Exhibit 99.1

News Release

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

EXELON REPORTS FOURTH QUARTER AND FULL YEAR 2017 RESULTS

AND INITIATES 2018 FINANCIAL OUTLOOK

• Exelon reported GAAP Net Income of $1.94 per share and $3.97 per share for the fourth quarter and full year 2017, respectively, and Adjusted (non-GAAP) Operating Earnings of $0.55 per share and $2.60 per share for the fourth quarter and full year 2017, respectively.

• Exelon introduces a 2018 Adjusted (non-GAAP) Operating Earnings guidance range of $2.90 - $3.20 per share, reflecting growth in Utilities, full year recognition of both Illinois and New York ZEC revenue and the impact of tax reform.

• Exelon's Board of Directors increased the annual dividend growth rate to 5 percent from 2.5 percent, effective in the first quarter of 2018.

• Exelon Utilities project capital expenditures of $21 billion over the next 4 years to improve service and benefit customers, supporting over 7 percent annual rate base growth.

• Exelon Generation projects free cash flow before growth capex of $7.6 billion over the next 4 years, supporting Exelon's priorities of Utility reinvestment and debt reduction.

• Quad Cities Units 1 & 2 and Clinton Unit 1 were winning bidders in Illinois ZEC procurement.

CHICAGO (February 7, 2018)— Exelon Corporation (NYSE: EXC) today reported its financial results for the fourth quarter and full year 2017.

"Exelon had a strong 2017, with our utilities turning in first-quartile and in several cases best-ever performance in reliability and customer service, and our nuclear generation fleet producing the most power on record, all thanks to the great work of our people, who also set company records for volunteerism and charitable giving,” said Christopher M. Crane, Exelon’s president and CEO. “We will build on this momentum in 2018 with our new dividend growth rate of 5 percent annually over the next three years, tax reform that will benefit utility customers and reduce tax expenses at Generation, and movement on needed power price formation changes in PJM and broader resiliency reviews at FERC.”

“In 2017, Exelon delivered solid financial performance with $2.60 of Adjusted (non-GAAP) Operating Earnings, which is within our range,” said Jonathan W. Thayer, Exelon’s Senior Executive Vice President and CFO. “We are introducing 2018 operating earnings guidance of $2.90 - $3.20 per share which incorporates the benefits of U.S. tax reform, strong utility growth, a full-year of ZEC programs in New York and Illinois, and recognition of Illinois ZEC revenue from 2017.”

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Fourth Quarter 2017

Exelon's GAAP Net Income for the fourth quarter2017 increased to $1.94 per share from $0.22 per share in the fourth quarter of 2016; Adjusted (non-GAAP) Operating Earnings increased to $0.55 per share in the fourth quarter of 2017 from $0.44 per share in the fourth quarter of 2016. For the reconciliations of GAAP Net Income to Adjusted (non-GAAP) Operating Earnings, refer to the tables beginning on page 9.

Adjusted (non-GAAP) Operating Earnings in the fourth quarter of 2017 reflect higher utility earnings due to regulatory rate increases and weather, partially offset by a 2017 impairment of certain transmission-related income tax regulatory assets; and, at Generation, New York ZEC revenue and higher capacity prices, partially offset by lower realized energy prices.

Full Year 2017

For the full year 2017, Exelon's GAAP Net Income increased to $3.97 per share from $1.22 per share in 2016. Exelon's Adjusted (non-GAAP) Operating Earnings for 2017 decreased to $2.60 per share from $2.68 per share in 2016.

Adjusted (non-GAAP) Operating Earnings for the full year 2017 reflect higher utility earnings due to regulatory rate increases, partially offset by weather and a 2017 impairment of certain transmission-related income tax regulatory assets; and, at Generation, lower realized energy prices, the impacts of lower load volumes delivered due to mild weather in the third quarter 2017, the conclusion of the Ginna RSSA and the impact of declining natural gas prices on Generation's natural gas portfolio, partially offset by New York ZEC revenue and higher capacity prices.

Operating Company Results¹ 

ComEd² 

ComEd's fourth quarter2017 GAAP Net Income was $120 million compared with $80 million in the fourth quarter of 2016. ComEd’s Adjusted (non-GAAP) Operating Earnings for the fourth quarter2017 were $123 million compared with $81 million in the fourth quarter of 2016, primarily reflecting higher electric distribution and transmission formula rate earnings.

PECO

PECO’s fourth quarter2017 GAAP Net Income was $107 million compared with $92 million in the fourth quarter of 2016. PECO’s fourth quarter2017 Adjusted (non-GAAP) Operating Earnings of $95 million remained relatively consistent with fourth quarter2016 Adjusted (non-GAAP) Operating Earnings of $94 million.

Heating degree days were up 6.1 percent relative to the same period in 2016 and were 7.2 percent below normal. Total retail electric deliveries were up 3.4 percent compared with the fourth quarter of 2016. Natural gas deliveries (including both retail and transportation segments) in the fourth quarter of 2017 were up 9.0 percent compared with the same period in 2016.

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¹Exelon’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.

²For BGE, Pepco and DPL Maryland and beginning in 2017 for ComEd, customer rates are adjusted to eliminate the impacts of weather and customer usage on distribution volumes.

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BGE² 

BGE’s fourth quarter2017 GAAP Net Income was $76 million compared with $103 million in the fourth quarter of 2016. BGE’s Adjusted (non-GAAP) Operating Earnings for the fourth quarter2017 were $82 million compared with $105 million in the fourth quarter of 2016, primarily due to a favorable 2016 settlement of a Baltimore City conduit fee dispute and a 2017 impairment of certain transmission-related income tax regulatory assets.

PHI² 

PHI’s fourth quarter2017 GAAP Net Income was $4 million compared with $30 million in the fourth quarter of 2016. PHI’s Adjusted (non-GAAP) Operating Earnings for the fourth quarter2017 were $48 million compared with $42 million in the fourth quarter of 2016, primarily due to regulatory rate increases, partially offset by a 2017 impairment of certain transmission-related income tax regulatory assets.

Generation

Generation's fourth quarter2017 GAAP Net Income was $2,215 million compared with a GAAP Net Loss of $41 million in the fourth quarter of 2016. Generation’s Adjusted (non-GAAP) Operating Earnings for the fourth quarter2017 were $252 million compared with $162 million in the fourth quarter of 2016, primarily reflecting New York ZEC revenue and higher capacity prices, partially offset by lower realized energy prices.

The proportion of expected generation hedged as of Dec. 31, 2017, was 85.0 percent to 88.0 percent for 2018, 55.0 percent to 58.0 percent for 2019 and 26.0 percent to 29.0 percent for 2020.

Initiates Annual Guidance for 2018

Exelon introduced a guidance range for 2018 Adjusted (non-GAAP) Operating Earnings of $2.90 to $3.20 per share. Adjusted (non-GAAP) Operating Earnings guidance is based on the assumption of normal weather, which is determined based on historical average heating and cooling degree days for a 30-year period in the respective utilities' service territories, except at PHI, where a 20-year period is used. The outlook for 2018 Adjusted (non-GAAP) Operating Earnings for Exelon and its subsidiaries excludes the following items:

• Mark-to-market adjustments from economic hedging activities;

• Unrealized gains and losses 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 the date of the acquisition of ConEdison Solutions in 2016 and FitzPatrick in 2017;

• Certain costs incurred related to the PHI and FitzPatrick acquisitions;

• Certain costs incurred related to plant retirements;

• Certain costs incurred to achieve cost management program savings;

• Other unusual items;

• Generation's noncontrolling interest related to CENG exclusion items; and

• One-time impacts of adopting new accounting standards.

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²For BGE, Pepco and DPL Maryland and beginning in 2017 for ComEd, customer rates are adjusted to eliminate the impacts of weather and customer usage on distribution volumes.

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Recent Developments

• Dividend Policy Update: On Jan. 30, 2018, the Board of Directors of Exelon announced an updated dividend policy targeting 5 percent annual dividend growth for the period covering 2018 through 2020. Since the last dividend policy of 2.5 percent annual growth was implemented in 2016, Exelon’s business position has continued to strengthen. The company has generated more earnings from regulated utilities following the PHI acquisition, recognized greater stability for its generation fleet with the Illinois and New York ZEC programs, and continued to focus on cost management and prudent balance sheet oversight. As a result of the strengthened outlook on earnings, Exelon is sharing the financial success with its shareholders through this updated dividend policy.

• Utility Capex and Rate Base Update: Exelon Utilities plan to invest nearly $21 billion of capital to ensure reliable, more resilient and more efficient transmission and distribution of electricity and gas for our customers. The increased capital investments and impacts of tax reform are expected to drive annual rate base growth of 7.4 percent through 2021, exceeding the 6.5 percent growth expectations for 2017-2020 projected a year ago.

• Generation and Free Cash Flow Outlook: Cumulativelyfrom 2018 through 2021, Generation projects $7.6 billion of free cash flow before growth capex, which is $0.8 billion higher than the prior 4-year outlook from 2017 through 2020. This financial outlook accounts for the latest power price forwards, updated gross margins at Constellation, continued efforts to reduce O&M cost and capital expenditures, the planned closure of Three Mile Island and Oyster Creek, and the impact of tax reform.

• Exelon Nuclear Plants Selected in Illinois ZEC Procurement Event: On Jan. 25, 2018, the ICC announced that Clinton Unit 1 and Quad Cities Units 1 & 2 were winning bidders through the Illinois Power Agency's ZEC procurement event, which entitles them to compensation for the sale of ZECs. Generation executed the ZEC procurement contracts with Illinois utilities, including ComEd, effective January 26, 2018, and will begin recognizing revenue. In addition to recognizing ZEC revenue generated in the first quarter of 2018, Generation will also recognize ZEC revenue retroactive to June 1, 2017, which will contribute approximately $0.11 to Adjusted (non-GAAP) Operating Earnings. The $0.11 contribution to Adjusted (non-GAAP) Operating Earnings is higher than the $0.09 originally expected in 2017 due to the lower tax rate in 2018 at Generation as a result of the Tax Cuts and Jobs Act (TCJA).

• Early Retirement of Oyster Creek Nuclear Facility: On Feb. 2, 2018, Generation announced that it will permanently cease generation operations at Oyster Creek Generating Station (Oyster Creek) at the end of its current operating cycle in October 2018. In 2010, Generation announced that Oyster Creek would retire by the end of 2019 as part of an agreement with the State of New Jersey to avoid significant costs associated with the construction of cooling towers to meet the State’s then new environmental regulations. Since then, like other nuclear sites, Oyster Creek has continued to face rising operating costs amid a historically low wholesale power price environment. The decision to retire Oyster Creek in 2018 at the end of its current operating cycle involved consideration of several factors, including economics and operating efficiencies, and avoids a refueling outage scheduled for the fall of 2018 that would have required advanced purchasing of fuel fabrication and materials beginning in late February 2018. Because of the decision to retire Oyster Creek in 2018, Generation will recognize certain one-time charges in the first quarter of 2018 ranging from an estimated $25 million to $35 million (pre-tax) related to a materials and supplies inventory reserve adjustment, employee-related costs, and construction work-in-progress impairment, among other items. The

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aforementioned one-time charges will be excluded from GAAP Net Income to arrive at Adjusted (non-GAAP) Operating Earnings in the first quarter 2018.

• DOE Notice of Proposed Rulemaking: On Aug. 23, 2017, the United States Department of Energy (DOE) released its report on the reliability of the electric grid. One aspect of the wide-ranging report is the DOE’s recognition that the electricity markets do not currently value the resiliency provided by baseload generation, such as nuclear plants. On Sept. 28, 2017, the DOE issued a Notice of Proposed Rulemaking (NOPR) that would entitle certain eligible resilient generating units (i.e., those located in organized markets, with a 90-day supply of fuel on site, not already subject to state cost of service regulation and satisfying certain other requirements) to recover fully allocated costs and earn a fair return on equity on their investment. On Jan. 8, 2018, the FERC issued an order terminating the rulemaking docket that was initiated to address the proposed rule in the DOE NOPR, concluding the proposed rule did not sufficiently demonstrate there is a resiliency issue and that it proposed a remedy that did not appear to be just, reasonable and nondiscriminatory as required under the Federal Power Act. At the same time, the FERC initiated a new proceeding to consider resiliency challenges to the bulk power system and evaluate whether additional FERC action to address resiliency would be appropriate. Exelon has been and will continue to be an active participant in these proceedings, but cannot predict the final outcome or its potential impact, if any, on Exelon or Generation.

Fourth Quarter Highlights

• Corporate Tax Reform: On Dec. 22, 2017, President Trump signed into law the TCJA. The Registrants remeasured their existing deferred income tax balances as of Dec. 31, 2017, to reflect the decrease in the corporate income tax rate from 35 percent to 21 percent, which resulted in a material decrease to their net deferred income tax liability balances. At Generation, this reduction in net deferred income tax liabilities resulted in a one-time credit to income tax expense of approximately $1.9 billion. The Utility Registrants offset virtually all similar reductions, totaling $7.3 billion, with net regulatory liabilities (rather than through earnings), given that changes in income taxes are generally passed through customer rates. The amount and timing of potential refunds of the established net regulatory liabilities will be determined by the Utility Registrants’ respective rate regulators, subject to certain IRS "normalization" rules.

