contracts with customers		Other^(b)			Total		Intersegment revenues			Total Revenues
Mid-Atlantic	$	2,574	$	138		$	2,712	$	10		$	2,722
Midwest	2,336		143			2,479		(4		)	2,475
New York	831		(31		)	800		1			801
ERCOT	315		169			484		2			486
Other Power Regions	1,696		277			1,973		(71		)	1,902
Total Competitive Businesses Electric Revenues	7,752		696			8,448		(62		)	8,386
Competitive Businesses Natural Gas Revenues	816		628			1,444		62			1,506
Competitive Businesses Other Revenues^(c)	258		(60		)	198		—			198
Total Generation Consolidated Operating Revenues	$	8,826	$	1,264		$	10,090	$	—		$	10,090

__________


(a)	Includes all wholesale and retail electric sales to third parties and affiliated sales to the Utility Registrants.


(b)	Includes revenues from derivatives and leases.


(c)	Other represents activities not allocated to a region. See text above for a description of included activities. Includes unrealized mark-to-market losses of $14 million and $102 million in 2019 and 2018, respectively, and elimination of intersegment revenues.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Revenues net of purchased power and fuel expense (Generation):



	Six Months Ended June 30, 2019							Six Months Ended June 30, 2018
	RNF from external customers^(a)		Intersegment RNF			Total RNF		RNF from external customers^(a)		Intersegment RNF			Total RNF
Mid-Atlantic	$	1,324	$	10		$	1,334	$	1,558	$	28		$	1,586
Midwest	1,506		(6		)	1,500		1,617		14			1,631
New York	512		7			519		541		8			549
ERCOT	178		(24		)	154		235		(117		)	118
Other Power Regions	328		(36		)	292		511		(87		)	424
Total Revenues net of purchased power and fuel expense for Reportable Segments	3,848		(49		)	3,799		4,462		(154		)	4,308
Other^(b)	161		49			210		55		154			209
Total Generation Revenues net of purchased power and fuel expense	$	4,009	$	—		$	4,009	$	4,517	$	—		$	4,517

__________


(a)	Includes purchases and sales from/to third parties and affiliated sales to the Utility Registrants.

(b)

Other represents activities not allocated to a region. See text above for a description of included activities. Includes unrealized mark-to-market losses of $102 million and $175 million in 2019 and 2018, respectively, accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 8 — Early Plant Retirements of $9 million and $34 million decrease to RNF in 2019 and 2018, respectively, and the elimination of intersegment RNF.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)

Electric and Gas Revenue by Customer Class (Utility Registrants):



	Six Months Ended June 30, 2019
Revenues from contracts with customers	ComEd			PECO			BGE		PHI		Pepco		DPL		ACE
Rate-regulated electric revenues
Residential	$	1,356		$	752		$	667	$	1,073	$	480	$	320	$	273
Small commercial & industrial	709			195			129		241		73		93		75
Large commercial & industrial	259			100			219		545		411		49		85
Public authorities & electric railroads	23			14			13		31		17		7		7
Other^(a)	442			123			160		317		108		101		108
Total rate-regulated electric revenues^(b)	2,789			1,184			1,188		2,207		1,089		570		548
Rate-regulated natural gas revenues
Residential	—			247			279		55		—		55		—
Small commercial & industrial	—			105			46		26		—		26		—
Large commercial & industrial	—			1			73		3		—		3		—
Transportation	—			13			—		7		—		7		—
Other^(c)	—			3			13		4		—		4		—
Total rate-regulated natural gas revenues^(d)	—			369			411		95		—		95		—
Total rate-regulated revenues from contracts with customers	2,789			1,553			1,599		2,302		1,089		665		548

Other revenues
Revenues from alternative revenue programs	(42		)	(6		)	17		12		13		1		(1		)
Other rate-regulated electric revenues^(e)	12			7			6		5		4		1		—
Other rate-regulated natural gas revenues^(e)	—			—			3		—		—		—		—
Total other revenues	(30		)	1			26		17		17		2		(1		)
Total rate-regulated revenues for reportable segments	$	2,759		$	1,554		$	1,625	$	2,319	$	1,106	$	667	$	547

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Dollars in millions, except per share data, unless otherwise noted)



	Six Months Ended June 30, 2018
Revenues from contracts with customers	ComEd			PECO		BGE			PHI		Pepco		DPL		ACE
Rate-regulated electric revenues
Residential	$	1,416		$	741	$	688		$	1,114	$	486	$	333	$	295
Small commercial & industrial	741			198		128			230		65		90		75
Large commercial & industrial	280			110		207			541		402		48		91
Public authorities & electric railroads	25			14		14			30		16		7		7
Other^(a)	444			122		156			289		98		82		110
Total rate-regulated electric revenues^(b)	2,906			1,185		1,193			2,204		1,067		560		578
Rate-regulated natural gas revenues
Residential	—			223		298			60		—		60		—
Small commercial & industrial	—			87		47			26		—		26		—
Large commercial & industrial	—			1		70			5		—		5		—
Transportation	—			11		—			9		—		9		—
Other^(c)	—			3		40			6		—		6		—
Total rate-regulated natural gas revenues^(d)	—			325		455			106		—		106		—
Total rate-regulated revenues from contracts with customers	2,906			1,510		1,648			2,310		1,067		666		578

Other revenues
Revenues from alternative revenue programs	(12		)	1		(17		)	12		10		5		(3		)
Other rate-regulated electric revenues^(e)	16			7		6			5		3		2		—
Other rate-regulated natural gas revenues^(e)	—			—		2			—		—		—		—
Total other revenues	4			8		(9		)	17		13		7		(3		)
Total rate-regulated revenues for reportable segments	$	2,910		$	1,518	$	1,639		$	2,327	$	1,080	$	673	$	575

__________


(a)	Includes revenues from transmission revenue from PJM, wholesale electric revenue and mutual assistance revenue.


(b)	Includes operating revenues from affiliates of $9 million, $2 million, $1 million, $7 million, $3 million, $3 million and $1 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2019 and $19 million, $3 million, $3 million, $7 million $3 million, $4 million and $2 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2018.


(c)	Includes revenues from off-system natural gas sales.


(d)	Includes operating revenues from affiliates of $1 million and $9 million at PECO and BGE, respectively, in 2019 and less than $1 million and $9 million at PECO and BGE, respectively, in 2018,


(e)	Includes late payment charge revenues.

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Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations

(Dollars in millions except per share data, unless otherwise noted)

Exelon

Executive Overview

Exelon is a utility services holding company engaged in the generation, delivery, and marketing of energy through Generation and the energy distribution and transmission businesses through ComEd, PECO, BGE, Pepco, DPL and ACE.

Exelon has eleven reportable segments consisting of Generation’s five reportable segments (Mid-Atlantic, Midwest, New York, ERCOT and Other Power Regions), ComEd, PECO, BGE, Pepco, DPL and ACE. During the first quarter of 2019, due to a change in economics in our New England region, Generation changed the way that information is reviewed by the CODM. The New England region will no longer be regularly reviewed as a separate region by the CODM nor will it be presented separately in any external information presented to third parties. Information for the New England region will be reviewed by the CODM as part of Other Power Regions. As a result, beginning in the first quarter of 2019, Generation disclosed five reportable segments consisting of Mid-Atlantic, Midwest, New York, ERCOT and Other Power Regions. See Note 1 — Significant Accounting Policies and Note 18 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information regarding Exelon's principal subsidiaries and reportable segments.

Exelon’s consolidated financial information includes the results of its eight separate operating subsidiary registrants, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, which, along with Exelon, are collectively referred to as the Registrants. The following combined Management’s Discussion and Analysis of Financial Condition and Results of Operations is separately filed by Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE. However, none of the Registrants makes any representation as to information related solely to any of the other Registrants.

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Financial Results of Operations

GAAP Results of Operations. The following table sets forth Exelon's GAAP consolidated Net Income attributable to common shareholders by Registrant for the three and six months ended June 30, 2019 compared to the same period in 2018. For additional information regarding the financial results for the three and six months ended June 30, 2019 and 2018 see the discussions of Results of Operations by Registrant.



	Three Months Ended June 30,				Favorable (unfavorable) variance			Six Months Ended June 30,						Favorable (unfavorable) variance
	2019		2018		Favorable (unfavorable) variance			2019			2018			Favorable (unfavorable) variance
Exelon	484		539		$	(55	)	$	1,391		$	1,125		$	266
Generation	108		178		(70		)	472			314			158
ComEd	186		164		22			344			329			15
PECO	102		96		6			270			210			60
BGE	45		51		(6		)	206			179			27
PHI	106		84		22			223			149			74
Pepco	64		54		10			119			85			34
DPL	30		26		4			83			57			26
ACE	14		8		6			24			15			9
Other^(a)	(63	)	(34	)	(29		)	(124		)	(56		)	(68		)

__________


(a)	Primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities and other financing and investing activities.

Three Months Ended June 30, 2019 Compared to Three Months Ended June 30, 2018. Net income attributable to common shareholders decreased by $55 million and diluted earnings per average common share decreased to $0.50 in 2019 from $0.56 in 2018 primarily due to:


•	Lower realized energy prices; and


•	Increased mark-to-market losses.

The decreases were partially offset by:


•	Higher net unrealized and realized gains on NDT Funds;


•	Decreased accelerated depreciation and amortization due to the early retirement of the Oyster Creek nuclear facility in September 2018;


•	Increased New York ZEC prices and the approval of the New Jersey ZEC Program in the second quarter of 2019; and


•	Regulatory rate increases at PECO, BGE, Pepco, DPL and ACE.

Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018. Net income attributable to common shareholders increased by $266 million and diluted earnings per average common share increased to $1.43 in 2019 from $1.16 in 2018 primarily due to:


•	Higher net unrealized and realized gains on NDT Funds;


•	Decreased accelerated depreciation and amortization due to the early retirement of the Oyster Creek nuclear facility in September 2018;


•	A benefit associated with the remeasurement of the TMI ARO in 2019;


•	Decreased mark-to-market losses;

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•	Regulatory rate increases at PECO, BGE, Pepco, DPL, and ACE; and


•	Decreased storms costs at PECO and BGE.

The increases were partially offset by:


•	Lower realized energy prices; and


•	The absence of the revenues recognized in the first quarter of 2018 related to ZECs generated in Illinois from June through December 2017, partially offset by increased New York ZEC prices and the approval of the New Jersey ZEC Program in the second quarter of 2019.

Adjusted (non-GAAP) Operating Earnings. In addition to net income, Exelon evaluates its operating performance using the measure of Adjusted (non-GAAP) operating earnings because management believes it represents earnings directly related to the ongoing operations of the business. Adjusted (non-GAAP) operating earnings exclude certain costs, expenses, gains and losses and other specified items. This information is intended to enhance an investor’s overall understanding of year-to-year operating results and provide an indication of Exelon’s baseline operating performance excluding items that are considered by management to be not directly related to the ongoing operations of the business. In addition, this information is among the primary indicators management uses as a basis for evaluating performance, allocating resources, setting incentive compensation targets and planning and forecasting of future periods. Adjusted (non-GAAP) operating earnings is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.

The following tables provide a reconciliation between net income attributable to common shareholders as determined in accordance with GAAP and adjusted (non-GAAP) operating earnings for the three and six months ended June 30, 2019 compared to the same period in 2018.



	Three Months Ended June 30,
	2019						2018
(All amounts in millions after tax)				Earnings per Diluted Share						Earnings per Diluted Share
Net Income Attributable to Common Shareholders	$	484		$	0.50		$	539		$	0.56
Mark-to-Market Impact of Economic Hedging Activities(net of taxes of $22 and $23, respectively)	68			0.07			(67		)	(0.07		)
Unrealized Losses Related to NDT Fund Investments (net of taxes of $28 and $77, respectively)^(a)	52			0.05			81			0.08
PHI Merger and Integration Costs(net of taxes of $0)	—			—			1			—
Long-Lived Asset Impairments (net of taxes of $1 and $11, respectively)^(b)	1			—			30			0.03
Plant Retirements and Divestitures(net of taxes of $37 and $47, respectively)^(c)	(24		)	(0.02		)	127			0.14
Cost Management Program (net of taxes of $1 and $4, respectively)^(d)	6			0.01			12			0.01
Change in Environmental Liabilities(net of taxes of $2)	—			—			5			0.01
Reassessment of Deferred Income Taxes (entire amount represents tax expense)^(e)	—			—			(8		)	(0.01		)
Litigation Settlement Gain (net of taxes of $7)	(19		)	(0.02		)	—			—
Noncontrolling Interests (net of taxes of $3 and $7, respectively)^(f)	15			0.02			(34		)	(0.04		)
Adjusted (non-GAAP) Operating Earnings	$	583		$	0.60		$	686		$	0.71

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	Six Months Ended June 30,
	2019						2018
(All amounts in millions after tax)				Earnings per Diluted Share						Earnings per Diluted Share
Net Income Attributable to Common Shareholders	$	1,391		$	1.43		$	1,125		$	1.16
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $34 and $46, respectively)	98			0.10			129			0.13
Unrealized (Gains) Losses Related to NDT Fund Investments(net of taxes of $133 and $122, respectively)^(a)	(142		)	(0.15		)	147			0.15
PHI Merger and Integration Costs(net of taxes of $2)	—			—			4
Long-Lived Asset Impairments(net of taxes of $2 and $11, respectively)^(b)	6			0.01			30			0.03
Plant Retirements and Divestitures(net of taxes of $32 and $78, respectively)^(c)	(4		)	—			220			0.23
Cost Management Program(net of taxes of $7 and $6, respectively)^(d)	16			0.02			16			0.02
Change in Environmental Liabilities(net of taxes of $2)	—			—			5			0.01
Reassessment of Deferred Income Taxes(entire amount represents tax expense)^(e)	—			—			(8		)	(0.01		)
Litigation Settlement Gain (net of taxes of $7)	(19		)	(0.02		)	—			—
Noncontrolling Interests(net of taxes of $15 and $13, respectively)^(f)	82			0.08			(57		)	(0.06		)
Adjusted (non-GAAP) Operating Earnings	$	1,429		$	1.47		$	1,611		$	1.66

__________

Note:

Amounts may not sum due to rounding.

Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net Income and Adjusted (non-GAAP) Operating Earnings is based on the marginal statutory federal and state income tax rates for each Registrant, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part. For all items except the unrealized gains and losses related to NDT fund investments, the marginal statutory income tax rates for 2019 and 2018 ranged from 26.0 percent to 29.0 percent. Under IRS regulations, NDT fund investment returns are taxed at different rates for investments if they are in qualified or non-qualified funds. The effective tax rates for the unrealized gains and losses related to NDT fund investments were 35.1 percent and 48.9 percent for the three months ended June 30, 2019 and 2018, respectively. The effective tax rates for the unrealized gains and losses related to NDT fund investments were 48.4 percent and 45.3 percent for the six months ended June 30, 2019 and 2018, respectively.


(a)	Reflects the impact of net unrealized gains and losses on Generation’s NDT fund investments for Non-Regulatory and Regulatory Agreement Units. The impacts of the Regulatory Agreement Units, including the associated income taxes, are contractually eliminated, resulting in no earnings impact.


(b)	In 2018, primarily reflects the impairment of certain wind projects at Generation.

(c)

In 2018, primarily reflects accelerated depreciation and amortization expenses and one-time charges associated with Generation's decision to early retire the Oyster Creek nuclear facility, as well as accelerated depreciation and amortization expenses associated with the 2017 decision to early retire the Three Mile Island nuclear facility, partially offset by a gain associated with Generation's sale of its electrical contracting business. In 2019, primarily reflects net realized gains related to Oyster Creek's NDT fund investments in conjunction with the Holtec sale on July 1, 2019, a benefit associated with a remeasurement in the first quarter 2019 of the TMI asset retirement obligation and a gain on the sale of certain wind assets in the second quarter of 2019, partially offset by accelerated depreciation and amortization expenses associated with Generation's previous decision to early retire the TMI nuclear facility.


(d)	Primarily represents reorganization costs related to cost management programs.


(e)	Reflects an adjustment to the remeasurement of deferred income taxes as a result of the TCJA.


(f)	Represents elimination from Generation’s results of the noncontrolling interests related to certain exclusion items, primarily related to the impact of unrealized gains and losses on NDT fund investments at CENG.

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Significant 2019 Transactions and Developments

Utility Rates and Base Rate Proceedings

The Utility Registrants file base rate cases with their regulatory commissions seeking increases or decreases to their electric transmission and distribution, and gas distribution rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Utility Registrants’ current and future financial statements.

The following tables show the Utility Registrants’ completed and pending distribution base rate case proceedings in 2019. See Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on these and other regulatory proceedings.

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)	April 16, 2018	$	(23	)	$	(24	)	8.69	%	December 4, 2018	January 1, 2019
PECO - Pennsylvania (Electric)	March 29, 2018	$	82		$	25		N/A		December 20, 2018	January 1, 2019
BGE - Maryland (Natural Gas)	June 8, 2018 (amended October 12, 2018)	$	61		$	43		9.8	%	January 4, 2019	January 4, 2019
ACE - New Jersey (Electric)	August 21, 2018 (amended November 19, 2018)	$	122		$	70		9.6	%	March 13, 2019	April 1, 2019

Pending Distribution Base Rate Case Proceedings



Registrant/Jurisdiction	Filing Date	Requested Revenue Requirement Increase (Decrease)			Requested ROE		Expected Approval Timing
Pepco - Maryland (Electric)	January 15, 2019 (amended May 16, 2019)	$	27		10.3	%	Third quarter of 2019
ComEd - Illinois (Electric)	April 8, 2019	$	(6	)	8.91	%	December 2019
BGE - Maryland (Electric)	May 24, 2019	$	74		10.3	%	December 2019
BGE - Maryland (Natural Gas)	May 24, 2019	$	59		10.3	%	December 2019
Pepco - District of Columbia (Electric)	May 30, 2019	$	162		10.3	%	Second quarter of 2020

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Transmission Formula Rate

The following total (decreases)/increases were included in ComEd's, BGE's, Pepco's, DPL's and ACE's 2019 annual electric transmission formula rate updates.



