UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

 

 

FORM 8-K

 

 

CURRENT REPORT

Pursuant to Section 13 or 15(d)

of the Securities Exchange Act of 1934

August 2, 2017

Date of Report (Date of earliest event reported)

 

 

 

Commission File Number		Exact Name of Registrant as Specified in Its Charter; State of Incorporation; Address of Principal Executive Offices; and Telephone Number		IRS Employer Identification Number
1-16169		EXELON CORPORATION (a Pennsylvania corporation) 10 South Dearborn Street P.O. Box 805379 Chicago, Illinois 60680-5379 (800) 483-3220		23-2990190
333-85496		EXELON GENERATION COMPANY, LLC (a Pennsylvania limited liability company) 300 Exelon Way Kennett Square, Pennsylvania 19348-2473 (610) 765-5959		23-3064219
1-1839		COMMONWEALTH EDISON COMPANY (an Illinois corporation) 440 South LaSalle Street Chicago, Illinois 60605-1028 (312) 394-4321		36-0938600
000-16844		PECO ENERGY COMPANY (a Pennsylvania corporation) P.O. Box 8699 2301 Market Street Philadelphia, Pennsylvania 19101-8699 (215) 841-4000		23-0970240
1-1910		BALTIMORE GAS AND ELECTRIC COMPANY (a Maryland corporation) 2 Center Plaza 110 West Fayette Street Baltimore, Maryland 21201 (410) 234-5000		52-0280210
001-31403		PEPCO HOLDINGS LLC (a Delaware limited liability company) 701 Ninth Street, N.W. Washington, District of Columbia 20068 (202) 872-2000		52-2297449
001-01072		POTOMAC ELECTRIC POWER COMPANY (a District of Columbia and Virginia corporation) 701 Ninth Street, N.W. Washington, District of Columbia 20068 (202) 872-2000		53-0127880
001-01405		DELMARVA POWER & LIGHT COMPANY (a Delaware and Virginia corporation) 500 North Wakefield Drive Newark, Delaware 19702 (202) 872-2000		51-0084283
001-03559		ATLANTIC CITY ELECTRIC COMPANY (a New Jersey corporation) 500 North Wakefield Drive Newark, Delaware 19702 (202) 872-2000		21-0398280

 

 

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

 

☐	Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

 

☐	Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

 

☐	Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

 

☐	Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Indicate by check market whether the any of the registrants are emerging growth companies as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter).

Emerging growth company  ☐

If an emerging growth company, indicate by check mark if any of the registrants have 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.  ☐

 

 

 

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Section 2 – Financial Information

 

Item 2.02.

Results of Operations and Financial Condition.

Section 7 – Regulation FD

 

Item 7.01.

Regulation FD Disclosure.

On August 2, 2017, Exelon Corporation (Exelon) announced via press release its results for the second quarter ended June 30, 2017. A copy of the press release and related attachments is attached hereto as Exhibit 99.1. Also attached as Exhibit 99.2 to this Current Report on Form 8-K are the presentation slides to be used at the second quarter 2017 earnings conference call. This Form 8-K and the attached exhibits are provided under Items 2.02, 7.01 and 9.01 of Form 8-K and are furnished to, but not filed with, the Securities and Exchange Commission.

Exelon has scheduled the conference call for 10:00 AM CT (11:00 AM ET ) on August 2, 2017. The call-in number in the U.S. and Canada is 800-690-3108, and the international call-in number is 973-935-8753. If requested, the conference ID number is 44816529. Media representatives are invited to participate on a listen-only basis. The call will be web-cast and archived on Exelon’s Web site: www.exeloncorp.com. (Please select the Investors page.)

Telephone replays will be available until August 16, 2017. The U.S. and Canada call-in number for replays is 855-859-2056, and the international call-in number is 404-537-3406. The conference ID number is 44816529.

Section 9 – Financial Statements and Exhibits

 

Item 9.01.

Financial Statements and Exhibits.

(d) Exhibits.

 

Exhibit No.		Description
99.1		Press release and earnings release attachments
99.2		Earnings conference call presentation slides

* * * * *

This combined Current Report on Form 8-K is being furnished separately by Exelon, Exelon Generation Company, LLC, Commonwealth Edison Company, PECO Energy Company, Baltimore Gas and Electric Company, Pepco Holdings LLC (PHI), Potomac Electric Power Company, Delmarva Power & Light Company, and Atlantic City Electric Company (Registrants). Information contained herein relating to any individual Registrant has been furnished by such Registrant on its own behalf. No Registrant makes any representation as to information relating to any other Registrant.

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 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) include those factors discussed herein, as well as the items discussed in (1) the Registrants’ 2016 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 24, Commitments and Contingencies; (2) the Registrants’ Second Quarter 2017 Quarterly Report on Form 10-Q (to be filed on August 2, 2017) 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 17, 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.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, each Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

 

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August 2, 2017

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EXHIBIT INDEX

 

Exhibit No.		Description
99.1		Press release and earnings release attachments
99.2		Earnings conference call presentation slides

Exhibit 99.1

 

 

Contact:		Dan Eggers
		Investor Relations
		312-394-2345
		Paul Adams
		Corporate Communications
		410-470-4167

EXELON REPORTS SECOND QUARTER 2017 RESULTS

Earnings Release Highlights

 

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GAAP Net Income of $0.09 per share and Adjusted Operating Earnings of $0.54 per share for the second quarter of 2017

 

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Reaffirming full year 2017 Adjusted Operating Earnings guidance of $2.50 to $2.80 per share

 

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Strong utility performance to the benefit of our customers, with every utility achieving top quartile CAIDI performance as well as BGE and ComEd achieving their best ever SAIFI performance

 

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Courts grant motions to dismiss legal challenges to the ZEC programs in Illinois and New York, preserving the economic and environmental benefits of this carbon-free generation

 

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Exelon Nuclear completed six refueling outages with fewer unplanned outage days than a year ago

 

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Two new combined-cycle gas turbines totaling nearly 2,200 MWs in Texas went into service, on-time and on-budget

CHICAGO (Aug. 2, 2017) — Exelon Corporation (NYSE: EXC) today reported its financial results for the second quarter 2017.

“Exelon delivered a strong second quarter for our shareholders and customers as we continued to make gains in reliability, customer service and operational performance across our business,” said Christopher M. Crane, Exelon’s president and CEO. “Exelon can continue to provide reliable and affordable carbon-free power while preserving high-value jobs thanks to the dismissal of challenges to Zero Emissions Credit programs by courts in Illinois and New York, a win for our customers, the

 

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economy and the environment. We also were recognized with several leadership awards including being one of only 27 companies in the Billion Dollar Roundtable, recognizing our nearly $2 billion of spending with diverse and minority-owned businesses. We were also named to the Points of Light Civic 50 list of the most community-minded companies, a true credit to our people who give back their time and resources volunteering in the communities where we work and live.”

“Exelon once again delivered strong financial performance with non-GAAP operating earnings of $0.54 per share, which is toward the upper end of our guidance range,” said Jonathan W. Thayer, Exelon’s senior executive vice president and CFO. “Exelon remains on track to meet our full-year guidance of $2.50-2.80 per share as well as our debt reduction targets.”

Second Quarter 2017

Exelon’s GAAP Net Income for the second quarter 2017 decreased to $0.09 per share from $0.29 per share in the second quarter of 2016; Adjusted (non-GAAP) Operating Earnings decreased to $0.54 per share in the second quarter of 2017 from $0.65 per share in the second quarter of 2016. For the reconciliations of GAAP to Adjusted (non-GAAP) Operating Earnings, refer to the tables beginning on [page 7].

Adjusted (non-GAAP) Operating Earnings in the second quarter of 2017 reflect the conclusion of the Ginna reliability support services agreement, increased nuclear outage days and lower realized energy prices, partially offset by Zero Emission Credit revenue related to the New York Clean Energy Standard and higher utility earnings due to regulatory rate increases.

Operating Company Results¹

ComEd

ComEd’s second quarter 2017 GAAP Net Income was $118 million compared with $145 million in the second quarter of 2016. ComEd’s Adjusted (non-GAAP) Operating Earnings for the second quarter 2017 were $141 million compared with $146 million in the second quarter of 2016, primarily due to favorable weather conditions in 2016, partially offset by higher electric distribution and transmission formula rate earnings. Pursuant to the Illinois Future Energy Jobs Act, beginning in 2017, customer rates for ComEd are adjusted to eliminate the favorable and unfavorable impacts of weather and customer usage patterns on distribution volumes.

 

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Exelon’s five business units include ComEd, which consists of electricity transmission and distribution operations in northern Illinois; PECO, which consists of electricity transmission and distribution operations and retail natural gas distribution operations in southeastern Pennsylvania, BGE, which consists of electricity transmission and distribution operations and retail natural gas distribution operations in central Maryland; PHI, which consists of electricity transmission and distribution operations in the District of Columbia and portions of Maryland, Delaware, and New Jersey and retail natural gas distribution operations in northern Delaware; and Generation, which consists of owned and contracted electric generating facilities and wholesale and retail customer supply of electric and natural gas products and services, including renewable energy products and risk management services.

 

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PECO

PECO’s second quarter 2017 GAAP Net Income was $88 million compared with $100 million in the second quarter of 2016. PECO’s Adjusted (non-GAAP) Operating Earnings for the second quarter 2017 were $89 million compared with $101 million in the second quarter of 2016, primarily due to unfavorable weather conditions and volumes.

For the second quarter of 2017, heating degree days were down 29.9 percent relative to the same period in 2016 and were 28.9 percent below normal. Cooling degree days were up 6.1 percent relative to the same period in 2016 and were 19.3 percent above normal. Total retail electric deliveries remained relatively consistent in the second quarter of 2017 compared with the same period in 2016. Natural gas deliveries (including both retail and transportation segments) in the second quarter of 2017 were down 3.0 percent compared with the same period in 2016.

Weather-normalized retail electric deliveries remained relatively consistent, while weather-normalized natural gas deliveries were up 5.3 percent in the second quarter of 2017 compared with the same period in 2016.

BGE

BGE’s second quarter 2017 GAAP Net Income was $45 million compared with $31 million in the second quarter of 2016. BGE’s Adjusted (non-GAAP) Operating Earnings for the second quarter 2017 were $46 million compared with $29 million in the second quarter of 2016, primarily due to the absence of 2016 charges for certain disallowances contained in June and July 2016 rate case orders and the net impact of approved rate increases. Due to revenue decoupling, BGE is not affected by actual weather.

PHI

PHI’s second quarter 2017 GAAP Net Income was $66 million compared with $52 million in the second quarter of 2016. PHI’s Adjusted (non-GAAP) Operating Earnings for the second quarter 2017 were $63 million compared with $53 million in the second quarter of 2016, primarily due to the impact of approved rate increases in 2016 and 2017. Due to decoupling, PHI’s revenues related to Pepco and DPL Maryland are not affected by actual weather.

Generation

Generation’s second quarter 2017 GAAP Net Loss was $250 million compared with a GAAP Net Loss of $8 million in the second quarter of 2016. Generation’s Adjusted (non-GAAP) Operating Earnings for the second quarter 2017 were $202 million compared with $328 million in the second quarter of 2016, primarily reflecting the conclusion of the Ginna reliability support services agreement, increased nuclear outage days and lower realized energy prices, partially offset by Zero Emission Credit revenue related to the New York Clean Energy Standard.

 

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The proportion of expected generation hedged as of June 30, 2017 was 96.0 percent to 99.0 percent for 2017, 71.0 percent to 74.0 percent for 2018 and 39.0 percent to 42.0 percent for 2019.

Second Quarter and Recent Highlights

 

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Early Retirement of Three Mile Island Facility: On May 30, 2017, Exelon announced it will permanently cease generation operations at Three Mile Island Generating Station (TMI) on or about September 30, 2019. In the second quarter of 2017, Exelon and Generation recognized one-time charges in Operating and maintenance expense of $71 million related to materials and supplies inventory reserve adjustments, employee-related costs and construction work-in-progress (CWIP) impairments, among other items. In addition to these one-time charges, there will be ongoing annual incremental non-cash charges to earnings stemming from shortening the expected economic useful life of TMI primarily related to accelerated depreciation of plant assets (including any asset retirement costs (ARC)), accelerated amortization of nuclear fuel, and additional asset retirement obligation (ARO) accretion expense associated with the changes in decommissioning timing and cost assumptions. Exelon’s and Generation’s second quarter 2017 results include an incremental $37 million of pre-tax expense for these items. The aforementioned one-time and incremental charges have been excluded from GAAP Net Income to arrive at Adjusted (non-GAAP) Operating Earnings.

 

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EGTP Assets Held for Sale Agreement: On May 2, 2017, EGTP entered into a consent agreement with its lenders to permit EGTP to draw on its revolving credit facility and initiate an orderly sales process to sell the assets of its wholly-owned subsidiaries, the proceeds from which will first be used to pay the administrative costs of the sale, the normal and ordinary costs of operating the plants and repayment of the secured debt of EGTP, including the revolving credit facility. As a result, in the second quarter, Exelon and Generation classified certain EGTP assets and liabilities as held for sale at their respective fair values less costs to sell. At June 30, 2017, a $418 million pre-tax impairment loss was recorded within Operating and maintenance expense on Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

 

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District of Columbia Power Line Undergrounding Initiative: The District of Columbia government enacted on an emergency basis (effective May 17, 2017) and thereafter on a permanent basis (effective July 11, 2017) legislation to amend the Electric Company Infrastructure Improvement Financing Act of 2014 (as amended) (the Infrastructure Improvement Financing Act) to authorize the District of Columbia Power Line Undergrounding (DC PLUG) initiative, a projected six year, $500 million project to place underground some of

 

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the District of Columbia’s most outage-prone power lines with $250 million of the project costs funded by Pepco and $250 million funded by the District of Columbia. The $250 million of project costs funded by Pepco will be recovered from Pepco’s customers in the District of Columbia. Pepco will earn a return on these project costs.The $250 million of project costs funded by the District of Columbia will come from two sources. Project costs of $187.5 million will be funded through a charge assessed on Pepco by the District of Columbia; Pepco will recover this charge from customers. The remaining costs up to $62.5 million are to be funded by the existing capital projects program of the District Department of Transportation (DDOT). Pepco will not recover or earn a return on the cost of these assets.

 

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Like Kind Exchange: In the third quarter 2016, the United States Tax Court rejected Exelon’s like-kind exchange position and ruled that Exelon was not entitled to defer the gain on the transaction. Exelon expects to timely appeal this decision to the U.S. Court of Appeals for the Seventh Circuit in the second half of 2017. In June of 2017, the IRS finalized its computation of tax, penalties and interest owed by Exelon pursuant to the Tax Court’s decision. As a result of the IRS’s finalization of its computation in the second quarter 2017, Exelon recorded a benefit to earnings of approximately $26 million, consisting of an income tax benefit of $50 million and a reduction of penalties of $2 million, partially offset by after-tax interest expense of $26 million, while ComEd recorded a charge to earnings of approximately $23 million, consisting of income tax expense of $15 million and after-tax interest expense of $8 million. No recovery will be sought from ComEd customers for any interest, penalty or additional income tax payment amounts resulting from the like-kind exchange tax position.

 

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DPL Delaware Electric and Natural Gas Distribution Rates Case: On March 8, 2017, DPL entered into a settlement agreement with the Division of the Public Advocate, Delaware Electric Users Group and the DPSC Staff in its electric distribution rate proceeding, which provides for an increase in DPL annual electric distribution rates of $31.5 million based on an ROE of 9.7 percent and compared to the $32.1 million increase previously put into effect. On May 23, 2017, the DPSC issued an order approving the settlement agreement, with the new rates effective June 1, 2017. Pursuant to the settlement agreement, no refund of any pre-settlement interim rates put into effect is required.

On April 6, 2017, DPL entered into a settlement agreement with the Division of the Public Advocate and the DPSC Staff in its natural gas distribution rate proceeding, which provides for an increase in DPL annual natural gas distribution rates of $4.9 million based on an ROE of 9.7 percent. On June 6, 2017, the DPSC issued an order approving the settlement agreement, with the new rates effective July 1, 2017. Pursuant to the settlement agreement, a rate refund plus interest of approximately $5 million will be issued to customers beginning in August 2017 for which a regulatory liability has been recorded as of June 30, 2017.

 

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DPL Maryland Electric Distribution Rates: On July 14, 2017, DPL filed an application with the MDPSC to increase its annual electric distribution base rates by $27 million based on a requested ROE of 10.1 percent. DPL expects a decision on the matter in the first quarter of 2018. DPL cannot predict how much of the requested increase the MDPSC will approve.

 

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Pepco District of Columbia Electric Distribution Rate Case: On July 25, 2017, the DCPSC issued an order granting Pepco an increase to its annual electric distribution base rates of $36.9 million effective Aug. 15, 2017, based on an ROE of 9.5 percent. In its decision, the DCPSC ordered that the $25.6 million customer rate credit created as a result of the Exelon and PHI merger will be provided primarily to residential customers and some small commercial customers until that amount has been exhausted, which is expected to be approximately two years. Additionally, the Commission is holding approximately $6 million to $7 million of the customer rate credit for use toward a possible new class of customers for certain senior citizens and disabled persons. The DCPSC also held that Pepco’s bill stabilization adjustment, which decouples distribution revenues from utility customers from the amount of electricity delivered, will continue to be in place and that no refund of previously collected funds is required.

 

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Nuclear Operations: Generation’s nuclear fleet, including its owned output from the Salem Generating Station and 100 percent of the CENG units, produced 44,065 gigawatt-hours (GWhs) in the second quarter of 2017, compared with 42,453 GWhs in the second quarter of 2016. Excluding Salem, the Exelon-operated nuclear plants at ownership achieved a 90.9 percent capacity factor for the second quarter of 2017, compared with 92.3 percent for the second quarter of 2016. The number of planned refueling outage days in the second quarter of 2017 totaled 125, compared with 87 in the second quarter of 2016. There were 12 non-refueling outage days in the second quarter of 2017, compared with 21 days in the second quarter of 2016.

 

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Fossil and Renewables Operations: The dispatch match rate for Generation’s gas and hydro fleet was 99.0 percent in the second quarter of 2017, compared with 97.4 percent in the second quarter of 2016. Energy capture for the wind and solar fleet was 95.5 percent in the second quarter of 2017, equal to the performance in the second quarter of 2016.

 

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Financing Activities:

 

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On April 3, 2017, Exelon completed the remarketing of $1.15 billion aggregate principal amount of its 2.500 percent Junior Subordinated Notes due 2024, originally issued as components of its equity units issued in June 2014, issuing $1.15 billion aggregate principal amount of 3.497 percent Junior Subordinated Notes due in 2022. Exelon conducted the remarketing on behalf of the holders of equity units and did not directly receive any proceeds therefrom. Instead, Exelon received $1.15 billion on June 1, 2017 upon settlement of the forward equity purchase contract and issued approximately 33 million shares of common stock from treasury stock at the time of settlement.

 

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On May 22, 2017, Pepco issued $200 million aggregate principal amount of its 4.150 percent First Mortgage Bonds due in 2043. The proceeds from the sale of the First Mortgage Bonds were used to repay outstanding commercial paper and for general corporate purposes.

 

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GAAP/Adjusted (non-GAAP) Operating Earnings Reconciliation

Adjusted (non-GAAP) Operating Earnings for the second quarter of 2017 do not include the following items (after tax) that were included in reported GAAP Earnings (Loss):

 

(in millions)		Exelon Earnings per Diluted Share				Exelon				ComEd				PECO				BGE				PHI				Generation
2017 GAAP Earnings (Loss)		$	0.09			$	80			$	118			$	88			$	45			$	66			$	(250	)
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $72 and $71, respectively)			0.12				113				—				—				—				—				114
Unrealized Gains Related to NDT Fund Investments (net of taxes of $20)			(0.05	)			(45	)			—				—				—				—				(45	)
Amortization of Commodity Contract Intangibles (net of taxes of $8)			0.01				12				—				—				—				—				12
Merger and Integration Costs (net of taxes of $9, $1 and $7, respectively)			0.01				15				—				—				—				1				12
Merger Commitments (net of taxes of $3)			—				—				—				—				—				(4	)			—
Long-Lived Asset Impairments (net of taxes of $172 and $171, respectively)			0.29				268				—				—				—				—				269
Plant Retirements and Divestitures (net of taxes of $42)			0.07				66				—				—				—				—				66
Cost Management Program (net of taxes of $4, $1, $1 and $3 respectively)			0.01				6				—				1				1				—				4
Like-Kind Exchange Tax Position (net of taxes of $66 and $9, respectively)			(0.03	)			(26	)			23				—				—				—				—
CENG Noncontrolling Interest (net of taxes of $5)			0.02				20				—				—				—				—				20
2017 Adjusted (non-GAAP) Operating Earnings		$	0.54			$	509			$	141			$	89			$	46			$	63			$	202

 

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Adjusted (non-GAAP) Operating Earnings for the second quarter of 2016 do not include the following items (after tax) that were included in reported GAAP Earnings (Loss):

 

(in millions)		Exelon Earnings per Diluted Share				Exelon				ComEd				PECO				BGE				PHI				Generation
2016 GAAP Earnings (Loss)		$	0.29			$	267			$	145			$	100			$	31			$	52			$	(8	)
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $120 and $119, respectively)			0.20				185				—				—				—				—				185
Unrealized Gains Related to NDT Fund Investments (net of taxes of $29)			(0.03	)			(27	)			—				—				—				—				(27	)
Amortization of Commodity Contract Intangibles (net of taxes of $4)			0.01				8				—				—				—				—				8
Merger and Integrations Costs (net of taxes of $0, $0, $2 and $2, respectively)			—				1				1				—				(3	)			—				3
Merger Commitments (entire amount represents tax expense)			—				1				—				—				—				1				—
Long-Lived Asset Impairments (net of taxes of $14)			0.02				22				—				—				—				—				22
Plant Retirements and Divestitures (net of taxes of $85)			0.14				133				—				—				—				—				133
Cost Management Program (net of taxes of $3, $0, $0 and $2, respectively)			0.01				6				—				1				1				—				4
CENG Noncontrolling Interest (net of taxes of $1)			0.01				8				—				—				—				—				8
2016 Adjusted (non-GAAP) Operating Earnings		$	0.65			$	604			$	146			$	101			$	29			$	53			$	328

Note:

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 ranged from 39 percent to 41 percent. Under IRS regulations, NDT fund investment returns are taxed at differing rates for investments in qualified vs. non-qualified funds. The tax rates applied to unrealized gains and losses related to NDT Fund investments were 31.4 percent and 47.5 percent for the three and six months ended June 30, 2017, respectively, and 51.6 percent and 52.5 percent for the three and six months ended June 30, 2016, respectively.