Pursuant to TCJA, beginning in 2018, Generation is expected to have higher operating cash flows over the next five years reflecting the reduction in the corporate federal income tax rate and full expensing of capital investments. The TCJA is generally expected to result in lower operating cash flows for the Utility Registrants as a result of the elimination of bonus depreciation and lower customer rates. Increased operating cash flows for the Utility Registrants from lower corporate federal income tax rates is expected to be more than offset over time by lower customer rates resulting from lower income tax expense and the settlement of deferred income tax net regulatory liabilities established pursuant to TCJA, partially offset by the impacts of higher rate base. The Utility Registrants expect to fund any required incremental operating cash outflows using third party debt financings and equity funding from Exelon in combinations generally consistent with existing capitalization ratio structures. To fund any additional equity contributions to the Utility Registrants, Exelon would have available to it its typical sources, including, but not limited to, the increased operating cash flows at Generation referenced above, which over time are expected to exceed the incremental equity needs at the Utility Registrants.

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The Utility Registrants continue to work with their state regulatory commissions to determine the amount and timing of the passing back of TCJA income tax savings benefits to customers; with filings either made, or expected to be made, at Pepco, DPL and ACE, and approved filings at ComEd and BGE. The amounts being passed back or proposed to be passed back to customers reflect the benefit of lower income tax expense beginning January 1, 2018 (Feb. 1, 2018 for DPL Delaware), and the settlement of a portion of deferred income tax regulatory liabilities established upon enactment of the TCJA. To date, neither the PAPUC nor FERC has yet issued guidance on how and when to reflect the impacts of the TCJA in customer rates.

• EGTP Bankruptcy: On Nov. 7, 2017, EGTP and all of its wholly-owned subsidiaries filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Code in the United States Bankruptcy Court for the District of Delaware. As a result, Exelon and Generation deconsolidated EGTP’s net liabilities, which included the previously impaired assets and related debt, from their consolidated financial statements, resulting in a $213 million pre-tax gain. Concurrently with the Chapter 11 filings, Generation entered into an asset purchase agreement to acquire one of EGTP’s generating plants, the Handley Generating Station, for approximately $60 million, subject to a potential adjustment for fuel oil and assumption of certain liabilities. The acquisition was approved by the Bankruptcy Court in January 2018 and the transaction is expected to be completed in the first half of 2018.

• Proposed Remedy for West Lake Landfill: On Feb. 1, 2018, the Environmental Protection Agency (EPA) announced a proposed remediation plan for the West Lake Landfill Superfund Site in Bridgeton, Missouri, for which Generation is one of the potentially responsible parties (PRPs). The proposed remediation plan includes a partial excavation of the site and an enhanced landfill cover and will be open for public comment through March 22, 2018, with the expectation that a Record of Decision will be issued during the third quarter of 2018. Thereafter, the EPA will seek to enter into a Consent Decree with the PRPs to effectuate the remedy, which Generation currently expects will occur in late 2018 or early 2019. The estimated total cost to fully execute the EPA’s proposed remedy is approximately $340 million, including cost escalation on an undiscounted basis, which will be allocated among the final group of PRPs. Generation increased its previous liability to reflect management’s best estimate of Generation’s allocable share of the cost of the proposed remedy among the PRPs, which could materially change in the future. The aforementioned 2017 charge has been excluded from GAAP Net Income to arrive at Adjusted (non-GAAP) Operating Earnings.

• ComEd Electric Distribution Rate Case: On Dec. 6, 2017, the ICC issued its final order approving ComEd’s 2017 annual distribution formula rate update. The final order resulted in an increase to the revenue requirement of $96 million, reflecting an increase of $78 million for the initial revenue requirement for 2017 and an increase of $18 million related to the annual reconciliation for 2016. The increase was set using an allowed return on rate base of 6.47 percent for the initial revenue requirement and 6.45 percent for the annual reconciliation (inclusive of an allowed ROE of 8.40 percent for 2017 less a reliability performance metric penalty of 6 basis points for the 2016 reconciliation). The rates took effect in January 2018.

• Pepco District of Columbia Electric Distribution Rate Case: On Dec. 19, 2017, Pepco filed an application with the DCPSC to increase its annual electric distribution base rates by $66 million, reflecting a requested ROE of 10.1 percent. By mid-February, Pepco will update its current distribution rate case to reflect the TCJA impacts. Pepco expects a decision in the matter in the fourth quarter of 2018, but cannot predict how much of the requested increase the DCPSC will approve.

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• Pepco Maryland Electric Distribution Rate Case: On Jan. 2, 2018, Pepco filed an application with the MDPSC to increase its annual electric distribution base rates by $41 million, reflecting a requested ROE of 10.1 percent. On Feb. 5, 2018, Pepco filed with the MDPSC an update to its current distribution rate case to reflect approximately $31 million in TCJA tax savings, thereby reducing the requested annual base rate increase to $11 million. Pepco expects a decision in the matter in the third quarter of 2018, but cannot predict how much of the requested increase the MDPSC will approve.

• DPL Maryland Electric Distribution Rate Case: On July 14, 2017, DPL filed an application with the MDPSC to increase its annual electric distribution base rates by $27 million, which was updated to $19 million on Nov. 16, 2017, reflecting a requested ROE of 10.1 percent. On Dec. 18, 2017, DPL, the MDPSC Staff and Maryland’s Office of People’s Counsel filed a settlement agreement with the MDPSC that would provide DPL a rate increase of $13 million, and a ROE of 9.5 percent solely for purposes of calculating AFUDC and regulatory asset carrying costs. By mid-February, DPL is planning to file with the MDPSC seeking approval to pass back to customers beginning in 2018 approximately $13 million in annual tax savings resulting from the enactment of the TCJA through a reduction in electric distribution rates. DPL expects a decision in the matter in the first quarter of 2018, but cannot predict whether the MDPSC will approve the settlement agreement as filed or how much of the requested increase will be approved.

• FERC Transmission-Related Regulatory Asset Order: On Nov. 16, 2017, FERC issued an order rejecting BGE’s proposed revisions to its transmission formula rate to recover certain transmission-related income tax regulatory assets. ComEd, Pepco, DPL and ACE have similar transmission-related income tax regulatory assets also requiring FERC approval separate from their transmission formula rate mechanisms. Pursuant to the FERC order, management of each company concluded that the portion of the total transmission-related income tax regulatory assets that would have been previously amortized and recovered through rates had the transmission formula rate provided for such recovery was no longer probable of recovery; and recorded impairment charges to Income tax expense of $35 million, $3 million, $5 million, $27 million, $14 million, $6 million and $7 million at Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE, respectively. Nevertheless, each company believes there is sufficient basis to support full recovery of all existing transmission-related income tax regulatory assets, and intends to further pursue such full recovery with FERC.

• Nuclear Operations: Generation’s nuclear fleet, including its owned output from the Salem Generating Station and 100 percent of the CENG units, produced 47,528 gigawatt-hours (GWhs) in the fourth quarter of 2017, compared with 44,834 GWhs in the fourth quarter of 2016. Excluding Salem, the Exelon-operated nuclear plants at ownership achieved a 95.3 percent capacity factor for the fourth quarter of 2017, compared with 94.2 percent for the fourth quarter of 2016. Excluding Salem, the number of planned refueling outage days in the fourth quarter of 2017 totaled 60, compared with 71 in the fourth quarter of 2016. There were 18 non-refueling outage days in the fourth quarter of 2017, compared with 32 days in the fourth quarter of 2016.

• Fossil and Renewables Operations: The dispatch match rate for Generation’s gas and hydro fleet was 98.4 percent in the fourth quarter of 2017, compared with 99.7 percent in the fourth quarter of 2016. The lower performance in the quarter was primarily due to outages at gas units in Texas and Alabama. The reported performance includes the EGTP sites, which Exelon maintained and operated through the quarter, but does not include Wolf Hollow II or Colorado Bend II, the two new CCGT units that went into full commercial operation in the second quarter. Energy capture for the wind and solar fleet was 96.2 percent in the fourth quarter of 2017, compared with 95.7 percent in the fourth quarter of 2016.

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• Financing Activities:

◦ On Nov. 28, 2017, ExGen Renewables IV, an indirect subsidiary of Exelon and Generation, entered into an $850 million non-recourse senior secured term loan credit facility agreement scheduled to mature on Nov. 28, 2024. The net proceeds of $785 million, after the initial funding of $50 million for debt service and liquidity reserves as well as deductions for original discount and issuance costs, were distributed to Generation for general corporate purposes. The term loan bears interest at a variable rate equal to LIBOR plus 3.00 percent, subject to a 1.00 percent LIBOR floor. As of Dec. 31, 2017, $850 million was outstanding. In addition to the financing, ExGen Renewables IV entered into interest rate swaps with an initial notional amount of $636 million at an interest rate of 2.32 percent to manage a portion of the interest rate exposure in connection with the financing.

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GAAP/Adjusted (non-GAAP) Operating Earnings Reconciliations

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

(in millions)	Exelon Earnings per Diluted Share			Exelon			ComEd		PECO			BGE			PHI			Generation
2017 GAAP Net Income	$	1.94		$	1,871		$	120	$	107		$	76		$	4		$	2,215
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $7 and $6, respectively)	0.01			8			—		—			—			—			9
Unrealized Gains Related to Nuclear Decommissioning Trust (NDT) Fund Investments (net of taxes of $67)	(0.12		)	(108		)	—		—			—			—			(108		)
Amortization of Commodity Contract Intangibles (net of taxes of $5)	0.01			8			—		—			—			—			8
Merger and Integration Costs (net of taxes of $1, $1 and $0, respectively)	—			1			—		—			1			—			1
Long-Lived Asset Impairments (net of taxes of $16, $9 and $8, respectively)	0.03			29			—		—			—			16			12
Plant Retirements and Divestitures (net of taxes of $45, respectively)	0.07			70			—		—			—			—			70
Cost Management Program (net of taxes of $6, $1, $1 and $5, respectively)	0.01			10			—		1			1			—			8
Reassessment of Deferred Income Taxes (entire amount represents tax expense)	(1.30		)	(1,257		)	3		(12		)	5			33			(1,874		)
Gain on Deconsolidation of Businesses (net of taxes of $83)	(0.14		)	(130		)	—		—			—			—			(130		)
Vacation Policy Change (net of taxes of $21, $1, $1, $3, and $16, respectively)	(0.03		)	(33		)	—		(1		)	(1		)	(5		)	(26		)
Change in Environmental Remediation Liabilities (net of taxes of $17)	0.03			27			—		—			—			—			27
Noncontrolling Interests (net of taxes of $8)	0.04			40			—		—			—			—			40
2017 Adjusted (non-GAAP) Operating Earnings	$	0.55		$	536		$	123	$	95		$	82		$	48		$	252

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

(in millions)	Exelon Earnings per Diluted Share			Exelon			ComEd		PECO		BGE		PHI		Generation
2016 GAAP Net Income	$	0.22		$	204		$	80	$	92	$	103	$	30	$	(41	)
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $28)	(0.05		)	(44		)	—		—		—		—		(44		)
Unrealized Losses Related to NDT Fund Investments (net of taxes of $13)	0.01			9			—		—		—		—		9
Amortization of Commodity Contract Intangibles (net of taxes of $16)	0.03			26			—		—		—		—		26
Merger and Integration Costs (net of taxes of $14, $0, $1, $1, $3 and $9, respectively)	0.02			23			1		1		1		4		15
Merger Commitments (net of taxes of $12, $2 and $9, respectively)	0.04			38			—		—		—		8		40
Long-Lived Asset Impairments (net of taxes of $1)	—			(1		)	—		—		—		—		—
Plant Retirements and Divestitures (net of taxes of $59)	0.10			94			—		—		—		—		94
Cost Management Program (net of taxes of $5, $1, $1 and $3, respectively)	0.01			8			—		1		1		—		6
Reassessment of State Deferred Income Taxes (entire amount represents tax expense)	0.01			10			—		—		—		—		14
Asset Retirement Obligation (net of taxes of $14)	(0.08		)	(75		)	—		—		—		—		(75		)
Curtailment of Generation Growth Development Activities (net of taxes of $35)	0.06			57			—		—		—		—		57
Noncontrolling Interests (net of taxes of $1)	0.07			61			—		—		—		—		61
2016 Adjusted (non-GAAP) Operating Earnings	$	0.44		$	410		$	81	$	94	$	105	$	42	$	162

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Adjusted (non-GAAP) Operating Earnings for the full year 2017 do not include the following items (after tax) that were included in reported GAAP Net Income:

(in millions)	Exelon Earnings per Diluted Share			Exelon			ComEd		PECO			BGE			PHI			Generation
2017 GAAP Net Income	$	3.97		$	3,770		$	567	$	434		$	307		$	362		$	2,694
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $68 and $66, respectively)	0.11			107			—		—			—			—			109
Unrealized Gains Related to NDT Fund Investments (net of taxes of $204)	(0.34		)	(318		)	—		—			—			—			(318		)
Amortization of Commodity Contract Intangibles (net of taxes of $22)	0.04			34			—		—			—			—			34
Merger and Integration Costs (net of taxes of $25, $0, $2, $2, $7 and $27, respectively)	0.04			40			1		2			2			(10		)	44
Merger Commitments (net of taxes of $137, $52 and $18, respectively)	(0.14		)	(137		)	—		—			—			(59		)	(18		)
Long-Lived Asset Impairments (net of taxes of $204, $9 and $194, respectively)	0.34			321			—		—			—			16			306
Plant Retirements and Divestitures (net of taxes of $134 and $133, respectively)	0.22			207			—		—			—			—			208
Reassessment of Deferred Income Taxes (entire amount represents tax expense)	(1.37		)	(1,299		)	1		(12		)	5			34			(1,856		)
Cost Management Program (net of taxes of $21, $3, $3 and $15 respectively)	0.04			34			—		4			5			—			25
Like-Kind Exchange Tax Position (net of taxes of $66 and $9, respectively)	(0.03		)	(26		)	23		—			—			—			—
Asset Retirement Obligation (net of taxes of $1)	—			(2		)	—		—			—			—			(2		)
Tax Settlements (net of taxes of $1)	(0.01		)	(5		)	—		—			—			—			(5		)
Bargain Purchase Gain (net of taxes of $0)	(0.25		)	(233		)	—		—			—			—			(233		)
Gain on Deconsolidation of Businesses (net of taxes of $83)	(0.14		)	(130		)	—		—			—			—			(130		)
Vacation Policy Change (net of taxes of $21, $1, $1, $3, and $16, respectively)	(0.03		)	(33		)	—		(1		)	(1		)	(5		)	(26		)
Change in Environmental Remediation Liabilities (net of taxes of $17)	0.03			27			—		—			—			—			27
Noncontrolling Interests (net of taxes of $24)	0.12			114			—		—			—			—			114
2017 Adjusted (non-GAAP) Operating Earnings	$	2.60		$	2,471		$	592	$	427		$	318		$	338		$	973

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Adjusted (non-GAAP) Operating Earnings for the full year 2016 do not include the following items (after tax) that were included in reported GAAP Net Income:

(in millions)	Exelon Earnings per Diluted Share			Exelon			ComEd			PECO		BGE		PHI			Generation
2016 GAAP Net Income	$	1.22		$	1,134		$	378		$	438	$	286	$	(61	)	$	496
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $18)	0.03			24			—			—		—		—			24
Unrealized Gains Related to NDT Fund Investments (net of taxes of $77)	(0.13		)	(118		)	—			—		—		—			(118		)
Amortization of Commodity Contract Intangibles (net of taxes of $22)	0.04			35			—			—		—		—			35
Merger and Integration Costs (net of taxes of $50, $2, $2, $28 and $22, respectively)	0.12			114			(3		)	3		—		42			35
Merger Commitments (net of taxes of $126, 77 and $10, respectively)	0.47			437			—			—		—		247			42
Long-Lived Asset Impairments (net of taxes of $68)	0.11			103			—			—		—		—			103
Plant Retirements and Divestitures (net of taxes of $273, respectively)	0.47			432			—			—		—		—			432
Reassessment of Deferred Income Taxes (entire amount represents tax expense)	0.01			10			—			—		—		—			20
Cost Management Program (net of taxes of $21, $2, $2 and $17 respectively)	0.04			34			—			3		3		—			28
Like-Kind Exchange Tax Position (net of taxes of $61 and $42, respectively)	0.21			199			149			—		—		—			—
Asset Retirement Obligation (net of taxes of $13)	(0.08		)	(75		)	—			—		—		—			(75		)
Curtailment of Generation Growth and Development Activities (net of taxes of $35)	0.06			57			—			—		—		—			57
Noncontrolling Interests (net of taxes of $9)	0.11			102			—			—		—		—			102
2016 Adjusted (non-GAAP) Operating Earnings	$	2.68		$	2,488		$	524		$	444	$	289	$	228		$	1,181

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 39.0 percent to 41.0 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

12

49.5 percent and 76.2 percent for the three months ended December 31, 2017 and 2016, respectively; and were 47.4 percent and 48.7 percent for the twelve months ended December 31, 2017 and 2016, respectively.

Webcast Information

Exelon will discuss fourth quarter2017 earnings in a one-hour conference call scheduled for today at 9 a.m. Central Time (10 a.m. Ea​stern Time).​ The webcast and associated materials can be accessed at www.exeloncorp.com/investor-relations.

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 2017 revenue of $33.5 billion. Exelon’s six utilities deliver electricity and natural gas to approximately 9 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 35,168 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 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 February 7, 2018.

13

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' Third Quarter 2017 Quarterly Report on Form 10-Q in (a) Part II, Other Information, ITEM 1A. Risk Factors; (b) Part 1, Financial Information, ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) Part I, Financial Information, ITEM 1. Financial Statements: Note 18, 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.

14

Earnings Release Attachments

Table of Contents

Consolidating Statements of Operations - Three Months Ended December 31, 2017 and 2016	1
Consolidating Statements of Operations - Twelve Months Ended December 31, 2017 and 2016	2
Business Segment Comparative Statements of Operations - Generation and ComEd - Three and Twelve Months Ended December 31, 2017 and 2016	3
Business Segment Comparative Statements of Operations - PECO and BGE - Three and Twelve Months Ended December 31, 2017 and 2016	4
Business Segment Comparative Statements of Operations - PHI and Other - Three and Twelve Months Ended December 31, 2017 and 2016	5
Consolidated Balance Sheets - December 31, 2017 and December 31, 2016	6
Consolidated Statements of Cash Flows - Twelve Months Ended December 31, 2017 and 2016	7
GAAP Consolidated Statements of Operations and Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments - Exelon - three months ended December 31, 2017 and 2016	8
GAAP Consolidated Statements of Operations and Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments - Exelon - twelve months ended December 31, 2017 and 2016	10
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Net Income - Three Months Ended December 31, 2017 and 2016	12
Reconciliation of Adjusted (non-GAAP) Operating Earnings to GAAP Net Income - Twelve Months Ended December 31, 2017 and 2016	14
GAAP Consolidated Statements of Operations and Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments - Generation - Three and Twelve Months Ended December 31, 2017 and 2016	17
GAAP Consolidated Statements of Operations and Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments - ComEd - Three and Twelve Months Ended December 31, 2017 and 2016	19
GAAP Consolidated Statements of Operations and Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments - PECO - Three and Twelve Months Ended December 31, 2017 and 2016	21
GAAP Consolidated Statements of Operations and Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments - BGE - Three and Twelve Months Ended December 31, 2017 and 2016	22
GAAP Consolidated Statements of Operations and Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments - PHI - Three and Twelve Months Ended December 31, 2017 and 2016	23
GAAP Consolidated Statements of Operations and Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments - Other - Three and Twelve Months Ended December 31, 2017 and 2016	25
Exelon Generation Statistics - Three Months Ended December 31, 2017, September 30, 2017, June 30, 2017, March 31, 2017 and December 31, 2016	27
Exelon Generation Statistics - Twelve Months Ended December 31, 2017 and 2016	28
ComEd Statistics - Three and Twelve Months Ended December 31, 2017 and 2016	29
PECO Statistics - Three and Twelve Months Ended December 31, 2017 and 2016	30
BGE Statistics - Three and Twelve Months Ended December 31, 2017 and 2016	32
Pepco Statistics - Three and Twelve Months Ended December 31, 2017 and 2016	34
DPL Statistics - Three and Twelve Months Ended December 31, 2017 and 2016	35
ACE Statistics - Three and Twelve Months Ended December 31, 2017 and 2016	37

EXELON CORPORATION

Consolidating Statements of Operations

(unaudited)

(in millions)

	Three Months Ended December 31, 2017
	Generation			ComEd			PECO			BGE			PHI (a)			Other (b)			Exelon Consolidated
Operating revenues	$	4,654		$	1,309		$	729		$	813		$	1,121		$	(245	)	$	8,381
Operating expenses
Purchased power and fuel	2,403			399			250			280			398			(222		)	3,508
Operating and maintenance	1,421			332			211			184			292			(45		)	2,395
Depreciation and amortization	412			220			73			125			164			21			1,015
Taxes other than income	130			73			38			61			108			8			418
Total operating expenses	4,366			1,024			572			650			962			(238		)	7,336
Gain (Loss) on sales of assets	—			1			—			—			—			(1		)	—
Gain on deconsolidation of business	213			—			—			—			—			—			213
Operating income (loss)	501			286			157			163			159			(8		)	1,258
Other income and (deductions)
Interest expense, net	(98		)	(87		)	(33		)	(25		)	(62		)	(60		)	(365		)
Other, net	299			10			3			4			15			—			331
Total other income and (deductions)	201			(77		)	(30		)	(21		)	(47		)	(60		)	(34		)
Income (Loss) before income taxes	702			209			127			142			112			(68		)	1,224
Income taxes	(1,585		)	89			20			66			108			583			(719		)
Equity in (losses) earnings of unconsolidated affiliates	(7		)	—			—			—			—			1			(6		)
Net income (loss)	2,280			120			107			76			4			(650		)	1,937
Net income attributable to noncontrolling interests	65			—			—			—			—			1			66
Net income (loss) attributable to common shareholders	$	2,215		$	120		$	107		$	76		$	4		$	(651	)	$	1,871
	Three Months Ended December 31, 2016
	Generation			ComEd			PECO			BGE			PHI (a)			Other (b)			Exelon Consolidated
Operating revenues	$	4,388		$	1,223		$	701		$	812		$	1,078		$	(327	)	$	7,875
Operating expenses
Purchased power and fuel	2,221			317			238			300			410			(308		)	3,178
Operating and maintenance	1,308			417			206			149			310			(19		)	2,371
Depreciation and amortization	550			201			69			115			160			20			1,115
Taxes other than income	126			71			38			58			107			8			408
Total operating expenses	4,205			1,006			551			622			987			(299		)	7,072
(Loss) Gain on sales of assets	(89		)	—			—			—			(1		)	1			(89		)
Operating income (loss)	94			217			150			190			90			(27		)	714
Other income and (deductions)
Interest expense, net	(92		)	(87		)	(31		)	(27		)	(61		)	(58		)	(356		)
Other, net	6			8			2			5			13			(1		)	33
Total other income and (deductions)	(86		)	(79		)	(29		)	(22		)	(48		)	(59		)	(323		)
Income (Loss) before income taxes	8			138			121			168			42			(86		)	391
Income taxes	(3		)	58			29			65			12			(25		)	136
Equity in (losses) earnings of unconsolidated affiliates	(9		)	—			—			—			—			1			(8		)
Net income (loss)	2			80			92			103			30			(60		)	247
Net income attributable to noncontrolling interests and preference stock dividends	43			—			—			—			—			—			43
Net (loss) income attributable to common shareholders	$	(41	)	$	80		$	92		$	103		$	30		$	(60	)	$	204

(a) PHI includes the consolidated results of 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.

1

EXELON CORPORATION

Consolidating Statements of Operations

(unaudited)

(in millions)

	Twelve Months Ended December 31, 2017
	Generation			ComEd			PECO			BGE			PHI			Other (a)			Exelon Consolidated
Operating revenues	$	18,466		$	5,536		$	2,870		$	3,176		$	4,679		$	(1,196	)	$	33,531
Operating expenses
Purchased power and fuel	9,690			1,641			969			1,133			1,716			(1,114		)	14,035
Operating and maintenance	6,291			1,427			806			716			1,068			(182		)	10,126
Depreciation and amortization	1,457			850			286			473			675			87			3,828
Taxes other than income	555			296			154			240			452			34			1,731
Total operating expenses	17,993			4,214			2,215			2,562			3,911			(1,175		)	29,720
Gain (Loss) on sales of assets	2			1			—			—			1			(1		)	3
Bargain purchase gain	233			—			—			—			—			—			233
Gain on deconsolidation of business	213			—			—			—			—			—			213
Operating income (loss)	921			1,323			655			614			769			(22		)	4,260
Other income and (deductions)
Interest expense, net	(440		)	(361		)	(126		)	(105		)	(245		)	(283		)	(1,560		)
Other, net	948			22			9			16			54			7			1,056
Total other income and (deductions)	508			(339		)	(117		)	(89		)	(191		)	(276		)	(504		)
Income (Loss) before income taxes	1,429			984			538			525			578			(298		)	3,756
Income taxes	(1,375		)	417			104			218			217			294			(125		)
Equity in (losses) earnings of unconsolidated affiliates	(33		)	—			—			—			1			—			(32		)
Net income (loss)	2,771			567			434			307			362			(592		)	3,849
Net income attributable to noncontrolling interests	77			—			—			—			—			2			79
Net income (loss) attributable to common shareholders	$	2,694		$	567		$	434		$	307		$	362		$	(594	)	$	3,770
	Twelve Months Ended December 31, 2016
	Generation			ComEd			PECO			BGE			PHI (b)			Other (a)			Exelon Consolidated
Operating revenues	$	17,751		$	5,254		$	2,994		$	3,233		$	3,643		$	(1,515	)	$	31,360
Operating expenses
Purchased power and fuel	8,830			1,458			1,047			1,294			1,447			(1,436		)	12,640
Operating and maintenance	5,641			1,530			811			737			1,233			96			10,048
Depreciation and amortization	1,879			775			270			423			515			74			3,936
Taxes other than income	506			293			164			229			354			30			1,576
Total operating expenses	16,856			4,056			2,292			2,683			3,549			(1,236		)	28,200
(Loss) Gain on sales of assets	(59		)	7			—			—			(1		)	5			(48		)
Operating income (loss)	836			1,205			702			550			93			(274		)	3,112
Other income and (deductions)
Interest expense, net	(364		)	(461		)	(123		)	(103		)	(195		)	(290		)	(1,536		)
Other, net	401			(65		)	8			21			44			4			413
Total other income and (deductions)	37			(526		)	(115		)	(82		)	(151		)	(286		)	(1,123		)
Income (loss) before income taxes	873			679			587			468			(58		)	(560		)	1,989
Income taxes	290			301			149			174			3			(156		)	761
Equity in (losses) earnings of unconsolidated affiliates	(25		)	—			—			—			—			1			(24		)
Net income (loss)	558			378			438			294			(61		)	(403		)	1,204
Net income attributable to noncontrolling interests and preference stock dividends	62			—			—			8			—			—			70
Net income (loss) attributable to common shareholders	$	496		$	378		$	438		$	286		$	(61	)	$	(403	)	$	1,134

(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.