Registrant	Initial Revenue Requirement Increase (Decrease)			Annual Reconciliation Increase (Decrease)			Total Revenue Requirement Increase (Decrease)			Allowed Return on Rate Base		Allowed ROE
ComEd	$	21		$	(16	)	$	5		8.21	%	11.50	%
BGE	(10		)	(23		)	(19		)	7.35	%	10.50	%
Pepco	15			11			26			7.75	%	10.50	%
DPL	17			(1		)	16			7.14	%	10.50	%
ACE	11			(2		)	9			7.79	%	10.50	%

PECO Transmission Formula Rate

On May 1, 2017, PECO filed a request with FERC seeking approval to update its transmission rates and change the manner in which PECO’s transmission rate is determined from a fixed rate to a formula rate. The formula rate will be updated annually to ensure that under this rate customers pay the actual costs of providing transmission services. PECO’s initial formula rate filing included a requested increase of $22 million to PECO’s annual transmission revenue requirement, which reflected a ROE of 11%, inclusive of a 50 basis point adder for being a member of a RTO. On June 27, 2017, FERC issued an Order accepting the filing and suspending the proposed rates until December 1, 2017, subject to refund, and set the matter for hearing and settlement judge procedures.

Early Plant Retirements and Divestitures

Oyster Creek. Generation permanently ceased generation operations at Oyster Creek in September 2018. On July 31, 2018, Generation entered into an agreement with Holtec International and its wholly owned subsidiary, Oyster Creek Environmental Protection, LLC, for the sale and decommissioning of Oyster Creek. The sale was completed on July 1, 2019. Exelon and Generation expect the loss on the sale, which will be recognized in the third quarter, to be immaterial. See Note 3 — Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.

Three Mile Island. On May 30, 2017, Generation announced it will permanently cease generation operations at TMI on or about September 30, 2019. As a result of the previous decision to early retire TMI, Exelon and Generation recorded a $75 million and $71 million incremental pre-tax net charge for the three and six months ended June 30, 2019 primarily due to accelerated depreciation of the plant assets, partially offset by a benefit associated with the remeasurement of the TMI ARO in the first quarter of 2019. For the full year ended December 31, 2019, Exelon and Generation estimate approximately $155 million of incremental pre-tax net non-cash charges associated with the early retirement of TMI, primarily due to accelerated depreciation of the plant assets.

Salem. In 2017, PSEG announced that its New Jersey nuclear plants, including Salem, of which Generation owns a 42.59% ownership interest, were showing increased signs of economic distress, which could lead to an early retirement. PSEG is the operator of Salem and also has the decision making authority to retire Salem. In 2018, New Jersey enacted legislation that established a ZEC program that provides compensation for nuclear plants that

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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. On April 18, 2019, the NJBPU approved the award of ZECs to Salem 1 and Salem 2. Assuming the continued effectiveness of the New Jersey ZEC program, Generation no longer considers Salem to be at heightened risk for early retirement.

Dresden, Byron and Braidwood. Generation’s Dresden, Byron and Braidwood nuclear plants in Illinois are also showing increased signs of economic distress, which could lead to an early retirement, in a market that does not currently compensate them for their unique contribution to grid resiliency and their ability to produce large amounts of energy without carbon and air pollution. The May 2018 PJM capacity auction for the 2021-2022 planning year resulted in the largest volume of nuclear capacity ever not selected in the auction, including all of Dresden, and portions of Byron and Braidwood. Exelon continues to work with stakeholders on state policy solutions, while also advocating for broader market reforms at the regional and federal level.

See Note 6 — Regulatory Matters, Note 8 — Early Plant Retirements and Note 13 — Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements for additional information.

Pacific Gas & Electric Bankruptcy

Generation’s Antelope Valley, a 242 MW solar facility in Lancaster, CA, sells all of its output to PG&E through a PPA. On January 29, 2019, PG&E filed for protection under Chapter 11 of the U.S. Bankruptcy Code. As of June 30, 2019, Generation had approximately $740 million and $500 million of net long-lived assets and nonrecourse debt outstanding, respectively, related to Antelope Valley. PG&E’s bankruptcy created an event of default for Antelope Valley’s nonrecourse debt that provides the lender with a right to accelerate amounts outstanding under the loan such that they would become immediately due and payable. As a result of the ongoing event of default and the absence of a waiver from the lender foregoing their acceleration rights, the debt was reclassified as current in Exelon’s and Generation’s Consolidated Balance Sheets in the first quarter of 2019 and continues to be classified as current as of June 30, 2019.

In the first quarter of 2019, Generation assessed and determined that Antelope Valley’s long-lived assets were not impaired. Significant changes in assumptions such as the likelihood of the PPA being rejected as part of the bankruptcy proceedings could potentially result in future impairments of Antelope Valley's net long-lived assets, which could be material. Generation is monitoring the bankruptcy proceedings for any changes in circumstances that would indicate the carrying amount of the net long-lived assets of Antelope Valley may not be recoverable.

See Note 7 — Impairment of Long-Lived Assets and Note 11 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the PG&E bankruptcy.

Other Key Business Drivers and Management Strategies

The following discussion of other key business driver and management strategies includes current developments of previously disclosed matters and new issues arising during the period that may impact future financial statements. This section should be read in conjunction with ITEM 1. Business and ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Other Key Business Drivers and Management Strategies in the Registrants' combined 2018 Form 10-K and Note 16 - Commitments and Contingencies to the Consolidated Financial Statements in this report for additional information on various environmental matters.

Power Markets

Complaints and PJM Filing at FERC Seeking to Mitigate ZEC Programs

PJM and NYISO capacity markets include a MOPR that is intended to preclude buyers from exercising buyer market power. If a resource is subjected to a MOPR, its offer is adjusted to effectively remove the revenues it receives through a government-provided financial support program - resulting in a higher offer that may not clear the capacity market. Currently, the MOPRs in PJM and NYISO apply only to certain new gas-fired resources.

On January 9, 2017, EPSA filed two requests with FERC: one seeking to amend a prior complaint against PJM and another seeking expedited action on a pending NYISO compliance filing in an existing proceeding. A similar complaint also against PJM was filed at FERC on May 31, 2018. These complaints generally allege that the relevant MOPR should be expanded to also apply to existing resources including those receiving ZEC compensation under the New

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Jersey ZEC, New York CES and Illinois ZES programs. Exelon filed protests at FERC in response to each filing, arguing generally that ZEC payments provide compensation for an environmental attribute and are no different than other renewable support programs that have generally not been subject to a MOPR. However, if successful, for Generation’s facilities in PJM and NYISO that are currently receiving ZEC compensation, an expanded MOPR could 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, which could have a material effect on Exelon’s and Generation’s future cash flows and results of operations.

In June 2018, FERC addressed one of the MOPR complaints involving PJM and concluded that PJM’s existing tariff allows resources receiving out-of-market support to affect capacity prices in a manner that will cause unjust and unreasonable and unduly discriminatory rates in PJM. FERC suggested that modifying two elements of PJM’s existing tariff, as follows could produce a just and reasonable replacement.


•	An expansion of the current MOPR mechanism to cover all existing generating resources, regardless of resource type, including those receiving either ZEC or REC compensation, could protect the capacity markets from unwanted price suppression.

•

A modified version of PJM’s existing Fixed Resource Requirement (FRR) option could enable state subsidized resources and a corresponding amount of load to be removed from the capacity market, thereby alleviating their price suppressive effects on capacity clearing prices. Under this alternative, state supported generating resources would potentially be compensated through mechanisms other than through PJM’s existing market mechanism.

FERC established March 21, 2016 as the refund effective date and also allowed PJM to delay its next capacity auction from May 2019 to August 2019 to allow parties time to file proposals in the FERC proceeding, FERC time to determine the appropriate solution and PJM time to implement FERC's solution. On October 2, 2018, Exelon, along with several ratepayer advocates, environmental organizations and other nuclear generators, submitted shared principles supporting a workable new FRR mechanism. FERC has not yet issued a decision on the second MOPR complaint involving PJM or the MOPR complaint involving NYISO. On April 10, 2019, PJM notified FERC of its intent to proceed with the next capacity auction in August 2019 under the existing market rules and asked FERC to clarify that it would not require PJM to re-run the auction in the event FERC alters those market rules in its decision on the MOPR complaint. On July 25, 2019, FERC issued an order denying PJM’s request to clarify that any alteration of PJM’s existing market rules would operate prospectively and, therefore, directed PJM to not conduct the capacity auction in August 2019. It is too early to predict the final outcome of each of these proceedings or their potential financial impact, if any, on Exelon or Generation.

Complaint at FERC Seeking to Alter Capacity Market Default Offer Caps

On February 21, 2019, PJM’s Independent Market Monitor (IMM) filed a complaint alleging that the number of performance assessment intervals used to calculate the default offer cap for bids to supply capacity in PJM is too high, resulting in an overstated default offer cap that obviates the need for most sellers to seek unit-specific approval of their offers. The IMM claims that this allows for the exercise of market power. The IMM asks FERC to require PJM to reduce the number of performance assessment intervals used to calculate the opportunity costs of a capacity supplier assuming a capacity obligation. This would, in turn, lower the default offer cap and allow the IMM to review more offers on a unit-specific basis. It is too early to predict the final outcome of this proceeding or its potential financial impact, if any, on Exelon or Generation.

Section 232 Uranium Petition

On January 16, 2018, two Canadian-owned uranium mining companies with operations in the U.S. jointly submitted a petition to the U.S. Department of Commerce (DOC) seeking relief under Section 232 of the Trade Expansion Act of 1962, as amended, (the Act) from imports of uranium products, alleging that these imports threaten national security (the Petition). The relief requested would have required U.S. nuclear reactors to purchase at least 25% of their uranium needs from domestic mines for the next 10 years or more. The Act was promulgated by Congress to protect essential national security industries whose survival is threatened by imports. As such, the Act authorizes the Secretary of Commerce (the Secretary) to conduct investigations to evaluate the effects of imports of any item on the national security of the U.S. The Petition alleges that the loss of a viable U.S. uranium mining industry would have a significant detrimental impact on the national, energy, and economic security of the U.S. and the ability of the country to sustain an independent nuclear fuel cycle.

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On July 18, 2018, the Secretary announced that the DOC had initiated an investigation in response to the petition. The Secretary submitted a report to President Trump on April 14, 2019 that has not been made public. On July 12, 2019, the President issued a memorandum indicating that he did not agree with the Secretary’s finding that uranium imports threaten to impair the national security of the United States, choosing not to impose any trade restrictions at this time. The President found that a fuller analysis of national security considerations with respect to the entire nuclear fuel supply chain is necessary and directed that a United States Nuclear Fuel Working Group (Working Group) be established to develop recommendations for reviving and expanding domestic nuclear fuel production with a mandate to submit a report back to him within 90 days. The Working Group is to be co-chaired by the Assistant to the President for National Security Affairs and the Assistant to the President for Economic Policy. Exelon will monitor and volunteer to provide information to support the Working Group’s efforts. Exelon and Generation cannot currently predict the outcome of the Working Group report and subsequent actions.

Hedging Strategy

Exelon’s policy to hedge commodity risk on a ratable basis over three-year periods is intended to reduce the financial impact of market price volatility. Generation is exposed to commodity price risk associated with the unhedged portion of its electricity portfolio. Generation enters into non-derivative and derivative contracts, including financially-settled swaps, futures contracts and swap options, and physical options and physical forward contracts, all with credit-approved counterparties, to hedge this anticipated exposure. As of June 30, 2019, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York and ERCOT reportable segments is 92%-95%, 70%-73% and 40%-43% for 2019, 2020, and 2021 respectively. Generation has been and will continue to be proactive in using hedging strategies to mitigate commodity price risk.

Generation procures natural gas through long-term and short-term contracts and spot-market purchases. Nuclear fuel assemblies are obtained predominantly through long-term uranium concentrate supply contracts, contracted conversion services, contracted enrichment services, or a combination thereof, and contracted fuel fabrication services. The supply markets for uranium concentrates and certain nuclear fuel services are subject to price fluctuations and availability restrictions. Approximately 62% of Generation’s uranium concentrate requirements from 2019 through 2023 are supplied by three producers. In the event of non-performance by these or other suppliers, Generation believes that replacement uranium concentrate can be obtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements. Non-performance by these counterparties could have a material adverse impact on Exelon’s and Generation’s financial statements.

See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements and Item 3. Quantitative and Qualitative Disclosures about Market Risk for additional information.

The Utility Registrants mitigate commodity price risk through regulatory mechanisms that allow them to recover procurement costs from retail customers.

Environmental Legislative and Regulatory Developments

Air Quality

Clean Power Plan. On April 28, 2017, the D.C. Circuit Court issued orders in separate litigation related to the EPA’s actions under the Clean Power Plan (CPP) to amend Clean Air Act Section 111(d) regulation of existing fossil-fired electric generating units and Section 111(b) regulation of new fossil-fired electric generating units. In both cases, the Court has determined to hold the litigation in abeyance pending a determination whether the rule should be remanded to the EPA. In June 2019, EPA issued a final rule that repealed the CPP, and finalized the Affordable Clean Energy (ACE) rule to replace the CPP with less stringent emissions guidelines based on heat rate improvement measures that could be achieved within the fence line of existing power plants.

Primary SO2 National Ambient Air Quality Standards (NAAQS). EPA took final action on April 17, 2019 to retain the current primary SO2 standard without revision, leaving the standard established in 2010 in effect.

See Note 16 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information related to environmental matters, including the impact of environmental regulation.

Other Legislative and Regulatory Developments

Illinois Clean Energy Progress Act

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On March 14, 2019, the Clean Energy Progress Act was introduced in the Illinois General Assembly to preserve Illinois’ clean energy choices arising from FEJA and empower the IPA to conduct capacity procurements outside of PJM’s base residual auction process, while utilizing the fixed resource requirement provisions in PJM's tariffs which are still subject to penalties and other obligations under the PJM tariffs. The most significant provisions of the proposed legislation are as follows: (1) it allows the IPA to procure capacity directly from clean energy resources that have previously sold ZECs or RECs, including certain of Generation’s nuclear plants in Illinois, or from new clean energy resources, (2) it establishes a goal of achieving 100% carbon-free power in the ComEd service territory by 2032, and (3) it implements reforms to enhance consumer protections in the state’s competitive retail electricity and natural gas markets, including Generation’s retail customers. Energy legislation has also been proposed by other stakeholders, including renewable resource developers, environmental advocates, and coal-fueled generators. Exelon and Generation are working with legislators and stakeholders and cannot predict the outcome or the potential financial impact, if any, on Exelon or Generation.

Keep Powering Pennsylvania Act

On March 11, 2019, the Keep Powering Pennsylvania Act was introduced in the Pennsylvania General Assembly to amend the Alternative Energy Portfolio Standards Act of 2004. The proposed legislation recognizes the value that all zero-emission electric generation resources provide to Pennsylvania by adding nuclear plants and certain other renewable generation resources (Tier III resources) to the zero-emission electric generation resources that currently receive alternative energy credits in Pennsylvania. Further, the proposed legislation would allow for these Tier III resources to continue to receive capacity payments at the same level as the PJM capacity auction clearing price. In order to initially qualify as a Tier III resource, a resource must make a commitment to operate for at least six years. The price of the alternative energy credits for Tier III resources is tied to the value of existing Tier I resources, with a price cap. Regulated utilities, including PECO, would be required to purchase alternative energy credits for all retail customers and allowed to recover those costs from customers. Exelon and Generation are working with legislators and stakeholders and cannot predict the outcome or the potential financial impact, if any, on Exelon or Generation.

Nuclear Powers Act of 2019

On April 12, 2019, the Nuclear Powers America Act of 2019 was introduced to the United States Congress, which expands the current investment tax credit to existing nuclear power plants. The proposed legislation would provide a credit equal to 30% of continued capital investment in certain nuclear energy-related expenditures, including capital expenses and nuclear fuel, starting from tax years 2019 through 2023. Thereafter, the credit rate would be reduced to 26% in 2024, 22% in 2025, and 10% in 2026 and beyond. To qualify for the credit, the plant must be currently operational and must have applied for an operating license renewal before 2026. Exelon and Generation are working with legislators and stakeholders and cannot predict the outcome or the potential financial impact, if any, on Exelon or Generation.

Employees

In April 2019, the CBAs with IBEW Local 15 covering employees at BSC, ComEd and Generation, were extended through 2024. The CBA between Pepco and IBEW Local 1900 was scheduled to expire on May 26, 2019, but has been extended to September 7, 2019. On June 23, 2019, BGE’s union contract for the 1,400 employees within local 410 was ratified. BGE is now in the process of implementing its terms, which do not have a material impact on BGE's financial statements.

Critical Accounting Policies and Estimates

Management of each of the Registrants makes a number of significant estimates, assumptions and judgments in the preparation of its financial statements. At June 30, 2019, the Registrants’ critical accounting policies and estimates had not changed significantly from December 31, 2018. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — CRITICAL ACCOUNTING POLICIES AND ESTIMATES in the Registrants' 2018 Form 10-K for further information.