Webcast Information

Exelon will discuss second quarter 2017 earnings in a one-hour conference call scheduled for today at 10 a.m. Central Time (11 a.m. Eastern Time). The webcast and associated materials can be accessed at www.exeloncorp.com/investor-relations.

 

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About Exelon

Exelon Corporation (NYSE: EXC) is a Fortune 100 energy company with the largest number of utility customers in the U.S. Exelon does business in 48 states, the District of Columbia and Canada and had 2016 revenue of $31.4 billion. Exelon’s six utilities deliver electricity and natural gas to approximately 10 million customers in Delaware, the District of Columbia, Illinois, Maryland, New Jersey and Pennsylvania through its Atlantic City Electric, BGE, ComEd, Delmarva Power, PECO and Pepco subsidiaries. Exelon is one of the largest competitive U.S. power generators, with more than 33,300 megawatts of nuclear, gas, wind, solar and hydroelectric generating capacity comprising one of the nation’s cleanest and lowest-cost power generation fleets. The company’s Constellation business unit provides energy products and services to approximately 2.2 million residential, public sector and business customers, including more than two-thirds of the Fortune 100. Follow Exelon on Twitter @Exelon.

Non-GAAP Financial Measures

In addition to net income as determined under generally accepted accounting principles in the United States (GAAP), 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 measure is intended to enhance an investor’s overall understanding of period over period 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 measure 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’ presentation. The Company has provided the non-GAAP financial measure as supplemental information and in addition to the financial measures that are calculated and presented in accordance with GAAP. Adjusted (non-GAAP) Operating Earnings should not be deemed more useful than, a substitute for, or an alternative to the most comparable GAAP Net Income measures provided in this earnings release and attachments. This press release and earnings release attachments provide reconciliations of adjusted (non-GAAP) Operating Earnings to the most directly comparable financial measures calculated and presented in accordance with GAAP, are posted on Exelon’s website: www.exeloncorp.com, and have been furnished to the Securities and Exchange Commission on Form 8-K on Aug. 2, 2017.

 

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Cautionary Statements Regarding Forward-Looking Information

This press release 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 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) include those factors discussed herein, as well as the items discussed in (1) the Registrants’ 2016 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 24, Commitments and Contingencies; (2) the Registrants’ Second Quarter 2017 Quarterly Report on Form 10-Q (to be filed on August 2, 2017) 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 17, 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 press release. 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 press release.

 

11

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Earnings Release Attachments

Table of Contents

 

Consolidating Statements of Operations - three months ended June 30, 2017 and 2016			2
Consolidating Statements of Operations - six months ended June 30, 2017 and 2016			3
Business Segment Comparative Statements of Operations - Generation and ComEd - three and six months ended June 30, 2017 and 2016			4
Business Segment Comparative Statements of Operations - PECO and BGE - three and six months ended June 30, 2017 and 2016			5
Business Segment Comparative Statements of Operations - PHI and Other - three and six months ended June 30, 2017 and 2016			6
Consolidated Balance Sheets - June 30, 2017 and December 31, 2016			7
Consolidated Statements of Cash Flows - six months ended June 30, 2017 and 2016			8
GAAP Consolidated Statements of Operations and Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments - Exelon - three months ended June 30, 2017 and 2016			9
GAAP Consolidated Statements of Operations and Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments - Exelon - six months ended June 30, 2017 and 2016			11
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Earnings - three months ended June 30, 2017 and 2016			13
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Earnings - six months ended June 30, 2017 and 2016			15
GAAP Consolidated Statements of Operations and Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments - Generation - three and six months ended June 30, 2017 and 2016			17
GAAP Consolidated Statements of Operations and Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments - ComEd - three and six months ended June 30, 2017 and 2016			19
GAAP Consolidated Statements of Operations and Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments - PECO - three and six months ended June 30, 2017 and 2016			20
GAAP Consolidated Statements of Operations and Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments - BGE - three and six months ended June 30, 2017 and 2016			21
GAAP Consolidated Statements of Operations and Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments - PHI - three and six months ended June 30, 2017 and 2016			22
GAAP Consolidated Statements of Operations and Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments - Other - three and six months ended June 30, 2017 and 2016			23
Exelon Generation Statistics - three months ended June 30, 2017, March 31, 2017, December 31, 2016, September 30, 2016 and June 30, 2016			24
Exelon Generation Statistics - six months ended June 30, 2017 and 2016			25
ComEd Statistics - three and six months ended June 30, 2017 and 2016			26
PECO Statistics - three and six months ended June 30, 2017 and 2016			27
BGE Statistics - three and six months ended June 30, 2017 and 2016			29
Pepco Statistics - three and six months ended June 30, 2017 and 2016			31
DPL Statistics - three and six months ended June 30, 2017 and 2016			32
ACE Statistics - three and six months ended June 30, 2017 and 2016			34

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EXELON CORPORATION

Consolidating Statements of Operations

(unaudited)

(in millions)

 

		Three Months Ended June 30, 2017
		Generation				ComEd				PECO				BGE				PHI (b)				Other (a)				Exelon Consolidated
Operating revenues		$	4,174			$	1,357			$	630			$	674			$	1,074			$	(286	)		$	7,623
Operating expenses
Purchased power and fuel			2,157				378				197				234				383				(263	)			3,086
Operating and maintenance			2,010				377				190				174				269				(49	)			2,971
Depreciation and amortization			334				211				71				112				165				22				915
Taxes other than income			140				72				35				56				110				7				420
Total operating expenses			4,641				1,038				493				576				927				(283	)			7,392
Gain on sales of assets			—				—				—				—				1				—				1
Operating income (loss)			(467	)			319				137				98				148				(3	)			232
Other income and (deductions)
Interest expense, net			(129	)			(101	)			(31	)			(26	)			(59	)			(90	)			(436	)
Other, net			181				4				2				4				13				1				205
Total other income and (deductions)			52				(97	)			(29	)			(22	)			(46	)			(89	)			(231	)
Income (loss) before income taxes			(415	)			222				108				76				102				(92	)			1
Income taxes			(158	)			104				20				31				36				(105	)			(72	)
Equity in (losses) earnings of unconsolidated affiliates			(9	)			—				—				—				—				—				(9	)
Net income (loss)			(266	)			118				88				45				66				13				64
Net loss attributable to noncontrolling interests			(16	)			—				—				—				—				—				(16	)
Net income (loss) attributable to common shareholders		$	(250	)		$	118			$	88			$	45			$	66			$	13			$	80
		Three Months Ended June 30, 2016
		Generation				ComEd				PECO				BGE				PHI (b)				Other (a)				Exelon Consolidated
Operating revenues		$	3,589			$	1,286			$	664			$	680			$	1,066			$	(375	)		$	6,910
Operating expenses
Purchased power and fuel			1,577				339				217				261				416				(356	)			2,454
Operating and maintenance			1,530				368				190				208				246				(37	)			2,505
Depreciation and amortization			408				190				67				97				160				19				941
Taxes other than income			118				65				38				55				108				10				394
Total operating expenses			3,633				962				512				621				930				(364	)			6,294
Gain on sales of assets			31				—				—				—				—				—				31
Operating income (loss)			(13	)			324				152				59				136				(11	)			647
Other income and (deductions)
Interest expense, net			(99	)			(91	)			(31	)			(24	)			(66	)			(65	)			(376	)
Other, net			117				3				2				5				11				6				144
Total other income and (deductions)			18				(88	)			(29	)			(19	)			(55	)			(59	)			(232	)
Income (loss) before income taxes			5				236				123				40				81				(70	)			415
Income taxes			(31	)			91				23				6				29				(16	)			102
Equity in losses of unconsolidated affiliates			(8	)			—				—				—				—				1				(7	)
Net income (loss)			28				145				100				34				52				(53	)			306
Net income attributable to noncontrolling interests and preference stock dividends			36				—				—				3				—				—				39
Net income (loss) attributable to common shareholders		$	(8	)		$	145			$	100			$	31			$	52			$	(53	)		$	267

 

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

(b)	PHI includes the consolidated results of Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company.

 

2

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EXELON CORPORATION

Consolidating Statements of Operations

(unaudited)

(in millions)

 

		Six Months Ended June 30, 2017
		Generation				ComEd				PECO				BGE				PHI				Other (a)				Exelon Consolidated
Operating revenues		$	9,061			$	2,656			$	1,426			$	1,625			$	2,248			$	(635	)		$	16,381
Operating expenses
Purchased power and fuel			4,955				713				484				584				845				(596	)			6,985
Operating and maintenance			3,497				747				398				357				524				(92	)			5,431
Depreciation and amortization			637				419				141				239				332				43				1,811
Taxes other than income			282				144				74				119				221				17				857
Total operating expenses			9,371				2,023				1,097				1,299				1,922				(628	)			15,084
Gain on sales of assets			4				—				—				—				1				—				5
Bargain purchase gain			226				—				—				—				—				—				226
Operating income (loss)			(80	)			633				329				326				327				(7	)			1,528
Other income and (deductions)
Interest expense, net			(228	)			(185	)			(62	)			(54	)			(122	)			(158	)			(809	)
Other, net			440				8				3				8				26				3				488
Total other income and (deductions)			212				(177	)			(59	)			(46	)			(96	)			(155	)			(321	)
Income (loss) before income taxes			132				456				270				280				231				(162	)			1,207
Income taxes			(31	)			197				55				111				26				(215	)			143
Equity in losses of unconsolidated affiliates			(19	)			—				—				—				—				1				(18	)
Net income			144				259				215				169				205				54				1,046
Net loss attributable to noncontrolling interests			(30	)			—				—				—				—				—				(30	)
Net income attributable to common shareholders		$	174			$	259			$	215			$	169			$	205			$	54			$	1,076
		Six Months Ended June 30, 2016
		Generation				ComEd				PECO				BGE				PHI (b)				Other (a)				Exelon Consolidated
Operating revenues		$	8,329			$	2,535			$	1,505			$	1,609			$	1,171			$	(664	)		$	14,485
Operating expenses
Purchased power and fuel			4,020				686				537				634				454				(623	)			5,708
Operating and maintenance			2,997				736				405				410				695				98				5,341
Depreciation and amortization			697				379				134				206				174				36				1,626
Taxes other than income			244				141				80				114				123				18				720
Total operating expenses			7,958				1,942				1,156				1,364				1,446				(471	)			13,395
Gain on sales of assets			31				5				—				—				—				4				40
Operating income (loss)			402				598				349				245				(275	)			(189	)			1,130
Other income and (deductions)
Interest expense, net			(196	)			(177	)			(62	)			(48	)			(71	)			(109	)			(663	)
Other, net			210				7				4				11				12				14				258
Total other income and (deductions)			14				(170	)			(58	)			(37	)			(59	)			(95	)			(405	)
Income (loss) before income taxes			416				428				291				208				(334	)			(284	)			725
Income taxes			120				168				67				73				(77	)			(66	)			285
Equity in losses of unconsolidated affiliates			(11	)			—				—				—				—				1				(10	)
Net income (loss)			285				260				224				135				(257	)			(217	)			430
Net (loss) income attributable to noncontrolling interests and preference stock dividends			(17	)			—				—				6				—				1				(10	)
Net income (loss) attributable to common shareholders		$	302			$	260			$	224			$	129			$	(257	)		$	(218	)		$	440

 

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

(b)	PHI includes the consolidated results of Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company beginning on March 24, 2016, the day after the merger was completed.

 

3

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EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

 

		Generation
		Three Months Ended June 30,												Six Months Ended June 30,
		2017				2016				Variance				2017				2016				Variance
Operating revenues		$	4,174			$	3,589			$	585			$	9,061			$	8,329			$	732
Operating expenses
Purchased power and fuel			2,157				1,577				580				4,955				4,020				935
Operating and maintenance			2,010				1,530				480				3,497				2,997				500
Depreciation and amortization			334				408				(74	)			637				697				(60	)
Taxes other than income			140				118				22				282				244				38
Total operating expenses			4,641				3,633				1,008				9,371				7,958				1,413
Gain on sales of assets			—				31				(31	)			4				31				(27	)
Bargain purchase gain			—				—				—				226				—				226
Operating income			(467	)			(13	)			(454	)			(80	)			402				(482	)
Other income and (deductions)
Interest expense, net			(129	)			(99	)			(30	)			(228	)			(196	)			(32	)
Other, net			181				117				64				440				210				230
Total other income and (deductions)			52				18				34				212				14				198
Income before income taxes			(415	)			5				(420	)			132				416				(284	)
Income taxes			(158	)			(31	)			(127	)			(31	)			120				(151	)
Equity in losses of unconsolidated affiliates			(9	)			(8	)			(1	)			(19	)			(11	)			(8	)
Net (loss) income			(266	)			28				(294	)			144				285				(141	)
Net (loss) income attributable to noncontrolling interests			(16	)			36				(52	)			(30	)			(17	)			(13	)
Net (loss) income attributable to membership interest		$	(250	)		$	(8	)		$	(242	)		$	174			$	302			$	(128	)
		ComEd
		Three Months Ended June 30,												Six Months Ended June 30,
		2017				2016				Variance				2017				2016				Variance
Operating revenues		$	1,357			$	1,286			$	71			$	2,656			$	2,535			$	121
Operating expenses
Purchased power			378				339				39				713				686				27
Operating and maintenance			377				368				9				747				736				11
Depreciation and amortization			211				190				21				419				379				40
Taxes other than income			72				65				7				144				141				3
Total operating expenses			1,038				962				76				2,023				1,942				81
Gain on sales of assets			—				—				—				—				5				(5	)
Operating income			319				324				(5	)			633				598				35
Other income and (deductions)
Interest expense, net			(101	)			(91	)			(10	)			(185	)			(177	)			(8	)
Other, net			4				3				1				8				7				1
Total other income and (deductions)			(97	)			(88	)			(9	)			(177	)			(170	)			(7	)
Income before income taxes			222				236				(14	)			456				428				28
Income taxes			104				91				13				197				168				29
Net income		$	118			$	145			$	(27	)		$	259			$	260			$	(1	)

 

4

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EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

 

		PECO
		Three Months Ended June 30,												Six Months Ended June 30,
		2017				2016				Variance				2017				2016				Variance
Operating revenues		$	630			$	664			$	(34	)		$	1,426			$	1,505			$	(79	)
Operating expenses
Purchased power and fuel			197				217				(20	)			484				537				(53	)
Operating and maintenance			190				190				—				398				405				(7	)
Depreciation and amortization			71				67				4				141				134				7
Taxes other than income			35				38				(3	)			74				80				(6	)
Total operating expenses			493				512				(19	)			1,097				1,156				(59	)
Operating income			137				152				(15	)			329				349				(20	)
Other income and (deductions)
Interest expense, net			(31	)			(31	)			—				(62	)			(62	)			—
Other, net			2				2				—				3				4				(1	)
Total other income and (deductions)			(29	)			(29	)			—				(59	)			(58	)			(1	)
Income before income taxes			108				123				(15	)			270				291				(21	)
Income taxes			20				23				(3	)			55				67				(12	)
Net income		$	88			$	100			$	(12	)		$	215			$	224			$	(9	)
		BGE
		Three Months Ended June 30,												Six Months Ended June 30,
		2017				2016				Variance				2017				2016				Variance
Operating revenues		$	674			$	680			$	(6	)		$	1,625			$	1,609			$	16
Operating expenses
Purchased power and fuel			234				261				(27	)			584				634				(50	)
Operating and maintenance			174				208				(34	)			357				410				(53	)
Depreciation and amortization			112				97				15				239				206				33
Taxes other than income			56				55				1				119				114				5
Total operating expenses			576				621				(45	)			1,299				1,364				(65	)
Operating income			98				59				39				326				245				81
Other income and (deductions)
Interest expense, net			(26	)			(24	)			(2	)			(54	)			(48	)			(6	)
Other, net			4				5				(1	)			8				11				(3	)
Total other income and (deductions)			(22	)			(19	)			(3	)			(46	)			(37	)			(9	)
Income before income taxes			76				40				36				280				208				72
Income taxes			31				6				25				111				73				38
Net income			45				34				11				169				135				34
Preference stock dividends			—				3				(3	)			—				6				(6	)
Net income attributable to common shareholder		$	45			$	31			$	14			$	169			$	129			$	40

 

5

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EXELON CORPORATION    

Business Segment Comparative Statements of Operations    

(unaudited)

(in millions)

 

		PHI
		Three Months Ended June 30,												Six Months Ended June 30,
		2017				2016				Variance				2017				2016 (a)				Variance
Operating revenues		$	1,074			$	1,066			$	8			$	2,248			$	1,171			$	1,077
Operating expenses
Purchased power and fuel			383				416				(33	)			845				454				391
Operating and maintenance			269				246				23				524				695				(171	)
Depreciation and amortization			165				160				5				332				174				158
Taxes other than income			110				108				2				221				123				98
Total operating expenses			927				930				(3	)			1,922				1,446				476
Gain on sales of assets			1				—				1				1				—				1
Operating income (loss)			148				136				12				327				(275	)			602
Other income and (deductions)
Interest expense, net			(59	)			(66	)			7				(122	)			(71	)			(51	)
Other, net			13				11				2				26				12				14
Total other income and (deductions)			(46	)			(55	)			9				(96	)			(59	)			(37	)
Income (loss) before income taxes			102				81				21				231				(334	)			565
Income taxes			36				29				7				26				(77	)			103
Net income (loss)		$	66			$	52			$	14			$	205			$	(257	)		$	462
		Other (b)
		Three Months Ended June 30,												Six Months Ended June 30,
		2017				2016				Variance				2017				2016				Variance
Operating revenues		$	(286	)		$	(375	)		$	89			$	(635	)		$	(664	)		$	29
Operating expenses
Purchased power and fuel			(263	)			(356	)			93				(596	)			(623	)			27
Operating and maintenance			(49	)			(37	)			(12	)			(92	)			98				(190	)
Depreciation and amortization			22				19				3				43				36				7
Taxes other than income			7				10				(3	)			17				18				(1	)
Total operating expenses			(283	)			(364	)			81				(628	)			(471	)			(157	)
Gain on sales of assets			—				—				—				—				4				(4	)
Operating loss			(3	)			(11	)			8				(7	)			(189	)			182
Other income and (deductions)
Interest expense, net			(90	)			(65	)			(25	)			(158	)			(109	)			(49	)
Other, net			1				6				(5	)			3				14				(11	)
Total other income and (deductions)			(89	)			(59	)			(30	)			(155	)			(95	)			(60	)
Loss before income taxes			(92	)			(70	)			(22	)			(162	)			(284	)			122
Income taxes			(105	)			(16	)			(89	)			(215	)			(66	)			(149	)
Equity in earnings of unconsolidated affiliates		$	—			$	1			$	(1	)		$	1			$	1			$	—
Net income (loss) attributable to common shareholders			13				(53	)			66			$	54			$	(217	)		$	271
Net loss attributable to noncontrolling interests and preference stock dividends			—				—				—				—				1				(1	)
Net loss attributable to common shareholders		$	13			$	(53	)		$	66			$	54			$	(218	)		$	272

 

(a)	PHI includes the consolidated results of Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company beginning on March 24, 2016, the day after the merger was completed.