2

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

	Generation
	Three Months Ended December 31,									Twelve Months Ended December 31,
	2017			2016			Variance			2017			2016			Variance
Operating revenues	$	4,654		$	4,388		$	266		$	18,466		$	17,751		$	715
Operating expenses
Purchased power and fuel	2,403			2,221			182			9,690			8,830			860
Operating and maintenance	1,421			1,308			113			6,291			5,641			650
Depreciation and amortization	412			550			(138		)	1,457			1,879			(422		)
Taxes other than income	130			126			4			555			506			49
Total operating expenses	4,366			4,205			161			17,993			16,856			1,137
(Loss) Gain on sales of assets	—			(89		)	89			2			(59		)	61
Bargain purchase gain	—			—			—			233			—			233
Gain on deconsolidation of business	213			—			213			213			—			213
Operating income	501			94			407			921			836			85
Other income and (deductions)
Interest expense, net	(98		)	(92		)	(6		)	(440		)	(364		)	(76		)
Other, net	299			6			293			948			401			547
Total other income and (deductions)	201			(86		)	287			508			37			471
Income before income taxes	702			8			694			1,429			873			556
Income taxes	(1,585		)	(3		)	(1,582		)	(1,375		)	290			(1,665		)
Equity in losses of unconsolidated affiliates	(7		)	(9		)	2			(33		)	(25		)	(8		)
Net income	2,280			2			2,278			2,771			558			2,213
Net income attributable to noncontrolling interests	65			43			22			77			62			15
Net income (loss) attributable to membership interest	$	2,215		$	(41	)	$	2,256		$	2,694		$	496		$	2,198
	ComEd
	Three Months Ended December 31,									Twelve Months Ended December 31,
	2017			2016			Variance			2017			2016			Variance
Operating revenues	$	1,309		$	1,223		$	86		$	5,536		$	5,254		$	282
Operating expenses
Purchased power	399			317			82			1,641			1,458			183
Operating and maintenance	332			417			(85		)	1,427			1,530			(103		)
Depreciation and amortization	220			201			19			850			775			75
Taxes other than income	73			71			2			296			293			3
Total operating expenses	1,024			1,006			18			4,214			4,056			158
Gain on sales of assets	1			—			1			1			7			(6		)
Operating income	286			217			69			1,323			1,205			118
Other income and (deductions)
Interest expense, net	(87		)	(87		)	—			(361		)	(461		)	100
Other, net	10			8			2			22			(65		)	87
Total other income and (deductions)	(77		)	(79		)	2			(339		)	(526		)	187
Income before income taxes	209			138			71			984			679			305
Income taxes	89			58			31			417			301			116
Net income	$	120		$	80		$	40		$	567		$	378		$	189

.

3

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

	PECO
	Three Months Ended December 31,									Twelve Months Ended December 31,
	2017			2016			Variance			2017			2016			Variance
Operating revenues	$	729		$	701		$	28		$	2,870		$	2,994		$	(124	)
Operating expenses
Purchased power and fuel	250			238			12			969			1,047			(78		)
Operating and maintenance	211			206			5			806			811			(5		)
Depreciation and amortization	73			69			4			286			270			16
Taxes other than income	38			38			—			154			164			(10		)
Total operating expenses	572			551			21			2,215			2,292			(77		)
Operating income	157			150			7			655			702			(47		)
Other income and (deductions)
Interest expense, net	(33		)	(31		)	(2		)	(126		)	(123		)	(3		)
Other, net	3			2			1			9			8			1
Total other income and (deductions)	(30		)	(29		)	(1		)	(117		)	(115		)	(2		)
Income before income taxes	127			121			6			538			587			(49		)
Income taxes	20			29			(9		)	104			149			(45		)
Net income	$	107		$	92		$	15		$	434		$	438		$	(4	)
	BGE
	Three Months Ended December 31,									Twelve Months Ended December 31,
	2017			2016			Variance			2017			2016			Variance
Operating revenues	$	813		$	812		$	1		$	3,176		$	3,233		$	(57	)
Operating expenses
Purchased power and fuel	280			300			(20		)	1,133			1,294			(161		)
Operating and maintenance	184			149			35			716			737			(21		)
Depreciation and amortization	125			115			10			473			423			50
Taxes other than income	61			58			3			240			229			11
Total operating expenses	650			622			28			2,562			2,683			(121		)
Operating income	163			190			(27		)	614			550			64
Other income and (deductions)
Interest expense, net	(25		)	(27		)	2			(105		)	(103		)	(2		)
Other, net	4			5			(1		)	16			21			(5		)
Total other income and (deductions)	(21		)	(22		)	1			(89		)	(82		)	(7		)
Income before income taxes	142			168			(26		)	525			468			57
Income taxes	66			65			1			218			174			44
Net income	76			103			(27		)	307			294			13
Preference stock dividends	—			—			—			—			8			(8		)
Net income attributable to common shareholder	$	76		$	103		$	(27	)	$	307		$	286		$	21

4

EXELON CORPORATION

Business Segment Comparative Statements of Operations

(unaudited)

(in millions)

	PHI
	Three Months Ended December 31,									Twelve Months Ended December 31,
	2017			2016			Variance			2017			2016 (a)			Variance
Operating revenues	$	1,121		$	1,078		$	43		$	4,679		$	3,643		$	1,036
Operating expenses
Purchased power and fuel	398			410			(12		)	1,716			1,447			269
Operating and maintenance	292			310			(18		)	1,068			1,233			(165		)
Depreciation and amortization	164			160			4			675			515			160
Taxes other than income	108			107			1			452			354			98
Total operating expenses	962			987			(25		)	3,911			3,549			362
(Loss) Gain on sales of assets	—			(1		)	1			1			(1		)	2
Operating income	159			90			69			769			93			676
Other income and (deductions)
Interest expense, net	(62		)	(61		)	(1		)	(245		)	(195		)	(50		)
Other, net	15			13			2			54			44			10
Total other income and (deductions)	(47		)	(48		)	1			(191		)	(151		)	(40		)
Income (loss) before income taxes	112			42			70			578			(58		)	636
Income taxes	108			12			96			217			3			214
Equity in earnings of unconsolidated affiliates	—			—			—			1			—			1
Net income (loss)	$	4		$	30		$	(26	)	$	362		$	(61	)	$	423
	Other (b)
	Three Months Ended December 31,									Twelve Months Ended December 31,
	2017			2016			Variance			2017			2016			Variance
Operating revenues	$	(245	)	$	(327	)	$	82		$	(1,196	)	$	(1,515	)	$	319
Operating expenses
Purchased power and fuel	(222		)	(308		)	86			(1,114		)	(1,436		)	322
Operating and maintenance	(45		)	(19		)	(26		)	(182		)	96			(278		)
Depreciation and amortization	21			20			1			87			74			13
Taxes other than income	8			8			—			34			30			4
Total operating expenses	(238		)	(299		)	61			(1,175		)	(1,236		)	61
(Loss) Gain on sales of assets	(1		)	1			(2		)	(1		)	5			(6		)
Operating loss	(8		)	(27		)	19			(22		)	(274		)	252
Other income and (deductions)
Interest expense, net	(60		)	(58		)	(2		)	(283		)	(290		)	7
Other, net	—			(1		)	1			7			4			3
Total other income and (deductions)	(60		)	(59		)	(1		)	(276		)	(286		)	10
Loss before income taxes	(68		)	(86		)	18			(298		)	(560		)	262
Income taxes	583			(25		)	608			294			(156		)	450
Equity in earnings of unconsolidated affiliates	1			1			—			—			1			(1		)
Net loss	(650		)	(60		)	(590		)	$	(592	)	$	(403	)	$	(189	)
Net income attributable to noncontrolling interests and preference stock dividends	1			—			1			2			—			2
Net loss attributable to common shareholders	$	(651	)	$	(60	)	$	(591	)	$	(594	)	$	(403	)	$	(191	)

(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.

5

EXELON CORPORATION

Consolidated Balance Sheets

(unaudited) (in millions)

	December 31, 2017			December 31, 2016
Assets
Current assets
Cash and cash equivalents	$	898		$	635
Restricted cash and cash equivalents	207			253
Deposit with IRS	—			1,250
Accounts receivable, net
Customer	4,401			4,158
Other	1,132			1,201
Mark-to-market derivative assets	976			917
Unamortized energy contract assets	60			88
Inventories, net
Fossil fuel and emission allowances	340			364
Materials and supplies	1,311			1,274
Regulatory assets	1,267			1,342
Other	1,242			930
Total current assets	11,834			12,412
Property, plant and equipment, net	74,202			71,555
Deferred debits and other assets
Regulatory assets	8,021			10,046
Nuclear decommissioning trust funds	13,272			11,061
Investments	640			629
Goodwill	6,677			6,677
Mark-to-market derivative assets	337			492
Unamortized energy contract assets	395			447
Pledged assets for Zion Station decommissioning	—			113
Other	1,322			1,472
Total deferred debits and other assets	30,664			30,937
Total assets	$	116,700		$	114,904
Liabilities and shareholders’ equity
Current liabilities
Short-term borrowings	$	929		$	1,267
Long-term debt due within one year	2,088			2,430
Accounts payable	3,532			3,441
Accrued expenses	1,835			3,460
Payables to affiliates	5			8
Regulatory liabilities	523			602
Mark-to-market derivative liabilities	232			282
Unamortized energy contract liabilities	231			407
Renewable energy credit obligation	352			428
PHI merger related obligation	87			151
Other	982			981
Total current liabilities	10,796			13,457
Long-term debt	32,176			31,575
Long-term debt to financing trusts	389			641
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	11,222			18,138
Asset retirement obligations	10,029			9,111
Pension obligations	3,736			4,248
Non-pension postretirement benefit obligations	2,093			1,848
Spent nuclear fuel obligation	1,147			1,024
Regulatory liabilities	9,865			4,187
Mark-to-market derivative liabilities	409			392
Unamortized energy contract liabilities	609			830
Payable for Zion Station decommissioning	—			14
Other	2,097			1,827
Total deferred credits and other liabilities	41,207			41,619
Total liabilities	84,568			87,292
Commitments and contingencies
Shareholders’ equity
Common stock	18,964			18,794
Treasury stock, at cost	(123		)	(2,327		)
Retained earnings	13,503			12,030
Accumulated other comprehensive loss, net	(2,487		)	(2,660		)
Total shareholders’ equity	29,857			25,837
Noncontrolling interests	2,275			1,775
Total equity	32,132			27,612
Total liabilities and shareholders’ equity	$	116,700		$	114,904

6

EXELON CORPORATION

Consolidated Statements of Cash Flows

(unaudited)

(in millions)

	Twelve Months Ended December 31,
	2017			2016
Cash flows from operating activities
Net income	$	3,849		$	1,204
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization	5,427			5,576
Impairments of long-lived assets, intangible assets, and losses on regulatory assets	573			306
Gain on deconsolidation of business	(213		)	—
(Gain) Loss on sales of assets	(3		)	48
Bargain purchase gain	(233		)	—
Deferred income taxes and amortization of investment tax credits	(361		)	664
Net fair value changes related to derivatives	151			24
Net realized and unrealized (gains) losses on nuclear decommissioning trust fund investments	(616		)	(229		)
Other non-cash operating activities	713			1,333
Changes in assets and liabilities:
Accounts receivable	(426		)	(432		)
Inventories	(72		)	7
Accounts payable and accrued expenses	(378		)	771
Option premiums (paid) received, net	28			(66		)
Collateral received (posted), net	(158		)	931
Income taxes	299			576
Pension and non-pension postretirement benefit contributions	(405		)	(397		)
Deposit with IRS	—			(1,250		)
Other assets and liabilities	(683		)	(621		)
Net cash flows provided by operating activities	7,492			8,445
Cash flows from investing activities
Capital expenditures	(7,584		)	(8,553		)
Proceeds from termination of direct financing lease investment	—			360
Proceeds from nuclear decommissioning trust fund sales	7,845			9,496
Investment in nuclear decommissioning trust funds	(8,113		)	(9,738		)
Acquisition of businesses, net	(208		)	(6,934		)
Proceeds from sales of long-lived assets	219			61
Change in restricted cash	(50		)	(42		)
Other investing activities	(55		)	(153		)
Net cash flows used in investing activities	(7,946		)	(15,503		)
Cash flows from financing activities
Changes in short-term borrowings	(261		)	(353		)
Proceeds from short-term borrowings with maturities greater than 90 days	621			240
Repayments on short-term borrowings with maturities greater than 90 days	(700		)	(462		)
Issuance of long-term debt	3,470			4,716
Retirement of long-term debt	(2,490		)	(1,936		)
Retirement of long-term debt to financing trust	(250		)	—
Restricted proceeds from issuance of long-term debt	(50		)	—
Redemption of preference stock	—			(190		)
Sale of noncontrolling interests	396			372
Dividends paid on common stock	(1,236		)	(1,166		)
Common stock issued from treasury	1,150			—
Proceeds from employee stock plans	150			55
Other financing activities	(83		)	(85		)
Net cash flows provided by financing activities	717			1,191
Increase (Decrease) in cash and cash equivalents	263			(5,867		)
Cash and cash equivalents at beginning of period	635			6,502
Cash and cash equivalents at end of period	$	898		$	635