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Results of Operations by Registrant

The Registrants' Results of Operations includes discussion of RNF, which is a financial measure not defined under GAAP and may not be comparable to other companies' presentations or deemed more useful than the GAAP information provided elsewhere in this report. The CODMs for Exelon and Generation evaluate the performance of Generation's electric business activities and allocate resources based on RNF. Generation believes that RNF is a useful measure because it provides information that can be used to evaluate its operational performance. For the Utility Registrants, their Operating revenues reflect the full and current recovery of commodity procurement costs given the rider mechanisms approved by their respective state regulators. The commodity procurement costs, which are recorded in Purchased power and fuel expense, and the associated revenues can be volatile. Therefore, the Utility Registrants believe that RNF is a useful measure because it excludes the effect on Operating revenues caused by the volatility in these expenses.

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Generation

Results of Operations — Generation



	Three Months Ended June 30,						Favorable (Unfavorable) Variance			Six Months Ended June 30,						Favorable (Unfavorable) Variance
	2019			2018			Favorable (Unfavorable) Variance			2019			2018			Favorable (Unfavorable) Variance
Operating revenues	$	4,210		$	4,579		$	(369	)	$	9,506		$	10,090		$	(584	)
Purchased power and fuel expense	2,292			2,280			(12		)	5,497			5,573			76
Revenues net of purchased power and fuel expense	1,918			2,299			(381		)	4,009			4,517			(508		)
Other operating expenses
Operating and maintenance	1,266			1,418			152			2,484			2,756			272
Depreciation and amortization	409			466			57			814			914			100
Taxes other than income	129			134			5			264			272			8
Total other operating expenses	1,804			2,018			214			3,562			3,942			380
Gain on sales of assets and businesses	33			1			32			33			54			(21		)
Operating income	147			282			(135		)	480			629			(149		)
Other income and (deductions)
Interest expense, net	(116		)	(102		)	(14		)	(227		)	(202		)	(25		)
Other, net	171			29			142			601			(15		)	616
Total other income and (deductions)	55			(73		)	128			374			(217		)	591
Income before income taxes	202			209			(7		)	854			412			442
Income taxes	78			23			(55		)	301			32			(269		)
Equity in losses of unconsolidated affiliates	(6		)	(5		)	(1		)	(13		)	(12		)	(1		)
Net income	118			181			(63		)	540			368			172
Net income attributable to noncontrolling interests	10			3			(7		)	68			54			(14		)
Net income attributable to membership interest	$	108		$	178		$	(70	)	$	472		$	314		$	158

Three Months Ended June 30, 2019 Compared to Three Months Ended June 30, 2018. Net income attributable to membership interest decreased by $70 million primarily due to:


•	Lower realized energy prices; and


•	Increased mark-to-market losses.

The decreases were partially offset by:


•	Higher net unrealized and realized gains on NDT funds;


•	Decreased accelerated depreciation and amortization due to the early retirement of the Oyster Creek nuclear facility in September 2018; and


•	Increased New York ZEC prices and the approval of the New Jersey ZEC Program in the second quarter of 2019.

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Generation

Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018. Net income attributable to membership interest increased by $158 million primarily due to:


•	Higher net unrealized and realized gains on NDT funds;


•	Decreased accelerated depreciation and amortization due to the early retirement of the Oyster Creek nuclear facility in September 2018;


•	A benefit associated with the remeasurement of the TMI ARO in 2019; and


•	Decreased mark-to-market losses.

The increases were partially offset by:


•	Lower realized energy prices; and


•	The absence of revenues recognized in the first quarter of 2018 related to ZECs generated in Illinois from June through December 2017, partially offset by increased New York ZEC prices and approval of New Jersey ZECs in the second quarter of 2019.

Revenues Net of Purchased Power and Fuel Expense. The basis for Generation's reportable segments is the integrated management of its electricity business that is located in different geographic regions, and largely representative of the footprints of ISO/RTO and/or NERC regions, which utilize multiple supply sources to provide electricity through various distribution channels (wholesale and retail). Generation's hedging strategies and risk metrics are also aligned with these same geographic regions. Generation's five reportable segments are Mid-Atlantic, Midwest, New York, ERCOT and Other Power Regions. During the first quarter of 2019, due to a change in economics in our New England region, Generation is changing the way that information is reviewed by the CODM. The New England region will no longer be regularly reviewed as a separate region by the CODM nor will it be presented separately in any external information presented to third parties. Information for the New England region will be reviewed by the CODM as part of Other Power Regions. See Note 24 - Segment Information of the Combined Notes to Consolidated Financial Statements for additional information.

The following business activities are not allocated to a region and are reported under Other: natural gas, as well as other miscellaneous business activities that are not significant to overall operating revenues or results of operations. Further, the following activities are not allocated to a region and are reported in Other: accelerated nuclear fuel amortization associated with nuclear decommissioning; and other miscellaneous revenues.

Generation evaluates the operating performance of electric business activities using the measure of RNF. Operating revenues include all sales to third parties and affiliated sales to the Utility Registrants. Purchased power costs include all costs associated with the procurement and supply of electricity including capacity, energy and ancillary services. Fuel expense includes the fuel costs for owned generation and fuel costs associated with tolling agreements.

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Generation

For the three and six months ended June 30, 2019 and 2018, RNF by region were as follows:



	Three Months Ended June 30,					Variance			% Change		Six Months Ended June 30,						Variance			% Change
	2019			2018		Variance			% Change		2019			2018			Variance			% Change
Mid-Atlantic^(a)	$	652		$	735	$	(83	)	(11.3	)%	$	1,334		$	1,586		$	(252	)	(15.9	)%
Midwest^(b)	730			772		(42		)	(5.4	)%	1,500			1,631			(131		)	(8.0	)%
New York	253			266		(13		)	(4.9	)%	519			549			(30		)	(5.5	)%
ERCOT	79			82		(3		)	(3.7	)%	154			118			36			30.5	%
Other Power Regions	134			186		(52		)	(28.0	)%	292			424			(132		)	(31.1	)%
Total electric revenue net of purchased power and fuel expense	1,848			2,041		(193		)	(9.5	)%	3,799			4,308			(509		)	(11.8	)%
Proprietary Trading	7			29		(22		)	(75.9	)%	11			35			(24		)	(68.6	)%
Mark-to-market gains (losses)	(74		)	90		(164		)	(182.2	)%	(102		)	(175		)	73			(41.7	)%
Other	137			139		(2		)	(1.4	)%	301			349			(48		)	(13.8	)%
Total revenue net of purchased power and fuel expense	$	1,918		$	2,299	$	(381	)	(16.6	)%	$	4,009		$	4,517		$	(508	)	(11.2	)%

_________


(a)	Includes results of transactions with PECO, BGE, Pepco, DPL and ACE.


(b)	Includes results of transactions with ComEd.

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Generation

Generation’s supply sources by region are summarized below:



	Three Months Ended June 30,		Variance		% Change		Six Months Ended June 30,		Variance		% Change
Supply source (GWhs)	2019	2018	Variance		% Change		2019	2018	Variance		% Change
Nuclear Generation^(a)
Mid-Atlantic	14,075	16,498	(2,423	)	(14.7	)%	29,155	32,727	(3,572	)	(10.9	)%
Midwest	23,996	23,100	896		3.9	%	47,729	46,698	1,031		2.2	%
New York	6,677	6,125	552		9.0	%	13,579	13,239	340		2.6	%
Total Nuclear Generation	44,748	45,723	(975	)	(2.1	)%	90,463	92,664	(2,201	)	(2.4	)%
Fossil and Renewables
Mid-Atlantic	915	907	8		0.9	%	1,865	1,807	58		3.2	%
Midwest	328	321	7		2.2	%	719	776	(57	)	(7.3	)%
New York	1	1	—		—	%	2	2	—		—	%
ERCOT	3,066	2,303	763		33.1	%	6,144	5,252	892		17.0	%
Other Power Regions	2,514	3,037	(523	)	(17.2	)%	5,654	7,065	(1,411	)	(20.0	)%
Total Fossil and Renewables	6,824	6,569	255		3.9	%	14,384	14,902	(518	)	(3.5	)%
Purchased Power
Mid-Atlantic	2,557	557	2,000		359.1	%	5,123	1,323	3,800		287.2	%
Midwest	250	223	27		12.1	%	538	559	(21	)	(3.8	)%
ERCOT	1,213	2,320	(1,107	)	(47.7	)%	2,255	3,692	(1,437	)	(38.9	)%
Other Power Regions	11,116	10,455	661		6.3	%	23,684	20,025	3,659		18.3	%
Total Purchased Power	15,136	13,555	1,581		11.7	%	31,600	25,599	6,001		23.4	%
Total Supply/Sales by Region
Mid-Atlantic^(b)	17,547	17,962	(415	)	(2.3	)%	36,143	35,857	286		0.8	%
Midwest^(b)	24,574	23,644	930		3.9	%	48,986	48,033	953		2.0	%
New York	6,678	6,126	552		9.0	%	13,581	13,241	340		2.6	%
ERCOT	4,279	4,623	(344	)	(7.4	)%	8,399	8,944	(545	)	(6.1	)%
Other Power Regions	13,630	13,492	138		1.0	%	29,338	27,090	2,248		8.3	%
Total Supply/Sales by Region	66,708	65,847	861		1.3	%	136,447	133,165	3,282		2.5	%

_________


(a)	Includes the proportionate share of output where Generation has an undivided ownership interest in jointly-owned generating plants and includes the total output of plants that are fully consolidated (e.g. CENG).


(b)	Includes affiliate sales to PECO and BGE in the Mid-Atlantic region, affiliate sales to ComEd in the Midwest region and affiliate sales to Pepco, DPL and ACE in the Mid-Atlantic region.

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Generation

For the three and six months ended June 30, 2019 and 2018, changes in RNF by region were as follows:



	Increase/ (Decrease)			Three Months Ended June 30, 2019	Increase/ (Decrease)			Six Months Ended June 30, 2019
Mid-Atlantic	$	(83	)	• decreased revenue due to permanent cease of generation operations at Oyster Creek in Q3 2018 • lower realized energy prices • increased nuclear outage days primarily related to Salem	$	(252	)	• lower realized energy prices • decreased revenue due to permanent cease of generation operations at Oyster Creek in Q3 2018 • increased nuclear outage days primarily related to Salem, partially offset by • increased capacity prices
Midwest	(42		)	• lower realized energy prices, partially offset by • decreased nuclear outage days	(131		)	• the absence of the revenue recognized in the first quarter 2018 related to ZECs generated in Illinois from June through December 2017 • lower realized energy prices, partially offset by • increased capacity prices and • decreased nuclear outage days
New York	(13		)	• lower realized energy prices, partially offset by • increased ZEC revenues due to higher ZEC prices	(30		)	• lower realized energy prices, partially offset by • increased ZEC revenues due to higher ZEC prices
ERCOT	(3		)	• lower realized energy prices	36			• higher realized energy prices
Other Power Regions	(52		)	• lower realized energy prices • decreased capacity prices	(132		)	• lower realized energy prices • decreased capacity prices
Proprietary Trading	(22		)	• congestion activity	(24		)	• congestion activity
Mark-to-market^(a)	(164		)	• losses on economic hedging activities of $74 million in 2019 compared to gains of $90 million in 2018	73			• losses on economic hedging activities of $102 million in 2019 compared to losses of $175 million in 2018
Other	(2		)	• the impacts of declining natural gas prices	(48		)	• the impacts of declining natural gas prices
Total	$	(381	)		$	(508	)

_________


(a)	See Note 10 — Derivative Financial Instruments for additional information on mark-to-market losses.

Nuclear Fleet Capacity Factor. The following table presents nuclear fleet operating data for the Generation-operated plants, which reflects ownership percentage of stations operated by Exelon, excluding Salem, which is operated by PSEG. The nuclear fleet capacity factor presented in the table is defined as the ratio of the actual output of a plant over a period of time to its output if the plant had operated at full average annual mean capacity for that time period. Generation considers capacity factor to be a useful measure to analyze the nuclear fleet performance between periods. Generation has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, these measures are not a presentation defined under GAAP and may not be comparable to other companies’ presentations or be more useful than the GAAP information provided elsewhere in this report.



	Three Months Ended June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
Nuclear fleet capacity factor	95.1	%	93.2	%	96.1	%	94.8	%
Refueling outage days	56		94		130		162
Non-refueling outage days	28		2		28		8

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Generation

The changes in Operating and maintenance expense consisted of the following:



	Three Months Ended June 30, 2019			Six Months Ended June 30, 2019
	Increase (Decrease)			Increase (Decrease)
Labor, other benefits, contracting, materials^(a)	$	(30	)	$	(60	)
Nuclear refueling outage costs, including the co-owned Salem plants	(22		)	(16		)
Corporate allocations	(18		)	(29		)
Insurance^(b)	1			31
Merger and integration costs	(1		)	(5		)
Plant retirements and divestitures^(c)	15			(87		)
Change in environmental liabilities	(7		)	(7		)
Cost management program	(8		)	—
Long-lived asset impairments^(d)	(38		)	(33		)
Pension and non-pension postretirement benefits expense	(17		)	(33		)
Allowance for uncollectible accounts	(6		)	(17		)
Accretion expense	(10		)	(17		)
Other	(11		)	1
Decrease in Operating and maintenance expense	$	(152	)	$	(272	)

_________


(a)	Primarily reflects decreased costs related to the permanent cease of generation operations at Oyster Creek in the third quarter of 2018.


(b)	Primarily reflects the absence of a supplemental NEIL insurance distribution received in the first quarter 2018.


(c)	Primarily due to the benefit recorded in the first quarter of 2019 for the remeasurement of the TMI ARO.


(d)	Primarily due to the impairment of certain wind projects recorded in the second quarter of 2018.

Depreciation and Amortization Expense for the three and six months ended June 30, 2019 compared to the same period in 2018 decreased primarily due to the permanent cease of generation operations at Oyster Creek in the third quarter of 2018.

Gain on Sales of Assets and Businesses for the three months ended June 30, 2019 compared to the same period in 2018 increased primarily due to Generation's sale of certain wind assets in the second quarter of 2019. Gain on sales of assets and businesses for the six months ended June 30, 2019 compared to the same period in 2018 decreased primarily due to Generation's sale of its electrical contracting business in the first quarter of 2018.

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Generation

Other, net for the three and six months ended June 30, 2019 compared to the same period in 2018 increased due to activity associated with NDT funds as described in the table below:



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019		2018
Net unrealized gains (losses) on NDT funds^(a)	$	(98	)	$	(120	)	$	182	$	(215	)
Net realized gains on sale of NDT funds^(a)	193			108			222		135
Interest and dividend income on NDT funds^(a)	36			36			61		63
Contractual elimination of income tax expense^(b)	34			3			120		(4		)
Other	6			2			16		6
Total other, net	$	171		$	29		$	601	$	(15	)

_________


(a)	Unrealized gains (losses), realized gains and interest and dividend income on the NDT funds are associated with the Non-Regulatory Agreement units.


(b)	Contractual elimination of income tax expense is associated with the income taxes on the NDT funds of the Regulatory Agreement units.

Effective income tax rates were 38.6% and 11.0% for the three months ended June 30, 2019 and 2018, respectively. Generation's effective income tax rates were 35.2% and 7.8% for the six months ended June 30, 2019 and 2018, respectively. The change is primarily related to a reduction in renewable tax credits and one-time tax adjustments. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.

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ComEd

Results of Operations — ComEd



	Three Months Ended June 30,						Favorable (Unfavorable) Variance			Six Months Ended June 30,						Favorable (Unfavorable) Variance
	2019			2018			Favorable (Unfavorable) Variance			2019			2018			Favorable (Unfavorable) Variance
Operating revenues	$	1,351		$	1,398		$	(47	)	$	2,759		$	2,910		$	(151	)
Purchased power expense	407			477			70			892			1,082			190
Revenues net of purchased power expense	944			921			23			1,867			1,828			39
Other operating expenses
Operating and maintenance	305			324			19			626			638			12
Depreciation and amortization	257			231			(26		)	508			459			(49		)
Taxes other than income	71			79			8			148			156			8
Total other operating expenses	633			634			1			1,282			1,253			(29		)
Gain on sales of assets	—			1			(1		)	3			5			(2		)
Operating income	311			288			23			588			580			8
Other income and (deductions)
Interest expense, net	(89		)	(85		)	(4		)	(178		)	(175		)	(3		)
Other, net	10			4			6			19			12			7
Total other income and (deductions)	(79		)	(81		)	2			(159		)	(163		)	4
Income before income taxes	232			207			25			429			417			12
Income taxes	46			43			(3		)	85			88			3
Net income	$	186		$	164		$	22		$	344		$	329		$	15

Three Months Ended June 30, 2019 Compared to Three Months Ended June 30, 2018 . Net income for the three months ended June 30, 2019 increased $22 million as compared to the same period in 2018, primarily due to higher electric distribution, transmission and energy efficiency formula rate earnings(reflecting the impacts of higher rate base, partially offset by lower allowed electric distribution ROE due to a decrease in treasury rates).

Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018. Net income for the six months ended June 30, 2019 increased $15 million as compared to the same period in 2018, primarily due to higher electric distribution, transmission and energy efficiency formula rate earnings (reflecting the impacts of higher rate base, partially offset by lower allowed electric distribution ROE due to a decrease in treasury rates).

Revenues Net of Purchased Power Expense. There are certain drivers of Operating revenues that are fully offset by their impact on Purchased power expense, such as commodity, REC, and ZEC procurement costs and participation in customer choice programs. ComEd recovers electricity, REC, and ZEC procurement costs from customers without mark-up. Therefore, fluctuations in these costs have no impact on RNF.

Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries but do impact Operating revenues related to supplied electricity.