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

 

6

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EXELON CORPORATION    

Consolidated Balance Sheets    

(unaudited) (in millions)    

 

		June 30, 2017				December 31, 2016
Assets
Current assets
Cash and cash equivalents		$	536			$	635
Restricted cash and cash equivalents			252				253
Deposit with IRS			1,250				1,250
Accounts receivable, net
Customer			3,825				4,158
Other			958				1,201
Mark-to-market derivative assets			833				917
Unamortized energy contract assets			84				88
Inventories, net
Fossil fuel and emission allowances			334				364
Materials and supplies			1,267				1,274
Regulatory assets			1,293				1,342
Other			1,600				930
Total current assets			12,232				12,412
Property, plant and equipment, net			72,748				71,555
Deferred debits and other assets
Regulatory assets			9,945				10,046
Nuclear decommissioning trust funds			12,641				11,061
Investments			638				629
Goodwill			6,677				6,677
Mark-to-market derivative assets			464				492
Unamortized energy contract assets			419				447
Pledged assets for Zion Station decommissioning			75				113
Other			1,265				1,472
Total deferred debits and other assets			32,124				30,937
Total assets		$	117,104			$	114,904
Liabilities and shareholders’ equity
Current liabilities
Short-term borrowings		$	1,757			$	1,267
Long-term debt due within one year			3,619				2,430
Accounts payable			3,134				3,441
Accrued expenses			2,878				3,460
Payables to affiliates			8				8
Regulatory liabilities			574				602
Mark-to-market derivative liabilities			244				282
Unamortized energy contract liabilities			340				407
Renewable energy credit obligation			308				428
PHI merger related obligation			126				151
Other			977				981
Total current liabilities			13,965				13,457
Long-term debt			30,315				31,575
Long-term debt to financing trusts			641				641
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits			18,521				18,138
Asset retirement obligations			9,848				9,111
Pension obligations			4,082				4,248
Non-pension postretirement benefit obligations			1,955				1,848
Spent nuclear fuel obligation			1,139				1,024
Regulatory liabilities			4,398				4,187
Mark-to-market derivative liabilities			417				392
Unamortized energy contract liabilities			705				830
Payable for Zion Station decommissioning			—				14
Other			1,828				1,827
Total deferred credits and other liabilities			42,893				41,619
Total liabilities			87,814				87,292
Commitments and contingencies
Shareholders’ equity
Common stock			18,860				18,794
Treasury stock, at cost			(123	)			(2,327	)
Retained earnings			11,442				12,030
Accumulated other comprehensive loss, net			(2,633	)			(2,660	)
Total shareholders’ equity			27,546				25,837
Noncontrolling interests			1,744				1,775
Total equity			29,290				27,612
Total liabilities and shareholders’ equity		$	117,104			$	114,904

 

7

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EXELON CORPORATION    

Consolidated Statements of Cash Flows    

(unaudited)    

(in millions)    

 

		Six Months Ended June 30,
		2017				2016
Cash flows from operating activities
Net income		$	1,046			$	430
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization			2,591				2,396
Impairment of long-lived assets and losses on regulatory assets			445				239
Gain on sales of assets			(5	)			(40	)
Bargain purchase gain			(226	)			—
Deferred income taxes and amortization of investment tax credits			107				261
Net fair value changes related to derivatives			230				194
Net realized and unrealized gains on nuclear decommissioning trust fund investments			(284	)			(114	)
Other non-cash operating activities			412				1,056
Changes in assets and liabilities:
Accounts receivable			342				86
Inventories			(23	)			89
Accounts payable and accrued expenses			(811	)			(363	)
Option premiums paid, net			(8	)			(10	)
Collateral (posted) received, net			(173	)			710
Income taxes			58				470
Pension and non-pension postretirement benefit contributions			(325	)			(258	)
Other assets and liabilities			(478	)			(593	)
Net cash flows provided by operating activities			2,898				4,553
Cash flows from investing activities
Capital expenditures			(3,845	)			(4,489	)
Proceeds from nuclear decommissioning trust fund sales			5,213				4,977
Investment in nuclear decommissioning trust funds			(5,339	)			(5,094	)
Acquisition of businesses, net			(212	)			(6,642	)
Proceeds from sales of long-lived assets			211				45
Proceeds from termination of direct financing lease investment			—				360
Change in restricted cash			1				15
Other investing activities			(9	)			(49	)
Net cash flows used in investing activities			(3,980	)			(10,877	)
Cash flows from financing activities
Changes in short-term borrowings			422				(798	)
Proceeds from short-term borrowings with maturities greater than 90 days			576				194
Repayments on short-term borrowings with maturities greater than 90 days			(510	)			(315	)
Issuance of long-term debt			981				3,174
Retirement of long-term debt			(1,049	)			(217	)
Dividends paid on common stock			(607	)			(582	)
Common stock issued from treasury			1,150				—
Proceeds from employee stock plans			43				17
Other financing activities			(23	)			(4	)
Net cash flows provided by financing activities			983				1,469
Decrease in cash and cash equivalents			(99	)			(4,855	)
Cash and cash equivalents at beginning of period			635				6,502
Cash and cash equivalents at end of period		$	536			$	1,647

 

8

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EXELON CORPORATION

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions, except per share data)

 

		Three Months Ended June 30, 2017												Three Months Ended June 30, 2016
		GAAP (a)				Non-GAAP Adjustments								GAAP (a)				Non-GAAP Adjustments
Operating revenues		$	7,623			$	158				(b	),(d)		$	6,910			$	626				(b	),(d),(e)
Operating expenses
Purchased power and fuel			3,086				(48	)			(b	),(d)			2,454				300				(b	),(d),(h)
Operating and maintenance			2,971				(524	)			(e	),(f),(g),(h),(i)			2,505				(172	)			(e	),(g),(h),(i)
Depreciation and amortization			915				(35	)			(h	)			941				(114	)			(h	)
Taxes other than income			420												394
Total operating expenses			7,392												6,294
Gain on sales of assets			1												31
Operating income			232												647
Other income and (deductions)
Interest expense, net			(436	)			63				(g	),(j)			(376	)
Other, net			205				(66	)			(c	),(j)			144				(89	)			(c	),(h)
Total other income and (deductions)			(231	)											(232	)
Income before income taxes			1												415
											(b	),(c),(d),(e),											(b	),(c),(d),(e),
Income taxes			(72	)			353				(f	),(g),(h),(i),(j)			102				194				(f	),(g),(h),(i)
Equity in losses of unconsolidated affiliates			(9	)											(7	)
Net income			64												306
Net income (loss) attributable to noncontrolling interests and preference stock dividends			(16	)			(20	)			(k	)			39				(8	)			(k	)
Net income attributable to common shareholders		$	80											$	267
Effective tax rate(l)			(7,200.0	)%											24.6	%
Earnings per average common share
Basic		$	0.09											$	0.29
Diluted		$	0.09											$	0.29
Average common shares outstanding
Basic			934												924
Diluted			936												926
Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP:
Mark-to-market impact of economic hedging activities (b)						$	0.12											$	0.20
Unrealized gains related to NDT fund investments (c)							(0.05	)											(0.03	)
Amortization of commodity contract intangibles (d)							0.01												0.01
Merger and integration costs (e)							0.01												—
Merger commitments (f)							—												—
Long-lived asset impairments (g)							0.29												0.02
Plant retirements and divestitures (h)							0.07												0.14
Cost management program (i)							0.01												0.01
Like-kind exchange tax position (j)							(0.03	)											—
CENG noncontrolling interest (k)							0.02												0.01
Total adjustments						$	0.45											$	0.36

 

(a)	Results reported in accordance with accounting principles generally accepted in the United States (GAAP).

(b)	Adjustment to exclude the mark-to-market impact of Exelon’s economic hedging activities, net of intercompany eliminations.

(c)	Adjustment to exclude the unrealized gains and losses on NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements.

(d)	Adjustment to exclude the non-cash amortization of intangible assets, net, primarily related to commodity contracts recorded at fair value related to the Integrys acquisition in 2016, and in 2017, the ConEdison Solutions and FitzPatrick acquisitions.

(e)

Adjustment to exclude certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses and integration activities related to the PHI acquisition in 2016, partially offset in 2016 at BGE and PHI by the anticipated recovery of previously incurred PHI acquisition costs, and in 2017, the PHI and FitzPatrick acquisitions.

(f)	Adjustment to exclude costs incurred as part of the settlement orders approving the PHI acquisition.

(g)	Adjustment to exclude charges to earnings related to the impairment of certain wind projects at Generation in 2016, and in 2017, impairments as a result of the ExGen Texas Power, LLC assets held for sale.

(h)

Adjustment to exclude accelerated depreciation and amortization expenses, increases to materials and supplies inventory reserves, charges for severance reserves and construction work in progress impairments associated with Generation’s previous decision to early retire the Clinton and Quad Cities nuclear facilities in 2016, and Generation’s decision to early retire the Three Mile Island nuclear facility in 2017, partially offset in 2016 by a gain associated with Generation’s sale of the New Boston generating site.

 

9

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(i)	Adjustment to exclude reorganization costs, and in 2016 severance costs, related to a cost management program.

(j)	Adjustment to excluded income tax, penalties and interest expenses in the second quarter of 2017 as a result of the finalization of the IRS tax computation related to Exelon’s like-kind exchange tax position.

(k)	Adjustment to eliminate from Generation’s results of the noncontrolling interest related to CENG exclusion items, primarily related to the impact of unrealized gains and losses on NDT fund investments and mark-to-market activity.

(l)

The effective tax rate related to Adjusted (non-GAAP) Operating Earnings is 36.8% and 31.6% for the three months ended June 30, 2017 and June 30, 2016, respectively. The effective tax rate for the three months ended June 30, 2017 is disproportionately impacted due to the decline in pre-tax GAAP earnings and changes in other reconciling items.

 

10

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EXELON CORPORATION

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions, except per share data)

 

		Six Months Ended June 30, 2017												Six Months Ended June 30, 2016
		GAAP (a)				Non-GAAP Adjustments								GAAP (a)				Non-GAAP Adjustments
Operating revenues		$	16,381			$	116				(b	),(d)		$	14,485			$	534				(b	),(d),(e)
Operating expenses
Purchased power and fuel			6,985				(141	)			(b	),(d),(h)			5,708				338				(b	),(d),(h)
Operating and maintenance			5,431				(572	)			(e	),(f),(g),(h),(j)			5,341				(932	)			(e	),(f),(g),(h),(j)
Depreciation and amortization			1,811				(37	)			(d	),(h)			1,626				(114	)			(h	)
Taxes other than income			857												720				(1	)			(j	)
Total operating expenses			15,084												13,395
Gain on sales of assets			5				(1	)			(h	)			40
Bargain purchase gain			226				(226	)			(l	)			—
Operating income			1,528												1,130
Other income and (deductions)
Interest expense, net			(809	)			59				(g	),(k),(m)			(663	)
Other, net			488				(274	)			(c	),(m)			258				(155	)			(c	),(h)
Total other income and (deductions)			(321	)											(405	)
Income before income taxes			1,207												725
											(b	),(c),(d),(e),(f),(g),											(b	),(c),(d),(e),(f),(g),
Income taxes			143				441				(h	),(i),(j),(k),(m)			285				311				(h	),(j)
Equity in losses of unconsolidated affiliates			(18	)											(10	)
Net income			1,046												430
Net loss attributable to noncontrolling interests and preference stock dividends			(30	)			(55	)			(n	)			(10	)			(18	)			(n	)
Net income attributable to common shareholders		$	1,076											$	440
Effective tax rate(o)			11.8	%											39.3	%
Earnings per average common share
Basic		$	1.16											$	0.48
Diluted		$	1.15											$	0.48
Average common shares outstanding
Basic			931												923
Diluted			932												926
Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP:
Mark-to-market impact of economic hedging activities (b)						$	0.15											$	0.12
Unrealized gains related to NDT fund investments (c)							(0.15	)											(0.07	)
Amortization of commodity contract intangibles (d)							0.02												—
Merger and integration costs (e)							0.04												0.09
Merger commitments (f)							(0.15	)											0.43
Long-lived asset impairments (g)							0.29												0.10
Plant retirements and divestitures (h)							0.07												0.14
Reassessment of state deferred income taxes (i)							(0.02	)											—
Cost management program (j)							0.01												0.02
Tax settlements (k)							(0.01	)											—
Bargain purchase gain (l)							(0.24	)											—
Like-kind exchange tax position (m)							(0.03	)											—
CENG noncontrolling interest (n)							0.06												0.02
Total adjustments						$	0.04											$	0.85

As a result of the PHI acquisition completion on March 23, 2016, the table includes financial results for PHI beginning on March 24, 2016 to June 30, 2017. Therefore, the results of operations from 2017 and 2016 are not comparable for Exelon. The explanations below identify any other significant or unusual items affecting the results of operations.

 

(a)	Results reported in accordance with accounting principles generally accepted in the United States (GAAP).

(b)	Adjustment to exclude the mark-to-market impact of Exelon’s economic hedging activities, net of intercompany eliminations.

 

11

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(c)	Adjustment to exclude the unrealized gains and losses on NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements.

(d)	Adjustment to exclude the non-cash amortization of intangible assets, net, primarily related to commodity contracts recorded at fair value related to the Integrys acquisition in 2016, and in 2017, the ConEdison Solutions and FitzPatrick acquisitions.

(e)

Adjustment to exclude certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses and integration activities related to the PHI acquisition in 2016, partially offset in 2016 at ComEd, BGE and PHI by the anticipated recovery of previously incurred PHI acquisition costs, and in 2017, the PHI and FitzPatrick acquisitions, partially offset in 2017 at PHI by the anticipated recovery of previously incurred PHI acquisition costs.

(f)	Adjustment to exclude in 2016 costs incurred as part of the settlement orders approving the PHI acquisition, and in 2017, a decrease in reserves for uncertain tax positions related to the deductibility of certain merger commitments associated with the 2012 CEG and 2016 PHI acquisitions.

(g)	Adjustment to exclude charges to earnings related to the impairment of upstream assets and certain wind projects at Generation in 2016, and in 2017, impairments as a result of the ExGen Texas Power, LLC assets held for sale.

(h)

Adjustment to exclude accelerated depreciation and amortization expenses, increases to materials and supplies inventory reserves, charges for severance reserves and construction work in progress impairments associated with Generation’s previous decision to early retire the Clinton and Quad Cities nuclear facilities in 2016, and Generation’s decision to early retire the Three Mile Island nuclear facility in 2017, partially offset in 2016 by a gain associated with Generation’s sale of the New Boston generating site.

(i)	Adjustment to exclude the non-cash impact of the remeasurement of state deferred income taxes, primarily as a result of changes in forecasted apportionment related to the PHI acquisition in 2016, and in 2017, a change in the statutory tax rate.

(j)	Adjustment to exclude reorganization costs, and in 2016 severance costs, related to a cost management program

(k)	Adjustment to exclude benefits related to the favorable settlement in 2017 of certain income tax positions related to PHI’s unregulated business interests

(l)	Adjustment to exclude the excess of the fair value of assets and liabilities acquired over the purchase price for the FitzPatrick acquisition.

(m)	Adjustment to exclude income tax, penalties and interest expenses in the second quarter of 2017 as a result of the finalization of the IRS tax computation related to Exelon’s like-kind exchange tax position.

(n)	Adjustment to exclude from Generation’s results of the noncontrolling interest related to CENG exclusion items, primarily related to the impact of unrealized gains and losses on NDT fund investments and mark-to-market activity

(o)	The effective tax rate related to Adjusted (non-GAAP) Operating Earnings is 35.8% and 32.9% for the six months ended June 30, 2017 and June 30, 2016, respectively.

 

12

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EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating

Earnings to GAAP Earnings (in millions)

Three Months Ended June 30, 2017 and 2016

(unaudited)

 

		Exelon
		Earnings per
		Diluted																				PHI				Other
		Share				Generation				ComEd				PECO				BGE				(a)				(b)				Exelon
2016 GAAP Earnings (Loss)		$	0.29			$	(8	)		$	145			$	100			$	31			$	52			$	(53	)		$	267
2016 Adjusted (non-GAAP) Operating (Earnings) Loss Adjustments:
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $119 and $120, respectively)			0.20				185				—				—				—				—				—				185
Unrealized Gains Related to NDT Fund Investments (net of taxes of $29) (1)			(0.03	)			(27	)			—				—				—				—				—				(27	)
Amortization of Commodity Contract Intangibles (net of taxes of $4) (2)			0.01				8				—				—				—				—				—				8
Merger and Integration Costs (net of taxes of $2, $0, $2 and $0, respectively) (3)			—				3				1				—				(3	)			—				—				1
Merger Commitments (entire amount represents tax expense) (4)			—				—				—				—				—				1				—				1
Long-Lived Asset Impairments (net of taxes of $14) (5)			0.02				22				—				—				—				—				—				22
Plant Retirements and Divestitures (net of taxes of $85) (6)			0.14				133				—				—				—				—				—				133
Cost Management Program (net of taxes of $2, $0, $0 and $3, respectively) (7)			0.01				4				—				1				1				—				—				6
CENG Noncontrolling Interest (net of taxes of $1) (8)			0.01				8				—				—				—				—				—				8
2016 Adjusted (non-GAAP) Operating Earnings (Loss)			0.65				328				146				101				29				53				(53	)			604
Year Over Year Effects on Earnings:
ComEd, PECO, BGE and PHI Margins:
Weather			(0.02	)			—				(7	) (c)			(2	)			—	(c)			(6	) (c)			—				(15	)
Load			—				—				(3	) (c)			(2	)			—	(c)			8	(c)			—				3
Other Energy Delivery (10)			0.06				—				28	(d)			(5	) (d)			13	(d)			23	(d)			—				59
Generation Energy Margins, Excluding Mark-to-Market:
Nuclear Volume (11)			0.03				28				—				—				—				—				—				28
Nuclear Fuel Cost (12)			—				2				—				—				—				—				—				2
Capacity Pricing (13)			—				(2	)			—				—				—				—				—				(2	)
Zero Emission Credit Revenue (14)			0.05				45				—				—				—				—				—				45
Market and Portfolio Conditions (15)			(0.16	)			(144	)			—				—				—				—				—				(144	)
Operating and Maintenance Expense:
Labor, Contracting and Materials (16)			(0.01	)			(7	)			1				(2	)			—				(6	)			—				(14	)
Planned Nuclear Refueling Outages (17)			(0.05	)			(50	)			—				—				—				—				—				(50	)
Pension and Non-Pension Postretirement Benefits (18)			—				(2	)			(1	)			1				1				—				(1	)			(2	)
Other Operating and Maintenance (19)			(0.01	)			(25	)			(5	)			2				23				(10	)			9				(6	)
Depreciation and Amortization Expense (20)			(0.04	)			(3	)			(13	)			(2	)			(9	)			(3	)			(2	)			(32	)
Interest Expense, Net (21)			—				(6	)			2				—				(2	)			4				(1	)			(3	)
Income Taxes (22)			—				(2	)			(2	)			(3	)			(11	)			—				14				(4	)
Equity in Earnings of Unconsolidated Affiliates			—				(1	)			—				—				—				—				—				(1	)
Noncontrolling Interests (23)			0.04				40				—				—				—				—				—				40
Other			—				1				(5	)			1				2				—				2				1
2017 Adjusted (non-GAAP) Operating Earnings (Loss)			0.54				202				141				89				46				63				(32	)			509
2017 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $71, $1 and $72, respectively)			(0.12	)			(114	)			—				—				—				—				1				(113	)
Unrealized Gains Related to NDT Fund Investments (net of taxes of $20) (1)			0.05				45				—				—				—				—				—				45
Amortization of Commodity Contract Intangibles (net of taxes of $8) (2)			(0.01	)			(12	)			—				—				—				—				—				(12	)
Merger and Integration Costs (net of taxes of $1, $7, $1 and $9, respectively) (3)			(0.01	)			(12	)			—				—				—				(1	)			(2	)			(15	)
Merger Commitments (net of taxes of $3, $3 and $0, respectively) (4)			—				—				—				—				—				4				(4	)			—
Long-Lived Asset Impairments (net of taxes of $171, $1 and $172, respectively) (5)			(0.29	)			(269	)			—				—				—				—				1				(268	)
Plant Retirements and Divestitures (net of taxes of $42) (6)			(0.07	)			(66	)			—				—				—				—				—				(66	)
Cost Management Program (net of taxes of $3, $1, $1 and $4, respectively) (7)			(0.01	)			(4	)			—				(1	)			(1	)			—				—				(6	)
Like-Kind Exchange Tax Position (net of taxes of $9, $75 and $66, respectively) (9)			0.03				—				(23	)			—				—				—				49				26
CENG Noncontrolling Interest (net of taxes of $5) (8)			(0.02	)			(20	)			—				—				—				—				—				(20	)
2017 GAAP Earnings (Loss)		$	0.09			$	(250	)		$	118			$	88			$	45			$	66			$	13			$	80

 

13

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Note:

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 ranged from 39 percent to 41 percent. Under IRS regulations, NDT fund investment returns are taxed at differing rates for investments in qualified vs. non-qualified funds. The tax rates applied to unrealized gains and losses related to NDT Fund investments were 31.4 percent and 47.5 percent for the three and six months ended June 30, 2017, respectively, and 51.6 percent and 52.5 percent for the three and six months ended June 30, 2016, respectively.

 

(a)

PHI consolidated results includes Potomac Electric Power Company, Delmarva Power & Light Company, and Atlantic City Electric Company.

(b)

Other primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities and other financing and investment activities.

(c)

As approved by the Maryland PSC and District of Columbia PSC, customer rates for BGE, Pepco and DPL Maryland are adjusted to eliminate the favorable and unfavorable impacts of weather and usage patterns per customer on distribution volumes. Pursuant to the Illinois Future Energy Jobs Act, beginning in 2017, customer rates for ComEd are adjusted to eliminate the favorable and unfavorable impacts of weather and customer usage patterns on distribution volumes.

(d)

For regulatory recovery mechanisms, including ComEd’s distribution formula rate, ComEd, BGE and PHI utilities transmission formula rates, and riders across all utilities, revenues increase and decrease i) as fully recoverable costs fluctuate (with no impact on net earnings), and ii) pursuant to changes in rate base, capital structure and ROE (which impact net earnings).

(1)

Reflects the impact of unrealized gains on NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements.

(2)

Represents the non-cash amortization of intangible assets, net, primarily related to commodity contracts recorded at fair value related to the Integrys acquisition in 2016, and in 2017, the ConEdison Solutions and FitzPatrick acquisitions.

(3)

Reflects certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses and integration activities related to the PHI acquisition in 2016, partially offset in 2016 at BGE and PHI by the anticipated recovery of previously incurred PHI acquisition costs, and in 2017, the PHI and FitzPatrick acquisitions.

(4)

Represents costs incurred as part of the settlement orders approving the PHI acquisition.

(5)

Primarily reflects charges to earnings related to the impairment of certain wind projects at Generation in 2016, and in 2017, impairments as a result of the ExGen Texas Power, LLC assets held for sale.

(6)

Primarily reflects accelerated depreciation and amortization expenses, increases to materials and supplies inventory reserves, charges for severance reserves and construction work in progress impairments associated with Generation’s previous decision to early retire the Clinton and Quad Cities nuclear facilities in 2016, and Generation’s decision to early retire the Three Mile Island nuclear facility in 2017, partially offset in 2016 by a gain associated with Generation’s sale of the New Boston generating site.

(7)

Represents reorganization costs, and in 2016 severance costs, related to a cost management program.

(8)

Represents elimination from Generation’s results of the noncontrolling interest related to CENG exclusion items, primarily related to the impact of unrealized gains and losses on NDT fund investments and mark-to-market activity.

(9)

Represents adjustments to income tax, penalties and interest expenses in the second quarter of 2017 as a result of the finalization of the IRS tax computation related to Exelon’s like-kind exchange tax position.