7

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   December 31, 2017							Three Months Ended   December 31, 2016
	GAAP (a)			Non-GAAP Adjustments				GAAP (a)			Non-GAAP Adjustments
Operating revenues	$	8,381		$	93		(b),(d)	$	7,875		$	177		(b),(d)
Operating expenses
Purchased power and fuel	3,508			61			(b),(d),(g)	3,178			184			(b),(d),(g)
Operating and maintenance	2,395			(53		)	(e),(f),(g),(h),(i),(k),(o)	2,371			107			(e),(g),(h),(l),(m),(n)
Depreciation and amortization	1,015			(109		)	(g)	1,115			(251		)	(g)
Taxes other than income	418			2			(k)	408			—
Total operating expenses	7,336							7,072
Loss on sales of assets	—			—				(89		)	89			(g),(n)
Gain on deconsolidation of business	213			(213		)	(j)	—
Operating income	1,258							714
Other income and (deductions)
Interest expense, net	(365		)	—				(356		)	—
Other, net	331			(244		)	(c),(i)	33			37			(c),(g),(n)
Total other income and (deductions)	(34		)					(323		)
Income before income taxes	1,224							391
Income taxes	(719		)	1,110			(b),(c),(d),(e),(f),(g),(h),(i),(j),(k),(o)	136			118			(b),(c),(d),(e),(g),(h),(i),(l),(m),(n)
Equity in losses of unconsolidated affiliates	(6		)	—				(8		)	—
Net income	1,937							247
Net income attributable to noncontrolling interests and preference stock dividends	66			(40		)	(p)	43			(61		)	(p)
Net income attributable to common shareholders	$	1,871						$	204
Effective tax rate(q)(r)	(58.7		)%					34.8		%
Earnings per average common share
Basic	$	1.94						$	0.22
Diluted	$	1.94						$	0.22
Average common shares outstanding
Basic	964							925
Diluted	967							928
Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP:
Mark-to-market impact of economic hedging activities (b)				$	0.01						$	(0.05	)
Unrealized (gains) losses related to NDT fund investments (c)				(0.12		)					0.01
Amortization of commodity contract intangibles (d)				0.01							0.03
Merger and integration costs (e)				—							0.02
Long-lived asset impairments (f)				0.03							—
Plant retirements and divestitures (g)				0.07							0.10
Cost management program (h)				0.01							0.01
Reassessment of deferred income taxes (i)				(1.30		)					0.01
Gain on deconsolidation of business (j)				(0.14		)					—
Vacation policy change (k)				(0.03		)					—
Merger commitments (l)				—							0.04
Asset retirement obligation (m)				—							(0.08		)
Curtailment of Generation growth and development activities (n)				—							0.06
Change in environmental remediation liabilities (o)				0.03							—
Noncontrolling interests (p)				0.04							0.07
Total adjustments				$	(1.39	)					$	0.22

(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 impact of 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.

8

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

(f) Adjustment to exclude charges to earnings related to the PHI 2017 impairment of the District of Columbia sponsorship intangible asset.

(g) Adjustment to exclude in 2016, incremental accelerated depreciation and amortization expenses from June 2, 2016 through December 6, 2016 pursuant to the second quarter decision to early retire the Clinton and Quad Cities nuclear generation facilities, which decision was reversed in December 2016, partially offset by the reversal of certain one-time charges for materials & supplies inventory reserves and severance reserves upon Generation’s decision to continue operating the plants with the passage of the Illinois Zero Emission Standard, and in 2017, an adjustment to exclude accelerated depreciation and amortization expenses associated with Generation’s decision to early retire the Three Mile Island nuclear facility.

(h) Adjustment to exclude severance and reorganization costs related to a cost management program.

(i) Adjustment to exclude in 2016 the non-cash impact of the remeasurement of deferred income taxes as a result of changes in forecasted apportionment related to the PHI acquisition, and in 2017, the one-time non-cash impacts associated with the Tax Cuts and Jobs Act (including impacts on pension obligations).

(j) Adjustment to exclude the gain recorded upon deconsolidation of EGTP's net liabilities, which included the previously impaired assets and related debt, as a result of the November 2017 bankruptcy filing.

(k) Adjustment to exclude the reversal of previously accrued vacation expenses as a result of a change in Exelon's vacation vesting policy.

(l) Adjustment to exclude costs incurred as part of the settlement orders approving the PHI acquisition and a charge related to a 2012 CEG merger commitment.

(m) Adjustment to exclude a non-cash benefit pursuant to the annual update of the Generation nuclear decommissioning obligation related to the non-regulatory units.

(n) Adjustment to exclude the one-time recognition for a loss on sale of assets and asset impairment charges pursuant to Generation’s strategic decision in the fourth quarter of 2016 to narrow the scope and scale of its growth and development activities.

(o) Represents charges to adjust the environmental reserve associated with future remediation of the West Lake Landfill Superfund Site.

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

(q) The effective tax rate related to GAAP Net Income for the three months ended December 31, 2017 includes the impact of the Tax Cuts and Jobs Act.

(r) The effective tax rate related to Adjusted (non-GAAP) Operating Earnings is 40.8% and 38.8% for the three months ended December 31, 2017 and 2016, respectively.

9

EXELON CORPORATION

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions, except per share data)

	Twelve Months Ended   December 31, 2017							Twelve Months Ended   December 31, 2016
	GAAP (a)			Non-GAAP Adjustments				GAAP (a)			Non-GAAP Adjustments
Operating revenues	$	33,531		$	170		(b),(d)	$	31,360		$	545		(b),(d),(e)
Operating expenses
Purchased power and fuel	14,035			(72		)	(b),(d),(h)	12,640			395			(b),(d),(h)
Operating and maintenance	10,126			(686		)	(e),(g),(h),(i),(j),(l),(p),(r)	10,048			(849		)	(e),(f),(g),(h),(j),(l),(q)
Depreciation and amortization	3,828			(252		)	(d),(h)	3,936			(704		)	(e),(h)
Taxes other than income	1,731			2			(p)	1,576			(1		)	(j)
Total operating expenses	29,720							28,200
Gain (Loss) on sales of assets	3			1			(h)	(48		)	57			(h),(q)
Bargain purchase gain	233			(233		)	(n)	—			—
Gain on deconsolidation of business	213			(213		)	(o)	—			—
Operating income	4,260							3,112
Other income and (deductions)
Interest expense, net	(1,560		)	58			(g),(k),(m)	(1,536		)	153			(k)
Other, net	1,056			(638		)	(c),(i),(k)	413			(124		)	(c),(h),(k),(q)
Total other income and (deductions)	(504		)					(1,123		)
Income before income taxes	3,756							1,989
Income taxes	(125		)	1,566			(b),(c),(d),(e),(f),(g),(h),(i),(j),(k),(l),(m),(o),(p),(r)	761			538			(b),(c),(d),(e),(f),(g),(h),(i),(j),(k),(l),(q)
Equity in losses of unconsolidated affiliates	(32		)	—				(24		)	—
Net income	3,849							1,204
Net income attributable to noncontrolling interests and preference stock dividends	79			(114		)	(s)	70			(102		)	(s)
Net income attributable to common shareholders	$	3,770						$	1,134
Effective tax rate(t)(u)	(3.3		)%					38.3		%
Earnings per average common share
Basic	$	3.98						$	1.23
Diluted	$	3.97						$	1.22
Average common shares outstanding
Basic	947							924
Diluted	949							927
Effect of adjustments on earnings per average diluted common share recorded in accordance with GAAP:
Mark-to-market impact of economic hedging activities (b)				$	0.11						$	0.03
Unrealized gains related to NDT fund investments (c)				(0.34		)					(0.13		)
Amortization of commodity contract intangibles (d)				0.04							0.04
Merger and integration costs (e)				0.04							0.12
Merger commitments (f)				(0.14		)					0.47
Long-lived asset impairments (g)				0.34							0.11
Plant retirements and divestitures (h)				0.22							0.47
Reassessment of deferred income taxes (i)				(1.37		)					0.01
Cost management program (j)				0.04							0.04
Like-kind exchange tax position (k)				(0.03		)					0.21
Asset retirement obligation (l)				—							(0.08		)
Tax settlements (m)				(0.01		)					—
Bargain purchase gain (n)				(0.25		)					—
Gain on Deconsolidation of Business (o)				(0.14		)					—
Vacation policy change (p)				(0.03		)					—
Curtailment of generation growth and development activities (q)				—							0.06
Change in environmental remediation liabilities (r)				0.03							—
Noncontrolling interests (s)				0.12							0.11
Total adjustments				$	(1.37	)					$	1.46

10

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 December 31, 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.

(c) Adjustment to exclude 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.

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

(f) Adjustment to exclude costs incurred as part of the settlement orders approving the PHI acquisition, and in 2016, a charge related to a 2012 CEG merger commitment, 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 of the ExGen Texas Power, LLC (EGTP) assets and PHI District of Columbia sponsorship intangible asset.

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

(i) Adjustment to exclude in 2016 the non-cash impact of the remeasurement of deferred income taxes as a result of changes in forecasted apportionment related to the PHI acquisition, and in 2017, one-time non-cash impacts associated with remeasurements of deferred income taxes as a result of the Tax Cuts and Jobs Act (including impacts on pension obligations), changes in the Illinois and District of Columbia statutory tax rates and changes in forecasted apportionment.

(j) Adjustment to exclude severance and reorganization costs related to a cost management program.

(k) Adjustment to exclude in 2016 the recognition of a penalty and associated interest expense as a result of a tax court decision on Exelon’s like-kind exchange tax position, and in 2017, adjustments to income tax, penalties and interest expenses as a result of the finalization of the IRS tax computation related to Exelon’s like-kind exchange tax position.

(l) Adjustment to exclude a non-cash benefit pursuant to the annual update of the Generation nuclear decommissioning obligation related to the non-regulatory units.

(m) Adjustment to exclude benefits related to the favorable settlement in 2017 of certain income tax positions related to PHI's unregulated business interests that were transferred to Generation.

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

(o) Adjustment to exclude the gain recorded upon deconsolidation of EGTP's net liabilities, which included the previously impaired assets and related debt, as a result of the November 2017 bankruptcy filing.

(p) Adjustment to exclude the reversal of previously accrued vacation expenses as a result of a change in Exelon's vacation vesting policy.

(q) Adjustment to exclude the one-time recognition for a loss on sale of assets and asset impairment charges pursuant to Generation’s strategic decision in the fourth quarter of 2016 to narrow the scope and scale of its growth and development activities.

(r) Represents charges to adjust the environmental reserve associated with future remediation of the West Lake Landfill Superfund Site.

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

(t) The effective tax rate related to GAAP Net Income for the twelve months ended December 31, 2017 includes the impact of the Tax Cuts and Jobs Act.

(u) The effective tax rate related to Adjusted (non-GAAP) Operating Earnings is 36.9% and 34.4% for the twelve months ended December 31, 2017 and 2016, respectively.

11

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating

Earnings to GAAP Net Income (in millions)

Three Months Ended December 31, 2017 and 2016

(unaudited)