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ComEd

The changes in RNF consisted of the following:



	Three Months Ended June 30, 2019			Six Months Ended June 30, 2019
	Increase (Decrease)			Increase (Decrease)
Electric distribution	$	12		$	37
Transmission	13			22
Energy efficiency	14			27
Uncollectible accounts recovery, net	(2		)	(2		)
Other	(14		)	(45		)
Total increase	$	23		$	39

Revenue Decoupling. The demand for electricity is affected by weather conditions and customer usage. Operating revenues are not impacted by abnormal weather, usage per customer or number of customers as a result of a change to the electric distribution formula rate pursuant to FEJA.

Distribution Revenue. EIMA and FEJA provide for a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs that the ICC determines are prudently and reasonably incurred in a given year. Electric distribution revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered, and allowed ROE. Electric distribution revenue increased during the three and six months ended June 30, 2019 as compared to the same period in 2018, primarily due to the impact of higher rate base and increased depreciation expenses, offset by lower allowed ROE due to a decrease in treasury rates. See Depreciation and amortization expense discussions below and Note 6 — Regulatory Matters.

Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered and the highest daily peak load, which is updated annually in January based on the prior calendar year. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. Transmission revenue increased for the three and six months ended June 30, 2019 as compared to the same period in 2018, primarily due to the increased peak load and higher rate base. See Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Energy Efficiency Revenue. FEJA provides for a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs that the ICC determines are prudently and reasonably incurred in a given year. Under FEJA, energy efficiency revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered, and allowed ROE. Energy efficiency revenue increased during the three and six months ended June 30, 2019 as compared to the same period in 2018, primarily due to the impact of higher rate base. See Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Uncollectible Accounts Recovery, Net represents recoveries under the uncollectible accounts tariff. See Operating and maintenance expense discussion below for additional information on this tariff.

Other revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues, and recoveries of environmental costs associated with MGP sites. The decrease in Other revenue for the three and six months ended June 30, 2019 as compared to the same period in 2018 primarily reflects absence of mutual assistance revenues associated with hurricane and winter storm restoration efforts that occurred in Q1 2018. An equal and offsetting amount was included in Operating and maintenance expense and Taxes other than income.

See Note 18 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ComEd's revenue disaggregation.

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The decrease in Operating and maintenance expense consisted of the following:



	Three Months Ended June 30, 2019			Six Months Ended June 30, 2019
	Increase (Decrease)			Increase (Decrease)
Baseline
Labor, other benefits, contracting and materials^(a)	$	—		$	(4	)
Pension and non-pension postretirement benefits expense^(b)	(9		)	(20		)
Storm-related costs	—			18
Uncollectible accounts expense — recovery, net^(c)	(2		)	(2		)
BSC costs^(a)	(8		)	(7		)
Other^(a)	—			3
Total decrease	$	(19	)	$	(12	)

_________


(a)	Reflects absence of mutual assistance expenses. An equal and offsetting decrease has been recognized in Operating revenues for the period presented.


(b)	Primarily reflects an increase in discount rates and the favorable impacts of the merger of two of Exelon’s pension plans effective in January 2019, partially offset by lower than expected asset returns in 2018.

(c)

ComEd is allowed to recover from or refund to customers the difference between the utility’s annual uncollectible accounts expense and the amounts collected in rates annually through a rider mechanism. During the three and six months ended June 30, 2019, ComEd recorded a net decrease in Operating and maintenance expense related to uncollectible accounts due to the timing of regulatory cost recovery. An equal and offsetting increase has been recognized in Operating revenues for the period presented.

The increase in Depreciation and amortization expense consisted of the following:



	Three Months Ended June 30, 2019		Six Months Ended June 30, 2019
	Increase		Increase
Depreciation and amortization^(a)	$	17	$	32
Regulatory asset amortization^(b)	9		17
Total increase	$	26	$	49

_________


(a)	Reflects ongoing capital expenditures and higher depreciation rates effective January 2019.


(b)	Includes amortization of ComEd's energy efficiency formula rate regulatory asset.

Effective income tax rate was 19.8% and 20.8% for the three months ended June 30, 2019 and 2018, respectively. Effective income tax rate was 19.8% and 21.1% for the six months ended June 30, 2019 and 2018, respectively. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

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PECO

Results of Operations — PECO



	Three Months Ended June 30,						Favorable (Unfavorable) Variance			Six Months Ended June 30,						Favorable (Unfavorable) Variance
	2019			2018			Favorable (Unfavorable) Variance			2019			2018			Favorable (Unfavorable) Variance
Operating revenues	$	655		$	653		$	2		$	1,554		$	1,518		$	36
Purchased power and fuel expense	191			222			31			520			555			35
Revenues net of purchased power and fuel expense	464			431			33			1,034			963			71
Other operating expenses
Operating and maintenance	199			191			(8		)	424			466			42
Depreciation and amortization	83			74			(9		)	164			149			(15		)
Taxes other than income	37			39			2			79			79			—
Total other operating expenses	319			304			(15		)	667			694			27
Operating income	145			127			18			367			269			98
Other income and (deductions)
Interest expense, net	(33		)	(32		)	(1		)	(67		)	(64		)	(3		)
Other, net	3			—			3			7			2			5
Total other income and (deductions)	(30		)	(32		)	2			(60		)	(62		)	2
Income before income taxes	115			95			20			307			207			100
Income taxes	13			(1		)	(14		)	37			(3		)	(40		)
Net income	$	102		$	96		$	6		$	270		$	210		$	60

Three Months Ended June 30, 2019 Compared to Three Months Ended June 30, 2018. Net income increased by $6 million primarily due to higher electric distribution rates that became effective January 2019 and higher natural gas distribution rates, partially offset by unfavorable weather conditions.

Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018. Net income increased by $60 million primarily due to higher electric distribution rates that became effective January 2019, higher natural gas distribution rates and lower storm costs, partially offset by unfavorable weather conditions.

Revenues Net of Purchased Power and Fuel Expense

There are certain drivers of Operating revenues that are fully offset by their impact on Purchased power and fuel expense such as commodity and REC procurement costs and participation in customer choice programs. PECO recovers electricity, natural gas and REC procurement costs from customers without mark-up. Therefore, fluctuations in these costs have no impact on RNF.

Customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers. Customer choice programs do not impact the volume of deliveries or RNF, but impact Operating revenues related to supplied electricity and natural gas.

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PECO

The changes in RNF consisted of the following:



	Three Months Ended June 30, 2019									Six Months Ended June 30, 2019
	Increase (Decrease)									Increase (Decrease)
	Electric			Gas			Total			Electric			Gas			Total
Weather	$	(5	)	$	(7	)	$	(12	)	$	(5	)	$	(5	)	$	(10	)
Volume	(6		)	3			(3		)	(4		)	5			1
Pricing	35			5			40			49			14			63
Regulatory required programs	10			1			11			21			5			26
Other	(3		)	—			(3		)	(9		)	—			(9		)
Total increase	$	31		$	2		$	33		$	52		$	19		$	71

Weather. The demand for electricity and natural gas is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the three and six months ended June 30, 2019 compared to the same period in 2018, RNF related to weather decreased due to unfavorable weather conditions.

Heating and cooling degree-days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree-days for a 30-year period in PECO's service territory. The changes in heating and cooling degree-days in PECO’s service territory for the three and six months ended June 30, 2019 compared to the same period in 2018 and normal weather consisted of the following:



Heating and Cooling Degree-Days			Normal	% Change
Three Months Ended June 30,	2019	2018	Normal	From 2018		2019 vs. Normal
Heating Degree-Days	270	482	435	(44.0	)%	(37.9	)%
Cooling Degree-Days	425	382	384	11.3	%	10.7	%

Six Months Ended June 30,
Heating Degree-Days	2,702	2,879	2,863	(6.1	)%	(5.6	)%
Cooling Degree-Days	427	382	385	11.8	%	10.9	%

Volume. Electric volume, exclusive of the effects of weather, for the three and six months ended June 30, 2019 compared to the same period in 2018, decreased due to the impact of energy efficiency initiatives on customer usages for residential, commercial and industrial electric classes, partially offset by the impact of customer growth. Natural gas volume for the three months ended June 30, 2019, compared to the same period in 2018, decreased due to lower customer usages for residential, commercial and industrial classes, partially offset by customer growth. Natural gas volume for the six months ended June 30, 2019, compared to the same period in 2018, increased due to customer and economic growth.

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Electric Retail Deliveries to Customers (in GWhs)	Three Months Ended June 30,		% Change		Weather - Normal % Change^(b)		Six Months Ended June 30,		% Change		Weather - Normal % Change^(b)
Electric Retail Deliveries to Customers (in GWhs)	2019	2018	% Change		Weather - Normal % Change^(b)		2019	2018	% Change		Weather - Normal % Change^(b)
Residential	2,821	2,946	(4.2	)%	(1.1	)%	6,462	6,574	(1.7	)%	(0.3	)%
Small commercial & industrial	1,823	1,930	(5.5	)%	(5.2	)%	3,889	3,958	(1.7	)%	(1.6	)%
Large commercial & industrial	3,769	3,811	(1.1	)%	(1.3	)%	7,340	7,514	(2.3	)%	(2.4	)%
Public authorities & electric railroads	182	182	—	%	(1.7	)%	377	379	(0.5	)%	(1.3	)%
Total electric retail deliveries^(a)	8,595	8,869	(3.1	)%	(2.1	)%	18,068	18,425	(1.9	)%	(1.5	)%



	As of June 30,
Number of Electric Customers	2019	2018
Residential	1,486,973	1,474,901
Small commercial & industrial	153,387	152,152
Large commercial & industrial	3,105	3,114
Public authorities & electric railroads	9,733	9,544
Total	1,653,198	1,639,711

_________


(a)	Reflects delivery volumes from customers purchasing electricity directly from PECO and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges.


(b)	Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.



Natural Gas Deliveries to Customers (in mmcf)	Three Months Ended June 30,		% Change		Weather - Normal % Change^(b)		Six Months Ended June 30,		% Change		Weather - Normal % Change^(b)
Natural Gas Deliveries to Customers (in mmcf)	2019	2018	% Change		Weather - Normal % Change^(b)		2019	2018	% Change		Weather - Normal % Change^(b)
Residential	3,351	5,889	(43.1	)%	(2.1	)%	24,569	26,463	(7.2	)%	0.6	%
Small commercial & industrial	4,040	3,598	12.3	%	(1.5	)%	14,684	14,016	4.8	%	(0.4	)%
Large commercial & industrial	17	6	183.3	%	22.5	%	36	52	(30.8	)%	3.1	%
Transportation	5,719	5,981	(4.4	)%	—	%	13,692	13,549	1.1	%	3.2	%
Total natural gas retail deliveries^(a)	13,127	15,474	(15.2	)%	(0.9	)%	52,981	54,080	(2.0	)%	1.0	%



	As of June 30,
Number of Natural Gas Customers	2019	2018
Residential	483,657	478,954
Small commercial & industrial	43,953	43,748
Large commercial & industrial	2	1
Transportation	737	767
Total	528,349	523,470

_________


(a)	Reflects delivery volumes from customers purchasing natural gas directly from PECO and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges.


(b)	Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.

Pricing for the three and six months ended June 30, 2019 compared to the same period in 2018 increased primarily due to an increase in electric distribution rates charged to customers. The increase in electric distribution rates was effective January 1, 2019 in accordance with the 2018 PAPUC approved electric distribution rate case settlement. Additionally, the increase represents revenue from higher natural gas distribution rates. See Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

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PECO

Regulatory Required Programs represents revenues collected under approved riders to recover costs incurred for regulatory programs such as smart meter, energy efficiency and the GSA. The riders are designed to provide full and current cost recovery as well as a return. The costs of these programs are included in Operating and maintenance expense, Depreciation and amortization expense and Income taxes.

Other revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues and wholesale transmission revenue.

See Note 18— Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of PECO's revenue disaggregation.

The changes in Operating and maintenance expense consisted of the following:



	Three Months Ended June 30, 2019			Six Months Ended June 30, 2019
	Increase (Decrease)			Increase (Decrease)
Baseline
Labor, other benefits, contracting and materials	$	—		$	9
Storm-related costs^(a)	7			(49		)
Pension and non-pension postretirement benefits expense	(1		)	(3		)
BSC costs	(1		)	2
Other	2			(1		)
	7			(42		)
Regulatory Required Programs
Energy efficiency	1			—
Total increase (decrease)	$	8		$	(42	)

__________


(a)	Reflects decreased storm costs due to the March 2018 winter storms.

The changes in Depreciation and amortization expense consisted of the following:



	Three Months Ended June 30, 2019			Six Months Ended June 30, 2019
	Increase (Decrease)			Increase
Depreciation and amortization^(a)	$	9		$	14
Regulatory asset amortization	1			1
Other	(1		)	—
Total increase	$	9		$	15

__________


(a)	Depreciation and amortization increased primarily due to ongoing capital expenditures.

Effective Income Tax Rates were 11.3% and (1.1)% for the three months ended June 30, 2019 and 2018, respectively, and 12.1% and (1.4)% for the six months ended June 30, 2019 and 2018, respectively. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

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BGE

Results of Operations — BGE



	Three Months Ended June 30,						Favorable (Unfavorable) Variance			Six Months Ended June 30,						Favorable (Unfavorable) Variance
	2019			2018			Favorable (Unfavorable) Variance			2019			2018			Favorable (Unfavorable) Variance
Operating revenues	$	649		$	662		$	(13	)	$	1,625		$	1,639		$	(14	)
Purchased power and fuel expense	208			229			21			570			609			39
Revenues net of purchased power and fuel expense	441			433			8			1,055			1,030			25
Other operating expenses
Operating and maintenance	182			176			(6		)	372			397			25
Depreciation and amortization	117			114			(3		)	252			248			(4		)
Taxes other than income	62			59			(3		)	131			124			(7		)
Total other operating expenses	361			349			(12		)	755			769			14
Gain on sales of assets	—			1			(1		)	—			1			(1		)
Operating income	80			85			(5		)	300			262			38
Other income and (deductions)
Interest expense, net	(29		)	(25		)	(4		)	(58		)	(51		)	(7		)
Other, net	5			4			1			11			9			2
Total other income and (deductions)	(24		)	(21		)	(3		)	(47		)	(42		)	(5		)
Income before income taxes	56			64			(8		)	253			220			33
Income taxes	11			13			2			47			41			(6		)
Net income	$	45		$	51		$	(6	)	$	206		$	179		$	27

Three Months Ended June 30, 2019 Compared to Three Months Ended June 30, 2018. Net income decreased by $6 million primarily due to an increase in various expenses, including interest, partially offset by higher natural gas distribution rates that became effective January 2019.

Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018. Net income increased by $27 million primarily due to higher natural gas distribution rates that became effective January 2019 and lower storm costs, partially offset by higher interest expense.

Revenues Net of Purchased Power and Fuel Expense. There are certain drivers to Operating revenues that are fully offset by their impact on Purchased power and fuel expense, such as commodity procurement costs and participation in customer choice programs. BGE recovers electricity, natural gas and procurement costs from customers without mark-up. Therefore, fluctuations in these costs have no impact on RNF.

Customers have the choice to purchase electricity and natural gas from electric generation and natural gas competitive suppliers. Customer choice programs do not impact the volume of deliveries or RNF but impact Operating revenues related to supplied electricity and natural gas.

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BGE

The changes in RNF consisted of the following:



	Three Months Ended June 30, 2019									Six Months Ended June 30, 2019
	Increase (Decrease)									Increase (Decrease)
	Electric			Gas			Total			Electric			Gas			Total
Distribution	$	1		$	11		$	12		$	6		$	42		$	48
Regulatory required programs	(2		)	(2		)	(4		)	(4		)	(5		)	(9		)
Transmission	3			—			3			(2		)	—			(2		)
Other, net	(1		)	(2		)	(3		)	(8		)	(4		)	(12		)
Total increase (decrease)	$	1		$	7		$	8		$	(8	)	$	33		$	25

Revenue Decoupling. The demand for electricity and natural gas is affected by weather and customer usage. However, Operating revenues are not impacted by abnormal weather or usage per customer as a result of a bill stabilization adjustment (BSA) that provides for a fixed distribution charge per customer by customer class. While Operating revenues are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.



	As of June 30,
Number of Electric Customers	2019	2018
Residential	1,171,815	1,163,789
Small commercial & industrial	113,982	113,745
Large commercial & industrial	12,275	12,183
Public authorities & electric railroads	264	268
Total	1,298,336	1,289,985



	As of June 30,
Number of Natural Gas Customers	2019	2018
Residential	634,939	630,714
Small commercial & industrial	38,164	38,274
Large commercial & industrial	5,991	5,900
Total	679,094	674,888

Distribution Revenue increased for the three and six months ended June 30, 2019, compared to the same period in 2018, primarily due to the impact of higher natural gas distribution rates that became effective in January 2019. See Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as conservation, demand response, STRIDE, and the POLR mechanism. The riders are designed to provide full and current cost recovery, as well as a return in certain instances. The costs of these programs are included in Operating and maintenance expense, Depreciation and amortization expense and Taxes other than income.

Transmission Revenue. Under a FERC approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered and the highest daily peak load, which is updated annually in January based on the prior calendar year. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. Transmission revenue remained relatively consistent for the three and six months ended June 30, 2019, compared to the same period in 2018. See Operating and maintenance expense below and Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

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BGE

Other revenue includes revenue related to administrative charges, mutual assistance revenues, off-system sales, and late payment charges.

See Note 18 — Segment Information of the Combined Notes to the Consolidated Financial Statements for the presentation of BGE's revenue disaggregation.