(10)

For ComEd, primarily reflects increased electric distribution and transmission formula rate revenues (due to increased capital investments and higher electric distribution ROE, which is due to an increase in treasury rates). For BGE and PHI, primarily reflects increased revenue as a result of rate increases.

(11)

Primarily reflects the acquisition of the FitzPatrick nuclear facility.

(12)

Primarily reflects a decrease in fuel prices, partially offset by increased nuclear output as a result of the FitzPatrick acquisition.

(13)

Primarily reflects decreased capacity prices in the Mid-Atlantic region, partially offset by increased capacity prices in the New England region.

(14)

Reflects the impact of the New York Clean Energy Standard.

(15)

Primarily reflects the conclusion of the Ginna Reliability Support Services Agreement, lower realized energy prices and lower optimization in Generation’s natural gas portfolio.

(16)

For Generation, primarily reflects increased salaries and wages related to the acquisition of the FitzPatrick nuclear facility.

(17)

Primarily reflects an increase in the number of nuclear outage days in 2017, excluding Salem.

(18)

Primarily reflects the unfavorable impact of lower pension and OPEB discount rates, partially offset by the favorable impact of lower health care claims experience.

(19)

For Generation, primarily reflects an increase in nuclear decommissioning obligation expense. For BGE, primarily reflects the absence of 2016 charges for certain disallowances contained in the June and July 2016 rate case orders.

(20)

For BGE, primarily reflects increased amortization due to the initiation of cost recovery of the AMI programs and increased depreciation from AMI program capital expenditures. Additionally, primarily reflects increased depreciation from ongoing capital expenditures across all operating companies.

(21)

For Generation, primarily reflects increased interest expense due to higher outstanding debt.

(22)

For BGE, primarily reflects a 2016 cumulative adjustment to tax expense for transmission-related regulatory assets. For Corporate, primarily reflects the 2016 unfavorable impact of the expiration of statutes of limitations.

(23)

Reflects elimination from Generation’s results of activity attributable to noncontrolling interests, primarily for CENG.

 

14

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EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating

Earnings to GAAP Earnings (in millions)

Six Months Ended June 30, 2017 and 2016

(unaudited)

 

		Exelon
		Earnings per
		Diluted																				PHI				Other				Exelon
		Share				Generation				ComEd				PECO				BGE				(a)				(b)				(a)
2016 GAAP Earnings (Loss)		$	0.48			$	302			$	260			$	224			$	129			$	(257	)		$	(218	)		$	440
2016 Adjusted (non-GAAP) Operating (Earnings) Loss Adjustments:
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $81)			0.12				121				—				—				—				—				—				121
Unrealized Gains Related to NDT Fund Investments (net of taxes of $64) (1)			(0.07	)			(59	)			—				—				—				—				—				(59	)
Amortization of Commodity Contract Intangibles (net of taxes of $2) (2)			—				(4	)			—				—				—				—				—				(4	)
Merger and Integration Costs (net of taxes of $8, $3, $1, $2, $23, $1 and $26, respectively) (3)			0.09				14				(4	)			1				(2	)			33				37				79
Merger Commitments (net of taxes of $1, $84, $28 and $113, respectively) (4)			0.43				2				—				—				—				279				114				395
Long-Lived Asset Impairments (net of taxes of $62) (5)			0.10				93				—				—				—				—				—				93
Plant Retirements and Divestitures (net of taxes of $85) (6)			0.14				133				—				—				—				—				—				133
Reassessment of State Deferred Income Taxes (entire amount represents tax expense) (7)			—				6				—				—				—				—				(6	)			—
Cost Management Program (net of taxes of $9, $1, $1 and $12, respectively) (8)			0.02				15				—				2				2				—				—				19
CENG Noncontrolling Interest (net of taxes of $3) (9)			0.02				18				—				—				—				—				—				18
2016 Adjusted (non-GAAP) Operating Earnings (Loss)			1.33				641				256				227				129				55				(73	)			1,235
Year Over Year Effects on Earnings:
ComEd, PECO, BGE and PHI Margins:
Weather			(0.01	)			—				(2	) (c)			—				—	(c)			(6	) (c)			—				(8	)
Load			—				—				(4	) (c)			(5	)			—	(c)			8	(c)			—				(1	)
Other Energy Delivery (13)			0.54				—				67	(d)			(11	) (d)			39	(d)			406	(d)			—				501
Generation Energy Margins, Excluding Mark-to-Market:
Nuclear Volume (14)			0.01				9				—				—				—				—				—				9
Nuclear Fuel Cost (15)			0.02				14				—				—				—				—				—				14
Capacity Pricing (16)			(0.03	)			(31	)			—				—				—				—				—				(31	)
Zero Emission Credit Revenue (17)			0.05				45				—				—				—				—				—				45
Market and Portfolio Conditions (18)			(0.14	)			(129	)			—				—				—				—				—				(129	)
Operating and Maintenance Expense:
Labor, Contracting and Materials (19)			(0.15	)			(53	)			4				(4	)			(2	)			(84	)			—				(139	)
Planned Nuclear Refueling Outages (20)			(0.07	)			(69	)			—				—				—				—				—				(69	)
Pension and Non-Pension Postretirement Benefits (21)			(0.01	)			—				(1	)			1				1				(7	)			(1	)			(7	)
Other Operating and Maintenance (22)			(0.07	)			(44	)			(10	)			7				35				(63	)			14				(61	)
Depreciation and Amortization Expense (23)			(0.17	)			(10	)			(24	)			(4	)			(20	)			(94	)			(4	)			(156	)
Interest Expense, Net (24)			(0.06	)			(8	)			4				—				(4	)			(30	)			(19	)			(57	)
Income Taxes (25)			(0.01	)			(18	)			(3	)			4				(8	)			8				11				(6	)
Equity in Earnings of Unconsolidated Affiliates			(0.01	)			(5	)			—				—				—				—				—				(5	)
Noncontrolling Interests (26)			0.03				30				—				—				—				—				—				30
Other			(0.05	)			1				(5	)			3				2				(49	)			(3	)			(51	)
Share Differential (27)			(0.01	)			—				—				—				—				—				—				—
2017 Adjusted (non-GAAP) Operating Earnings (Loss)			1.19				373				282				218				172				144				(75	)			1,114
2017 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $90, $1 and $91, respectively)			(0.15	)			(143	)			—				—				—				—				1				(142	)
Unrealized Gains Related to NDT Fund Investments (net of taxes of $130) (1)			0.15				144				—				—				—				—				—				144
Amortization of Commodity Contract Intangibles (net of taxes of $9) (2)			(0.02	)			(15	)			—				—				—				—				—				(15	)
Merger and Integration Costs (net of taxes of $23, $1, $1, $1, $1 and $25, respectively) (3)			(0.04	)			(37	)			—				(1	)			(1	)			1				(2	)			(40	)
Merger Commitments ( net of taxes of $18, $52, $67 and $137, respectively) (4)			0.15				18				—				—				—				60				59				137
Long-Lived Asset Impairments (net of taxes of $171, $1 and $172, respectively) (5)			(0.29	)			(269	)			—				—				—				—				1				(268	)
Plant Retirements and Divestitures (net of taxes of $42) (6)			(0.07	)			(66	)			—				—				—				—				—				(66	)
Reassessment of State Deferred Income Taxes (entire amount represents tax expense) (7)			0.02				—				—				—				—				—				20				20
Cost Management Program (net of taxes of $4, $1, $1, $0 and $7, respectively)(8)			(0.01	)			(7	)			—				(2	)			(2	)			—				1				(10	)
Tax Settlements (net of taxes of $1) (10)			0.01				5				—				—				—				—				—				5
Bargain Purchase Gain (11)			0.24				226				—				—				—				—				—				226
Like-Kind Exchange Tax Position (net of taxes of $9, $75 and $66, respectively) (12)			0.03				—				(23	)			—				—				—				49				26
CENG Noncontrolling Interest (net of taxes of $12) (9)			(0.06	)			(55	)			—				—				—				—				—				(55	)
2017 GAAP Earnings		$	1.15			$	174			$	259			$	215			$	169			$	205			$	54			$	1,076

 

15

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Note:

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 ranged from 39 percent to 41 percent. Under IRS regulations, NDT fund investment returns are taxed at differing rates for investments in qualified vs. non-qualified funds. The tax rates applied to unrealized gains and losses related to NDT Fund investments were 31.4 percent and 47.5 percent for the three and six months ended June 30, 2017, respectively, and 51.6 percent and 52.5 percent for the three and six months ended June 30, 2016, respectively.

 

(a)

For the six months ended June 30, 2016, includes financial results for PHI beginning on March 24, 2016, the day after the merger was completed. Therefore, the results of operations from 2017 and 2016 are not comparable for PHI and Exelon. The explanations below identify any other significant or unusual items affecting the results of operations. PHI consolidated results includes Potomac Electric Power Company, Delmarva Power & Light Company, and Atlantic City Electric Company.

(b)

Other primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities and other financing and investment activities.

(c)

As approved by the Maryland PSC and District of Columbia PSC, customer rates for BGE, Pepco and DPL Maryland are adjusted to eliminate the favorable and unfavorable impacts of weather and usage patterns per customer on distribution volumes. Pursuant to the Illinois Future Energy Jobs Act, beginning in 2017, customer rates for ComEd are adjusted to eliminate the favorable and unfavorable impacts of weather and customer usage patterns on distribution volumes.

(d)

For regulatory recovery mechanisms, including ComEd’s distribution formula rate, ComEd, BGE and PHI utilities transmission formula rates, and riders across all utilities, revenues increase and decrease i) as fully recoverable costs fluctuate (with no impact on net earnings), and ii) pursuant to changes in rate base, capital structure and ROE (which impact net earnings).

(1)

Reflects the impact of unrealized gains on NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements.

(2)

Represents the non-cash amortization of intangible assets, net, primarily related to commodity contracts recorded at fair value related to the Integrys acquisition in 2016, and in 2017, the ConEdison Solutions and FitzPatrick acquisitions.

(3)

Reflects certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses and integration activities related to the PHI acquisition in 2016, partially offset in 2016 at ComEd, BGE and PHI by the anticipated recovery of previously incurred PHI acquisition costs, and in 2017, the PHI and FitzPatrick acquisitions, partially offset in 2017 at PHI by the anticipated recovery of previously incurred PHI acquisition costs.

(4)

Primarily reflects in 2016 costs incurred as part of the settlement orders approving the PHI acquisition, and in 2017, a decrease in reserves for uncertain tax positions related to the deductibility of certain merger commitments associated with the 2012 CEG and 2016 PHI acquisitions.

(5)

Primarily reflects charges to earnings related to the impairment of upstream assets and certain wind projects at Generation in 2016, and in 2017, impairments as a result of the ExGen Texas Power, LLC assets held for sale.

(6)

Primarily reflects accelerated depreciation and amortization expenses, increases to materials and supplies inventory reserves, charges for severance reserves and construction work in progress impairments associated with Generation’s previous decision to early retire the Clinton and Quad Cities nuclear facilities in 2016, and Generation’s decision to early retire the Three Mile Island nuclear facility in 2017, partially offset in 2016 by a gain associated with Generation’s sale of the New Boston generating site.

(7)

Reflects the non-cash impact of the remeasurement of state deferred income taxes, primarily as a result of changes in forecasted apportionment related to the PHI acquisition in 2016, and in 2017, a change in the statutory tax rate.

(8)

Represents reorganization costs, and in 2016 severance costs, related to a cost management program.

(9)

Represents elimination from Generation’s results of the noncontrolling interest related to CENG exclusion items, primarily related to the impact of unrealized gains and losses on NDT fund investments and mark-to-market activity.

(10)

Reflects benefits related to the favorable settlement in 2017 of certain income tax positions related to PHI’s unregulated business interests.

(11)

Represents the excess of the fair value of assets and liabilities acquired over the purchase price for the FitzPatrick acquisition.

(12)

Represents adjustments to income tax, penalties and interest expenses in the second quarter of 2017 as a result of the finalization of the IRS tax computation related to Exelon’s like-kind exchange tax position.

(13)

For ComEd, primarily reflects increased electric distribution and transmission formula rate revenues (due to increased capital investments and higher electric distribution ROE, which is due to an increase in treasury rates) and an increase in fully recoverable costs. For BGE and PHI, primarily reflects increased revenue as a result of rate increases.

(14)

Primarily reflects the acquisition of the FitzPatrick nuclear facility, partially offset by an increase in nuclear outage days.

(15)

Primarily reflects a decrease in fuel prices.

(16)

Primarily reflects decreased capacity prices in the Mid-Atlantic and Midwest regions, partially offset by increased capacity prices in the New England region.

(17)

Reflects the impact of the New York Clean Energy Standard.

(18)

Primarily reflects the impacts of declining natural gas prices and lower optimization in Generation’s natural gas portfolio, the conclusion of the Ginna Reliability Support Services Agreement and lower realized energy prices, partially offset by the inclusion of Pepco Energy Services results in 2017, the absence of oil inventory write downs that occurred in 2016 and revenue related to energy efficiency projects.

(19)

For Generation, primarily reflects the inclusion of Pepco Energy Services results in 2017, increased contracting costs related to energy efficiency projects and increased salaries and wages related to the acquisition of the FitzPatrick nuclear facility.

(20)

Primarily reflects an increase in the number of nuclear outage days in 2017, excluding Salem.

(21)

Primarily reflects the favorable impact of lower health care claims experience, partially offset by the unfavorable impact of lower pension and OPEB discount rates.

(22)

For Generation, primarily reflects an increase in nuclear decommissioning obligation expense. For ComEd, primarily reflects increased fully recoverable costs associated with energy efficiency programs. For BGE, primarily reflects the absence of 2016 charges for certain disallowances contained in the June and July 2016 rate case orders and decreased storm costs in the BGE service territory.

(23)

For BGE, primarily reflects increased amortization due to the initiation of cost recovery of the AMI programs and increased depreciation from AMI program capital expenditures. Additionally, primarily reflects increased depreciation from ongoing capital expenditures across all operating companies.

(24)

For Generation, primarily reflects increased interest expense due to higher outstanding debt. For Corporate, primarily reflects increased interest expense due to higher outstanding debt, as well as debt issuance costs related to the April 2017 remarketing of Junior Subordinated Notes due in 2024.

(25)

For Generation, primarily reflects the favorable settlement of certain income tax positions in 2016. For BGE, primarily reflects a 2016 cumulative adjustment to tax expense for transmission-related regulatory assets. For Corporate, primarily reflects the 2016 unfavorable impact of the expiration of statutes of limitations.

(26)

Reflects elimination from Generation’s results of activity attributable to noncontrolling interests, primarily for CENG.

(27)

Reflects the impact on earnings per share due to the increase in Exelon’s average diluted common shares outstanding as a result of the June 2017 common stock issuance.

 

16

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EXELON CORPORATION

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions)

 

		Generation
		Three Months Ended June 30, 2017										Three Months Ended June 30, 2016
		GAAP (a)				Non-GAAP Adjustments						GAAP (a)				Non-GAAP Adjustments
Operating revenues		$	4,174			$	158			(b),(d)		$	3,589			$	625			(b),(d)
Operating expenses
Purchased power and fuel			2,157				(48	)		(b),(d),(h)			1,577				300			(b),(d),(h)
Operating and maintenance			2,010				(516	)		(e),(g),(h),(i)			1,530				(174	)		(e),(g),(h),(i)
Depreciation and amortization			334				(35	)		(h)			408				(114	)		(h)
Taxes other than income			140										118
Total operating expenses			4,641										3,633
Gain on sales of assets			—										31
Operating income			(467	)									(13	)
Other income and (deductions)
Interest expense, net			(129	)			21			(g)			(99	)
Other, net			181				(64	)		(c)			117				(89	)		(c),(h)
Total other income and (deductions)			52										18
Income before income taxes			(415	)									5
Income taxes			(158	)			282			(b),(c),(d),(e), (g),(h),(i)			(31	)			196			(b),(c),(d),(e), (g),(h),(i)
Equity in losses of unconsolidated affiliates			(9	)									(8	)
Net (loss) income			(266	)									28
Net (loss) income attributable to noncontrolling interests			(16	)			(20	)		(l)			36				(8	)		(l)
Net (loss) income attributable to membership interest		$	(250	)								$	(8	)
		Six Months Ended June 30, 2017										Six Months Ended June 30, 2016
		GAAP (a)				Non-GAAP Adjustments						GAAP (a)				Non-GAAP Adjustments
Operating revenues		$	9,061			$	116			(b),(d)		$	8,329			$	542			(b),(d)
Operating expenses
Purchased power and fuel			4,955				(141	)		(b),(d),(h)			4,020				338			(b),(d),(h)
Operating and maintenance			3,497				(562	)		(e),(g),(i),(h),			2,997				(330	)		(e),(f),(g),(h),(i)
Depreciation and amortization			637				(37	)		(d),(h)			697				(114	)		(h)
Taxes other than income			282										244				(1	)		(i)
Total operating expenses			9,371										7,958
Gain on sales of assets			4				(1	)		(h)			31
Bargain purchase gain			226				(226	)		(k),(h)			—
Operating income			(80	)									402
Other income and (deductions)
Interest expense, net			(228	)			18			(g),(j)			(196	)
Other, net			440				(273	)		(c)			210				(155	)		(c),(h)
Total other income and (deductions)			212										14
Income before income taxes			132										416
Income taxes			(31	)			230			(b),(c),(d),(e), (f),(g),(h),(i),(j)			120				173			(b),(c),(d),(e), (f),(g),(h),(i),(k)
Equity in losses of unconsolidated affiliates			(19	)									(11	)
Net income			144										285
Net loss attributable to noncontrolling interests			(30	)			(55	)		(l)			(17	)			(18	)		(l)
Net income attributable to membership interest		$	174									$	302

 

17

---

(a)	Results reported in accordance with GAAP.

(b)	Adjustment to exclude the mark-to-market impact of Exelon’s economic hedging activities, net of intercompany eliminations.

(c)	Adjustment to exclude the unrealized gains and losses on NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements.

(d)	Adjustment to exclude the non-cash amortization of intangible assets, net, primarily related to commodity contracts recorded at fair value related to the Integrys acquisition in 2016, and in 2017, the ConEdison Solutions and FitzPatrick acquisitions.

(e)	Adjustment to exclude costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses, and integration activities related to the PHI acquisition in 2016.

(f)	Adjustment to exclude 2016 costs incurred as part of the settlement orders approving the PHI acquisition, and in 2017, a decrease in reserves for uncertain tax positions related to the deductibility of certain merger commitments associated with the 2012 CEG and 2016 PHI acquisitions.

(g)	Adjustment to exclude charges to earnings related to the impairment of upstream assets and certain wind projects at Generation in 2016, and in 2017, impairments as a result of the ExGen Texas Power, LLC assets held for sale.

(h)

Adjustment to exclude accelerated depreciation and amortization expenses, increases to materials and supplies inventory reserves, charges for severance reserves and construction work in progress impairments associated with Generation’s previous decision to early retire the Clinton and Quad Cities nuclear facilities in 2016, and Generation’s decision to early retire the Three Mile Island nuclear facility in 2017, partially offset in 2016 by a gain associated with Generation’s sale of the New Boston generating site.

(i)	Adjustment to exclude reorganization costs, and in 2016 severance costs, related to a cost management program.

(j)	Adjustment to exclude the benefits related to the favorable settlement in 2017 of certain income tax positions related to PHI’s unregulated business interests.

(k)	Adjustment to exclude the excess of the fair value of assets and liabilities acquired over the purchase price for the FitzPatrick acquisition.

(l)	Adjustment to exclude the elimination from Generation’s results of the noncontrolling interest related to CENG exclusion items, primarily related to the impact of unrealized gains and losses on NDT fund investments and mark-to-market activity.

 

18

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EXELON CORPORATION

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions)

 

		ComEd
		Three Months Ended June 30, 2017								Three Months Ended June 30, 2016
		GAAP (a)				Non-GAAP Adjustments				GAAP (a)				Non-GAAP Adjustments
Operating revenues		$	1,357							$	1,286			$	1  (b	)
Operating expenses
Purchased power and fuel			378								339
Operating and maintenance			377				(1	)  (c)			368
Depreciation and amortization			211								190
Taxes other than income			72								65
Total operating expenses			1,038								962
Operating income			319								324
Other income and (deductions)
Interest expense, net			(101	)			14	(c)			(91	)
Other, net			4								3
Total other income and (deductions)			(97	)							(88	)
Income before income taxes			222								236
Income taxes			104				(8	)  (c)			91
Net income		$	118							$	145
		Six Months Ended June 30, 2017								Six Months Ended June 30, 2016
		GAAP (a)				Non-GAAP Adjustments				GAAP (a)				Non-GAAP Adjustments
Operating revenues		$	2,656							$	2,535			$	(8	)  (b)
Operating expenses
Purchased power and fuel			713								686
Operating and maintenance			747				(1	)  (c)			736				(1	)  (b)
Depreciation and amortization			419								379
Taxes other than income			144								141
Total operating expenses			2,023								1,942
Gain on sales of assets			—								5
Operating income			633								598
Other income and (deductions)
Interest expense, net			(185	)			14	(c)			(177	)
Other, net			8								7
Total other income and (deductions)			(177	)							(170	)
Income before income taxes			456								428
Income taxes			197				(8	)  (c)			168				(3	)  (b)
Net income		$	259							$	260

 

(a)	Results reported in accordance with GAAP.

(b)	Adjustment to exclude costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses, and integration activities, partially offset in 2016 at ComEd by the anticipated recovery of previously incurred PHI acquisition costs.

(c)	Adjustment to excluded income tax, penalties and interest expenses in the second quarter of 2017 as a result of the finalization of the IRS tax computation related to Exelon’s like-kind exchange tax position.