	Exelon Earnings per Diluted Share			Generation			ComEd				PECO				BGE				PHI (a)				Other(b)			Exelon
2016 GAAP Net Income (Loss)	$	0.22		$	(41	)	$	80			$	92			$	103			$	30			$	(60	)	$	204
2016 Adjusted (non-GAAP) Operating (Earnings) Loss Adjustments:
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $28)	(0.05		)	(44		)	—				—				—				—				—			(44		)
Unrealized Losses Related to NDT Fund Investments (net of taxes of $13) (1)	0.01			9			—				—				—				—				—			9
Amortization of Commodity Contract Intangibles (net of taxes of $16) (2)	0.03			26			—				—				—				—				—			26
Merger and Integration Costs (net of taxes of $9, $0, $1, $1, $3, $0 and $14, respectively) (3)	0.02			15			1				1				1				4				1			23
Merger Commitments (net of taxes of $9, $2, $1 and $12, respectively) (4)	0.04			40			—				—				—				8				(10		)	38
Long-Lived Asset Impairments (net of taxes of $1) (5)	—			—			—				—				—				—				(1		)	(1		)
Plant Retirements and Divestitures (net of taxes of $59) (6)	0.10			94			—				—				—				—				—			94
Cost Management Program (net of taxes of $3, $1, $1 and $5, respectively) (7)	0.01			6			—				1				1				—				—			8
Reassessment of Deferred Income Taxes (entire amount represents tax expense) (8)	0.01			14			—				—				—				—				(4		)	10
Asset Retirement Obligation (net of taxes of $14) (9)	(0.08		)	(75		)	—				—				—				—				—			(75		)
Curtailment of Generation Growth and Development Activities (net of taxes of $35) (10)	0.06			57			—				—				—				—				—			57
Noncontrolling Interests (net of taxes of $1) (11)	0.07			61			—				—				—				—				—			61
2016 Adjusted (non-GAAP) Operating Earnings (Loss)	0.44			162			81				94				105				42				(74		)	410
Year Over Year Effects on Earnings:
ComEd, PECO, BGE and PHI Margins:
Weather	0.02			—			—			(c)	13				—			(c)	4			(c)	—			17
Load	—			—			4			(c)	(5		)		—			(c)	(1		)	(c)	—			(2		)
Other Energy Delivery (15)	0.04			—			(1		)	(d)	1			(d)	13			(d)	30			(d)	—			43
Generation Energy Margins, Excluding Mark-to-Market:
Nuclear Volume (16)	0.04			37			—				—				—				—				—			37
Nuclear Fuel Cost (17)	—			—			—				—				—				—				—			—
Capacity Pricing (18)	0.05			49			—				—				—				—				—			49
Zero Emission Credit Revenue (19)	0.08			74			—				—				—				—				—			74
Market and Portfolio Conditions (20)	(0.09		)	(83		)	—				—				—				—				—			(83		)
Operating and Maintenance Expense:
Labor, Contracting and Materials (21)	0.04			13			18				(1		)		6				(1		)		—			35
Planned Nuclear Refueling Outages (22)	—			(4		)	—				—				—				—				—			(4		)
Pension and Non-Pension Postretirement Benefits (23)	—			(4		)	(1		)		—				1				2				(1		)	(3		)
Other Operating and Maintenance (24)	0.05			25			33				(3		)		(28		)		8				19			54
Depreciation and Amortization Expense (25)	(0.03		)	(3		)	(11		)		(2		)		(6		)		(2		)		(1		)	(25		)
Interest Expense, Net	—			1			—				(2		)		1				(1		)		(2		)	(3		)
Income Taxes (26)	(0.04		)	10			(1		)		(1		)		(7		)		(32		)		(4		)	(35		)
Equity in Earnings of Unconsolidated Affiliates	—			1			—				—				—				—				—			1
Noncontrolling Interests (27)	(0.03		)	(27		)	—				—				—				—				—			(27		)
Other	—			1			1				1				(3		)		(1		)		(1		)	(2		)
Share Differential (28)	(0.02		)	—			—				—				—				—				—			—
2017 Adjusted (non-GAAP) Operating Earnings (Loss)	0.55			252			123				95				82				48				(64		)	536
2017 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $6, $1 and $7, respectively)	(0.01		)	(9		)	—				—				—				—				1			(8		)
Unrealized Gains Related to NDT Fund Investments (net of taxes of $67) (1)	0.12			108			—				—				—				—				—			108
Amortization of Commodity Contract Intangibles (net of taxes of $5) (2)	(0.01		)	(8		)	—				—				—				—				—			(8		)
Merger and Integration Costs (net of taxes of $0, $1, $0 and $1, respectively) (3)	—			(1		)	—				—				(1		)		—				1			(1		)
Long-Lived Asset Impairments (net of taxes of $8, $9, $1 and $16, respectively) (5)	(0.03		)	(12		)	—				—				—				(16		)		(1		)	(29		)
Plant Retirements and Divestitures (net of taxes of $45) (6)	(0.07		)	(70		)	—				—				—				—				—			(70		)
Cost Management Program (net of taxes of $5, $1, $0 and $6, respectively) (7)	(0.01		)	(8		)	—				(1		)		(1		)		—				—			(10		)
Reassessment of Deferred Income Taxes (entire amount represents tax expense) (8)	1.30			1,874			(3		)		12				(5		)		(33		)		(588		)	1,257
Gain on Deconsolidation of Business (net of taxes of $83) (12)	0.14			130			—				—				—				—				—			130
Vacation Policy Change (net of taxes of $16, $1, $1, $3 and $21, respectively) (13)	0.03			26			—				1				1				5				—			33
Change in Environmental Remediation Liabilities (net of taxes of $17) (14)	(0.03		)	(27		)	—				—				—				—				—			(27		)
Noncontrolling Interests (net of taxes of $8) (11)	(0.04		)	(40		)	—				—				—				—				—			(40		)
2017 GAAP Net Income (Loss)	$	1.94		$	2,215		$	120			$	107			$	76			$	4			$	(651	)	$	1,871

12

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 39.0 percent to 41.0 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 49.5 percent and 76.2 percent for the three months ended December 31, 2017 and 2016, respectively.

(a) PHI consolidated results include 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) For BGE, Pepco and DPL Maryland and beginning in 2017 for ComEd, customer rates are adjusted to eliminate the impacts of weather and customer usage 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 and losses 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, in 2016, the Integrys and ConEdison Solutions acquisitions, and in 2017, the ConEdison Solutions and FitzPatrick acquisitions.

(3) Primarily 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 and FitzPatrick acquisitions.

(4) Represents costs incurred as part of the settlement orders approving the PHI acquisition and a charge related to a 2012 CEG merger commitment.

(5) Primarily reflects charges to earnings related to the PHI 2017 impairment of the District of Columbia sponsorship intangible asset.

(6) In 2016, primarily reflects incremental accelerated depreciation and amortization expenses from June 2, 2016 through December 6, 2016 pursuant to the second quarter decision to early retire the Clinton and Quad Cities nuclear generation facilities, which decision was reversed in December 2016, partially offset by the reversal of certain one-time charges for materials & supplies inventory reserves and severance reserves upon Generation’s decision to continue operating the plants with the passage of the Illinois Zero Emission Standard. In 2017, primarily reflects accelerated depreciation and amortization expenses associated with Generation’s decision to early retire the Three Mile Island nuclear facility.

(7) Represents severance and reorganization costs related to a cost management program.

(8) Reflects in 2016 the non-cash impact of the remeasurement of deferred income taxes as a result of changes in forecasted apportionment related to the PHI acquisition, and in 2017, the one-time non-cash impacts associated with the Tax Cuts and Jobs Act (including impacts on pension obligations contained within Other).

(9) Reflects a non-cash benefit pursuant to the annual update of the Generation nuclear decommissioning obligation related to the non-regulatory units.

(10) Reflects the one-time recognition for a loss on sale of assets and asset impairment charges pursuant to Generation’s strategic decision in the fourth quarter of 2016 to narrow the scope and scale of its growth and development activities.

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

(12) Represents the gain recorded upon deconsolidation of EGTP's net liabilities, which included the previously impaired assets and related debt, as a result of the November 2017 bankruptcy filing.

(13) Represents the reversal of previously accrued vacation expenses as a result of a change in Exelon's vacation vesting policy.

(14) Represents charges to adjust the environmental reserve associated with future remediation of the West Lake Landfill Superfund Site.

(15) For ComEd, primarily reflects lower revenues resulting from the change to defer and recover over time energy efficiency costs pursuant to the Illinois Future Energy Jobs Act, almost entirely offset by 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.

(16) Primarily reflects the acquisition of the FitzPatrick nuclear facility and increased nuclear output.

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

(18) Primarily reflects increased capacity prices in the New England, Midwest and Mid-Atlantic regions.

(19) Reflects the impact of the New York Clean Energy Standard.

(20) Primarily reflects lower realized energy prices and the conclusion of the Ginna Reliability Support Services Agreement, partially offset by the addition of two combined-cycle gas turbines in Texas.

(21) Primarily reflects decreased variable compensation costs across the operating companies, partially offset at Generation by increased costs related to the acquisition of the FitzPatrick nuclear facility.

(22) Primarily reflects the impact of increased refueling outage costs given an increased scope of outage activities, despite decreased outage days excluding Salem.

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

(24) For Generation, primarily reflects the impact of an increased NEIL insurance credit. For ComEd, primarily reflects the change to defer and recover over time energy efficiency costs pursuant to the Illinois Future Energy Jobs Act. For BGE, primarily reflects the favorable 2016 settlement of the Baltimore City conduit fee dispute and an increase in uncollectible accounts expense.

(25) For Generation, reflects increased depreciation for the addition of two combined-cycle gas turbines in Texas, partially offset by the absence of depreciation related to EGTP assets. Additionally, primarily reflects increased depreciation from ongoing capital expenditures across all operating companies.

(26) For Generation, primarily reflects the favorable change in one-time tax adjustments. Additionally, primarily reflects 2017 impairments at ComEd, BGE, and PHI of certain transmission-related income tax regulatory assets.

(27) Reflects elimination from Generation’s results of activity attributable to noncontrolling interests, primarily for CENG and the Renewables Joint Venture.

(28) 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.

13

EXELON CORPORATION

Reconciliation of Adjusted (non-GAAP) Operating

Earnings to GAAP Net Income (in millions)

Twelve Months Ended December 31, 2017 and 2016

(unaudited)

	Exelon Earnings per Diluted Share			Generation			ComEd				PECO				BGE				PHI (a)				Other (b)			Exelon (a)
2016 GAAP Net Income (Loss)	$	1.22		$	496		$	378			$	438			$	286			$	(61	)		$	(403	)	$	1,134
2016 Adjusted (non-GAAP) Operating (Earnings) Loss Adjustments:
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $18)	0.03			24			—				—				—				—				—			24
Unrealized Gains Related to NDT Fund Investments (net of taxes of $77) (1)	(0.13		)	(118		)	—				—				—				—				—			(118		)
Amortization of Commodity Contract Intangibles (net of taxes of $22) (2)	0.04			35			—				—				—				—				—			35
Merger and Integration Costs (net of taxes of $22, $2, $2, $28, $0, and $50, respectively) (3)	0.12			35			(3		)		3				—				42				37			114
Merger Commitments (net of taxes of $10, $77, $39 and $126, respectively) (4)	0.47			42			—				—				—				247				148			437
Long-Lived Asset Impairments (net of taxes of $68) (5)	0.11			103			—				—				—				—				—			103
Plant Retirements and Divestitures (net of taxes of $273) (6)	0.47			432			—				—				—				—				—			432
Reassessment of Deferred Income Taxes (entire amount represents tax expense) (7)	0.01			20			—				—				—				—				(10		)	10
Cost Management Program (net of taxes of $17, $2, $2 and $21, respectively) (8)	0.04			28			—				3				3				—				—			34
Like-Kind Exchange Tax Position (net of taxes of $42, $19 and $61, respectively) (9)	0.21			—			149				—				—				—				50			199
Asset Retirement Obligation (net of taxes of $13) (10)	(0.08		)	(75		)	—				—				—				—				—			(75		)
Curtailment of Generation Growth and Development Activities (net of taxes of $35) (11)	0.06			57			—				—				—				—				—			57
Noncontrolling Interests (net of taxes of $9) (12)	0.11			102			—				—				—				—				—			102
2016 Adjusted (non-GAAP) Operating Earnings (Loss)	2.68			1,181			524				444				289				228				(178		)	2,488
Year Over Year Effects on Earnings:
ComEd, PECO, BGE and PHI Margins:
Weather	(0.05		)	—			(21		)	(c)	(14		)		—			(c)	(8		)	(c)	—			(43		)
Load	(0.01		)	—			(3		)	(c)	(9		)		—			(c)	3			(c)	—			(9		)
Other Energy Delivery (18)	0.64			—			88			(d)	(4		)	(d)	62			(d)	462			(d)	—			608
Generation Energy Margins, Excluding Mark-to-Market:
Nuclear Volume (19)	0.11			106			—				—				—				—				—			106
Nuclear Fuel Cost (20)	0.01			12			—				—				—				—				—			12
Capacity Pricing (21)	0.07			64			—				—				—				—				—			64
Zero Emission Credit Revenue (22)	0.20			192			—				—				—				—				—			192
Market and Portfolio Conditions (23)	(0.43		)	(412		)	—				—				—				—				—			(412		)
Operating and Maintenance Expense:
Labor, Contracting and Materials (24)	(0.10		)	(32		)	24				(10		)		7				(85		)		—			(96		)
Planned Nuclear Refueling Outages (25)	(0.07		)	(69		)	—				—				—				—				—			(69		)
Pension and Non-Pension Postretirement Benefits (26)	(0.01		)	(6		)	(2		)		2				2				(4		)		(2		)	(10		)
Other Operating and Maintenance (27)	0.03			(12		)	38				11				7				(54		)		37			27
Depreciation and Amortization Expense (28)	(0.22		)	(19		)	(45		)		(9		)		(30		)		(95		)		(7		)	(205		)
Interest Expense, Net (29)	(0.08		)	(27		)	6				(2		)		(2		)		(29		)		(20		)	(74		)
Income Taxes (30)	(0.06		)	(16		)	(12		)		12				(17		)		(27		)		—			(60		)
Equity in Earnings of Unconsolidated Affiliates	(0.01		)	(5		)	—				—				—				—				—			(5		)
Noncontrolling Interests (31)	—			(2		)	—				—				—				—				—			(2		)
Other (32)	(0.04		)	18			(5		)		6				—				(53		)		(7		)	(41		)
Share Differential (33)	(0.06		)	—			—				—				—				—				—			—
2017 Adjusted (non-GAAP) Operating Earnings (Loss)	2.60			973			592				427				318				338				(177		)	2,471
2017 Adjusted (non-GAAP) Operating Earnings (Loss) Adjustments:
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $66, $2 and $68, respectively)	(0.11		)	(109		)	—				—				—				—				2			(107		)
Unrealized Gains Related to NDT Fund Investments (net of taxes of $204) (1)	0.34			318			—				—				—				—				—			318
Amortization of Commodity Contract Intangibles (net of taxes of $22) (2)	(0.04		)	(34		)	—				—				—				—				—			(34		)
Merger and Integration Costs (net of taxes of $27, $0, $2, $2, $7, $1 and $25, respectively) (3)	(0.04		)	(44		)	(1		)		(2		)		(2		)		10				(1		)	(40		)
Merger Commitments (net of taxes of $18, $52, $67 and $137, respectively) (4)	0.14			18			—				—				—				59				60			137
Long-Lived Asset Impairments (net of taxes of $194, $9, $1 and $204, respectively) (5)	(0.34		)	(306		)	—				—				—				(16		)		1			(321		)
Plant Retirements and Divestitures (net of taxes of $133, $1 and $134, respectively) (6)	(0.22		)	(208		)	—				—				—				—				1			(207		)
Reassessment of Deferred Income Taxes (entire amount represents tax expense) (7)	1.37			1,856			(1		)		12				(5		)		(34		)		(529		)	1,299
Cost Management Program (net of taxes of $15, $3, $3 and $21, respectively) (8)	(0.04		)	(25		)	—				(4		)		(5		)		—				—			(34		)
Like-Kind Exchange Tax Position (net of taxes of $9, $75 and $66, respectively) (9)	0.03			—			(23		)		—				—				—				49			26
Asset Retirement Obligation (net of taxes of $1) (10)	—			2			—				—				—				—				—			2
Tax Settlements (net of taxes of $1) (13)	0.01			5			—				—				—				—				—			5
Bargain Purchase Gain (net of taxes of $0) (14)	0.25			233			—				—				—				—				—			233
Gain on Deconsolidation of Business (net of taxes of $83) (15)	0.14			130			—				—				—				—				—			130
Vacation Policy Change (net of taxes of $16, $1, $1, $3 and $21, respectively) (16)	0.03			26			—				1				1				5				—			33
Change in Environmental Remediation Liabilities (net of taxes of $17) (17)	(0.03		)	(27		)	—				—				—				—				—			(27		)
Noncontrolling Interests (net of taxes of $24) (12)	(0.12		)	(114		)	—				—				—				—				—			(114		)
2017 GAAP Net Income (Loss)	$	3.97		$	2,694		$	567			$	434			$	307			$	362			$	(594	)	$	3,770