The changes in Operating and maintenance expense consisted of the following:



	Three Months Ended June 30, 2019			Six Months Ended June 30, 2019
	Increase (Decrease)			Increase (Decrease)
Baseline
Storm-related costs^(a)	$	6		$	(24	)
Labor, other benefits, contracting and materials	4			3
Pension and non-pension postretirement benefits expense	—			1
Uncollectible accounts expense	(1		)	(1		)
BSC costs	(1		)	1
Other	(1		)	(4		)
	7			(24		)
Regulatory Required Programs
Other	(1		)	(1		)
Total decrease	$	6		$	(25	)

__________


(a)	For the six months ended June 30, 2019, reflects decreased storm costs due to the March 2018 winter storms.

The changes in Depreciation and amortization expense consisted of the following:



	Three Months Ended June 30, 2019			Six Months Ended June 30, 2019
	Increase (Decrease)			Increase (Decrease)
Depreciation and amortization^(a)	$	6		$	11
Regulatory asset amortization	—			1
Regulatory required programs	(3		)	(8		)
Total increase	$	3		$	4

_________


(a)	Depreciation and amortization increased primarily due to ongoing capital expenditures.

Effective income tax rates were 19.6% and 20.3% for the three months ended June 30, 2019 and 2018, respectively, and 18.6% both the six months ended June 30, 2019 and 2018. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

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PHI

Results of Operations — PHI

PHI’s results of operations include the results of its three reportable segments, Pepco, DPL and ACE. PHI also has a business services subsidiary, PHISCO, which provides a variety of support services and the costs are directly charged or allocated to the applicable subsidiaries. Additionally, the results of PHI’s corporate operations include interest costs from various financing activities. All material intercompany accounts and transactions have been eliminated in consolidation. See the results of operations for Pepco, DPL and ACE for additional information.



	Three Months Ended June 30,						Favorable (Unfavorable) Variance		Six Months Ended June 30,						Favorable (Unfavorable) Variance
	2019			2018			Favorable (Unfavorable) Variance		2019			2018			Favorable (Unfavorable) Variance
PHI	$	106		$	84		$	22	$	223		$	149		$	74
Pepco	64			54			10		119			85			34
DPL	30			26			4		83			57			26
ACE	14			8			6		24			15			9
Other^(a)	(2		)	(4		)	2		(3		)	(8		)	5

_________


(a)	Primarily includes eliminating and consolidating adjustments, PHI's corporate operations, shared service entities and other financing and investing activities.

Three Months Ended June 30, 2019 Compared to Three Months Ended June 30, 2018. Net Income increased by $22 million primarily due to higher electric and natural gas distribution rates (not reflecting the impact of TCJA), higher transmission revenues due to an increase in the transmission rates and the highest daily peak load, and lower contracting costs.

Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018. Net Income increased by $74 million primarily due to higher electric and natural gas distribution rates (not reflecting the impact of TCJA), higher transmission revenues due to an increase in the transmission rates and the highest daily peak load, lower contracting costs, lower uncollectible accounts expense, and lower write-offs of construction work in progress.

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Pepco

Results of Operations — Pepco



	Three Months Ended June 30,						Favorable (Unfavorable) Variance			Six Months Ended June 30,						Favorable (Unfavorable) Variance
	2019			2018			Favorable (Unfavorable) Variance			2019			2018			Favorable (Unfavorable) Variance
Operating revenues	$	531		$	523		$	8		$	1,106		$	1,080		$	26
Purchased power expense	144			140			(4		)	331			322			(9		)
Revenues net of purchased power expense	387			383			4			775			758			17
Other operating expenses
Operating and maintenance	111			116			5			230			246			16
Depreciation and amortization	93			92			(1		)	186			188			2
Taxes other than income	90			90			—			182			183			1
Total other operating expenses	294			298			4			598			617			19
Operating income	93			85			8			177			141			36
Other income and (deductions)
Interest expense, net	(34		)	(32		)	(2		)	(68		)	(63		)	(5		)
Other, net	7			8			(1		)	14			16			(2		)
Total other income and (deductions)	(27		)	(24		)	(3		)	(54		)	(47		)	(7		)
Income before income taxes	66			61			5			123			94			29
Income taxes	2			7			5			4			9			5
Net income	$	64		$	54		$	10		$	119		$	85		$	34

Three Months Ended June 30, 2019 Compared to Three Months Ended June 30, 2018. Net income increased by $10 million primarily due to higher electric distribution rates in Maryland that became effective June 2018 (not reflecting the impact of TCJA), higher electric distribution rates in the District of Columbia that became effective August 2018 (not reflecting the impact of TCJA), higher transmission revenues due to an increase in the transmission rates and the highest daily peak load, and lower contracting costs.

Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018. Net income increased by $34 million primarily due to higher electric distribution rates in Maryland that became effective June 2018 (not reflecting the impact of TCJA), higher electric distribution rates in the District of Columbia that became effective August 2018 (not reflecting the impact of TCJA), higher transmission revenues due to an increase in transmission rates and the highest daily peak load, lower contracting costs, and lower uncollectible accounts expense.

Revenues Net of Purchased Power Expense. There are certain drivers of Operating revenues that are fully offset by their impact on Purchased power expense, such as commodity and REC procurement costs and participation in customer choice programs. Pepco recovers electricity and REC procurement costs from customers with a slight mark-up. Therefore, fluctuations in these costs have minimal impact on RNF.

Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries or RNF, but impact Operating revenues related to supplied electricity.

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Pepco

The changes in RNF consisted of the following:



	Three Months Ended June 30, 2019			Six Months Ended June 30, 2019
	Increase (Decrease)			Increase (Decrease)
Volume	$	4		$	8
Distribution	4			10
Regulatory required programs	(8		)	(18		)
Transmission	7			20
Other	(3		)	(3		)
Total increase	$	4		$	17

Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in both Maryland and the District of Columbia are not impacted by abnormal weather or usage per customer as a result of a bill stabilization adjustment (BSA) that provides for a fixed distribution charge per customer by customer class. While Operating revenues are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.

Volume, exclusive of the effects of weather, increased for the three and six months ended June 30, 2019 compared to the same period in 2018, primarily due to the impact of residential customer growth.



	As of June 30,
Number of Electric Customers	2019	2018
Residential	811,985	798,741
Small commercial & industrial	54,194	53,460
Large commercial & industrial	22,155	21,846
Public authorities & electric railroads	155	147
Total	888,489	874,194

Distribution Revenues increased for the three and six months ended June 30, 2019 compared to the same period in 2018 primarily due to higher electric distribution rates (not reflecting the impact of TCJA) in Maryland that became effective in June 2018 and higher electric distribution rates (not reflecting the impact of TCJA) in the District of Columbia that became effective in August 2018, partially offset by the accelerated amortization of certain deferred income tax regulatory liabilities established upon the enactment of TCJA as the result of regulatory settlements. See Note 6 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, DC PLUG and SOS administrative costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Operating and maintenance expense, Depreciation and amortization expense and Taxes other than income.

Transmission Revenues. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered and the highest daily peak load, which is updated annually in January based on the prior calendar year. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. Transmission revenues increased for the three and six months ended June 30, 2019 compared to the same period in 2018 primarily due to rate increases and an increase in the highest daily peak load.

Other revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues and recoveries of other taxes.

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See Note 18 - Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of Pepco's revenue disaggregation.

The changes in Operating and maintenance expense consisted of the following:



	Three Months Ended June 30, 2019			Six Months Ended June 30, 2019
	Increase (Decrease)			Increase (Decrease)
Baseline
Labor, other benefits, contracting and materials	$	(5	)	$	(11	)
Pension and non-pension postretirement benefits expense	2			3
Uncollectible accounts expense	(2		)	(5		)
Storm-related costs	—			(3		)
BSC and PHISCO costs	(4		)	(7		)
Other	6			10
	(3		)	(13		)

Regulatory required programs	(2		)	(3		)
Total decrease	$	(5	)	$	(16	)

The changes in Depreciation and amortization expense consisted of the following:



	Three Months Ended June 30, 2019			Six Months Ended June 30, 2019
	Increase (Decrease)			Increase (Decrease)
Depreciation and amortization^(a)	$	6		$	11
Regulatory asset amortization^(b)	1			2
Regulatory required programs	(6		)	(15		)
Total increase (decrease)	$	1		$	(2	)

_________


(a)	Depreciation and amortization increased primarily due to ongoing capital expenditures.


(b)	Regulatory asset amortization increased primarily due to additional regulatory assets related to rate case activity.

Interest expense, net for the three and six months ended June 30, 2019 compared to the same period in 2018 increased primarily due to higher outstanding debt.

Effective income tax rates were 3.0% and 11.5% for the three months ended June 30, 2019 and 2018, respectively, and 3.3% and 9.6% for the six months ended June 30, 2019 and 2018, respectively. The decrease is primarily due to the accelerated amortization of certain deferred income tax regulatory liabilities established upon the enactment of TCJA as the result of regulatory settlements. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates.

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DPL

Results of Operations — DPL



	Three Months Ended June 30,						Favorable (Unfavorable) Variance			Six Months Ended June 30,						Favorable (Unfavorable) Variance
	2019			2018			Favorable (Unfavorable) Variance			2019			2018			Favorable (Unfavorable) Variance
Operating revenues	$	287		$	289		$	(2	)	$	667		$	673		$	(6	)
Purchased power and fuel expense	107			114			7			271			291			20
Revenues net of purchased power and fuel expense	180			175			5			396			382			14
Other operating expenses
Operating and maintenance	77			77			—			160			175			15
Depreciation and amortization	45			43			(2		)	91			88			(3		)
Taxes other than income	14			13			(1		)	28			28			—
Total other operating expenses	136			133			(3		)	279			291			12
Operating income	44			42			2			117			91			26
Other income and (deductions)
Interest expense, net	(15		)	(14		)	(1		)	(30		)	(27		)	(3		)
Other, net	5			3			2			7			5			2
Total other income and (deductions)	(10		)	(11		)	1			(23		)	(22		)	(1		)
Income before income taxes	34			31			3			94			69			25
Income taxes	4			5			1			11			12			1
Net income	$	30		$	26		$	4		$	83		$	57		$	26

Three Months Ended June 30, 2019 Compared to Three Months Ended June 30, 2018. Net income increased by $4 million primarily due to higher electric distribution rates in Maryland and Delaware that became effective throughout 2018 (not reflecting the impact of TCJA), higher natural gas distribution rates in Delaware that became effective throughout 2018 (not reflecting the impact of TCJA), and higher transmission revenues due to an increase in the transmission rates and the highest daily peak load.

Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018. Net income increased by $26 million primarily due to higher electric distribution rates in Maryland and Delaware that became effective throughout 2018 (not reflecting the impact of TCJA), higher natural gas distribution rates in Delaware that became effective throughout 2018 (not reflecting the impact of TCJA), higher transmission revenues due to an increase in the transmission rates and the highest daily peak load, and lower write-offs of construction work in progress.

Revenues Net of Purchased Power and Fuel Expense. There are certain drivers to Operating revenues that are fully offset by their impact on Purchased power and fuel expense, such as commodity and REC procurement costs and participation in customer choice programs. DPL recovers electricity and REC procurement costs from customers with a slight mark-up and natural gas costs from customers without mark-up. Therefore, fluctuations in these costs have minimal impact on RNF.

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The changes in RNF consisted of the following:



	Three Months Ended June 30, 2019									Six Months Ended June 30, 2019
	Increase (Decrease)									Increase (Decrease)
	Electric			Gas			Total			Electric			Gas			Total
Weather	$	—		$	(3	)	$	(3	)	$	—		$	(2	)	$	(2	)
Volume	1			—			1			—			2			2
Distribution	(2		)	2			—			2			—			2
Regulatory required programs	(2		)	—			(2		)	(4		)	(1		)	(5		)
Transmission	9			—			9			17			—			17
Total increase (decrease)	$	6		$	(1	)	$	5		$	15		$	(1	)	$	14

Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in Maryland are not impacted by abnormal weather or usage per customer as a result of a bill stabilization adjustment (BSA) that provides for a fixed distribution charge per customer by customer class. While Operating revenues from electric distribution customers in Maryland are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.

Weather. The demand for electricity and natural gas in Delaware is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as "favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the three and six months ended June 30, 2019 compared to the same period in 2018, RNF related to weather decreased primarily due to unfavorable weather conditions in DPL's Delaware service territory.

Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 20-year period in DPL's Delaware electric service territory and a 30-year period in DPL's Delaware natural gas service territory. The changes in heating and cooling degree days in DPL’s Delaware service territory for the three and six months ended June 30, 2019 compared to same period in 2018 and normal weather consisted of the following:



Delaware Electric Service Territory				% Change
Three Months Ended June 30,	2019	2018	Normal	2019 vs. 2018		2019 vs. Normal
Heating Degree-Days	300	481	476	(37.6	)%	(37.0	)%
Cooling Degree-Days	386	349	327	10.6	%	18.0	%

				% Change
Six Months Ended June 30,	2019	2018	Normal	2019 vs. 2018		2019 vs. Normal
Heating Degree-Days	2,822	2,985	2,984	(5.5	)%	(5.4	)%
Cooling Degree-Days	386	349	328	10.6	%	17.7	%



Delaware Natural Gas Service Territory				% Change
Three Months Ended June 30,	2019	2018	Normal	2019 vs. 2018		2019 vs. Normal
Heating Degree-Days	300	481	495	(37.6	)%	(39.4	)%

				% Change
Six Months Ended June 30,	2019	2018	Normal	2019 vs. 2018		2019 vs. Normal
Heating Degree-Days	2,822	2,985	2,990	(5.5	)%	(5.6	)%

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Volume, exclusive of the effects of weather, increased for the three and six months ended June 30, 2019 compared to the same period in 2018 primarily due to residential customer growth.



Electric Retail Deliveries to Delaware Customers (in GWhs)	Three Months Ended June 30,		% Change		Weather - Normal % Change^(b)		Six Months Ended June 30,		% Change		Weather - Normal % Change^(b)
Electric Retail Deliveries to Delaware Customers (in GWhs)	2019	2018	% Change		Weather - Normal % Change^(b)		2019	2018	% Change		Weather - Normal % Change^(b)
Residential	652	671	(2.8	)%	(0.6	)%	1,503	1,541	(2.5	)%	(1.1	)%
Small commercial & industrial	306	321	(4.7	)%	(4.3	)%	626	651	(3.8	)%	(3.5	)%
Large commercial & industrial	866	928	(6.7	)%	(6.7	)%	1,676	1,757	(4.6	)%	(4.6	)%
Public authorities & electric railroads	9	8	12.5	%	12.8	%	17	17	—	%	2.2	%
Total electric retail deliveries^(a)	1,833	1,928	(4.9	)%	(4.1	)%	3,822	3,966	(3.6	)%	(3.0	)%



	As of June 30,
Number of Total Electric Customers (Maryland and Delaware)	2019	2018
Residential	465,423	461,596
Small commercial & industrial	61,552	61,189
Large commercial & industrial	1,398	1,362
Public authorities & electric railroads	619	624
Total	528,992	524,771

_________


(a)	Reflects delivery volumes from customers purchasing electricity directly from DPL and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges.


(b)	Reflects the change in delivery volumes assuming normalized weather based on the historical 20-year average.



Natural Gas Retail Deliveries to Delaware Customers (in mmcf)	Three Months Ended June 30,		% Change		Weather - Normal % Change^(b)		Six Months Ended June 30,		% Change		Weather - Normal % Change^(b)
	2019	2018	% Change		Weather - Normal % Change^(b)		2019	2018	% Change		Weather - Normal % Change^(b)
Residential	741	957	(22.6	)%	9.6	%	5,348	5,442	(1.7	)%	3.2	%
Small commercial & industrial	566	644	(12.1	)%	8.6	%	2,586	2,521	2.6	%	7.1	%
Large commercial & industrial	442	466	(5.2	)%	(5.2	)%	965	984	(1.9	)%	(1.8	)%
Transportation	1,475	1,420	3.9	%	8.8	%	3,693	3,633	1.7	%	3.3	%
Total natural gas deliveries^(a)	3,224	3,487	(7.5	)%	7.1	%	12,592	12,580	0.1	%	3.6	%



	As of June 30,
Number of Delaware Natural Gas Customers	2019	2018
Residential	124,325	122,754
Small commercial & industrial	9,907	9,810
Large commercial & industrial	18	18
Transportation	158	154
Total	134,408	132,736

__________


(a)	Reflects delivery volumes from customers purchasing natural gas directly from DPL and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges.


(b)	Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.

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Distribution Revenue increased for the six months ended June 30, 2019 compared to the same period in 2018 primarily due to higher electric distribution rates (not reflecting the impact of TCJA) in Maryland and Delaware that became effective throughout 2018 and higher natural gas distribution rates (not reflecting the impact of TCJA) in Delaware that became effective throughout 2018, partially offset by the accelerated amortization of certain deferred income tax regulatory liabilities established upon the enactment of TCJA as the result of regulatory settlements. See Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, DE Renewable Portfolio Standards, SOS administrative costs and GCR costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Operating and maintenance expense, Depreciation and amortization expense and Taxes other than income.

Transmission Revenues. Under a FERC approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered and the highest daily peak load, which is updated annually in January based on the prior calendar years. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. Transmission revenue increased for the three and six months ended June 30, 2019 compared to the same period in 2018 due to rate increases and an increase in the highest daily peak load.

See Note 18 - Segment Information for the Combined Notes to Consolidated Financial Statements for the presentation of DPL's revenue disaggregation.