 

19

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EXELON CORPORATION

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions)

 

		PECO
		Three Months Ended June 30, 2017								Three Months Ended June 30, 2016
		GAAP (a)				Non-GAAP Adjustments				GAAP (a)				Non-GAAP Adjustments
Operating revenues		$	630							$	664
Operating expenses
Purchased power and fuel			197								217
Operating and maintenance			190				(2	)  (b)			190				(2	) (b),(c)
Depreciation and amortization			71								67
Taxes other than income			35								38
Total operating expenses			493								512
Operating income			137								152
Other income and (deductions)
Interest expense, net			(31	)							(31	)
Other, net			2								2
Total other income and (deductions)			(29	)							(29	)
Income before income taxes			108								123
Income taxes			20				1	(b)			23				1	(c)
Net income		$	88							$	100
		Six Months Ended June 30, 2017								Six Months Ended June 30, 2016
		GAAP (a)				Non-GAAP Adjustments				GAAP (a)				Non-GAAP Adjustments
Operating revenues		$	1,426							$	1,505
Operating expenses
Purchased power and fuel			484								537
Operating and maintenance			398				(5	) (b),(c)			405				(5	) (b),(c)
Depreciation and amortization			141								134
Taxes other than income			74								80
Total operating expenses			1,097								1,156
Operating income			329								349
Other income and (deductions)
Interest expense, net			(62	)							(62	)
Other, net			3								4
Total other income and (deductions)			(59	)							(58	)
Income before income taxes			270								291
Income taxes			55				2	(b),(c)			67				2	(b),(c)
Net income		$	215							$	224

 

(a)	Results reported in accordance with GAAP.

(b)	Adjustment to exclude certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses, integration activities, and upfront credit facilities fees related to the PHI acquisition.

(c)	Adjustment to exclude reorganization costs related to a cost management program.

 

20

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EXELON CORPORATION

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions)

 

		BGE
		Three Months Ended June 30, 2017								Three Months Ended June 30, 2016
		GAAP (a)				Non-GAAP Adjustments				GAAP (a)				Non-GAAP Adjustments
Operating revenues		$	674							$	680
Operating expenses
Purchased power and fuel			234								261
Operating and maintenance			174				(2	) (b),(c)			208				4	(b),(c)
Depreciation and amortization			112								97
Taxes other than income			56								55
Total operating expenses			576								621
Operating income			98								59
Other income and (deductions)
Interest expense, net			(26	)							(24	)
Other, net			4								5
Total other income and (deductions)			(22	)							(19	)
Income before income taxes			76								40
Income taxes			31				1	(b),(c)			6				(2	) (b),(c)
Net income			45								34
Preference stock dividends			—								3
Net income attributable to common shareholder		$	45							$	31
		Six Months Ended June 30, 2017								Six Months Ended June 30, 2016
		GAAP (a)				Non-GAAP Adjustments				GAAP (a)				Non-GAAP Adjustments
Operating revenues		$	1,625							$	1,609
Operating expenses
Purchased power and fuel			584								634
Operating and maintenance			357				(5	) (b),(c)			410				1	(b),(c)
Depreciation and amortization			239								206
Taxes other than income			119								114
Total operating expenses			1,299								1,364
Operating income			326								245
Other income and (deductions)
Interest expense, net			(54	)							(48	)
Other, net			8								11
Total other income and (deductions)			(46	)							(37	)
Income before income taxes			280								208
Income taxes			111				2	(b),(c)			73				(1	) (b),(c)
Net income			169								135
Preference stock dividends			—								6
Net income attributable to common shareholder		$	169							$	129

 

(a)	Results reported in accordance with GAAP.

(b)

Adjustment to exclude certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses, integration activities, and upfront credit facilities fees, partially offset in 2016 by the anticipated recovery of previously incurred PHI acquisition costs.

(c)	Adjustment to exclude reorganization costs related to a cost management program.

 

21

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EXELON CORPORATION

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions)

 

		PHI
		Three Months Ended June 30, 2017								Three Months Ended June 30, 2016
		GAAP (a)				Non-GAAP Adjustments				GAAP (a)				Non-GAAP Adjustments
Operating revenues		$	1,074							$	1,066
Operating expenses
Purchased power and fuel			383								416
Operating and maintenance			269				4	(c),(d)			246
Depreciation and amortization			165								160
Taxes other than income			110								108
Total operating expenses			927								930
Gain on sales of assets			1								—
Operating income			148								136
Other income and (deductions)
Interest expense, net			(59	)							(66	)
Other, net			13								11
Total other income and (deductions)			(46	)							(55	)
Income before income taxes			102								81
Income taxes			36				(1	) (c),(d)			29				(1	)(d)
Net income		$	66							$	52
		Six Months Ended June 30, 2017								Six Months Ended June 30, 2016 (b)
		GAAP (a)				Non-GAAP Adjustments				GAAP (a)				Non-GAAP Adjustments
Operating revenues		$	2,248							$	1,171
Operating expenses
Purchased power and fuel			845								454
Operating and maintenance			524				10	(c),(d)			695				(419	) (c),(d)
Depreciation and amortization			332								174
Taxes other than income			221								123
Total operating expenses			1,922								1,446
Gain on sales of assets			1								—
Operating income (loss)			327								(275	)
Other income and (deductions)
Interest expense, net			(122	)							(71	)
Other, net			26								12
Total other income and (deductions)			(96	)							(59	)
Income (loss) before income taxes			231								(334	)
Income taxes			26				51	(c),(d)			(77	)			107	(c),(d)
Net income (loss)		$	205							$	(257	)

 

(a)	Results reported in accordance with GAAP.

(b)

For the six months ended June 30, 2016, includes financial results for PHI beginning on March 24, 2016, the day after the merger was completed. Therefore, the results of operations from 2017 and 2016 are not comparable for PHI and Exelon. The explanations below identify any other significant or unusual items affecting the results of operations. PHI consolidated results includes Potomac Electric Power Company, Delmarva Power & Light Company, and Atlantic City Electric Company.

(c)

Adjustment to exclude certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses, integration activities, and upfront credit facilities fees, partially offset in 2016 at PHI by the anticipated recovery of previously incurred PHI acquisition costs.

(d)	Adjustment to exclude costs incurred as part of the settlement orders approving the PHI acquisition.

 

22

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EXELON CORPORATION

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions)

 

		Other (a)
		Three Months Ended June 30, 2017								Three Months Ended June 30, 2016
		GAAP (b)				Non-GAAP Adjustments				GAAP (b)				Non-GAAP Adjustments
Operating revenues		$	(286	)						$	(375	)
Operating expenses
Purchased power and fuel			(263	)							(356	)
Operating and maintenance			(49	)			(7	) (d),(e)			(37	)
Depreciation and amortization			22								19
Taxes other than income			7								10
Total operating expenses			(283	)							(364	)
Operating loss			(3	)							(11	)
Other income and (deductions)
Interest expense, net			(90	)			28	(h)			(65	)
Other, net			1				(2	) (h)			6
Total other income and (deductions)			(89	)							(59	)
Loss before income taxes			(92	)							(70	)
Income taxes			(105	)			78	(d),(e),(f),(h)			(16	)
Equity in earnings of unconsolidated affiliates			—								1
Net income (loss) attributable to common shareholders		$	13							$	(53	)
		Six Months Ended June 30, 2017								Six Months Ended June 30, 2016
		GAAP (b)				Non-GAAP Adjustments				GAAP (b)				Non-GAAP Adjustments
Operating revenues		$	(635	)						$	(664	)
Operating expenses
Purchased power and fuel			(596	)							(623	)
Operating and maintenance			(92	)			(9	) (d),(e)			98				(178	)  (d),(e)
Depreciation and amortization			43								36
Taxes other than income			17								18
Total operating expenses			(628	)							(471	)
Gain on sales of assets			—								4
Operating loss			(7	)							(189	)
Other income and (deductions)
Interest expense, net			(158	)			27	(h)			(109	)
Other, net			3				(1	) (h)			14
Total other income and (deductions)			(155	)							(95	)
Loss before income taxes			(162	)							(284	)
Income taxes			(215	)			164	(d),(e),(f),    (g),(h)			(66	)			33	(d),(e),(g)
Equity in earnings of unconsolidated affiliates			1								1
Net income (loss)			54								(217	)
Net income attributable to noncontrolling interests and preference stock dividends			—								1
Net income (loss) attributable to common shareholders		$	54							$	(218	)

 

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

(b)	Results reported in accordance with GAAP.

(c)	Adjustment to exclude the mark-to-market impact of Exelon’s economic hedging activities, net of intercompany eliminations.

(d)	Adjustment to exclude certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses and integration activities related to the PHI acquisition.

(e)	Adjustment to exclude in 2016 costs incurred as part of the settlement orders approving the PHI acquisition, and in 2017, a decrease in reserves for uncertain tax positions related to the deductibility of certain merger commitments associated with the 2016 PHI acquisition.

(f)	Adjustment to exclude the impact of impairments as a result of the ExGen Texas Power, LLC assets held for sale.

(g)	Reflects the non-cash impact of the remeasurement of state deferred income taxes, primarily as a result of changes in forecasted apportionment related to the PHI acquisition in 2016, and in 2017, a change in the statutory tax rate.

(h)	Adjustment to exclude the impact to income tax, penalties and interest expenses in the second quarter of 2017 as a result of the finalization of the IRS tax computation related to Exelon’s like-kind exchange tax position.

 

23

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EXELON CORPORATION

Exelon Generation Statistics

 

		Three Months Ended
		June 30, 2017				March 31, 2017				December 31, 2016				September 30, 2016				June 30, 2016
Supply (in GWhs)
Nuclear Generation
Mid-Atlantic(a)			15,246				16,545				16,410				15,604				15,224
Midwest			22,592				22,468				23,743				24,262				23,001
New York(a),(f)			6,227				4,491				4,681				4,843				4,228
Total Nuclear Generation			44,065				43,504				44,834				44,709				42,453
Fossil and Renewables
Mid-Atlantic			899				836				442				706				685
Midwest			417				418				442				273				324
New England			1,925				2,077				1,142				1,886				2,016
New York			1				1				1				1				1
ERCOT			2,315				1,370				1,056				2,472				1,879
Other Power Regions(b)			2,084				1,423				1,935				2,103				1,995
Total Fossil and Renewables			7,641				6,125				5,018				7,441				6,900
Purchased Power
Mid-Atlantic			2,901				3,398				2,849				7,139				3,131
Midwest			413				388				400				461				688
New England			4,343				5,064				4,768				3,927				3,782
New York			—				28				—				—				—
ERCOT			1,871				2,655				3,189				2,895				2,259
Other Power Regions(b)			3,507				2,868				3,308				3,803				3,879
Total Purchased Power			13,035				14,401				14,514				18,225				13,739
Total Supply/Sales by Region(c)
Mid-Atlantic(d)			19,046				20,779				19,701				23,449				19,040
Midwest(d)			23,422				23,274				24,585				24,996				24,013
New England			6,268				7,141				5,910				5,813				5,798
New York			6,228				4,520				4,682				4,844				4,229
ERCOT			4,186				4,025				4,245				5,367				4,138
Other Power Regions(b)			5,591				4,291				5,243				5,906				5,874
Total Supply/Sales by Region			64,741				64,030				64,366				70,375				63,092
		Three Months Ended
		June 30, 2017				March 31, 2017				December 31, 2016				September 30, 2016				June 30, 2016
Outage Days(e)
Refueling(f)			125				95				71				17				87
Non-refueling(f)			12				8				32				—				21
Total Outage Days			137				103				103				17				108

 

(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)	Other Power Regions includes, South, West and Canada.

(c)	Excludes physical proprietary trading volumes of 2,312 GHhs, 1,850 GWhs, 2,164 GWhs, 1,506 GWhs, and 1,289 GWhs for the three months ended June 30, 2017, March 31, 2017, December 31, 2016, September 30, 2016, and June 30, 2016, respectively.

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

(e)	Outage days exclude Salem.

(f)	Includes the ownership of the FitzPatrick nuclear facility from March 31, 2017.

 

24

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EXELON CORPORATION

Exelon Generation Statistics

Six Months Ended June 30, 2017 and 2016

 

		June 30, 2017				June 30, 2016
Supply (in GWhs)
Nuclear Generation
Mid-Atlantic(a)			31,790				31,432
Midwest			45,061				46,663
New York(a),(d)			10,718				9,160
Total Nuclear Generation			87,569				87,255
Fossil and Renewables
Mid-Atlantic			1,734				1,583
Midwest			835				773
New England			4,002				3,940
New York			2				2
ERCOT			3,684				3,255
Other Power Regions			3,507				4,142
Total Fossil and Renewables			13,764				13,695
Purchased Power
Mid-Atlantic			6,299				6,886
Midwest			801				1,394
New England			9,407				7,937
New York			28				—
ERCOT			4,525				4,553
Other Power Regions			6,375				6,479
Total Purchased Power			27,435				27,249
Total Supply/Sales by Region(b)
Mid-Atlantic(c)			39,823				39,901
Midwest(c)			46,697				48,830
New England			13,409				11,877
New York			10,748				9,162
ERCOT			8,209				7,808
Other Power Regions			9,882				10,621
Total Supply/Sales by Region			128,768				128,199

 

(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)	Excludes physical proprietary trading volumes of 4,162 GWh and 2,509 GWh for the six months ended June 30, 2017 and 2016, respectively.

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

(d)	Includes the ownership of the FitzPatrick nuclear facility from March 31, 2017.

 

25

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EXELON CORPORATION

ComEd Statistics

Three Months Ended June 30, 2017 and 2016

 

		Electric Deliveries (in GWhs)																Revenue (in millions)
		2017				2016				% Change				Weather- Normal % Change				2017				2016				% Change
Retail Deliveries and Sales (a)
Residential			5,919				6,349				(6.8	)%			(3.0	)%		$	656			$	625				5.0	%
Small Commercial & Industrial			7,437				7,735				(3.9	)%			(2.7	)%			347				329				5.5	%
Large Commercial & Industrial			6,798				6,736				0.9	%			1.5	%			123				116				6.0	%
Public Authorities & Electric Railroads			282				277				1.8	%			1.8	%			11				11				—	%
Total Retail			20,436				21,097				(3.1	)%			(1.4	)%			1,137				1,081				5.2	%
Other Revenue (b)																			220				205				7.3	%
Total Electric Revenue (c)																		$	1,357			$	1,286				5.5	%
Purchased Power																		$	378			$	339				11.5	%
																		% Change
Heating and Cooling Degree-Days						2017				2016				Normal				From 2016								From Normal
Heating Degree-Days							577				755				734								(23.6	)%			(21.4	)%
Cooling Degree-Days							263				290				241								(9.3	)%			9.1	%
Six Months Ended June 30, 2017 and 2016
		Electric Deliveries (in GWhs)																Revenue (in millions)
		2017				2016				% Change				Weather- Normal % Change				2017				2016				% Change
Retail Deliveries and Sales (a)
Residential			12,160				12,725				(4.4	)%			(1.3	)%		$	1,283			$	1,232				4.1	%
Small Commercial & Industrial			15,146				15,615				(3.0	)%			(1.8	)%			680				651				4.5	%
Large Commercial & Industrial			13,480				13,493				(0.1	)%			0.5	%			231				224				3.1	%
Public Authorities & Electric Railroads			625				639				(2.2	)%			(1.1	)%			24				23				4.3	%
Total Retail			41,411				42,472				(2.5	)%			(0.9	)%			2,218				2,130				4.1	%
Other Revenue (b)																			438				405				8.1	%
Total Electric Revenue (c)																		$	2,656			$	2,535				4.8	%
Purchased Power																		$	713			$	686				3.9	%
																		% Change
Heating and Cooling Degree-Days						2017				2016				Normal				From 2016								From Normal
Heating Degree-Days							3,227				3,655				3,875								(11.7	)%			(16.7	)%
Cooling Degree-Days							263				290				241								(9.3	)%			9.1	%

 

Number of Electric Customers		2017				2016
Residential			3,605,731				3,570,528
Small Commercial & Industrial			375,976				372,354
Large Commercial & Industrial			2,009				1,972
Public Authorities & Electric Railroads			4,785				4,749
Total			3,988,501				3,949,603

 

(a)

Reflects delivery volumes and revenues from customers purchasing electricity directly from ComEd and customers purchasing electricity from a competitive electric generation supplier, as all customers are assessed delivery charges. For customers purchasing electricity from ComEd, revenue also reflects the cost of energy and transmission.

(b)	Other revenue primarily includes transmission revenue from PJM. Other revenue includes rental revenues, revenues related to late payment charges, revenues from other utilities for mutual assistance programs and recoveries of remediation costs associated with MGP sites.

(c)	Includes operating revenues from affiliates totaling $3 million and $3 million for the three months ended June 30, 2017 and 2016, respectively, and $9 million and $8 million for the six months ended June 30, 2017 and 2016, respectively.

 

26

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EXELON CORPORATION

PECO Statistics

Three Months Ended June 30, 2017 and 2016

 

		Electric and Natural Gas Deliveries																Revenue (in millions)
														Weather-
														Normal
		2017				2016				% Change				% Change				2017				2016				% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential			2,809				2,909				(3.4	)%			(3.3	)%		$	331			$	355				(6.8	)%
Small Commercial & Industrial			1,914				1,887				1.4	%			0.9	%			100				106				(5.7	)%
Large Commercial & Industrial			3,830				3,770				1.6	%			0.4	%			57				65				(12.3	)%
Public Authorities & Electric Railroads			196				205				(4.4	)%			(4.4	)%			8				9				(11.1	)%
Total Retail			8,749				8,771				(0.3	)%			(0.8	)%			496				535				(7.3	)%
Other Revenue (b)																			54				52				3.8	%
Total Electric Revenue (d)																			550				587				(6.3	)%
Natural Gas (in mmcfs)
Retail Deliveries and Sales
Retail Sales (c)			7,621				7,883				(3.3	)%			11.8	%			72				70				2.9	%
Transportation and Other			5,759				5,906				(2.5	)%			(3.2	)%			8				7				14.3	%
Total Natural Gas (d)			13,380				13,789				(3.0	)%			5.3	%			80				77				3.9	%
Total Electric and Natural Gas Revenues																		$	630			$	664				(5.1	)%
Purchased Power and Fuel																		$	197			$	217				(9.2	)%
																		% Change
Heating and Cooling Degree-Days						2017				2016				Normal				From 2016				From Normal
Heating Degree-Days							329				469				463				(29.9	)%							(28.9	)%
Cooling Degree-Days							415				391				348				6.1	%							19.3	%

Six Months Ended June 30, 2017 and 2016

 

		Electric and Natural Gas Deliveries																Revenue (in millions)
														Weather-
														Normal
		2017				2016				% Change				% Change				2017				2016				% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential			6,187				6,324				(2.2	)%			(2.2	)%		$	713			$	766				(6.9	)%
Small Commercial & Industrial			3,890				3,912				(0.6	)%			(1.1	)%			197				225				(12.4	)%
Large Commercial & Industrial			7,456				7,364				1.2	%			0.5	%			109				123				(11.4	)%
Public Authorities & Electric Railroads			420				432				(2.8	)%			(2.8	)%			16				17				(5.9	)%
Total Retail			17,953				18,032				(0.4	)%			(0.9	)%			1,035				1,131				(8.5	)%
Other Revenue (b)																			105				101				4.0	%
Total Electric Revenue (d)																			1,140				1,232				(7.5	)%
Natural Gas (in mmcfs)
Retail Deliveries and Sales
Retail Sales (c)			34,832				34,994				(0.5	)%			2.0	%			269				256				5.1	%
Transportation and Other			13,448				13,602				(1.1	)%			(1.8	)%			17				17				—	%
Total Natural Gas (d)			48,280				48,596				(0.7	)%			1.0	%			286				273				4.8	%
Total Electric and Natural Gas Revenues																		$	1,426			$	1,505				(5.2	)%
Purchased Power and Fuel																		$	484			$	537				(9.9	)%

 

																		% Change
Heating and Cooling Degree-Days						2017				2016				Normal				From 2016				From Normal
Heating Degree-Days							2,423				2,606				2,939				(7.0	)%							(17.6	)%
Cooling Degree-Days							415				396				348				4.8	%							19.3	%

 

27

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Number of Electric Customers		2017				2016				Number of Natural Gas Customers		2017				2016
Residential			1,461,931				1,449,450			Residential			474,360				469,230
Small Commercial & Industrial			150,783				149,523			Commercial & Industrial			43,404				43,046
Large Commercial & Industrial			3,105				3,088			Total Retail			517,764				512,276
Public Authorities & Electric Railroads			9,795				9,813			Transportation			768				811
Total			1,625,614				1,611,874			Total			518,532				513,087

 

(a)

Reflects delivery volumes and revenues from customers purchasing electricity directly from PECO and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from PECO, revenue also reflects the cost of energy and transmission.

(b)	Other revenue includes transmission revenue from PJM and wholesale electric revenues.

(c)

Reflects delivery volumes and revenues 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. For customers purchasing natural gas from PECO, revenue also reflects the cost of natural gas.

(d)

Total electric revenue includes operating revenues from affiliates totaling $2 million and $2 million for the three months ended June 30, 2017 and 2016, respectively, and $3 million and $4 million for the six months ended June 30, 2017 and 2016, respectively. Total natural gas revenues includes operating revenues from affiliates totaling less than $1 million for both the three and six months ended June 30, 2017 and 2016.