14

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 39.0 percent to 41.0 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 47.4 percent and 48.7 percent for the twelve months ended December 31, 2017 and 2016, respectively.

(a) For the twelve months ended December 31, 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 include 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) For BGE, Pepco and DPL Maryland and beginning in 2017 for ComEd, customer rates are adjusted to eliminate the impacts of weather and customer usage 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, in 2016, the Integrys and ConEdison Solutions acquisitions, and in 2017, the ConEdison Solutions and FitzPatrick acquisitions.

(3) Primarily 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 and FitzPatrick acquisitions, partially offset in 2016 at ComEd, and in 2017 at PHI, by the anticipated recovery of previously incurred PHI acquisition costs.

(4) Represents costs incurred as part of the settlement orders approving the PHI acquisition, and in 2016, a charge related to a 2012 CEG merger commitment, 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 of the ExGen Texas Power, LLC (EGTP) assets and PHI District of Columbia sponsorship intangible asset.

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

(7) Reflects in 2016 the non-cash impact of the remeasurement of deferred income taxes as a result of changes in forecasted apportionment related to the PHI acquisition, and in 2017, one-time non-cash impacts associated with remeasurements of deferred income taxes as a result of the Tax Cuts and Jobs Act (including impacts on pension obligations contained within Other), changes in the Illinois and District of Columbia statutory tax rates and changes in forecasted apportionment.

(8) Represents severance and reorganization costs related to a cost management program.

(9) Represents in 2016 the recognition of a penalty and associated interest expense as a result of a tax court decision on Exelon’s like-kind exchange tax position, and in 2017, adjustments to income tax, penalties and interest expenses as a result of the finalization of the IRS tax computation related to Exelon’s like-kind exchange tax position.

(10) Reflects a non-cash benefit pursuant to the annual update of the Generation nuclear decommissioning obligation related to the non-regulatory units.

(11) Reflects the one-time recognition for a loss on sale of assets and asset impairment charges pursuant to Generation’s strategic decision in the fourth quarter of 2016 to narrow the scope and scale of its growth and development activities.

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

(13) Reflects benefits related to the favorable settlement in 2017 of certain income tax positions related to PHI's unregulated business interests that were transferred to Generation.

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

(15) Represents the gain recorded upon deconsolidation of EGTP's net liabilities, which included the previously impaired assets and related debt, as a result of the November 2017 bankruptcy filing.

(16) Represents the reversal of previously accrued vacation expenses as a result of a change in Exelon's vacation vesting policy.

(17) Represents charges to adjust the environmental reserve associated with future remediation of the West Lake Landfill Superfund Site.

(18) For ComEd, primarily reflects increased 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), partially offset by lower revenues resulting from the change to defer and recover over time energy efficiency costs pursuant to the Illinois Future Energy Jobs Act. For BGE and PHI, primarily reflects increased revenue as a result of rate increases.

(19) Primarily reflects the acquisition of the FitzPatrick nuclear facility.

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

(21) Primarily reflects increased capacity prices in the New England region, partially offset by a decrease in January through May capacity prices in the Mid-Atlantic region.

(22) Reflects the impact of the New York Clean Energy Standard.

(23) Primarily reflects lower realized energy prices, the impacts of lower load volumes delivered due to mild weather in the third quarter 2017, the conclusion of the Ginna Reliability Support Services Agreement and the impact of declining natural gas prices on Generation’s natural gas portfolio, partially offset by the addition of two combined-cycle gas turbines in Texas.

(24) For Generation, primarily reflects increased costs related to the acquisition of the FitzPatrick nuclear facility. Additionally, reflects decreased variable compensation costs across the operating companies.

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

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

15

(27) For Generation, primarily reflects costs related to the acquisition of FitzPatrick, partially offset by the impact of an increased NEIL insurance credit. For ComEd, primarily reflects the change to defer and recover over time energy efficiency costs pursuant to the Illinois Future Energy Jobs Act. For BGE, primarily reflects certain disallowances contained in 2016 rate case orders and decreased storm costs in the BGE service territory, partially offset by the favorable 2016 settlement of the Baltimore City conduit fee dispute.

(28) For Generation, reflects increased depreciation for the addition of two combined-cycle gas turbines in Texas, offset by the absence of depreciation related to the EGTP assets. For BGE, primarily reflects increased amortization due to the 2016 initiation of cost recovery of the AMI programs. Additionally, primarily reflects increased depreciation from ongoing capital expenditures across all operating companies.

(29) For Generation, primarily reflects the impact of project in-service dates on the capitalization of interest. 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.

(30) For Generation, primarily reflects the unfavorable change in one-time tax adjustments. For PECO, primarily reflects an increase in the repairs tax deduction. Additionally, primarily reflects 2016 favorable adjustments at ComEd and BGE and 2017 impairments at ComEd, BGE, and PHI of certain transmission-related income tax regulatory assets.

(31) Reflects elimination from Generation’s results of activity attributable to noncontrolling interests, primarily for CENG and the Renewables Joint Venture.

(32) For Generation, primarily reflects higher realized NDT fund gains, partially offset by increased real estate taxes as a result of the FitzPatrick acquisition.

(33) 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

EXELON CORPORATION

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions)

	Generation
	Three Months Ended   December 31, 2017							Three Months Ended   December 31, 2016
	GAAP (a)			Non-GAAP Adjustments				GAAP (a)			Non-GAAP Adjustments
Operating revenues	$	4,654		$	93		(b),(d)	$	4,388		$	177		(b),(d)
Operating expenses
Purchased power and fuel	2,403			61			(b),(d),(h)	2,221			184			(b),(h)
Operating and maintenance	1,421			(38		)	(e),(g),(j),(h),(o),(p)	1,308			123			(e),(f),(h),(j),(k),(r)
Depreciation and amortization	412			(109		)	(h)	550			(251		)	(h)
Taxes other than income	130			2			(o)	126			—
Total operating expenses	4,366							4,205
Loss on sales of assets	—			—				(89		)	89			(h),(r)
Gain on deconsolidation of business	213			(213		)	(n)	—			—
Operating income	501							94
Other income and (deductions)
Interest expense, net	(98		)	—				(92		)	—
Other, net	299			(244		)	(c),(i)	6			37			(c)
Total other income and (deductions)	201							(86		)
Income before income taxes	702							8
Income taxes	(1,585		)	1,724			(b),(c),(d),(e),(g),(h),(i),(j),(n),(o),(p)	(3		)	105			(b),(c),(d),(e),(f),(h),(i),(j),(k),(r)
Equity in losses of unconsolidated affiliates	(7		)	—				(9		)	—
Net income	2,280							2
Net income attributable to noncontrolling interests	65			(40		)	(q)	43			(61		)	(q)
Net income (loss) attributable to membership interest	$	2,215						$	(41	)
	Twelve Months Ended   December 31, 2017							Twelve Months Ended   December 31, 2016
	GAAP (a)			Non-GAAP Adjustments				GAAP (a)			Non-GAAP Adjustments
Operating revenues	$	18,466		$	170		(b),(d)	$	17,751		$	553		(b),(d)
Operating expenses
Purchased power and fuel	9,690			(72		)	(b),(d),(h)	8,830			395			(b),(d),(h)
Operating and maintenance	6,291			(669		)	(e),(g),(h),(j),(k),(o),(p)	5,641			(213		)	(e),(f),(g),(h),(j),(k),(r)
Depreciation and amortization	1,457			(252		)	(d),(h)	1,879			(704		)	(e),(h)
Taxes other than income	555			2			(o)	506			(1		)	(j)
Total operating expenses	17,993							16,856
Gain (Loss) on sales of assets	2			1			(h)	(59		)	57			(h),(r)
Bargain purchase gain	233			(233		)	(m)	—			—
Gain on deconsolidation of business	213			(213		)	(n)	—			—
Operating income	921							836
Other income and (deductions)
Interest expense, net	(440		)	17			(g),(l)	(364		)	—
Other, net	948			(636		)	(c),(i)	401			(230		)	(c)
Total other income and (deductions)	508							37
Income before income taxes	1,429							873
Income taxes	(1,375		)	1,932			(b),(c),(d),(e),(f),(g),(h),(i),(j),(k),(l),(n),(o),(p)	290			320			(b),(c),(d),(e),(f),(g),(h),(i),(j),(k),(r)
Equity in losses of unconsolidated affiliates	(33		)	—				(25		)	—
Net income	2,771							558
Net income attributable to noncontrolling interests	77			(114		)	(q)	62			(102		)	(q)
Net income attributable to membership interest	$	2,694						$	496

17

(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 impact of 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, in 2016, the Integrys and ConEdison Solutions acquisitions, 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 and FitzPatrick acquisitions.

(f) Adjustment to exclude in 2016 a charge related to a 2012 CEG merger commitment, and in 2017, a decrease in reserves for uncertain tax positions related to the deductibility of certain merger commitments associated with the 2012 CEG acquisition.

(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 of the ExGen Texas Power, LLC assets.

(h) Adjustment to exclude for the three months ended December 31, 2016, incremental accelerated depreciation and amortization expenses from June 2, 2016 through December 6, 2016 pursuant to the second quarter decision to early retire the Clinton and Quad Cities nuclear generation facilities, which decision was reversed in December 2016, partially offset by the reversal of certain one-time charges for materials & supplies inventory reserves and severance reserves upon Generation’s decision to continue operating the plants with the passage of the Illinois Zero Emission Standard; and for the twelve months ended December 31, 2016, accelerated depreciation and amortization expenses through December 2016 and construction work in progress impairments associated with Generation’s previous decision to early retire the Clinton and Quad Cities nuclear facilities, partially offset by a gain associated with Generation’s sale of the New Boston generating site. Additionally, reflects an adjustment to exclude in 2017 accelerated depreciation and amortization expenses, increases to materials and supplies inventory reserves, construction work in progress impairments and charges for severance reserves associated with Generation’s decision to early retire the Three Mile Island nuclear facility.

(i) Adjustment to exclude in 2016 the non-cash impact of the remeasurement of deferred income taxes as a result of changes in forecasted apportionment related to the PHI acquisition, and in 2017, one-time non-cash impacts associated with remeasurements of deferred income taxes as a result of the Tax Cuts and Jobs Act, a change in the Illinois statutory tax rate and changes in forecasted apportionment.

(j) Adjustment to exclude severance and reorganization costs related to a cost management program.

(k) Adjustment to exclude a non-cash benefit pursuant to the annual update of the Generation nuclear decommissioning obligation related to the non-regulatory units.

(l) Adjustment to exclude benefits related to the favorable settlement in 2017 of certain income tax positions related to PHI's unregulated business interests that were transferred to Generation.

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

(n) Adjustment to exclude the gain recorded upon deconsolidation of EGTP's net liabilities, which included the previously impaired assets and related debt, as a result of the November 2017 bankruptcy filing.

(o) Adjustment to exclude the reversal of previously accrued vacation expenses as a result of a change in Exelon's vacation vesting policy.

(p) Represents charges to adjust the environmental reserve associated with future remediation of the West Lake Landfill Superfund Site.

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

(r) Adjustment to exclude the one-time recognition for a loss on sale of assets and asset impairment charges pursuant to Generation’s strategic decision in the fourth quarter of 2016 to narrow the scope and scale of its growth and development activities.