The changes in Operating and maintenance expense consisted of the following:



	Three Months Ended June 30, 2019			Six Months Ended June 30, 2019
	Increase (Decrease)			Increase (Decrease)
Baseline
Labor, other benefits, contracting and materials	$	(1	)	$	1
Pension and non-pension postretirement benefits expense	1			1
Uncollectible accounts expense	3			(1		)
Storm-related costs	1			(3		)
BSC and PHISCO costs	(3		)	(5		)
Write-offs of construction work in progress	—			(7		)
Other	(2		)	—
	(1		)	(14		)

Regulatory required programs	1			(1		)
Total decrease	$	—		$	(15	)

The changes in Depreciation and amortization expense consisted of the following:



	Three Months Ended June 30, 2019			Six Months Ended June 30, 2019
	Increase (Decrease)			Increase (Decrease)
Depreciation and amortization^(a)	$	4		$	7
Regulatory required programs	(2		)	(4		)
Total increase	$	2		$	3

_________


(a)	Depreciation and amortization increased primarily due to ongoing capital expenditures.

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Interest expense, net for the three and six months ended June 30, 2019 compared to the same period in 2018 increased primarily due to higher outstanding debt.

Effective income tax rates were 11.8% and 16.1% for the three months ended June 30, 2019 and 2018, respectively, and 11.7% and 17.4% for the six months ended June 30, 2019 and 2018, respectively. The decrease is primarily due to the accelerated amortization of certain deferred income tax regulatory liabilities established upon the enactment of TCJA as the result of regulatory settlements. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates.

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ACE

Results of Operations — ACE



	Three Months Ended June 30,						Favorable (Unfavorable) Variance			Six Months Ended June 30,						Favorable (Unfavorable) Variance
	2019			2018			Favorable (Unfavorable) Variance			2019			2018			Favorable (Unfavorable) Variance
Operating revenues	$	274		$	265		$	9		$	547		$	575		$	(28	)
Purchased power expense	131			128			(3		)	270			289			19
Revenues net of purchased power expense	143			137			6			277			286			(9		)
Other operating expenses
Operating and maintenance	74			75			1			155			165			10
Depreciation and amortization	40			36			(4		)	71			69			(2		)
Taxes other than income	1			1			—			2			3			1
Total other operating expenses	115			112			(3		)	228			237			9
Operating income	28			25			3			49			49			—
Other income and (deductions)
Interest expense, net	(15		)	(16		)	1			(28		)	(32		)	4
Other, net	1			1			—			4			1			3
Total other income and (deductions)	(14		)	(15		)	1			(24		)	(31		)	7
Income before income taxes	14			10			4			25			18			7
Income taxes	—			2			2			1			3			2
Net income	$	14		$	8		$	6		$	24		$	15		$	9

Three Months Ended June 30, 2019 Compared to Three Months Ended June 30, 2018. Net income increased by $6 million primarily due to higher electric distribution rates effective April 2019 and higher transmission revenues due to an increase in the transmission rates and the highest daily peak load.

Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2018. Net income increased by $9 million primarily due to higher electric distribution rates that became effective April 2019 and higher transmission revenues due to an increase in the transmission rates and the highest daily peak load, partially offset by lower average residential usage.

Revenues Net of Purchased Power and Fuel Expense. There are certain drivers to Operating revenues that are fully offset by their impact on Purchased power and fuel expense, such as commodity and REC procurement costs and participation in customer choice programs. ACE recovers electricity and REC procurement costs from customers without mark-up. Therefore, fluctuations in these costs have no impact on RNF.

The changes in RNF consisted of the following:



	Three Months Ended June 30, 2019			Six Months Ended June 30, 2019
	Increase (Decrease)			Increase (Decrease)
Volume	$	—		$	(6	)
Distribution	8			5
Regulatory required programs	(5		)	(16		)
Transmission	3			8
Total increase (decrease)	$	6		$	(9	)

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ACE

Weather. The demand for electricity is affected by weather conditions. With respect to the electric business, very warm weather in summer months and very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity. Conversely, mild weather reduces demand. There was no change in RNF related to weather for the three and six months ended June 30, 2019 compared to same period in 2018.

Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 20-year period in ACE’s service territory. The changes in heating degree days in ACE’s service territory for the three and six months ended June 30, 2019 compared to same period in 2018 consisted of the following:



Heating and Cooling Degree-Days			Normal	% Change
Three Months Ended June 30,	2019	2018	Normal	2019 vs. 2018		2019 vs. Normal
Heating Degree-Days	380	515	553	(26.2	)%	(31.3	)%
Cooling Degree-Days	351	354	297	(0.8	)%	18.2	%

			Normal	% Change
Six Months Ended June 30,	2019	2018	Normal	2019 vs. 2018		2019 vs. Normal
Heating Degree-Days	2,886	2,927	3,042	(1.4	)%	(5.1	)%
Cooling Degree-Days	351	354	297	(0.8	)%	18.2	%

Volume, exclusive of the effects of weather, decreased for the six months ended June 30, 2019 compared to the same period in 2018, primarily due to lower average residential usage.



Electric Retail Deliveries to Customers (in GWhs)	Three Months Ended June 30,		% Change		Weather - Normal % Change^(b)		Six Months Ended June 30,		% Change		Weather - Normal % Change^(b)
Electric Retail Deliveries to Customers (in GWhs)	2019	2018	% Change		Weather - Normal % Change^(b)		2019	2018	% Change		Weather - Normal % Change^(b)
Residential	804	825	(2.5	)%	(1.6	)%	1,713	1,815	(5.6	)%	(5.7	)%
Small commercial & industrial	314	309	1.6	%	2.2	%	624	623	0.2	%	0.4	%
Large commercial & industrial	872	872	—	%	0.1	%	1,662	1,696	(2.0	)%	(2.0	)%
Public authorities & electric railroads	11	11	—	%	(1.2	)%	24	26	(7.7	)%	(6.6	)%
Total electric retail deliveries^(a)	2,001	2,017	(0.8	)%	(0.3	)%	4,023	4,160	(3.3	)%	(3.2	)%



	As of June 30,
Number of Electric Customers	2019	2018
Residential	492,940	489,050
Small commercial & industrial	61,416	61,134
Large commercial & industrial	3,464	3,590
Public authorities & electric railroads	672	654
Total	558,492	554,428

_________


(a)	Reflects delivery volumes from customers purchasing electricity directly from ACE and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges.


(b)	Reflects the change in delivery volumes assuming normalized weather based on the historical 20-year average.

Distribution Revenue increased for the three and six months ended June 30, 2019 compared to the same period in 2018 primarily due to higher electric distribution rates charged to customers that became effective in April 2019, partially offset by the accelerated amortization of certain deferred income tax regulatory liabilities established upon

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ACE

the enactment of TCJA as the result of regulatory settlements. See Note 6 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, Societal Benefits Charge, Transition Bonds and BGS administrative costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Operating and maintenance expense, Depreciation and amortization expense and Taxes other than income.

Transmission Revenues. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered and the highest daily peak load, which is updated annually in January based on the prior calendar year. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. Transmission revenue increased for the three and six months ended June 30, 2019 compared to the same period in 2018 primarily due to rate increases and an increase in the highest daily peak load.

See Note 18 - Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ACE's revenue disaggregation.

The changes in Operating and maintenance expense consisted of the following:



	Three Months Ended June 30, 2019			Six Months Ended June 30, 2019
	Increase (Decrease)			Increase (Decrease)
Baseline
Labor, other benefits, contracting and materials	$	—		$	(4	)
Uncollectible accounts expense^(a)	4			(2		)
Storm-related costs	2			(1		)
BSC and PHISCO costs	(2		)	(3		)
Other	(5		)	—
Total decrease	$	(1	)	$	(10	)

_________


(a)	ACE is allowed to recover from or refund to customers the difference between its annual uncollectible accounts expense and the amounts collected in rates annually through a rider mechanism. An equal and offsetting amount has been recognized in Operating revenues.

The changes in Depreciation and amortization expense consisted of the following:



	Three Months Ended June 30, 2019			Six Months Ended June 30, 2019
	Increase (Decrease)			Increase (Decrease)
Depreciation and amortization^(a)	$	7		$	10
Regulatory asset amortization^(b)	3			3
Regulatory required programs	(6		)	(11		)
Total increase	$	4		$	2

_________


(a)	Depreciation and amortization increased primarily due to ongoing capital expenditures.


(b)	Regulatory asset amortization increased primarily due to additional regulatory assets related to rate case activity.

Interest expense, net for the three and six months ended June 30, 2019 compared to the same period in 2018 decreased primarily due to lower outstanding debt.

Other, net for the six months ended June 30, 2019 compared to the same period in 2018 increased primarily due to higher income from AFUDC equity.

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ACE

Effective income tax rates were 0.0% and 20.0% for the three months ended June 30, 2019 and 2018, respectively and 4.0% and 16.7% for the six months ended June 30, 2019 and 2018, respectively. The decrease is primarily due to the accelerated amortization of certain deferred income tax regulatory liabilities established upon the enactment of TCJA as the result of regulatory settlements. See Note 12 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates.

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Liquidity and Capital Resources

All results included throughout the liquidity and capital resources section are presented on a GAAP basis.

The Registrants’ operating and capital expenditures requirements are provided by internally generated cash flows from operations as well as funds from external sources in the capital markets and through bank borrowings. The Registrants’ businesses are capital intensive and require considerable capital resources. Each of the Registrants annually evaluates its financing plan, dividend practices and credit line sizing, focusing on maintaining its investment grade ratings while meeting its cash needs to fund capital requirements, retire debt, pay dividends, fund pension and OPEB obligations and invest in new and existing ventures. A broad spectrum of financing alternatives beyond the core financing options can be used to meet its needs and fund growth including monetizing assets in the portfolio via project financing, asset sales, and the use of other financing structures (e.g., joint ventures, minority partners, etc.). Each Registrant’s access to external financing on reasonable terms depends on its credit ratings and current overall capital market business conditions, including that of the utility industry in general. If these conditions deteriorate to the extent that the Registrants no longer have access to the capital markets at reasonable terms, the Registrants have access to unsecured revolving credit facilities with aggregate bank commitments of $9 billion. In addition, Generation has $645 million in bilateral facilities with banks which have various expirations between October 2019 and April 2021 and $159 million in credit facilities for project finance. The Registrants utilize their credit facilities to support their commercial paper programs, provide for other short-term borrowings and to issue letters of credit. See the “Credit Matters” section below for additional information. The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs and capital expenditure requirements.

The Registrants primarily use their capital resources, including cash, to fund capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and other postretirement benefit obligations and invest in new and existing ventures. The Registrants spend a significant amount of cash on capital improvements and construction projects that have a long-term return on investment. Additionally, the Utility Registrants operate in rate-regulated environments in which the amount of new investment recovery may be delayed or limited and where such recovery takes place over an extended period of time. See Note 11 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt and credit agreements.

NRC Minimum Funding Requirements (Exelon and Generation)

NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that sufficient funds will be available in certain minimum amounts to decommission the facility. These NRC minimum funding levels are based upon the assumption that decommissioning activities will commence after the end of the current licensed life of each unit. If a unit fails the NRC minimum funding test, then the plant’s owners or parent companies would be required to take steps, such as providing financial guarantees through letters of credit or parent company guarantees or making additional cash contributions to the NDT fund to ensure sufficient funds are available. See Note 13 — Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements for additional information.

If a nuclear plant were to early retire there is a risk that it will no longer meet the NRC minimum funding requirements due to the earlier commencement of decommissioning activities and a shorter time period over which the NDT fund investments could appreciate in value. A shortfall could require that Generation address the shortfall by, among other things, obtaining a parental guarantee for Generation’s share of the funding assurance. However, the amount of any guarantees or other assurance will ultimately depend on the decommissioning approach, the associated level of costs, and the NDT fund investment performance going forward. Within two years after shutting down a plant, Generation must submit a PSDAR to the NRC that includes the planned option for decommissioning the site. On April 5, 2019, Generation filed with the NRC the TMI PSDAR which details the selection of the SAFSTOR option for decommissioning TMI Unit 1. As of June 30, 2019, under the SAFSTOR approach, sufficient funds would be available to satisfy Generation's radiological decommissioning obligations for TMI Unit 1. See Note 13 — Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements for additional information.

Upon issuance of any required financial guarantees, each site would be able to utilize the respective NDT funds for radiological decommissioning costs, which represent the majority of the total expected decommissioning costs. However, the NRC must approve an exemption in order for the plant’s owner(s) to utilize the NDT fund to pay for non-radiological decommissioning costs (i.e., spent fuel management and site restoration costs). If a unit does not receive this exemption, the costs would be borne by the owner(s) without reimbursement from or access to the NDT

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funds. While the ultimate costs for spent fuel management may vary greatly and could be reduced by alternate decommissioning scenarios and/or reimbursement of certain costs under the DOE reimbursement agreements, if TMI does not obtain an exemption, Generation estimates it could incur spent fuel management and site restoration costs over the next ten years of up to $95 million net of taxes under SAFSTOR. On April 12, 2019, Generation submitted an exemption request to the NRC to use TMI NDT funds for spent fuel management activities.

Project Financing (Exelon and Generation)

Project financing is used to help mitigate risk of specific generating assets. Project financing is based upon a nonrecourse financial structure, in which project debt is paid back from the cash generated by the specific asset or portfolio of assets. Borrowings under these agreements are secured by the assets and equity of each respective project. The lenders do not have recourse against Exelon or Generation in the event of a default. If a specific project financing entity does not maintain compliance with its specific debt financing covenants, there could be a requirement to accelerate repayment of the associated debt or other project-related borrowings earlier than the stated maturity dates. In these instances, if such repayment was not satisfied, or restructured, the lenders or security holders would generally have rights to foreclose against the project-specific assets and related collateral. The potential requirement to satisfy its associated debt or other borrowings earlier than otherwise anticipated could lead to impairments due to a higher likelihood of disposing of the respective project-specific assets significantly before the end of their useful lives. Additionally, project finance has credit facilities. See Note 13 - Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on nonrecourse debt.

Pension Funding Strategy (All Registrants)

Management considers various factors when making qualified pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006 (the Act), management of the pension obligation and regulatory implications. The Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification). Beginning in 2020, Exelon will implement a funding strategy to make levelized annual contributions with the objective of achieving 100% funded status on an ABO basis over time. This level funding strategy helps minimize volatility of future period required pension contributions. Based on this funding strategy and current market conditions, which are subject to change, Exelon’s estimated annual qualified pension contributions will be approximately $500 million beginning in 2020. This funding strategy does not change Exelon’s expected 2019 qualified pension contributions of approximately $300 million.

Cash Flows from Operating Activities (All Registrants)

General

Generation’s cash flows from operating activities primarily result from the sale of electric energy and energy-related products and services to customers. Generation’s future cash flows from operating activities may be affected by future demand for and market prices of energy and its ability to continue to produce and supply power at competitive costs as well as to obtain collections from customers.

The Utility Registrants' cash flows from operating activities primarily result from the transmission and distribution of electricity and, in the case of PECO, BGE and DPL, gas distribution services. The Utility Registrants' distribution services are provided to an established and diverse base of retail customers. The Utility Registrants' future cash flows may be affected by the economy, weather conditions, future legislative initiatives, future regulatory proceedings with respect to their rates or operations, and their ability to achieve operating cost reductions.

See Notes 4 — Regulatory Matters and 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements of the Exelon 2018 Form 10-K for additional information of regulatory and legal proceedings and proposed legislation.

The following table provides a summary of the change in cash provided by (used in) operating activities for the six months ended June 30, 2019 and 2018 by Registrant:

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Change - Cash Provided by (Used in)	Exelon			Generation			ComEd			PECO			BGE			PHI			Pepco			DPL			ACE
Net income	$	281		$	172		$	15		$	60		$	27		$	74		$	34		$	26		$	9
Add (subtract):
Non-cash operating activities	(527		)	(529		)	(1		)	26			26			(23		)	—			(14		)	(7		)
Pension and non-pension postretirement benefit contributions	(10		)	(29		)	(29		)	(2		)	7			51			5			(1		)	6
Income taxes	22			263			58			(30		)	16			(25		)	(26		)	(5		)	3
Changes in working capital and other noncurrent assets and liabilities	(429		)	(187		)	(2		)	10			(83		)	(145		)	(63		)	(51		)	(17		)
Option premiums received, net	84			84			—			—			—			—			—			—			—
Collateral posted, net	(392		)	(409		)	24			—			(5		)	—			—			—			—
Net cash flows provided by (used in) operations	$	(971	)	$	(635	)	$	65		$	64		$	(12	)	$	(68	)	$	(50	)	$	(45	)	$	(6	)

Changes in the Registrants' cash flows from operations were generally consistent with changes in each Registrant’s respective results of operations, as adjusted by changes in working capital in the normal course of business, except as discussed below. In addition, significant operating cash flow impacts for the Registrants for the six months ended June 30, 2019 and 2018 were as follows:


•	See Note 17 — Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements and the Registrants’ Consolidated Statement of Cash Flows for additional information on non-cash operating activity.


•	Depending upon whether Generation is in a net mark-to-market liability or asset position, collateral may be required to be posted with or collected from its counterparties. In addition, the collateral posting and collection requirements differ depending on whether the transactions are on an exchange or in the OTC markets.

Cash Flows from Investing Activities (All Registrants)

The following table provides a summary of the change in cash provided by (used in) investing activities for the six months ended June 30, 2019 and 2018 by Registrant:



Change - Cash Provided by (Used in)	Exelon			Generation			ComEd		PECO			BGE			PHI			Pepco			DPL		ACE
Capital expenditures	$	235		$	408		$	65	$	(36	)	$	(108	)	$	(69	)	$	(11	)	$	6	$	(57	)
Proceeds from NDT fund sales, net	175			175			—		—			—			—			—			—		—
Acquisitions of assets and businesses, net	57			57			—		—			—			—			—			—		—
Proceeds from sales of assets and businesses	(75		)	(75		)	—		—			—			—			—			—		—
Changes in intercompany money pool	—			6			—		—			—			—			(38		)	—		—
Other investing activities	(5		)	4			—		(1		)	(2		)	—			(1		)	—		2
Net cash flows provided by (used in) investing activities	$	387		$	575		$	65	$	(37	)	$	(110	)	$	(69	)	$	(50	)	$	6	$	(55	)

Significant investing cash flow impacts for the Registrants for six months ended June 30, 2019 and 2018 were as follows:


•	Variances in capital expenditures are primarily due to the timing of cash expenditures for capital projects. Refer to Liquidity and Capital Resources of the Exelon 2018 Form 10-K for additional information on projected capital expenditure spending.