 

28

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EXELON CORPORATION    

BGE Statistics

Three Months Ended June 30, 2017 and 2016    

 

		Electric and Natural Gas Deliveries												Revenue (in millions)
		2017				2016				% Change				2017				2016				% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential			2,629				2,616				0.5	%		$	315			$	324				(2.8	)%
Small Commercial & Industrial			677				692				(2.2	)%			63				65				(3.1	)%
Large Commercial & Industrial			3,373				3,417				(1.3	)%			110				115				(4.3	)%
Public Authorities & Electric Railroads			72				72				—	%			8				9				(11.1	)%
Total Retail			6,751				6,797				(0.7	)%			496				513				(3.3	)%
Other Revenue (b)(c)															75				71				5.6	%
Total Electric Revenue															571				584				(2.2	)%
Natural Gas (in mmcfs)
Retail Deliveries and Sales (d)
Retail Sales			13,028				17,672				(26.3	)%			99				93				6.5	%
Transportation and Other (e)			116				271				(57.2	)%			4				3				33.3	%
Total Natural Gas (f)			13,144				17,943				(26.7	)%			103				96				7.3	%
Total Electric and Natural Gas Revenues														$	674			$	680				(0.9	)%
Purchased Power and Fuel														$	234			$	261				(10.3	)%

 

														% Change
Heating and Cooling Degree-Days		2017				2016				Normal				From 2016				From Normal
Heating Degree-Days			397				574				511				(30.8	)%			(22.3	)%
Cooling Degree-Days			283				219				255				29.2	%			11.0	%

Six Months Ended June 30, 2017 and 2016

 

		Electric and Natural Gas Deliveries												Revenue (in millions)
		2017				2016				% Change				2017				2016				% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential			5,756				6,095				(5.6	)%		$	720			$	753				(4.4	)%
Small Commercial & Industrial			1,425				1,466				(2.8	)%			135				137				(1.5	)%
Large Commercial & Industrial			6,641				6,635				0.1	%			223				215				3.7	%
Public Authorities & Electric Railroads			140				143				(2.1	)%			15				18				(16.7	)%
Total Retail			13,962				14,339				(2.6	)%			1,093				1,123				(2.7	)%
Other Revenue (b)(c)															144				141				2.1	%
Total Electric Revenue															1,237				1,264				(2.1	)%
Natural Gas (in mmcfs)
Retail Deliveries and Sales (d)
Retail Sales			49,399				56,256				(12.2	)%			369				331				11.5	%
Transportation and Other (e)			2,395				2,767				(13.4	)%			19				14				35.7	%
Total Natural Gas (f)			51,794				59,023				(12.2	)%			388				345				12.5	%
Total Electric and Natural Gas Revenues														$	1,625			$	1,609				1.0	%
Purchased Power and Fuel														$	584			$	634				(7.9	)%

 

														% Change
Heating and Cooling Degree-Days		2017				2016				Normal				From 2016				From Normal
Heating Degree-Days			2,460				2,854				2,915				(13.8	)%		(15.6)%
Cooling Degree-Days			283				219				255				29.2	%		11.0 %

 

Number of Electric Customers		2017				2016				Number of Natural Gas Customers		2017				2016
Residential			1,154,330				1,142,073			Residential			624,392				618,268
Small Commercial & Industrial			113,329				112,980			Commercial & Industrial			44,020				44,078
Large Commercial & Industrial			12,113				11,980			Total Retail			668,412				662,346
Public Authorities & Electric Railroads			276				281			Transportation			—				—
Total			1,280,048				1,267,314			Total			668,412				662,346

 

(a)

Reflects delivery volumes and revenues from customers purchasing electricity directly from BGE and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from BGE, revenue also reflects the cost of energy and transmission.

 

29

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(b)	Other revenue primarily includes wholesale transmission revenue and late payment charges.

(c)	Includes operating revenues from affiliates totaling $2 million and $2 million for the three months ended June 30, 2017 and 2016, respectively, and $3 million and $4 million for the six months ended June 30, 2017 and 2016, respectively.

(d)

Reflects delivery volumes and revenues from customers purchasing natural gas directly from BGE and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges. For customers purchasing natural gas from BGE, revenue also reflects the cost of natural gas.

(e)

Transportation and other natural gas revenue includes off-system revenue of 116 mmcfs ($1 million) and 271 mmcfs ($2 million) for the three months ended June 30, 2017 and 2016, respectively, and 2,395 mmcfs ($13 million) and 2,767 mmcfs ($11 million) for the six months ended June 30, 2017 and 2016, respectively.

(f)	Includes operating revenues from affiliates totaling $1 million and $2 million for the three months ended June 30, 2017 and 2016, respectively, and $5 million and $5 million for the six months ended June 30, 2017 and 2016, respectively.

 

30

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EXELON CORPORATION    

PEPCO Statistics    

Three Months Ended June 30, 2017 and 2016    

 

		Electric Deliveries												Revenue (in millions)
		2017				2016				% Change				2017				2016				% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential			1,757				1,760				(0.2	)%		$	220			$	220				—	%
Small Commercial & Industrial			326				348				(6.3	)%			41				36				13.9	%
Large Commercial & Industrial			3,675				3,631				1.2	%			192				195				(1.5	)%
Public Authorities & Electric Railroads			172				176				(2.3	)%			8				8				—	%
Total Retail			5,930				5,915				0.3	%			461				459				0.4	%
Other Revenue (b)															53				50				6.0	%
Total Electric Revenue (c)															514				509				1.0	%
Purchased Power														$	143			$	152				(5.9	)%

 

														% Change
Heating and Cooling Degree-Days		2017				2016				Normal				From 2016				From Normal
Heating Degree-Days			314				397				500				(20.9	)%			(37.2	)%
Cooling Degree-Days			546				452				475				20.8	%			14.9	%

Six Months Ended June 30, 2017 and 2016

 

		Electric Deliveries												Revenue (in millions)
		2017				2016				% Change				2017				2016				% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential			3,757				3,978				(5.6	)%		$	461			$	476				(3.2	)%
Small Commercial & Industrial			652				730				(10.7	)%			75				73				2.7	%
Large Commercial & Industrial			7,160				7,576				(5.5	)%			387				395				(2.0	)%
Public Authorities & Electric Railroads			362				364				(0.5	)%			16				16				—	%
Total Retail			11,931				12,648				(5.7	)%			939				960				(2.2	)%
Other Revenue (b)															106				101				5.0	%
Total Electric Revenue (c)															1,045				1,061				(1.5	)%
Purchased Power														$	309			$	351				(12.0	)%

 

														% Change
Heating and Cooling Degree-Days		2017				2016				Normal				From 2016				From Normal
Heating Degree-Days			2,062				2,407				2,638				(14.3	)%			(21.8	)%
Cooling Degree-Days			550				454				478				21.1	%			15.1	%

 

Number of Electric Customers		2017				2016
Residential			787,708				771,541
Small Commercial & Industrial			53,393				53,345
Large Commercial & Industrial			21,767				21,401
Public Authorities & Electric Railroads			139				127
Total			863,007				846,414

 

(a)

Reflects delivery volumes and revenues from customers purchasing electricity directly from Pepco and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from Pepco, revenue also reflects the cost of energy and transmission.

(b)	Other revenue includes transmission revenue from PJM and wholesale electric revenues.

(c)	Includes operating revenues from affiliates totaling $1 million and $1 million for the three months ended June 30, 2017 and 2016, respectively, and $3 million and $3 million for the six months ended June 30, 2017 and 2016, respectively.

 

31

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EXELON CORPORATION

DPL Statistics

Three Months Ended June 30, 2017 and 2016

 

		Electric and Natural Gas Deliveries												Revenue (in millions)
		2017				2016				% Change				2017				2016				% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential			1,045				1,038				0.7	%		$	144			$	143				0.7	%
Small Commercial & Industrial			526				532				(1.1	)%			45				46				(2.2	)%
Large Commercial & Industrial			1,131				1,164				(2.8	)%			25				25				—	%
Public Authorities & Electric Railroads			12				12				—	%			4				3				33.3	%
Total Retail			2,714				2,746				(1.2	)%			218				217				0.5	%
Other Revenue (b)															42				38				10.5	%
Total Electric Revenue (c)															260				255				2.0	%
Natural Gas (in mmcfs)
Retail Deliveries and Sales (d)
Retail Sales			1,678				2,072				(19.0	)%			17				21				(19.0	)%
Transportation and Other (e)			1,325				1,321				0.3	%			5				5				—	%
Total Natural Gas			3,003				3,393				(11.5	)%			22				26				(15.4	)%
Total Electric and Natural Gas Revenues														$	282			$	281				0.4	%
Purchased Power and Fuel														$	113			$	122				(7.4	)%
Electric Service Territory														% Change
Heating and Cooling Degree-Days		2017				2016				Normal				From 2016				From Normal
Heating Degree-Days			481				551				702				(12.7	)%							(31.5	)%
Cooling Degree-Days			342				304				264				12.5	%							29.5	%
Gas Service Territory														% Change
Heating Degree-Days		2017				2016				Normal				From 2016				From Normal
Heating Degree-Days			372				559				504				(33.5	)%							(26.2	)%

Six Months Ended June 30, 2017 and 2016

 

		Electric and Natural Gas Deliveries												Revenue (in millions)
		2017				2016				% Change				2017				2016				% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential			2,404				2,465				(2.5	)%		$	325			$	323				0.6	%
Small Commercial & Industrial			1,057				1,104				(4.3	)%			89				95				(6.3	)%
Large Commercial & Industrial			2,195				2,242				(2.1	)%			51				50				2.0	%
Public Authorities & Electric Railroads			25				26				(3.8	)%			8				7				14.3	%
Total Retail			5,681				5,837				(2.7	)%			473				475				(0.4	)%
Other Revenue (b)															84				83				1.2	%
Total Electric Revenue (c)															557				558				(0.2	)%
Natural Gas (in mmcfs)
Retail Deliveries and Sales (d)
Retail Sales			7,610				8,132				(6.4	)%			75				74				1.4	%
Transportation and Other (e)			3,493				3,289				6.2	%			12				11				9.1	%
Total Natural Gas			11,103				11,421				(2.8	)%			87				85				2.4	%
Total Electric and Natural Gas Revenues														$	644			$	643				0.2	%
Purchased Power and Fuel														$	270			$	298				(9.4	)%

 

Electric Service Territory														% Change
Heating and Cooling Degree-Days		2017				2016				Normal				From 2016				From Normal
Heating Degree-Days			2,483				2,798				3,119				(11.3	)%							(20.4	)%
Cooling Degree-Days			342				307				266				11.4	%							28.6	%
Gas Service Territory														% Change
Heating Degree-Days		2017				2016				Normal				From 2016				From Normal
Heating Degree-Days			2,403				2,893				3,020				(16.9	)%							(20.4	)%

 

32

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Number of Electric Customers		2017				2016				Number of Natural Gas Customers		2017				2016
Residential			458,361				454,402			Residential			121,166				119,592
Small Commercial & Industrial			60,499				59,904			Commercial & Industrial			9,743				9,669
Large Commercial & Industrial			1,410				1,417			Total Retail			130,909				129,261
Public Authorities & Electric Railroads			636				643			Transportation			155				157
Total			520,906				516,366			Total			131,064				129,418

 

(a)

Reflects delivery volumes and revenues from customers purchasing electricity directly from DPL and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from DPL, revenue also reflects the cost of energy and transmission.

(b)	Other revenue includes transmission revenue from PJM and wholesale electric revenues.

(c)	Includes operating revenues from affiliates totaling $2 million and $2 million for the three months ended June 30, 2017 and 2016, respectively, and $4 million and $4 million for the six months ended June 30, 2017 and 2016, respectively.

(d)

Reflects delivery volumes and revenues 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. For customers purchasing natural gas from DPL, revenue also reflects the cost of natural gas.

(e)	Transportation and other revenue includes off-system natural gas sales and the short-term release of interstate pipeline transportation and storage capacity not needed to serve customers.

 

33

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EXELON CORPORATION

ACE Statistics

Three Months Ended June 30, 2017 and 2016

 

		Electric Deliveries												Revenue (in millions)
		2017				2016				% Change				2017				2016				% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential			814				814				—	%		$	130			$	131				(0.8	)%
Small Commercial & Industrial			302				283				6.7	%			40				39				2.6	%
Large Commercial & Industrial			853				853				—	%			49				50				(2.0	)%
Public Authorities & Electric Railroads			11				9				22.2	%			4				3				33.3	%
Total Retail			1,980				1,959				1.1	%			223				223				—	%
Other Revenue (b)															47				47				—	%
Total Electric Revenue (c)															270				270				—	%
Purchased Power														$	128			$	141				(9.2	)%
																		% Change
Heating and Cooling Degree-Days						2017				2016				Normal				From 2016				From Normal
Heating Degree-Days							600				651				806				(7.8	)%			(25.6	)%
Cooling Degree-Days							324				258				285				25.6	%			13.7	%
Six Months Ended June 30, 2017 and 2016
		Electric Deliveries												Revenue (in millions)
		2017				2016				% Change				2017				2016				% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential			1,693				1,752				(3.4	)%		$	272			$	281				(3.2	)%
Small Commercial & Industrial			585				572				2.3	%			76				78				(2.6	)%
Large Commercial & Industrial			1,618				1,673				(3.3	)%			94				101				(6.9	)%
Public Authorities & Electric Railroads			24				24				—	%			7				6				16.7	%
Total Retail			3,920				4,021				(2.5	)%			449				466				(3.6	)%
Other Revenue (b)															95				95				—	%
Total Electric Revenue (c)															544				561				(3.0	)%
Purchased Power														$	266			$	298				(10.7	)%
																		% Change
Heating and Cooling Degree-Days						2017				2016				Normal				From 2016				From Normal
Heating Degree-Days							2,750				2,921				3,294				(5.9	)%			(16.5	)%
Cooling Degree-Days							324				261				286				24.1	%			13.3	%

 

Number of Electric Customers		2017				2016
Residential			486,173				483,044
Small Commercial & Industrial			61,013				60,928
Large Commercial & Industrial			3,744				3,806
Public Authorities & Electric Railroads			629				594
Total			551,559				548,372

 

(a)

Reflects delivery volumes and revenues from customers purchasing electricity directly from ACE and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from ACE, revenue also reflects the cost of energy and transmission.

(b)	Other revenue includes transmission revenue from PJM and wholesale electric revenues.

(c)	Includes operating revenues from affiliates totaling $1 million and $1 million for the three months ended June 30, 2017 and 2016, respectively, and $1 million and $2 million for the six months ended June 30, 2017 and 2016, respectively.

 

34

Earnings Conference Call 2nd Quarter 2017 August 2, 2017 Exhibit 99.2

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Cautionary Statements Regarding Forward-Looking Information This presentation 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 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) include those factors discussed herein, as well as the items discussed in (1) Exelon’s 2016 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 24, Commitments and Contingencies; (2) Exelon’s Second Quarter 2017 Quarterly Report on Form 10-Q (to be filed on August 2, 2017) 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 17; and (2) 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 press release. 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 presentation.

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Non-GAAP Financial Measures Exelon reports its financial results in accordance with accounting principles generally accepted in the United States (GAAP). Exelon supplements the reporting of financial information determined in accordance with GAAP with certain non-GAAP financial measures, including: Adjusted operating earnings exclude certain costs, expenses, gains and losses and other specified items, including mark-to-market adjustments from economic hedging activities, unrealized gains and losses from nuclear decommissioning trust fund investments, merger and integration related costs, impairments of certain long-lived assets, certain amounts associated with plant retirements and divestitures, costs related to a cost management program and other items as set forth in the reconciliation in the Appendix Adjusted operating and maintenance expense excludes regulatory operating and maintenance costs for the utility businesses and direct cost of sales for certain Constellation and Power businesses, decommissioning costs that do not affect profit and loss, the impact from operating and maintenance expense related to variable interest entities at Generation, and other items as set forth in the reconciliation in the Appendix Total gross margin is defined as operating revenues less purchased power and fuel expense, excluding revenue related to decommissioning, gross receipts tax, Exelon Nuclear Partners, JExel Nuclear JV, variable interest entities, and net of direct cost of sales for certain Constellation and Power businesses Adjusted cash flow from operations primarily includes net cash flows from operating activities and net cash flows from investing activities excluding capital expenditures, net merger and acquisitions, and equity investments Free cash flow primarily includes net cash flows from operating activities and net cash flows from investing activities excluding certain capital expenditures, net merger and acquisitions, and equity investments Operating ROE is calculated using operating net income divided by average equity for the period. The operating income reflects all lines of business for the utility business (Electric Distribution, Gas Distribution, Transmission). EBITDA is defined as earnings before interest, taxes, depreciation and amortization. Includes nuclear fuel amortization expense. Revenue net of purchased power and fuel expense is calculated as the GAAP measure of operating revenue less the GAAP measure of purchased power and fuel expense Due to the forward-looking nature of some forecasted non-GAAP measures, information to reconcile the forecasted adjusted (non-GAAP) measures to the most directly comparable GAAP measure may not be currently available, as management is unable to project all of these items for future periods

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Non-GAAP Financial Measures Continued This information is intended to enhance an investor’s overall understanding of period over period financial results and provide an indication of Exelon’s baseline operating performance by 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. These non-GAAP financial measures are not a presentation defined under GAAP and may not be comparable to other companies’ presentation. Exelon has provided these non-GAAP financial measures as supplemental information and in addition to the financial measures that are calculated and presented in accordance with GAAP. These non-GAAP measures should not be deemed more useful than, a substitute for, or an alternative to the most comparable GAAP measures provided in the materials presented. Non-GAAP financial measures are identified by the phrase “non-GAAP” or an asterisk. Reconciliations of these non-GAAP measures to the most comparable GAAP measures are provided in the appendices and attachments to this presentation, except for the reconciliation for total gross margin, which appears on slide 33 of this presentation.

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  Note: Amounts may not sum due to rounding * Refer to pages 3 and 4 for information regarding non-GAAP financial measures Strong 2nd Quarter Results * Q2 2017 EPS Results GAAP earnings were $0.09/share in Q2 2017 vs. $0.29/share in Q2 2016 Adjusted operating earnings* were $0.54/share in Q2 2017 vs. $0.65/share in Q2 2016, near the top end of our guidance range of $0.45-$0.55/share

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Operating Highlights Operations Metric Q2 2017 BGE ComEd PECO PHI Electric Operations OSHA Recordable Rate 2.5 Beta SAIFI (Outage Frequency)(1) 2.5 Beta CAIDI (Outage Duration) Customer Operations Customer Satisfaction Service Level % of Calls Answered in <30 sec Abandon Rate Gas Operations Percent of Calls Responded to in <1 Hour No Gas Operations 2.5 Beta SAIFI is YE projection Excludes Salem 2016 industry average Exelon Utilities Operational Metrics Exelon Generation Operational Metrics Continued best in class performance across our Nuclear fleet: Q2 Nuclear Capacity Factor: 90.9%(2) Q2 average refueling outage duration of 24 days versus industry average of 36 days(3) Shortest refueling outage duration record set for Nine Mile Point 1 Strong performance across our Fossil and Renewable fleet: Q2 Renewables energy capture: 95.5% Q2 Power dispatch match: 99.0% BGE and ComEd are meeting 1st decile performance in CAIDI BGE’s CAIDI and SAIFI performance was best on record ComEd’s SAIFI performance was best on record Pepco identified in JD Power customer satisfaction study as one of the most improved utilities for 2017 vs 2016 Quartiles Q1 Q2 Q3 Q4

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Key Developments from the Second Quarter ZEC Litigation Updates PHI Rate Case Progress PJM Capacity Auction TMI Shutdown Decision

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Key Market Policy Updates New York ZEC Legal Challenges IL ZEC Legal Challenges Federal Case: Case dismissed on July 25 and judgment entered on July 27 “The ZEC program does not thwart the goal of an efficient energy market; rather, it encourages through financial incentives the production of clean energy.” The plaintiffs are expected to appeal to the US Court of Appeals for the 2nd Circuit The 2nd Circuit will set the briefing schedule after the appeal is filed State Case: Motions to dismiss procedural challenges filed in NY State court were briefed in 1Q17 The court heard oral arguments on June 19, 2017 Currently awaiting decision; next step determined by outcome Both cases dismissed and judgment entered July 14 “The ZEC program does not conflict with the Federal Power Act.” On July 17, both sets of plaintiffs appealed to the US Court of Appeals for the 7th Circuit On July 18, the 7th Circuit consolidated the appeals and set a briefing schedule: Plaintiff-Appellant Opening Brief due Aug 28 Defendant-Respondents Response Brief due Sep 27 Reply Briefs due Oct 27 Expect oral argument to follow DOE Report and PJM Reforms DOE Energy Report On April 14, 2017, Secretary of Energy Rick Perry ordered a review of the U.S. electrical grid, to determine if current policies are hastening the retirement of baseload plants and threatening power system resilience and reliability. “Nuclear power is a key component of our all-of-the-above energy strategy. Zero emissions, always on.”– Secretary Rick Perry Proposed PJM Reforms Recognize value of resiliency by instituting operational reforms in which PJM would commit additional reserves to account for the consumer impact from the most significant potential disruption Refine price formation to recognize the critical contribution of all resources, including “baseload” nuclear resources

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Q2 2017 Adjusted Operating EPS* Results Exelon Utilities Timing of O&M Exelon Generation Timing of O&M NDT realized gains(1) 2nd Quarter Adjusted Operating Earnings* Drivers Q2 2017 vs. Guidance of $0.45 - $0.55 $0.33 Note: Amounts may not sum due to rounding Gains related to unregulated sites

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Q2 Adjusted Operating Earnings* Waterfall $0.54 ($0.16) Market Conditions(1) ($0.05) O&M Impact of Outages(2) $0.05 Zero Emission Credit Revenue(3) $0.03 Other $0.03 Absence of 2016 Rate Case Disallowances $0.01 Increased Distribution Rates ($0.01) Income Taxes ($0.01) Other $0.02 Increased Distribution Rates ($0.01) O&M Note: Amounts may not sum due to rounding Includes the unfavorable impact of the conclusion of the Ginna Reliability Support Services Agreement, lower realized energy prices and lower optimization in Generation’s natural gas portfolio Driven by higher planned outages in 2017; excludes Salem Reflects the impact of the New York Clean Energy Standard Pursuant to the Illinois Future Energy Jobs Act, beginning in 2017, customer rates for ComEd are adjusted to eliminate the favorable and unfavorable impacts of weather and customer usage patterns on distribution volumes ($0.01) 2016 Weather(4) $0.01 Rate base $0.01 U.S. Treasuries (ROE) ($0.01) Other $0.02 Income Taxes $0.01 O&M ($0.01) Weather & Load

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YTD Adjusted Operating Earnings* Waterfall $1.19 ($0.17) Market Conditions(1) ($0.07) O&M Impact of Outages(2) ($0.07) Other O&M ($0.03) Capacity Pricing $0.05 Zero Emission Credit Revenue(3) $0.03 Increased Distribution Rates $0.03 Absence of 2016 Rate Case Disallowances $0.01 Decreased Storm Costs ($0.01) Depreciation & Amortization ($0.01) Income Taxes ($0.01) Other $0.05 Increased Distribution Rates $0.04 Other(5) Note: Amounts may not sum due to rounding Includes the unfavorable impacts of declining natural gas prices and lower optimization in Generation’s natural gas portfolio, the conclusion of the Ginna Reliability Support Services Agreement and lower realized energy prices, partially offset by the absence of oil inventory write downs that occurred in 2016 Driven by higher planned outages in 2017; excludes Salem Reflects the impact of the New York Clean Energy Standard Pursuant to the Illinois Future Energy Jobs Act, beginning in 2017, customer rates for ComEd are adjusted to eliminate the favorable and unfavorable impacts of weather and customer usage patterns on distribution volumes PHI reflects full six months of earnings in 2017 versus earnings from March 24, 2016 through June 30, 2016 $0.03 Rate Base $0.01 U.S. Treasuries (ROE) ($0.01) 2016 Weather & Load(4) ($0.01) Load & Depreciation

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$2.50 - $2.80(2) ~($0.20) $0.60 - $0.70 $0.40 - $0.50 $0.30 - $0.40 $0.25 - $0.35 $1.05 - $1.15 $2.68(1) Reaffirming 2017 Adjusted Operating Earnings* Guidance 2016 results based on 2016 average outstanding shares of 927M 2017 earnings guidance based on expected average outstanding shares of 949M. Earnings guidance for OpCos may not sum up to consolidated EPS guidance. Expect Q3 2017 Adjusted Operating Earnings* of $0.80 - $0.90 per share Key Year-Over-Year Drivers ExGen: Lower realized energy prices, partially offset by NY and IL ZEC revenues BGE: Higher D&A, partially offset by normalization of one time items and distribution revenue PHI: Full year of earnings and higher distribution and transmission revenue from investments to improve reliability PECO: Higher O&M for storms and higher D&A ComEd: Increased capital investments to improve reliability in distribution and transmission and higher U.S. Treasury yields

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Trailing 12 Month ROE vs Allowed ROE Twelve Month Trailing Earned ROEs* (1) Note: Represents the period from 6/30/16 to 6/30/17 and reflects all lines of business (Electric Distribution, Gas Distribution, and Transmission) (1) Pepco DC Distribution allowed ROE is based on an authorized ROE of 9.4% for the rates that were in effect during the trailing twelve month period.  The order issued on 7/25/17 authorized an ROE of 9.5%.