•	During the six months ended June 30, 2018, Exelon and Generation had proceeds of $79 million relating to the sale of its interest in an electrical contracting business.

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Capital Expenditure Spending

As of June 30, 2019, there have been no material changes to the Registrants’ projected capital expenditures as disclosed in Liquidity and Capital Resources of the Exelon 2018 Form 10-K.

Cash Flows from Financing Activities (All Registrants)

The following table provides a summary of the change in cash provided by (used in) financing activities for the six months ended June 30, 2019 and 2018 by Registrant:



Change - Cash Provided by (Used in)	Exelon			Generation			ComEd			PECO			BGE			PHI			Pepco			DPL			ACE
Changes in short-term borrowings, net	$	20		$	—		$	(17	)	$	(50	)	$	135		$	(49	)	$	(14	)	$	216		$	(251	)
Long-term debt, net	97			(27		)	—			125			—			10			50			(196		)	156
Changes in intercompany money pool	—			(46		)	—			(181		)	—			(4		)	—			38			—
Dividends paid on common stock	(38		)	—			(25		)	113			(7		)	—			(22		)	(30		)	(5		)
Distributions to member	—			(72		)	—			—			—			(107		)	—			—			—
Contributions from parent/member	—			—			(101		)	104			—			48			44			(150		)	155
Other financing activities	64			3			—			5			—			3			1			2			(1		)
Net cash flows provided by (used in) financing activities	$	143		$	(142	)	$	(143	)	$	116		$	128		$	(99	)	$	59		$	(120	)	$	54

Significant financing cash flow impacts for the Registrants for the six months ended June 30, 2019 and 2018 were as follows:


•	Changes in short-term borrowings, net, is driven by repayments on and issuances of notes due in less than 90 days. Refer to 11 — Debt and Credit Agreements of the Consolidated Financial Statements for additional information on short-term borrowings.


•	Long-term debt, net, varies due to debt issuances and redemptions each year. Refer to 11 — Debt and Credit Agreements of the Consolidated Financial Statements for additional information on debt issuances. Refer to debt redemptions tables below for more information.


•	Changes in intercompany money pool are driven by short-term borrowing needs. Refer to more information regarding the intercompany money pool below.

•

Exelon’s ability to pay dividends on its common stock depends on the receipt of dividends paid by its operating subsidiaries. The payments of dividends to Exelon by its subsidiaries in turn depend on their results of operations and cash flows and other items affecting retained earnings. See Note 16 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements of the Exelon 2018 Form 10-K for additional information on dividend restrictions. See below for quarterly dividends declared.

Debt

See Note 11 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt issuances.

During the six months ended June 30, 2019, the following long-term debt was retired and/or redeemed:

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Company	Type	Interest Rate		Maturity	Amount
Exelon	Oracle Annual Lease Payment	3.95	%	May 1, 2024	$	18
Generation	Antelope Valley DOE Nonrecourse Debt	2.33% - 3.56%		January 5, 2037	7
Generation	Kennett Square Capital Lease	7.83	%	September 20, 2020	2
Generation	Continental Wind Nonrecourse Debt	6.00	%	February 28, 2033	18
Generation	Pollution control notes	2.50	%	March 1, 2019	23
Generation	Renewable Power Generation Nonrecourse Debt	4.11	%	March 31, 2035	3
Generation	Energy Efficiency Project Financing	3.46	%	April 30, 2019	39
Generation	ExGen Renewables IV Nonrecourse debt	3mL +3%		November 30, 2024	38
Generation	Hannie Mae, LLC Defense Financing	4.12	%	November 30, 2019	1
ComEd	First Mortgage Bonds	2.15	%	January 15, 2019	300
Pepco	Unsecured Tax-Exempt Bonds	6.20	%	September 1, 2022	110
ACE	Transition Bonds	5.55	%	October 20, 2023	9

Antelope Valley’s nonrecourse debt of approximately $500 million was reclassified as current in Exelon’s and Generation’s Consolidated Balance Sheets in the first quarter of 2019 and continues to be classified as current as of June 30, 2019 as a result of the PG&E bankruptcy filing on January 29, 2019. See Note 11 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.

Dividends

Quarterly dividends declared by the Exelon Board of Directors during the six months ended June 30, 2019 and for the third quarter of 2019 were as follows:



Period	Declaration Date	Shareholder of Record Date	Dividend Payable Date	Cash per Share^(a)
First Quarter 2019	February 5, 2019	February 20, 2019	March 8, 2019	$	0.3625
Second Quarter 2019	April 30, 2019	May 15, 2019	June 10, 2019	$	0.3625
Third Quarter 2019	July 30, 2019	August 15, 2019	September 10, 2019	$	0.3625

_________


(a)	Exelon's Board of Directors approved an updated dividend policy providing an increase of 5% each year for the period covering 2018 through 2020.

Other

For the six months ended June 30, 2019, other financing activities primarily consist of debt issuance costs. See Note 11 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants’ debt issuances.

Credit Matters (All Registrants)

The Registrants fund liquidity needs for capital investment, working capital, energy hedging and other financial commitments through cash flows from continuing operations, public debt offerings, commercial paper markets and large, diversified credit facilities. The credit facilities include $9.8 billion in aggregate total commitments of which no financial institution has more than 7% of the aggregate commitments for the Registrants. The Registrants had access to the commercial paper market during the second quarter of 2019 to fund their short-term liquidity needs, when necessary. The Registrants routinely review the sufficiency of their liquidity position, including appropriate sizing of credit facility commitments, by performing various stress test scenarios, such as commodity price movements, increases in margin-related transactions, changes in hedging levels and the impacts of hypothetical credit downgrades. The Registrants have continued to closely monitor events in the financial markets and the

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financial institutions associated with the credit facilities, including monitoring credit ratings and outlooks, credit default swap levels, capital raising and merger activity. See PART I. ITEM 1A. RISK FACTORS of the Exelon 2018 Form 10-K for additional information regarding the effects of uncertainty in the capital and credit markets.

The Registrants believe their cash flow from operating activities, access to credit markets and their credit facilities provide sufficient liquidity. If Generation lost its investment grade credit rating as of June 30, 2019, it would have been required to provide incremental collateral of $1.5 billion to meet collateral obligations for derivatives, non-derivatives, normal purchases and normal sales contracts and applicable payables and receivables, net of the contractual right of offset under master netting agreements, which is well within the $4.6 billion of available credit capacity of its revolver.

The following table presents the incremental collateral that each Utility Registrant would have been required to provide in the event each Utility Registrant lost its investment grade credit rating at June 30, 2019 and available credit facility capacity prior to any incremental collateral at June 30, 2019:



	PJM Credit Policy Collateral		Other Incremental Collateral Required^(a)		Available Credit Facility Capacity Prior to Any Incremental Collateral
ComEd	$	11	$	—	$	995
PECO	1		31		600
BGE	12		31		594
Pepco	11		—		290
DPL	7		12		300
ACE	—		—		300

_________


(a)	Represents incremental collateral related to natural gas procurement contracts.

Exelon Credit Facilities

Exelon Corporate, ComEd, BGE, Pepco, DPL and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper. Generation and PECO meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the intercompany money pool. PHI Corporate meets its short-term liquidity requirements primarily through the issuance of short-term notes and the Exelon intercompany money pool. The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit.

See 11 — Debt and Credit Agreements and Note 16 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ short-term borrowing activity.

See Note 13 — Debt and Credit Agreements and Note 22 — Commitments and Contingencies of the Exelon 2018 Form 10-K for additional information on the Registrants’ credit facilities.

Security Ratings

The Registrants’ access to the capital markets, including the commercial paper market, and their respective financing costs in those markets, may depend on the securities ratings of the entity that is accessing the capital markets.

The Registrants’ borrowings are not subject to default or prepayment as a result of a downgrading of securities, although such a downgrading of a Registrant’s securities could increase fees and interest charges under that Registrant’s credit agreements.

As part of the normal course of business, the Registrants enter into contracts that contain express provisions or otherwise permit the Registrants and their counterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable contracts law, if the Registrants are downgraded by a credit rating agency, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance, which could include the posting of collateral. See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral provisions.

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Intercompany Money Pool

To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing, both Exelon and PHI operate an intercompany money pool. Maximum amounts contributed to and borrowed from the money pool by participant and the net contribution or borrowing as of June 30, 2019, are presented in the following table:



Exelon Intercompany Money Pool	During the Three Months Ended June 30, 2019					As of June 30, 2019
Contributed (Borrowed)	Maximum Contributed		Maximum Borrowed			Contributed (Borrowed)
Exelon Corporate	$	262	$	—		$	111
Generation	179		—			179
PECO	—		(67		)	(52		)
BSC	—		(374		)	(290		)
PHI Corporate	—		(5		)	(3		)
PCI	60		—			55



PHI Intercompany Money Pool	During the Three Months Ended June 30, 2019					As of June 30, 2019
Contributed (Borrowed)	Maximum Contributed		Maximum Borrowed			Contributed (Borrowed)
PHI Corporate	$	2	$	(2	)	$	2
Pepco	38		—			38
DPL	—		(38		)	(38		)
PHISCO	4		—			2

Shelf Registration Statements

Exelon, Generation, ComEd, PECO, BGE, Pepco, DPL and ACE have a currently effective combined shelf registration statement unlimited in amount, filed with the SEC, that will expire in August 2019. The ability of each Registrant to sell securities off the shelf registration statement or to access the private placement markets will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, as applicable, the current financial condition of the Registrant, its securities ratings and market conditions.

Regulatory Authorizations

ComEd, PECO, BGE, Pepco, DPL and ACE are required to obtain short-term and long-term financing authority from Federal and State Commissions as follows:

As of June 30, 2019

Short-term Financing Authority^(a)

Remaining Long-term Financing Authority^(a)

Commission

Expiration Date

Amount

Commission

Expiration Date

Amount

ComEd^(b)

FERC

December 31, 2019

2,500

ICC

August 1, 2021

693

PECO^(c)

FERC

December 31, 2019

1,500

PAPUC

December 31, 2021

1,900

BGE

FERC

December 31, 2019

700

MDPSC

N/A

400

Pepco

FERC

December 31, 2019

500

MDPSC / DCPSC

December 31, 2020

141

DPL

FERC

December 31, 2019

500

MDPSC / DPSC

December 31, 2020

150

ACE

NJBPU

December 31, 2019

350

NJBPU

December 31, 2020

200

_________


(a)	Generation currently has blanket financing authority it received from FERC in connection with its market-based rate authority.


(b)	ComEd had $693 million available in new money long-term debt financing authority from the ICC as of June 30, 2019 and has an expiration date of August 1, 2021.

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Contractual Obligations and Off-Balance Sheet Arrangements

Contractual obligations represent cash obligations that are considered to be firm commitments and commercial commitments triggered by future events. See Note 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in the Exelon 2018 Form 10-K.

Generation, ComEd, PECO, BGE, Pepco, DPL and ACE have obligations related to contracts for the purchase of power and fuel supplies, and ComEd and PECO have obligations related to their financing trusts. The power and fuel purchase contracts and the financing trusts have been considered for consolidation in the Registrants’ respective financial statements pursuant to the authoritative guidance for VIEs. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information.

For an in-depth discussion of the Registrants' contractual obligations and off-balance sheet arrangements, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Contractual Obligations and Off-Balance Sheet Arrangements” in the Exelon 2018 Form 10-K.

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Item 3. Quantitative and Qualitative Disclosures about Market Risk

The Registrants are exposed to market risks associated with adverse changes in commodity prices, counterparty credit, interest rates and equity prices. Exelon’s RMC approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of risk exposures. The RMC is chaired by the chief executive officer and includes the chief risk officer, chief strategy officer, chief executive officer of Exelon Utilities, chief commercial officer, chief financial officer and chief executive officer of Constellation. The RMC reports to the Finance and Risk Committee of the Exelon Board of Directors on the scope of the risk management activities. The following discussion serves as an update to ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK of Exelon’s 2018 Annual Report on Form 10-K incorporated herein by reference.

Commodity Price Risk (All Registrants)

Commodity price risk is associated with price movements resulting from changes in supply and demand, fuel costs, market liquidity, weather conditions, governmental regulatory and environmental policies and other factors. To the extent the total amount of energy Exelon generates and purchases differs from the amount of energy it has contracted to sell, Exelon is exposed to market fluctuations in commodity prices. Exelon seeks to mitigate its commodity price risk through the sale and purchase of electricity, fossil fuel and other commodities.

Generation

Electricity available from Generation’s owned or contracted generation supply in excess of Generation’s obligations to customers, including portions of the Utility Registrants' retail load, is sold into the wholesale markets. To reduce commodity price risk caused by market fluctuations, Generation enters into non-derivative contracts as well as derivative contracts, including swaps, futures, forwards and options, with approved counterparties to hedge anticipated exposures. Generation uses derivative instruments as economic hedges to mitigate exposure to fluctuations in commodity prices. Generation expects the settlement of the majority of its economic hedges will occur during 2019 through 2021.

As of June 30, 2019, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York and ERCOT reportable segments is 92%-95%, 70%-73% and 40%-43% for 2019, 2020 and 2021, respectively. Market price risk exposure is the risk of a change in the value of unhedged positions. The forecasted market price risk exposure for Generation’s entire economic hedge portfolio associated with a $5 reduction in the annual average around-the-clock energy price based on June 30, 2019 market conditions and hedged position would be a decrease in pre-tax net income of approximately $19 million, $230 million and $533 million, respectively, for 2019, 2020 and 2021. See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.

Fuel Procurement

Approximately 62% of Generation’s uranium concentrate requirements from 2019 through 2023 are supplied by three producers. In the event of non-performance by these or other suppliers, Generation believes that replacement uranium concentrates can be obtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements. Non-performance by these counterparties could have a material adverse impact on Exelon’s and Generation’s financial statements.

Utility Registrants

There have been no significant changes or additions to the Utility Registrants exposures to commodity price risk that were described in ITEM 1A. RISK FACTORS of Exelon’s 2018 Annual Report on Form 10-K. See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding commodity price risk exposure.

Trading and Non-Trading Marketing Activities

The following table detailing Exelon’s, Generation’s and ComEd’s trading and non-trading marketing activities is included to address the recommended disclosures by the energy industry’s Committee of Chief Risk Officers (CCRO).

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The following table provides detail on changes in Exelon’s, Generation’s and ComEd’s commodity mark-to-market net asset or liability balance sheet position from December 31, 2018 to June 30, 2019. It indicates the drivers behind changes in the balance sheet amounts. This table incorporates the mark-to-market activities that are immediately recorded in earnings. This table excludes all NPNS contracts and does not segregate proprietary trading activity. See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on the balance sheet classification of the mark-to-market energy contract net assets (liabilities) recorded as of June 30, 2019 and December 31, 2018.



	Exelon			Generation			ComEd
Total mark-to-market energy contract net assets (liabilities) at December 31, 2018^(a)	$	299		$	548		$	(249	)
Total change in fair value during 2019 of contracts recorded in results of operations	(200		)	(200		)	—
Reclassification to realized of contracts recorded in results of operations	113			113			—
Changes in fair value — recorded through regulatory assets and liabilities^(b)	(24		)	—			(24		)
Changes in allocated collateral	399			399			—
Net option premium paid/(received)	(48		)	(48		)	—
Option premium amortization	(43		)	(43		)	—
Upfront payments and amortizations^(c)	(32		)	(32		)	—
Total mark-to-market energy contract net assets (liabilities) at June 30, 2019^(a)	$	464		$	737		$	(273	)

_________


(a)	Amounts are shown net of collateral paid to and received from counterparties.

(b)

For ComEd, the changes in fair value are recorded as a change in regulatory assets or liabilities. As of June 30, 2019, ComEd recorded a regulatory liability of $273 million related to its mark-to-market derivative liabilities with Generation and unaffiliated suppliers. For the six months ended June 30, 2019, ComEd recorded $24 million of decreases in fair value and an increase for realized losses due to settlements of $145 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers.


(c)	Includes derivative contracts acquired or sold by Generation through upfront payments or receipts of cash, excluding option premiums, and the associated amortizations

Fair Values

The following tables present maturity and source of fair value for Exelon, Generation and ComEd mark-to-market commodity contract net assets (liabilities). The tables provide two fundamental pieces of information. First, the tables provide the source of fair value used in determining the carrying amount of the Registrants’ total mark-to-market net assets (liabilities), net of allocated collateral. Second, the tables show the maturity, by year, of the Registrants’ commodity contract net assets (liabilities), net of allocated collateral, giving an indication of when these mark-to-market amounts will settle and either generate or require cash. See Note 9 — Fair Value of Financial Assets and Liabilities of the Combined Notes to Consolidated Financial Statements for additional information regarding fair value measurements and the fair value hierarchy.

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Exelon



	Maturities Within																		Total Fair Value
	2019			2020			2021			2022			2023			2024 and Beyond			Total Fair Value
Normal Operations, Commodity derivative contracts^(a)(b):
Actively quoted prices (Level 1)	$	(73	)	$	(75	)	$	(10	)	$	(8	)	$	13		$	12		$	(141	)
Prices provided by external sources (Level 2)	44			(47		)	24			(16		)	—			—			5
Prices based on model or other valuation methods (Level 3)^(c)	221			405			96			5			(9		)	(118		)	600
Total	$	192		$	283		$	110		$	(19	)	$	4		$	(106	)	$	464

_________


(a)	Mark-to-market gains and losses on other economic hedge and trading derivative contracts that are recorded in results of operations.


(b)	Amounts are shown net of collateral paid to and received from counterparties (and offset against mark-to-market assets and liabilities) of $756 million at June 30, 2019.


(c)	Includes ComEd’s net assets (liabilities) associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.

Generation



	Maturities Within																Total Fair Value
	2019			2020			2021			2022			2023		2024 and Beyond		Total Fair Value
Normal Operations, Commodity derivative contracts^(a)(b):
Actively quoted prices (Level 1)	$	(73	)	$	(75	)	$	(10	)	$	(8	)	$	13	$	12	$	(141	)
Prices provided by external sources (Level 2)	44			(47		)	24			(16		)	—		—		5
Prices based on model or other valuation methods (Level 3)	235			433			124			33			18		30		873
Total	$	206		$	311		$	138		$	9		$	31	$	42	$	737

_________


(a)	Mark-to-market gains and losses on other economic hedge and trading derivative contracts that are recorded in the results of operations.


(b)	Amounts are shown net of collateral paid to and received from counterparties (and offset against mark-to-market assets and liabilities) of $756 million at June 30, 2019.

ComEd



	Maturities Within																		Total Fair Value
	2019			2020			2021			2022			2023			2024 and Beyond			Total Fair Value
Commodity derivative contracts^(a):
Prices based on model or other valuation methods (Level 3)	$	(14	)	$	(28	)	$	(28	)	$	(28	)	$	(27	)	$	(148	)	$	(273	)

_________


(a)	Represents ComEd’s net liabilities associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.

Credit Risk (All Registrants)

The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties that execute derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the

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fair value of contracts at the reporting date. See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for detailed discussion of credit risk.

Generation

The following tables provide information on Generation’s credit exposure for all derivative instruments, normal purchases and normal sales agreements, and applicable payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of June 30, 2019. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties and an indication of the duration of a company’s credit risk by credit rating of the counterparties. The figures in the tables below exclude credit risk exposure from individual retail customers, uranium procurement contracts, and exposure through RTOs, ISOs and commodity exchanges, which are discussed below. Additionally, the figures in the tables below exclude exposures with affiliates, including net receivables with ComEd, PECO, BGE, Pepco, DPL and ACE of $70 million, $30 million, $32 million, $39 million, $15 million and $8 million as of June 30, 2019, respectively.



Rating as of June 30, 2019	Total Exposure Before Credit Collateral		Credit Collateral^(a)		Net Exposure		Number of Counterparties Greater than 10% of Net Exposure		Net Exposure of Counterparties Greater than 10% of Net Exposure
Investment grade	$	859	$	12	$	847	$	2	$	249
Non-investment grade	30		11		19
No external ratings
Internally rated — investment grade	204		1		203
Internally rated — non-investment grade	117		11		106
Total	$	1,210	$	35	$	1,175	$	2	$	249



	Maturity of Credit Risk Exposure
Rating as of June 30, 2019	Less than 2 Years		2-5 Years		Exposure Greater than 5 Years		Total Exposure Before Credit Collateral
Investment grade	$	795	$	53	$	11	$	859
Non-investment grade	30		—		—		30
No external ratings
Internally rated — investment grade	135		37		32		204
Internally rated — non-investment grade	111		1		5		117
Total	$	1,071	$	91	$	48	$	1,210



Net Credit Exposure by Type of Counterparty	As of June 30, 2019
Financial institutions	$	3
Investor-owned utilities, marketers, power producers	810
Energy cooperatives and municipalities	302
Other	60
Total	$	1,175

_________


(a)	As of June 30, 2019, credit collateral held from counterparties where Generation had credit exposure included $25 million of cash and $9 million of letters of credit.

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The Utility Registrants

There have been no significant changes or additions to the Utility Registrants exposures to credit risk that are described in ITEM 1A. RISK FACTORS of Exelon’s 2018 Annual Report on Form 10-K.

See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding credit exposure to suppliers.

Credit-Risk-Related Contingent Features (All Registrants)

Generation

As part of the normal course of business, Generation routinely enters into physical or financial contracts for the sale and purchase of electricity, natural gas and other commodities. In accordance with the contracts and applicable law, if Generation is downgraded by a credit rating agency, especially if such downgrade is to a level below investment grade, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance. Depending on Generation’s net position with a counterparty, the demand could be for the posting of collateral. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding collateral requirements. See Note 16 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding the letters of credit supporting the cash collateral.

Generation transacts output through bilateral contracts. The bilateral contracts are subject to credit risk, which relates to the ability of counterparties to meet their contractual payment obligations. Any failure to collect these payments from counterparties could have a material impact on Exelon’s and Generation’s financial statements. As market prices rise above or fall below contracted price levels, Generation is required to post collateral with purchasers; as market prices fall below contracted price levels, counterparties are required to post collateral with Generation. To post collateral, Generation depends on access to bank credit facilities, which serve as liquidity sources to fund collateral requirements. See Note 13 — Debt and Credit Agreements of the Exelon Form 10-K for additional information.

Utility Registrants

As of June 30, 2019, the Utility Registrants were not required to post collateral under their energy and/or natural gas procurement contracts. See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.

Interest Rate and Foreign Exchange Risk (Exelon and Generation)

Exelon and Generation use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. Exelon and Generation may also utilize interest rate swaps to manage their interest rate exposure. A hypothetical 50 basis point increase in the interest rates associated with unhedged variable-rate debt (excluding Commercial Paper) and fixed-to-floating swaps would result in approximately a $3 million decrease in Exelon pre-tax income for the six months ended June 30, 2019. To manage foreign exchange rate exposure associated with international energy purchases in currencies other than U.S. dollars, Generation utilizes foreign currency derivatives, which are typically designated as economic hedges. See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.

Equity Price Risk (Exelon and Generation)

Exelon and Generation maintain trust funds, as required by the NRC, to fund certain costs of decommissioning its nuclear plants. As of June 30, 2019, Generation’s NDT funds are reflected at fair value in its Consolidated Balance Sheets. The mix of securities in the trust funds is designed to provide returns to be used to fund decommissioning and to compensate Generation for inflationary increases in decommissioning costs; however, the equity securities in the trust funds are exposed to price fluctuations in equity markets, and the value of fixed-rate, fixed-income securities are exposed to changes in interest rates. Generation actively monitors the investment performance of the trust funds and periodically reviews asset allocation in accordance with Generation’s NDT fund investment

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policy. A hypothetical 10% increase in interest rates and decrease in equity prices would result in a $563 million reduction in the fair value of the trust assets. This calculation holds all other variables constant and assumes only the discussed changes in interest rates and equity prices. See Liquidity and Capital Resources section of ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for additional information of equity price risk as a result of the current capital and credit market conditions.

Item 4. Controls and Procedures

During the second quarter of 2019, each of Exelon’s, Generation’s, ComEd’s, PECO’s, BGE’s, PHI's, Pepco's, DPL's and ACE's management, including its principal executive officer and principal financial officer, evaluated its disclosure controls and procedures related to the recording, processing, summarizing and reporting of information in its periodic reports that it files with the SEC. These disclosure controls and procedures have been designed by all Registrants to ensure that (a) material information relating to that Registrant, including its consolidated subsidiaries, is accumulated and made known to Exelon’s management, including its principal executive officer and principal financial officer, by other employees of that Registrant and its subsidiaries as appropriate to allow timely decisions regarding required disclosure, and (b) this information is recorded, processed, summarized, evaluated and reported, as applicable, within the time periods specified in the SEC’s rules and forms. Due to the inherent limitations of control systems, not all misstatements may be detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls could be circumvented by the individual acts of some persons or by collusion of two or more people.

Accordingly, as of June 30, 2019, the principal executive officer and principal financial officer of each of Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE concluded that such Registrant’s disclosure controls and procedures were effective to accomplish its objectives. All Registrants continually strive to improve their disclosure controls and procedures to enhance the quality of its financial reporting and to maintain dynamic systems that change as conditions warrant. There have been no changes in internal control over financial reporting that occurred during the second quarter of 2019 that have materially affected, or are reasonably likely to materially affect, any of Exelon’s, Generation’s, ComEd’s, PECO’s, BGE’s, PHI’s, Pepco’s, DPL’s and ACE’s internal control over financial reporting.

PART II — OTHER INFORMATION

Item 1. Legal Proceedings

The Registrants are parties to various lawsuits and regulatory proceedings in the ordinary course of their respective businesses. For information regarding material lawsuits and proceedings, see (a) ITEM 3. LEGAL PROCEEDINGS of Exelon’s 2018 Form 10-K and (b) Notes 6 — Regulatory Matters and 16 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in PART I, ITEM 1. FINANCIAL STATEMENTS of this Report. Such descriptions are incorporated herein by these references.

Item 1A. Risk Factors

Risks Related to Exelon

At June 30, 2019, the Registrants' risk factors were consistent with the risk factors described in the Registrants' combined 2018 Form 10-K in ITEM 1A. RISK FACTORS.

Item 4. Mine Safety Disclosures

All Registrants

Not applicable to the Registrants.

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Item 5. Other Information

Exelon and ComEd—Subpoena

Exelon and ComEd received a grand jury subpoena from the U.S. Attorney’s Office for the Northern District of Illinois requiring production of information concerning their lobbying activities in the State of Illinois. Exelon and ComEd have pledged to cooperate fully and are cooperating fully with the U.S. Attorney’s Office in expeditiously providing the requested information.

Item 6. Exhibits

Certain of the following exhibits are incorporated herein by reference under Rule 12b-32 of the Securities and Exchange Act of 1934, as amended. Certain other instruments which would otherwise be required to be listed below have not been so listed because such instruments do not authorize securities in an amount which exceeds 10% of the total assets of the applicable Registrant and its subsidiaries on a consolidated basis and the relevant Registrant agrees to furnish a copy of any such instrument to the Commission upon request.



Exhibit No.	Description
4.1	Atlantic City Electric Company Indenture Supplemental, dated as of May 2, 2019, to the Mortgage and Deed of Trust, dated January 15, 1937 (File No. 001-03559, Form 8-K dated May 21, 2019, Exhibit 4.3)

4.2	Potomac Electric Power Company Supplemental Indenture, dated as of May 2, 2019, with respect to the Mortgage and Deed of Trust, dated July 1, 1936 (File No. 001-01072, Form 8-K dated June 13, 2019, Exhibit 4.2)

4.3	Exempt Facilities Loan Agreement dated as of June 1, 2019 between the Maryland Economic Development Corporation and Potomac Electric Power Company (File No. 001-01072, Form 8-K dated June 27, 2019, Exhibit 4.1)

101.INS	XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

101.SCH	XBRL Taxonomy Extension Schema Document.

101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF	XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB	XBRL Taxonomy Extension Label Linkbase Document.

101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.

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Certifications Pursuant to Rule 13a-14(a) and 15d-14(a) of the Securities and Exchange Act of 1934 as to the Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2019 filed by the following officers for the following companies:



31-1	— Filed by Christopher M. Crane for Exelon Corporation

31-2	— Filed by Joseph Nigro for Exelon Corporation

31-3	— Filed by Kenneth W. Cornew for Exelon Generation Company, LLC

31-4	— Filed by Bryan P. Wright for Exelon Generation Company, LLC

31-5	— Filed by Joseph Dominguez for Commonwealth Edison Company

31-6	— Filed by Jeanne M. Jones for Commonwealth Edison Company

31-7	— Filed by Michael A. Innocenzo for PECO Energy Company

31-8	— Filed by Robert J. Stefani for PECO Energy Company

31-9	— Filed by Calvin G. Butler, Jr. for Baltimore Gas and Electric Company

31-10	— Filed by David M. Vahos for Baltimore Gas and Electric Company

31-11	— Filed by David M. Velazquez for Pepco Holdings LLC

31-12	— Filed by Phillip S. Barnett for Pepco Holdings LLC

31-13	— Filed by David M. Velazquez for Potomac Electric Power Company

31-14	— Filed by Phillip S. Barnett for Potomac Electric Power Company

31-15	— Filed by David M. Velazquez for Delmarva Power & Light Company

31-16	— Filed by Phillip S. Barnett for Delmarva Power & Light Company

31-17	— Filed by David M. Velazquez for Atlantic City Electric Company

31-18	— Filed by Phillip S. Barnett for Atlantic City Electric Company

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Certifications Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code (Sarbanes — Oxley Act of 2002) as to the Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2019 filed by the following officers for the following companies:




32-1	— Filed by Christopher M. Crane for Exelon Corporation

32-2	— Filed by Joseph Nigro for Exelon Corporation

32-3	— Filed by Kenneth W. Cornew for Exelon Generation Company, LLC

32-4	— Filed by Bryan P. Wright for Exelon Generation Company, LLC

32-5	— Filed by Joseph Dominguez for Commonwealth Edison Company

32-6	— Filed by Jeanne M. Jones for Commonwealth Edison Company

32-7	— Filed by Michael A. Innocenzo for PECO Energy Company

32-8	— Filed by Robert J. Stefani for PECO Energy Company

32-9	— Filed by Calvin G. Butler, Jr. for Baltimore Gas and Electric Company

32-10	— Filed by David M. Vahos for Baltimore Gas and Electric Company

32-11	— Filed by David M. Velazquez for Pepco Holdings LLC

32-12	— Filed by Phillip S. Barnett for Pepco Holdings LLC

32-13	— Filed by David M. Velazquez for Potomac Electric Power Company

32-14	— Filed by Phillip S. Barnett for Potomac Electric Power Company

32-15	— Filed by David M. Velazquez for Delmarva Power & Light Company

32-16	— Filed by Phillip S. Barnett for Delmarva Power & Light Company

32-17	— Filed by David M. Velazquez for Atlantic City Electric Company

32-18	— Filed by Phillip S. Barnett for Atlantic City Electric Company

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SIGNATURES

Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

EXELON CORPORATION



/s/ CHRISTOPHER M. CRANE		/s/ JOSEPH NIGRO
Christopher M. Crane		Joseph Nigro
President and Chief Executive Officer (Principal Executive Officer) and Director		Senior Executive Vice President and Chief Financial Officer (Principal Financial Officer)

/s/ FABIAN E. SOUZA
Fabian E. Souza
Senior Vice President and Corporate Controller (Principal Accounting Officer)

August 1, 2019

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Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

EXELON GENERATION COMPANY, LLC



/s/ KENNETH W. CORNEW		/s/ BRYAN P. WRIGHT
Kenneth W. Cornew		Bryan P. Wright
President and Chief Executive Officer (Principal Executive Officer)		Senior Vice President and Chief Financial Officer (Principal Financial Officer)

/s/ MATTHEW N. BAUER
Matthew N. Bauer
Vice President and Controller (Principal Accounting Officer)

August 1, 2019

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Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

COMMONWEALTH EDISON COMPANY



/s/ JOSEPH DOMINGUEZ		/s/ JEANNE M. JONES
Joseph Dominguez		Jeanne M. Jones
Chief Executive Officer (Principal Executive Officer)		Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)

/s/ GERALD J. KOZEL
Gerald J. Kozel
Vice President and Controller (Principal Accounting Officer)

August 1, 2019

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Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

PECO ENERGY COMPANY



/s/ MICHAEL A. INNOCENZO		/s/ ROBERT J. STEFANI
Michael A. Innocenzo		Robert J. Stefani
President and Chief Executive Officer (Principal Executive Officer)		Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)

/s/ SCOTT A. BAILEY
Scott A. Bailey
Vice President and Controller (Principal Accounting Officer)

August 1, 2019

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Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

BALTIMORE GAS AND ELECTRIC COMPANY



/s/ CALVIN G. BUTLER, JR.		/s/ DAVID M. VAHOS
Calvin G. Butler, Jr.		David M. Vahos
Chief Executive Officer (Principal Executive Officer)		Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)

/s/ ANDREW W. HOLMES
Andrew W. Holmes
Vice President and Controller (Principal Accounting Officer)

August 1, 2019

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Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

PEPCO HOLDINGS LLC



/s/ DAVID M. VELAZQUEZ		/s/ PHILLIP S. BARNETT
David M. Velazquez		Phillip S. Barnett
President and Chief Executive Officer (Principal Executive Officer)		Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)

/s/ ROBERT M. AIKEN
Robert M. Aiken
Vice President and Controller (Principal Accounting Officer)

August 1, 2019

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Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

POTOMAC ELECTRIC POWER COMPANY



/s/ DAVID M. VELAZQUEZ		/s/ PHILLIP S. BARNETT
David M. Velazquez		Phillip S. Barnett
President and Chief Executive Officer (Principal Executive Officer)		Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)

/s/ ROBERT M. AIKEN
Robert M. Aiken
Vice President and Controller (Principal Accounting Officer)

August 1, 2019

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Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

DELMARVA POWER & LIGHT COMPANY



/s/ DAVID M. VELAZQUEZ		/s/ PHILLIP S. BARNETT
David M. Velazquez		Phillip S. Barnett
President and Chief Executive Officer (Principal Executive Officer)		Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)

/s/ ROBERT M. AIKEN
Robert M. Aiken
Vice President and Controller (Principal Accounting Officer)

August 1, 2019

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Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

ATLANTIC CITY ELECTRIC COMPANY



/s/ DAVID M. VELAZQUEZ		/s/ PHILLIP S. BARNETT
David M. Velazquez		Phillip S. Barnett
President and Chief Executive Officer (Principal Executive Officer)		Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)

/s/ ROBERT M. AIKEN
Robert M. Aiken
Vice President and Controller (Principal Accounting Officer)

August 1, 2019

202