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Exelon Utilities Distribution Rate Case Summary Delmarva DE Electric Order Authorized Revenue Requirement Increase(1) $31.5M Authorized ROE 9.70% Common Equity Ratio N/A Order Received 5/23/17 Delmarva DE Gas Order Authorized Revenue Requirement Increase(1) $4.9M Authorized ROE 9.70% Common Equity Ratio N/A Order Received 6/6/17 Delmarva MD Order Authorized Revenue Requirement Increase(1) $38.3M Authorized ROE 9.60% Common Equity Ratio 49.10% Order Received 2/15/17 Pepco DC Order Authorized Revenue Requirement Increase(1) $36.9M Authorized ROE 9.50% Common Equity Ratio 49.14% Order Received 7/25/17 Pepco MD Filing Requested Revenue Requirement Increase(1) $68.6M Requested ROE 10.10% Requested Common Equity Ratio 50.15% Order Expected 10/20/17 ACE Filing Requested Revenue Requirement Increase(1) $72.6M Requested ROE 10.10% Requested Common Equity Ratio 50.14% Order Expected Q1 2018 Delmarva MD Filing Requested Revenue Requirement Increase(1) $27.0M Requested ROE 10.10% Requested Common Equity Ratio 50.68% Order Expected 2/14/18 ComEd Filing Requested Revenue Requirement Increase(1) $95.6M(2) Requested ROE 8.40% Requested Common Equity Ratio 45.89% Order Expected Q4 2017 Revenue requirement includes changes in depreciation and amortization expense where applicable, which have no impact on pre-tax earnings Amount represents ComEd’s position filed in Rebuttal testimony on July 21, 2017

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Cleared 16.2 GW of generation capacity in 2020/2021 PJM base residual auction The bulk of cleared capacity was in the ComEd and EMAAC zones, which cleared above rest of RTO pricing at $188/MW-d Despite volatility in PJM capacity market, capacity revenues have met or exceeded $1B annually Updates: RPM Results and TMI Closure (1) Based on May 31, 2017, pricing and exclude decommissioning impacts PJM 2020/2021 Capacity Auction TMI Closure Exelon announced that it will retire TMI in September 2019, absent needed policy reforms Announcement comes after TMI failed to clear PJM base residual auctions for the third consecutive year Financial impact(1) of TMI retirement is annual accretive EPS impact of $0.04-$0.07 and cumulative cash flow impact of ~$225M through 2021

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Exelon Generation: Gross Margin Update Gross margin categories rounded to nearest $50M Excludes EDF’s equity ownership share of the CENG Joint Venture Mark-to-Market of Hedges assumes mid-point of hedge percentages Based on June 30, 2017, market conditions Reflects TMI and Oyster Creek retirements in September 2019 and December 2019, respectively. EGTP removal impacts partial year 2017 and full year 2018 and 2019. EGTP removal results in $100M reduction to gross margin in 2018 and 2019 with positive EPS impacts of $0.02-$0.03. TMI retirement results in $50M reduction in gross margin in 2019. Executed $200M of Power New Business in 2017 Reflects removal of EGTP(5) and TMI(5) Behind ratable hedging position reflects the fundamental upside we see in power prices ~11-14% behind ratable in 2018 when considering cross commodity hedges Recent Developments

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Forward Market Liquidity Total calendar peak traded volumes for the rolling 5-year window have been trending lower over the past year Calendar peak traded volumes beyond prompt year +1 account for less than 10% of total traded volumes * Please note that hedging strategy utilizes various price points (i.e. NIHUB, ERCOT), channels to market (i.e. Origination, Mid-Marketing, Retail, OTC), products (i.e. calendar, seasonal), and other exchanges July 2016 July 2017 Overall liquidity is declining Limited liquidity in the outer years July 2016 PJM West Hub Calendar Peak Traded Volumes(1) (by year) July 2017 PJM West Hub Calendar Peak Traded Volumes(1) (by year) (1) Total monthly traded volumes for rolling prompt year + 4 years on ICE and NASDAQ Exchanges only

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Maintaining Strong Investment Grade Credit Ratings is a Top Financial Priority Current Ratings (2,3) ExCorp ExGen ComEd PECO BGE ACE DPL Pepco Moody’s Baa2 Baa2 A1 Aa3 A3 A3 A2 A2 S&P BBB- BBB A- A- A- A A A Fitch BBB BBB A A A- A- A A- Due to ring-fencing, S&P deconsolidates BGE from Exelon and analyzes solely as an equity investment Current senior unsecured ratings as of July 26, 2017, for Exelon, Exelon Generation and BGE and senior secured ratings for ComEd, PECO, ACE, DPL, and Pepco All ratings have “Stable” outlook Exelon Corp downgrade threshold (red dotted line) is based on the S&P Exelon Corp Summary Report; represents minimum level to maintain current Issuer Credit Rating of BBB at Exelon Corp Reflects net book debt (YE debt less cash on hand) / adjusted operating EBITDA* Reflects removal of EGTP ExGen Debt/EBITDA Ratio*(5,6) Exelon S&P FFO/Debt %*(1,4,6) Credit Ratings by Operating Company 18%-20% x x 3.0x Excluding Non-Recourse Book S&P Threshold

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Innovation Expo Highlights Our 2017 Innovation Expo in Washington, D.C. showcased the latest advanced technology products and processes Exelon is deploying to deliver on our commitment to provide safe, reliable, affordable and clean energy Exelon employees, vendors and industry experts explored how technology can solve challenges affecting the energy industry and our customers at our biggest event to date

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Recognition for Stewardship and Employee Engagement Supplier Diversity: Exelon is the only utility and energy company to be inducted into the Billion Dollar Roundtable, which recognizes corporations that have achieved spending of $1 billion with minority and women-owned suppliers; our 2016 spend was nearly $2B Civic 50: Points of Light named Exelon utility sector leader in its annual ranking of the nation’s most community-minded public and private companies Top 50 Companies for Diversity: National recognition from DiversityInc, first year in Top 50 after being named a DiversityInc “Top Utility” in 2015 and 2016 Best Places to Work in 2017: Ranked No. 18 on Indeed.com survey of Fortune 500 companies based on employee reviews CEO Action for Diversity & Inclusion™: Joined 150 leading companies in the largest CEO-driven business commitment to advance diversity and inclusion Top 50 Most Energy-Efficient Utilities: American Council for an Energy-Efficient Economy ranks BGE and ComEd in the top 10 with PECO also making the list Lowest Carbon Emissions: 2017 Air Emissions Benchmarking Report notes Exelon’s nuclear facilities had the lowest carbon dioxide emissions of the top 20 privately held and investor-owned energy producers

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The Exelon Value Proposition Regulated Utility Growth with utility EPS rising 6-8% annually from 2017-2020 and rate base growth of 6.5%, representing an expanding majority of earnings ExGen’s strong free cash generation will support utility growth while also reducing debt by ~$3B over the next 4 years Optimizing ExGen value by: Seeking fair compensation for the zero-carbon attributes of our fleet; Closing uneconomic plants; Monetizing assets; and Maximizing the value of the fleet through our generation to load matching strategy Strong balance sheet is a priority with all businesses comfortably meeting investment grade credit metrics through the 2020 planning horizon Capital allocation priorities targeting: Organic utility growth; Return of capital to shareholders with 2.5% annual dividend growth through 2018(1); Debt reduction; and Modest contracted generation investments (1) Quarterly dividends are subject to declaration by the board of directors

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Additional Disclosures

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PJM Capacity Revenues(1,2,3) (1) Revenues reflect capacity cleared in Base, CP transitional & incremental auctions and are for calendar years (2) Revenues reflect owned and contracted generation (3) Reflects 50.01% ownership at CENG (4) Volumes at ownership and rounded Revenues ($M) Capacity Price ($/MW-d) Capacity Market: PJM

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2017 Projected Sources and Uses of Cash Consistent and reliable free cash flows Enable growth & value creation Supported by a strong balance sheet Strong balance sheet enables flexibility to raise and deploy capital for growth Plan to issue $0.9B of long-term debt at the utilities, net of refinancing, to support continued growth Operational excellence and financial discipline drives free cash flow reliability Generating $4.9B of free cash flow, including $1.4B at ExGen and $3.4B at the Utilities Creating value for customers, communities and shareholders Investing $6.0B, with $5.3B at the Utilities and $0.8B at ExGen All amounts rounded to the nearest $25M. Figures may not add due to rounding. Gross of posted counterparty collateral Excludes counterparty collateral activity Figures reflect cash CapEx and CENG fleet at 100% Other Financing includes expected changes in short-term debt, money pool borrowings, tax sharing from the parent, debt issue costs, CENG credit facility, tax equity cash flows, Renewable JV, and capital leases Financing cash flow excludes intercompany dividends and other intercompany financing activities ExGen Growth CapEx primarily includes Texas CCGTs, AGE, W. Medway, Retail Solar, and Retail Growth Dividends are subject to declaration by the Board of Directors Includes cash flow activity from Holding Company, eliminations, and other corporate entities

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Exelon Generation Disclosures June 30, 2017

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Portfolio Management Strategy Protect Balance Sheet Ensure Earnings Stability Create Value Exercising Market Views % Hedged Purely ratable Actual hedge % Market views on timing, product allocation and regional spreads reflected in actual hedge % High End of Profit Low End of Profit % Hedged Open Generation with LT Contracts Portfolio Management & Optimization Portfolio Management Over Time Align Hedging & Financials Establishing Minimum Hedge Targets Strategic Policy Alignment Three-Year Ratable Hedging Ensure stability in near-term cash flows and earnings Bull / Bear Program Ability to exercise fundamental market views to create value within the ratable framework Hedge enough commodity risk to meet future cash requirements under a stress scenario Tenor aligns with customer preferences and market liquidity Multiple channels to market that allow us to maximize margins Cross-commodity hedging (heat rate positions, options, etc.) Delivery locations, regional and zonal spread relationships Aligns hedging program with financial policies and financial outlook Disciplined approach to hedging Large open position in outer years to benefit from price upside Modified timing of hedges versus purely ratable Establish minimum hedge targets to meet financial objectives of the company (dividend, credit rating) Credit Rating Capital & Operating Expenditure Dividend Capital Structure

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Components of Gross Margin Categories Margins move from new business to MtM of hedges over the course of the year as sales are executed(5) Margins move from “Non power new business” to “Non power executed” over the course of the year Gross margin linked to power production and sales Gross margin from other business activities (1) Hedged gross margins for South, West & Canada region will be included with Open Gross Margin; no expected generation, hedge %, EREP or reference prices provided for this region (2) MtM of hedges provided directly for the five larger regions; MtM of hedges is not provided directly at the regional level but can be easily estimated using EREP, reference price and hedged MWh (3) Proprietary trading gross margins will generally remain within “Non Power” New Business category and only move to “Non Power” Executed category upon management discretion (4) Gross margin for these businesses are net of direct “cost of sales” (5) Margins for South, West & Canada regions and optimization of fuel and PPA activities captured in Open Gross Margin Open Gross Margin Generation Gross Margin at current market prices, including ancillary revenues, nuclear fuel amortization and fossils fuels expense MtM of Hedges (2) Mark-to-Market ( MtM ) of power, capacity and ancillary hedges, including cross commodity, retail and wholesale load transactions “Power” New Business Retail, Wholesale planned electric sales “Non Power” Executed “Non Power” New Business Power Purchase Agreement (PPA) Costs and Revenues Provided at a consolidated level for all regions (includes hedged gross margin for South, West and Canada (1) ) Provided directly at a consolidated level for five major regions. Provided indirectly for each of the five major regions via Effective Realized Energy Price (EREP), reference price, hedge %, expected generation. Portfolio Management new business Mid marketing new business Retail, Wholesale executed gas sales Energy Efficiency (4) BGE Home (4) Distributed Solar Retail, Wholesale planned gas sales Energy Efficiency (4) BGE Home (4) Distributed Solar Portfolio Management / origination fuels new business Proprietary trading (3) Capacity and ZEC Revenues Expected capacity revenues for generation of electricity Expected revenues from Zero Emissions Credits (ZEC)

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ExGen Disclosures Gross margin categories rounded to nearest $50M Excludes EDF’s equity ownership share of the CENG Joint Venture Mark-to-Market of Hedges assumes mid-point of hedge percentages Based on June 30, 2017, market conditions Reflects ownership of FitzPatrick as of April 1, 2017, and TMI and Oyster Creek retirements in September 2019 and December 2019, respectively. EGTP removal impacts partial year 2017 and full year 2018 and 2019.

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ExGen Disclosures Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted for capacity based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products, and options. Expected generation assumes 15 refueling outages in 2017, 15 in 2018, and 11 in 2019 at Exelon-operated nuclear plants and Salem. Expected generation assumes capacity factors of 93.4%, 93.3% and 94.7% in 2017, 2018, and 2019, respectively at Exelon-operated nuclear plants, at ownership. These estimates of expected generation in 2018 and 2019 do not represent guidance or a forecast of future results as Exelon has not completed its planning or optimization processes for those years. Excludes EDF’s equity ownership share of CENG Joint Venture Percent of expected generation hedged is the amount of equivalent sales divided by expected generation. Includes all hedging products, such as wholesale and retail sales of power, options and swaps. Effective realized energy price is representative of an all-in hedged price, on a per MWh basis, at which expected generation has been hedged. It is developed by considering the energy revenues and costs associated with our hedges and by considering the fossil fuel that has been purchased to lock in margin. It excludes uranium costs, RPM capacity and ZEC revenues, but includes the mark-to-market value of capacity contracted at prices other than RPM clearing prices including our load obligations. It can be compared with the reference prices used to calculate open gross margin in order to determine the mark-to-market value of Exelon Generation's energy hedges. Spark spreads shown for ERCOT and New England Reflects ownership of FitzPatrick as of April 1, 2017, and TMI and Oyster Creek retirements in September 2019 and December 2019, respectively. EGTP removal impacts partial year 2017 and full year 2018 and 2019.

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ExGen Hedged Gross Margin* Sensitivities Based on June 30, 2017, market conditions and hedged position; gas price sensitivities are based on an assumed gas-power relationship derived from an internal model that is updated periodically; power price sensitivities are derived by adjusting the power price assumption while keeping all other price inputs constant; due to correlation of the various assumptions, the hedged gross margin impact calculated by aggregating individual sensitivities may not be equal to the hedged gross margin impact calculated when correlations between the various assumptions are also considered; sensitivities based on commodity exposure which includes open generation and all committed transactions; excludes EDF’s equity share of CENG Joint Venture

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ExGen Hedged Gross Margin* Upside/Risk Approximate Gross Margin* ($ million)(1,2,3) $8,200 $8,050 $8,450 $7,750 Represents an approximate range of expected gross margin, taking into account hedges in place, between the 5th and 95th percent confidence levels assuming all unhedged supply is sold into the spot market; approximate gross margin ranges are based upon an internal simulation model and are subject to change based upon market inputs, future transactions and potential modeling changes; these ranges of approximate gross margin in 2018 and 2019 do not represent earnings guidance or a forecast of future results as Exelon has not completed its planning or optimization processes for those years; the price distributions that generate this range are calibrated to market quotes for power, fuel, load following products, and options as of June 30, 2017 Gross Margin Upside/Risk based on commodity exposure which includes open generation and all committed transactions Reflects ownership of FitzPatrick as of April 1, 2017, and TMI and Oyster Creek retirements in September 2019 and December 2019, respectively. EGTP removal impacts partial year 2017 and full year 2018 and 2019. $6,850 $8,800

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Illustrative Example of Modeling Exelon Generation 2018 Gross Margin* Mark-to-market rounded to the nearest $5 million

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Additional ExGen Modeling Data Total Gross Margin Reconciliation (in $M)(1) 2017 2018 2019 Revenue Net of Purchased Power and Fuel Expense*(2,3) $8,675 $8,725 $8,300 Non-cash amortization of intangible assets, net, related to commodity contracts recorded at fair value at merger date $50 - - Other Revenues(4) $(150) $(225) $(200) Direct cost of sales incurred to generate revenues for certain Constellation and Power businesses(5) $(425) $(400) $(400) Total Gross Margin* (Non-GAAP) $8,150 $8,100 $7,700 All amounts rounded to the nearest $25M ExGen does not forecast the GAAP components of RNF separately, as to do so would be unduly burdensome. RNF also includes the RNF of our proportionate ownership share of CENG. Excludes the Mark-to-Market impact of economic hedging activities due to the volatility and unpredictability of the future changes to power prices Other Revenues reflects revenues from Exelon Nuclear Partners, JExel Nuclear JV, variable interest entities, funds collected through revenues for decommissioning the former PECO nuclear plants through regulated rates, and gross receipts tax revenues Reflects the cost of sales of certain Constellation and Power businesses ExGen amounts for O&M, TOTI, Depreciation & Amortization; excludes EDF’s equity ownership share of the CENG Joint Venture Other reflects Other Revenues excluding gross receipts tax revenues, nuclear decommissioning trust fund earnings from unregulated sites, and the minority interest in ExGen Renewables JV and Bloom TOTI excludes gross receipts tax of $150M Excludes P&L neutral decommissioning depreciation Interest expense includes impact of reduced capitalized interest due to Texas CCGT plants in service as of May and June of 2017. Capitalized interest will be an additional ~$25M lower in 2018 as well due to this. Key ExGen Modeling Inputs (in $M)(1,6) 2017 Other(7) $150 Adjusted O&M* $(4,850) Taxes Other Than Income (TOTI)(8) $(375) Depreciation & Amortization(9) $(1,100) Interest Expense(10) $(400) Effective Tax Rate 32.0%

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Exelon Utilities Rate Case Filing Summaries

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6/17 7/17 8/17 9/17 Pepco Electric Distribution Rates - DC Delmarva Electric Distribution Rates - MD Pepco Electric Distribution Rates - MD Exelon Utilities Distribution Rate Case Schedule 10/17 11/17 Note: Based on current schedules of Illinois Commerce Commission, Maryland Public Service Commission, and Delaware Public Service Commission and are subject to change 12/17 Commission Order Received July 25 ACE Electric Distribution Rates - NJ ComEd Electric Distribution Formula Rate Rebuttal Testimony Mid-July Intervenor Direct Testimony June 30 Rebuttal Testimony Aug. 1 Evidentiary Hearings Sept. 5-15 Rate Case Filed July 14 Commission Order Expected Oct. 20 Intervenor Direct Testimony Aug. 1 Rebuttal Testimony Sept. 6 Evidentiary Hearings Oct. 2-13 Hearings August 28 Proposed Order October 19 Commission Order Expected December 9

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Delmarva DE (Electric) Distribution Rate Case Final Order The Settlement is a partial “black box settlement” meaning that the Settling Parties have agreed to some terms in the Settlement, but not others. No adjusted rate base or earnings were documented. As permitted by Delaware law, Delmarva Power implemented interim rate increases of $2.5 million on July 16, 2016, and implemented an incremental $29.6M on December 17, 2016, subject to refund Revenue requirement includes changes in depreciation and amortization expense, which have no impact on pre-tax earnings Docket # 16-0649 Approved Black Box Settlement Test Year 2015 Calendar Year Test Period 12 months actual Authorized Common Equity Ratio 49.44% Authorized Rate of Return ROE: 10.60%; ROR: 7.19% ROE: 9.70% Rate Base(1) $839M Authorized Revenue Requirement Increase(2,3) $60.2M $31.5M Revenue increase includes approx. $7.5M of new depreciation and amortization expense Residential Total Bill % Increase 7.25% 4.80% Notes 5/17/16 DPL DE filed application with the Delaware Public Service Commission (DPSC) seeking increase in electric distribution base rates 18 month forward-looking reliability and other plant additions from January 2016 through June 2017 ($8.4M of Revenue Requirement based on 10.60% ROE) included in revenue requirement request Includes the Pay as You Go Program, a proposed pilot program that would be cooperatively designed to use the capability of the AMI meters to offer a voluntary pre-paid metering option for customers 3/8/17 Unanimous settlement filed with the DPSC New depreciation rates included in the revenue increase Recovery of $28.6M of direct load control and dynamic pricing regulatory assets to be amortized over 10 years Approval to establish regulatory asset for costs to achieve synergy savings, amortized over 5 years Actual synergy savings and costs to achieve will be reviewed in next base rate proceeding Commission Approved Settlement: 5/23/17 Rates effective June 1; no interim rate refunds

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Delmarva DE (Gas) Distribution Rate Case Final Order The Settlement is a partial “black box settlement” meaning that the Settling Parties have agreed to some terms in the Settlement, but not others. No adjusted rate base or earnings were documented. As permitted by Delaware law, Delmarva Power implemented interim rate increases of $2.5 million on July 16, 2016, and implemented an incremental $10.4M on December 17, 2016, subject to refund Revenue requirement includes changes in depreciation and amortization expense, which have no impact on pre-tax earnings Docket # 16-0650 Approved Black Box Settlement Test Year 2015 Calendar Year Test Period 12 months actual Common Equity Ratio 49.44% Rate of Return ROE: 10.60%; ROR: 7.19% ROE: 9.70% Rate Base(1) $362M Revenue Requirement Increase(2,3) $22.2M $4.9M Revenue increase includes net reduction of $4.8M in new depreciation and amortization expense Residential Total Bill % Increase 10.40% 2.70% Notes 5/17/16 DPL DE filed application with the DPSC seeking increase in gas distribution base rates 4/6/17 Unanimous settlement filed with the DPSC New depreciation rates included in the revenue increase Incremental labor costs for the Interface Management Unit (IMU) battery replacement project deferred into a regulatory asset for review in a future proceeding Approval to establish regulatory asset for costs to achieve synergy savings, amortized over 5 years Actual synergy savings and costs to achieve will be reviewed against actuals in next base rate proceeding Commission approved settlement: 6/6/17 Rates effective July 1 Refund will be issued for amounts collected, under interim rates, in excess of $4.9M revenue requirement increase

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Pepco DC Rate Case Final Order Formal Case No. 1139 Per Commission Order Test Year April 1, 2015 – March 31, 2016 Test Period 12 months actual Requested Common Equity Ratio 49.14% 49.14% Requested Rate of Return ROE: 10.60%; ROR: 8.00% ROE: 9.50%; ROR: 7.46% Proposed Rate Base (Adjusted) $1.7B $1.6B Requested Revenue Requirement Increase $76.8M(1) $36.9M EBIT impact is currently estimated at $39M related to new items per the Order Residential Total Bill % Increase 4.62% 2.52% Notes 6/30/16 Pepco filed application with District of Columbia Public Service Commission (DCPSC) seeking increase in electric distribution base rates Intervenor Positions: Office of People’s Council (OPC) revenue increase of $25.8M based on 8.60% ROE Apartment and Office Building Association (AOBA) revenue increase of $62.2M based on 9.25% ROE Healthcare Council of the National Capital Area (HCNCA) revenue increase of $16.8M based on 8.75% ROE District of Columbia Water and Sewer Authority (DC Water) revenue increase of $52.7M based on 9.10% ROE 7/25/17 DCPSC issued Final Order Bill Stabilization Adjustment (BSA) remains unchanged Approval to establish regulatory asset for costs to achieve (CTA) Customer Base Rate Credit (CBRC) will offset monthly bill increases $15M allocated to residential customers $2.3M designated to certain small commercial customers $6-7M reserved for disabled and senior citizens on fixed incomes in future rate cases Recovery of $27.4M of AMI, direct load control and dynamic pricing regulatory assets to be amortized over 5 years (1) Revenue requirement includes changes in amortization expense, which has no impact on pre-tax earnings

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Pepco MD Rate Case Filing Formal Case No. 9443 Test Year May 1, 2016 – April 30, 2017 Test Period 8 months actual and 4 months estimated Requested Common Equity Ratio 50.15% Requested Rate of Return ROE: 10.10%; ROR: 7.74% Proposed Rate Base (Adjusted) $1.7B Requested Revenue Requirement Increase(1) $68.6M Residential Total Bill % Increase 5.6% Notes 3/24/17 Pepco MD filed application with the Maryland Public Service Commission (MDPSC ) seeking increase in electric distribution base rates Size of ask is driven by Continued Investments in the electric distribution system to maintain and increase reliability and customer service Normalization of tax benefits on pre-1981 removal costs 8 month forward looking reliability and other plant additions from May 2017 through December 2017 ($13.3M of Revenue Requirement based on 10.10% ROE) included in revenue requirement request Company is seeking recovery of the restoration portion of the Supplemental Executive Retirement Plan (SERP) Procedural Schedule: Intervenor Direct Testimony Due: 6/30/17 Rebuttal Testimony Due: 8/1/17 Evidentiary Hearings: 9/5/17 – 9/15/17 Brief Due: 10/3/17 Commission Order Expected: 10/20/17 Revenue requirement includes changes in depreciation and amortization expense, which have no impact on pre-tax earnings. Updated June 7, 2017.

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Atlantic City Electric NJ Rate Case Filing BPU Docket No. ER17030308 Test Year August 1, 2016 – July 31, 2017 Test Period 5 months actual and 7 months estimated Requested Common Equity Ratio 50.14% Requested Rate of Return ROE: 10.10%; ROR: 7.83% Proposed Rate Base (Adjusted) $1.4B Requested Revenue Requirement Increase(1) $72.6M Residential Total Bill % Increase 6.57% Notes 3/30/17 ACE filed application with the New Jersey Board of Public Utilities (NJBPU) seeking increase in electric distribution base rates Recovery of investment in infrastructure to maintain and harden the electric distribution system Ratemaking adjustments to address declining sales 8 month forward-looking reliability and other plant additions from August 2017 through March 2018 ($8.4M of Revenue Requirement based on 10.10% ROE) included in revenue requirement request Proposal of a Non-Incremental System Renewal Recovery Charge for recovery of non-incremental reliability spend over four years (2018-2021) of $376 million. Procedural Schedule: Settlement Meeting: 7/17/17 Intervenor Direct Testimony Due: 8/1/17 Rebuttal Testimony Due: 9/6/17 Evidentiary Hearings: 10/2/17 – 10/13/17 Commission Order Expected: March 2018 (1) Updated on July 14, 2017

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Delmarva Power & Light MD Rate Case Filing Formal Case No. 9455 Test Year October 1, 2016 – September 30, 2017 Test Period 7 months actual and 5 months estimated Requested Common Equity Ratio 50.68% Requested Rate of Return ROE: 10.10%; ROR: 7.05% Proposed Rate Base (Adjusted) $791M Requested Revenue Requirement Increase $27.0M Residential Total Bill % Increase 1.9% Notes 7/14/17 DPL MD filed application with the Maryland Public Service Commission (MDPSC ) seeking increase in electric distribution base rates Size of ask is driven by continued investments in the electric distribution system to maintain and increase reliability and customer service Forward looking reliability and other plant additions through April 2018 ($3.1M of Revenue Requirement based on 10.10% ROE) included in revenue requirement request Requested year end rate base treatment ($4.1M of Revenue Requirement based on 10.10% ROE) Commission Order expected: 2/14/18

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ComEd April 2017 Distribution Formula Rate Docket # 17-0196 Filing Year 2016 Calendar Year Actual Costs and 2017 Projected Net Plant Additions are used to set the rates for calendar year 2018. Rates currently in effect (docket 16-0259) for calendar year 2017 were based on 2015 actual costs and 2016 projected net plant additions. Reconciliation Year Reconciles Revenue Requirement reflected in rates during 2016 to 2016 Actual Costs Incurred. Revenue requirement for 2016 is based on docket 15-0287 (2014 actual costs and 2015 projected net plant additions) approved in December 2015. Common Equity Ratio ~46% for both the filing and reconciliation year ROE 8.40% for the filing year (2016 30-yr Treasury Yield of 2.60% + 580 basis point risk premium) and 8.34% for the reconciliation year (2016 30-yr Treasury Yield of 2.60% + 580 basis point risk premium – 6 basis points performance metrics penalty). For 2017 and 2018, the actual allowed ROE reflected in net income will ultimately be based on the average of the 30-year Treasury Yield during the respective years plus 580 basis point spread, absent any metric penalties Requested Rate of Return ~6.5% for both the filing and reconciliation years Rate Base(1) $9,662 million– Filing year (represents projected year-end rate base using 2016 actual plus 2017 projected capital additions). 2017 and 2018 earnings will reflect 2017 and 2018 year-end rate base respectively. $8,807 million - Reconciliation year (represents year-end rate base for 2016) Revenue Requirement Increase(1) $95.6M increase ($17.5M increase due to the 2016 reconciliation and collar adjustment in addition to a $78.1M increase related to the filing year). The 2016 reconciliation impact on net income was recorded in 2016 as a regulatory asset. Timeline 04/13/17 Filing Date 240 Day Proceeding ICC Order on FRU expected to be issued by December 9, 2017 The 2017 distribution formula rate filing established the net revenue requirement used to set the rates that will take effect in January 2018 after the Illinois Commerce Commission's (ICC’s) review. There are two components to the annual distribution formula rate filing: Filing Year: Based on 2016 costs and 2017 projected plant additions Annual Reconciliation: For 2016, this amount reconciles the revenue requirement reflected in rates in effect during 2016 to the actual costs for that year. The annual reconciliation impacts cash flow in 2018 but the earnings impact has been recorded in 2016 as a regulatory asset. Given the retroactive ratemaking provision in the Energy Infrastructure Modernization Act (EIMA) legislation, ComEd net income during the year will be based on actual costs with a regulatory asset/liability recorded to reflect any under/over recovery reflected in rates. Revenue Requirement in rate filings impacts cash flow. Amount represents ComEd’s position filed in Rebuttal testimony on July 21, 2017

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Appendix Reconciliation of Non-GAAP Measures

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Q2 2016 QTD GAAP EPS Reconciliation NOTE: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not add due to rounding. Three Months Ended June 30, 2016 ExGen ComEd PECO BGE PHI Other Exelon 2016 GAAP Earnings (Loss) Per Share $0.00 $0.16 $0.11 $0.03 $0.06 ($0.06) $0.29 Mark-to-market impact of economic hedging activities 0.20 - - - - - 0.20 Unrealized gains related to NDT fund investments (0.03) - - - - - (0.03) Amortization of commodity contract intangibles 0.01 - - - - - 0.01 Long-Lived asset impairments 0.02 - - - - - 0.02 Plant retirements and divestitures 0.14 - - - - - 0.14 Cost management program - - - - - - 0.01 CENG noncontrolling interest 0.01 - - - - - 0.01 2016 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.35 $0.16 $0.11 $0.03 $0.06 $(0.06) $0.65

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Q2 2017 QTD GAAP EPS Reconciliation (continued) Three Months Ended June 30, 2017 ExGen ComEd PECO BGE PHI Other Exelon 2017 GAAP (Loss) Earnings Per Share ($0.27) $0.13 $0.09 $0.05 $0.07 $0.02 $0.09 Mark-to-market impact of economic hedging activities 0.12 - - - - - 0.12 Unrealized gains related to NDT fund investments (0.05) - - - - - (0.05) Amortization of commodity contract intangibles 0.01 - - - - - 0.01 Merger and integration costs 0.01 - - - - - 0.01 Long-lived asset impairments 0.29 - - - - - 0.29 Plant retirements and divestitures 0.07 - - - - - 0.07 Cost management program - - - - - - 0.01 Like-kind exchange tax position - 0.02 - - - (0.05) (0.03) CENG noncontrolling interest 0.02 - - - - - 0.02 2017 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.22 $0.15 $0.10 $0.05 $0.07 $(0.03) $0.54 NOTE: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not add due to rounding.

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Q2 2016 YTD GAAP EPS Reconciliation NOTE: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not add due to rounding. Six Months Ended June 30, 2016 ExGen ComEd PECO BGE PHI Other Exelon 2016 GAAP Earnings (Loss) Per Share $0.31 $0.28 $0.25 $0.14 ($0.28) $(0.23) $0.48 Mark-to-market impact of economic hedging activities 0.12 - - - - - 0.12 Unrealized gains related to NDT fund investments (0.07) - - - - - (0.07) Merger and integration costs 0.02 - - - 0.04 0.04 0.09 Merger commitments - - - - 0.30 0.12 0.43 Long-lived asset impairments 0.10 - - - - - 0.10 Plant retirements and divestitures 0.14 - - - - - 0.14 Reassessment of state deferred income taxes 0.01 - - - - (0.01) - Cost management program 0.02 - - - - - 0.02 CENG noncontrolling interest 0.02 - - - - - 0.02 2016 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.69 $0.28 $0.25 $0.14 $0.06 $(0.08) $1.33

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Q2 2017 YTD GAAP EPS Reconciliation (continued) Six Months Ended June 30, 2017 ExGen ComEd PECO BGE PHI Other Exelon 2017 GAAP Earnings (Loss) Per Share $0.19 $0.28 $0.23 $0.18 $0.22 $0.06 $1.15 Mark-to-market impact of economic hedging activities 0.15 - - - - - 0.15 Unrealized gains related to NDT fund investments (0.15) - - - - - (0.15) Amortization of commodity contract intangibles 0.02 - - - - - 0.02 Merger and integration costs 0.04 - - - - - 0.04 Merger commitments (0.02) - - - (0.06) (0.06) (0.15) Long-lived asset impairments 0.29 - - - - - 0.29 Plant retirements and divestitures 0.07 - - - - - 0.07 Reassessment of state deferred income taxes - - - - - (0.02) (0.02) Cost management program 0.01 - - - - - 0.01 Tax settlements (0.01) - - - - - (0.01) Bargain purchase gain (0.24) - - - - - (0.24) Like-kind exchange tax position - 0.02 - - - (0.05) (0.03) CENG noncontrolling interest 0.06 - - - - - 0.06 2017 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.40 $0.30 $0.23 $0.18 $0.15 ($0.08) $1.19 NOTE: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not add due to rounding.

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GAAP to Operating Adjustments Exelon’s 2017 adjusted (non-GAAP) operating earnings excludes the earnings effects of the following: Mark-to-market adjustments from economic hedging activities Unrealized gains from NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements Non-cash amortization of intangible assets, net, related to commodity contracts recorded at fair value at the ConEdison Solutions and FitzPatrick acquisition dates Certain merger and integration costs associated with the PHI and FitzPatrick acquisitions Adjustments to reserves for uncertain tax positions related to the deductibility of certain merger commitments associated with the 2012 CEG and 2016 PHI acquisitions Impairments of certain wind projects at Generation and impairments as a result of the ExGen Texas Power, LLC assets held for sale Plant retirements and divestitures at Generation Non-cash impact of the remeasurement of state deferred income taxes, related to a change in the statutory tax rate Costs incurred related to a cost management program Benefits related to the favorable settlement of certain income tax positions related to PHI's unregulated business interests The excess of the fair value of assets and liabilities acquired over the purchase price for the FitzPatrick acquisition Certain adjustments related to Exelon’s like-kind exchange tax position Generation’s non-controlling interest, primarily related to CENG exclusion items

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All amounts rounded to the nearest $25M Calculated using S&P Methodology. Due to ring-fencing, S&P deconsolidates BGE from Exelon and analyzes solely as an equity investment. Reflects impact of operating adjustments on GAAP EBITDA Includes other adjustments as prescribed by S&P Reflects present value of net capacity purchases Reflects present value of minimum future operating lease payments Reflects after-tax unfunded pension/OPEB Includes non-recourse project debt Applies 75% of excess cash against balance of LTD YE 2017 Exelon FFO Calculation ($M)(1,2) GAAP Operating Income $3,450 Depreciation & Amortization $3,375 EBITDA $6,825 +/- Non-operating activities and nonrecurring items(3) $550 - Interest Expense ($1,450) + Current Income Tax (Expense)/Benefit $25 + Nuclear Fuel Amortization $1,075 +/- Other S&P Adjustments(4) $375 = FFO (a) $7,400 YE 2017 Exelon Adjusted Debt Calculation ($M)(1,2) Long-Term Debt (including current maturities) $32,025 Short-Term Debt $1,225 + PPA Imputed Debt(5) $350 + Operating Lease Imputed Debt(6) $875 + Pension/OPEB Imputed Debt(7) $3,450 - Off-Credit Treatment of Debt(8) ($1,725) - Surplus Cash Adjustment(9) ($550) +/- Other S&P Adjustments(4) $275 = Adjusted Debt (b) $35,925 YE 2017 Exelon FFO/Debt(1,2) FFO (a) = 21% Adjusted Debt (b) GAAP to Non-GAAP Reconciliations

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YE 2017 ExGen Net Debt Calculation ($M)(1) Long-Term Debt (including current maturities) $8,875 Short-Term Debt $375 - Surplus Cash Adjustment ($300) = Net Debt (a) $8,950 YE 2017 Book Debt / EBITDA Net Debt (a) = 2.9x Operating EBITDA (b) All amounts rounded to the nearest $25M Reflects impact of operating adjustments on GAAP EBITDA YE 2017 ExGen Operating EBITDA Calculation ($M)(1) GAAP Operating Income $775 Depreciation & Amortization $1,400 EBITDA $2,175 +/- Non-operating activities and nonrecurring items(2) $875 = Operating EBITDA (b) $3,050 GAAP to Non-GAAP Reconciliations YE 2017 ExGen Net Debt Calculation ($M)(1) Long-Term Debt (including current maturities) $8,875 Short-Term Debt $375 - Surplus Cash Adjustment ($300) - Nonrecourse Debt ($1,900) = Net Debt (a) $7,050 YE 2017 Recourse Debt / EBITDA Net Debt (a) = 2.5x Operating EBITDA (b) YE 2017 ExGen Operating EBITDA Calculation ($M)(1) GAAP Operating Income $775 Depreciation & Amortization $1,400 EBITDA $2,175 +/- Non-operating activities and nonrecurring items(2) $875 - EBITDA from projects financed by nonrecourse debt ($250) = Operating EBITDA (b) $2,800

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GAAP to Non-GAAP Reconciliations ACE, Delmarva, and Pepco represents full year of earnings All amounts rounded to the nearest $25M. Items may not sum due to rounding. Reflects earnings neutral O&M Reflects the direct cost of sales of certain businesses, which are included in Total Gross Margin* Operating ROE Reconciliation ($M)(1) ACE Delmarva Pepco Legacy EXC Consolidated EU Net Income (GAAP)(1) $91 $127 $203 $1,132 $1,548 Operating Exclusions ($25) ($32) ($29) $186 $105 Adjusted Operating Earnings(1) $66 $95 $174 $1,318 $1,653 Average Equity $1,039 $1,300 $2,390 $12,308 $17,038 Operating ROE (Adjusted Operating Earnings/Average Equity) 6.4% 7.3% 7.3% 10.7% 9.7% ExGen Adjusted O&M Reconciliation ($M)(2) 2017 GAAP O&M $6,300 Decommissioning(3) 25 TMI Retirement (100) EGTP Impairment (425) Direct cost of sales incurred to generate revenues for certain Constellation and Power businesses(4) (425) O&M for managed plants that are partially owned (425) Other (100) Adjusted O&M (Non-GAAP) $4,850

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GAAP to Non-GAAP Reconciliations 2017 Adjusted Cash from Ops Calculation ($M)(1) ComEd PECO BGE PHI ExGen Other Exelon Net cash flows provided by operating activities (GAAP) $1,150 $750 $700 $1,150 $3,450 ($250) $6,975 Other cash from investing activities - - - - ($275) - ($275) Intercompany receivable adjustment ($350) - - - - $350 - Counterparty collateral activity - - - - $225 - $225 Adjusted Cash Flow from Operations $800 $750 $700 $1,150 $3,425 $100 $6,950 2017 Cash From Financing Calculation ($M)(1) ComEd PECO BGE PHI ExGen Other Exelon Net cash flow provided by financing activities (GAAP) $1,000 $175 $200 $175 ($275) $350 $1,625 Dividends paid on common stock $425 $300 $200 $325 $650 ($650) $1,250 Intercompany receivable adjustment $350 - - - - ($350) - Financing Cash Flow $1,775 $475 $400 $500 $375 ($650) $2,875 Exelon Total Cash Flow Reconciliation(1) 2017 GAAP Beginning Cash Balance $650 Adjustment for Cash Collateral Posted $400 Adjusted Beginning Cash Balance(3) $1,050 Net Change in Cash (GAAP)(2) $375 Adjusted Ending Cash Balance(3) $1,425 Adjustment for Cash Collateral Posted ($625) GAAP Ending Cash Balance $775 All amounts rounded to the nearest $25M. Items may not sum due to rounding. Represents the GAAP measure of net change in cash, which is the sum of cash flow from operations, cash from investing activities, and cash from financing activities. Figures reflect cash capital expenditures and CENG fleet at 100%. Adjusted Beginning and Ending cash balances reflect GAAP Beginning and End Cash Balances excluding counterparty collateral activity