18

EXELON CORPORATION

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions)

	ComEd
	Three Months Ended   December 31, 2017							Three Months Ended   December 31, 2016
	GAAP (a)			Non-GAAP Adjustments				GAAP (a)			Non-GAAP Adjustments
Operating revenues	$	1,309		$	—			$	1,223		$	—
Operating expenses
Purchased power and fuel	399			—				317			—
Operating and maintenance	332			—				417			(1		)	(d)
Depreciation and amortization	220			—				201			—
Taxes other than income	73			—				71			—
Total operating expenses	1,024							1,006
Gain on sales of assets	1			—				—			—
Operating income	286							217
Other income and (deductions)
Interest expense, net	(87		)	—				(87		)	—
Other, net	10			—				8			—
Total other income and (deductions)	(77		)					(79		)
Income before income taxes	209							138
Income taxes	89			(3		)	(b)	58			—
Net income	$	120						$	80
	Twelve Months Ended   December 31, 2017							Twelve Months Ended   December 31, 2016
	GAAP (a)			Non-GAAP Adjustments				GAAP (a)			Non-GAAP Adjustments
Operating revenues	$	5,536		$	—			$	5,254		$	(8	)	(d)
Operating expenses
Purchased power and fuel	1,641			—				1,458			—
Operating and maintenance	1,427			(2		)	(d)	1,530			(3		)	(d)
Depreciation and amortization	850			—				775			—
Taxes other than income	296			—				293			—
Total operating expenses	4,214							4,056
Gain on sales of assets	1			—				7			—
Operating income	1,323							1,205
Other income and (deductions)
Interest expense, net	(361		)	14			(c)	(461		)	105			(c)
Other, net	22			—				(65		)	86			(c)
Total other income and (deductions)	(339		)					(526		)
Income before income taxes	984							679
Income taxes	417			(9		)	(b),(c),(d)	301			40			(c),(d)
Net income	$	567						$	378

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

(b) Adjustment to exclude one-time non-cash impacts associated with remeasurements of deferred income taxes as a result of the Tax Cuts and Jobs Act and a change in the Illinois statutory tax rate.

(c) Adjustment to exclude in 2016 the recognition of a penalty and associated interest expense as a result of a tax court decision on Exelon's like-kind exchange tax position, and in 2017, adjustments to income tax and interest expenses as a result of the finalization of the IRS tax computation related to Exelon’s like-kind exchange tax position.

19

(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, partially offset in 2016 at ComEd by the anticipated recovery of previously incurred PHI acquisition costs.

20

EXELON CORPORATION

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions)

	PECO
	Three Months Ended   December 31, 2017							Three Months Ended   December 31, 2016
	GAAP (a)			Non-GAAP Adjustments				GAAP (a)			Non-GAAP Adjustments
Operating revenues	$	729		$	—			$	701		$	—
Operating expenses
Purchased power and fuel	250			—				238			—
Operating and maintenance	211			(1		)	(d),(e)	206			(3		)	(b),(d)
Depreciation and amortization	73			—				69			—
Taxes other than income	38			—				38			—
Total operating expenses	572							551
Operating income	157							150
Other income and (deductions)
Interest expense, net	(33		)	—				(31		)	—
Other, net	3			—				2			—
Total other income and (deductions)	(30		)					(29		)
Income before income taxes	127							121
Income taxes	20			13			(c),(d),(e)	29			1			(b),(d)
Net income	$	107						$	92
	Twelve Months Ended   December 31, 2017							Twelve Months Ended   December 31, 2016
	GAAP (a)			Non-GAAP Adjustments				GAAP (a)			Non-GAAP Adjustments
Operating revenues	$	2,870		$	—			$	2,994		$	—
Operating expenses
Purchased power and fuel	969			—				1,047			—
Operating and maintenance	806			(9		)	(b),(d),(e)	811			(10		)	(b),(d)
Depreciation and amortization	286			—				270			—
Taxes other than income	154			—				164			—
Total operating expenses	2,215							2,292
Operating income	655							702
Other income and (deductions)
Interest expense, net	(126		)	—				(123		)	—
Other, net	9			—				8			—
Total other income and (deductions)	(117		)					(115		)
Income before income taxes	538							587
Income taxes	104			16			(b),(c),(d),(e)	149			4			(b),(d)
Net income	$	434						$	438

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

(b) 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.

(c) Adjustment to exclude one-time non-cash impacts associated with remeasurements of deferred income taxes as a result of the Tax Cuts and Jobs Act.

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

(e) Adjustment to exclude the reversal of previously accrued vacation expenses as a result of a change in Exelon's vacation vesting policy.

21

EXELON CORPORATION

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions)

	BGE
	Three Months Ended   December 31, 2017							Three Months Ended   December 31, 2016
	GAAP (a)			Non-GAAP Adjustments				GAAP (a)			Non-GAAP Adjustments
Operating revenues	$	813		$	—			$	812		$	—
Operating expenses
Purchased power and fuel	280			—				300			—
Operating and maintenance	184			(2		)	(b),(d),(e)	149			(3		)	(b),(d)
Depreciation and amortization	125			—				115			—
Taxes other than income	61			—				58			—
Total operating expenses	650							622
Operating income	163							190
Other income and (deductions)
Interest expense, net	(25		)	—				(27		)	—
Other, net	4			—				5			—
Total other income and (deductions)	(21		)					(22		)
Income before income taxes	142							168
Income taxes	66			(4		)	(b),(c),(d),(e)	65			1			(b),(d)
Net income attributable to common shareholder	$	76						$	103
	Twelve Months Ended   December 31, 2017							Twelve Months Ended   December 31, 2016
	GAAP (a)			Non-GAAP Adjustments				GAAP (a)			Non-GAAP Adjustments
Operating revenues	$	3,176		$	—			$	3,233		$	—
Operating expenses
Purchased power and fuel	1,133			—				1,294			—
Operating and maintenance	716			(10		)	(b),(d),(e)	737			(5		)	(b),(d)
Depreciation and amortization	473			—				423			—
Taxes other than income	240			—				229			—
Total operating expenses	2,562							2,683
Operating income	614							550
Other income and (deductions)
Interest expense, net	(105		)	—				(103		)	—
Other, net	16			—				21			—
Total other income and (deductions)	(89		)					(82		)
Income before income taxes	525							468
Income taxes	218			(1		)	(b),(c),(d),(e)	174			2			(b),(d)
Net income	307							294
Preference stock dividends	—			—				8			—
Net income attributable to common shareholder	$	307						$	286

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

(b) 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.

(c) Adjustment to exclude one-time non-cash impacts associated with remeasurements of deferred income taxes as a result of the Tax Cuts and Jobs Act.

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

(e) Adjustment to exclude the reversal of previously accrued vacation expenses as a result of a change in Exelon's vacation vesting policy.

22

EXELON CORPORATION

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions)

	PHI
	Three Months Ended   December 31, 2017							Three Months Ended   December 31, 2016
	GAAP (a)			Non-GAAP Adjustments				GAAP (a)			Non-GAAP Adjustments
Operating revenues	$	1,121		$	—			$	1,078		$	—
Operating expenses
Purchased power and fuel	398			—				410			—
Operating and maintenance	292			(12		)	(e),(f),(g)	310			(17		)	(c),(d)
Depreciation and amortization	164			—				160			—
Taxes other than income	108			—				107			—
Total operating expenses	962							987
Loss on sales of assets	—			—				(1		)	—
Operating income	159							90
Other income and (deductions)
Interest expense, net	(62		)	—				(61		)	—
Other, net	15			—				13			—
Total other income and (deductions)	(47		)					(48		)
Income before income taxes	112							42
Income taxes	108			(33		)	(e),(f),(g)	12			5			(c),(d)
Net income	$	4						$	30
	Twelve Months Ended   December 31, 2017							Twelve Months Ended   December 31, 2016 (b)
	GAAP (a)			Non-GAAP Adjustments				GAAP (a)			Non-GAAP Adjustments
Operating revenues	$	4,679		$	—			$	3,643		$	—
Operating expenses
Purchased power and fuel	1,716			—				1,447			—
Operating and maintenance	1,068			13			(c),(d),(e),(f),(g)	1,233			(392		)	(c),(d)
Depreciation and amortization	675			—				515			—
Taxes other than income	452			—				354			—
Total operating expenses	3,911							3,549
Gain (loss) on sales of assets	1			—				(1		)	—
Operating income (loss)	769							93
Other income and (deductions)
Interest expense, net	(245		)	—				(195		)	—
Other, net	54			—				44			—
Total other income and (deductions)	(191		)					(151		)
Income (Loss) before income taxes	578							(58		)
Income taxes	217			10			(c),(d),(e),(f),(g)	3			103			(c),(d)
Equity in earnings of unconsolidated affiliates	1							—
Net income (loss)	$	362						$	(61	)

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

(b) For the twelve months ended December 31, 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 include Potomac Electric Power Company, Delmarva Power & Light Company, and Atlantic City Electric Company.

23

(c) 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, partially offset in 2017 by the anticipated recovery of previously incurred PHI acquisition costs.

(d) 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.

(e) Adjustment to exclude the impairment of the District of Columbia sponsorship intangible asset.

(f) Adjustment to exclude to exclude one-time non-cash impacts associated with remeasurements of deferred income taxes as a result of the Tax Cuts and Jobs Act.

(g) Adjustment to exclude the reversal of previously accrued vacation expenses as a result of a change in Exelon's vacation vesting policy.

24

EXELON CORPORATION

GAAP Consolidated Statements of Operations and

Adjusted (non-GAAP) Operating Earnings Reconciling Adjustments

(unaudited)

(in millions)

	Other (a)
	Three Months Ended   December 31, 2017							Three Months Ended   December 31, 2016
	GAAP (b)			Non-GAAP Adjustments				GAAP (b)			Non-GAAP Adjustments
Operating revenues	$	(245	)	$	—			$	(327	)	$	—
Operating expenses
Purchased power and fuel	(222		)	—				(308		)	—
Operating and maintenance	(45		)	—				(19		)	8			(d),(e)
Depreciation and amortization	21			—				20			—
Taxes other than income	8			—				8			—
Total operating expenses	(238		)					(299		)
(Loss) Gain on sales of assets	(1		)	—				1			—
Operating loss	(8		)					(27		)
Other income and (deductions)
Interest expense, net	(60		)	—				(58		)	—
Other, net	—			—				(1		)	—
Total other income and (deductions)	(60		)					(59		)
Loss before income taxes	(68		)					(86		)
Income taxes	583			(587		)	(c),(d),(f),(h)	(25		)	6			(d),(e),(f),(h)
Equity in earnings of unconsolidated affiliates	1			—				1			—
Net loss	(650		)					(60		)
Net income attributable to noncontrolling interests and preference stock dividends	1			—				—			—
Net loss attributable to common shareholders	$	(651	)					$	(60	)
	Twelve Months Ended   December 31, 2017							Twelve Months Ended   December 31, 2016
	GAAP (b)			Non-GAAP Adjustments				GAAP (b)			Non-GAAP Adjustments
Operating revenues	$	(1,196	)	$	—			$	(1,515	)	$	—
Operating expenses
Purchased power and fuel	(1,114		)	—				(1,436		)	—
Operating and maintenance	(182		)	(9		)	(d),(e)	96			(226		)	(d),(e)
Depreciation and amortization	87			—				74			—
Taxes other than income	34			—				30			—
Total operating expenses	(1,175		)					(1,236		)
(Loss) Gain on sales of assets	(1		)	—				5			—
Operating loss	(22		)					(274		)
Other income and (deductions)
Interest expense, net	(283		)	27			(g)	(290		)	48			(g)
Other, net	7			(2		)	(g)	4			20			(g)
Total other income and (deductions)	(276		)					(286		)
Loss before income taxes	(298		)					(560		)
Income taxes	294			(382		)	(c),(d),(e),(f),(g),(h)	(156		)	69			(d),(e),(f),(g)
Equity in earnings of unconsolidated affiliates	—			—				1			—
Net income (loss)	(592		)					(403		)
Net income attributable to noncontrolling interests and preference stock dividends	2			—				—			—
Net loss attributable to common shareholders	$	(594	)					$	(403	)

(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 accounting principles generally accepted in the United States (GAAP).

25

(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 in 2016 the non-cash impact of the remeasurement of deferred income taxes as a result of changes in forecasted apportionment related to the PHI acquisition, and in 2017, one-time non-cash impacts associated with remeasurements of deferred income taxes as a result of the Tax Cuts and Jobs Act (including impacts on pension obligations), changes in the Illinois and District of Columbia statutory tax rates and changes in forecasted apportionment.

(g) Adjustment to exclude in 2016 the recognition of a penalty and associated interest expense as a result of a tax court decision on Exelon’s like-kind exchange tax position, and in 2017, adjustments to income tax, penalties and interest expenses as a result of the finalization of the IRS tax computation related to Exelon’s like-kind exchange tax position.

(h) Adjustment to exclude costs related to impairments at Corporate.

26

EXELON CORPORATION

Exelon Generation Statistics

	Three Months Ended
	December 31, 2017	September 30, 2017	June 30, 2017	March 31, 2017	December 31, 2016
Supply (in GWhs)
Nuclear Generation
Mid-Atlantic(a)	16,196	16,480	15,246	16,545	16,410
Midwest	23,922	24,362	22,592	22,468	23,743
New York(a)(e)	7,410	6,905	6,227	4,491	4,681
Total Nuclear Generation	47,528	47,747	44,065	43,504	44,834
Fossil and Renewables
Mid-Atlantic	459	596	899	836	442
Midwest	430	218	417	418	442
New England	1,258	1,919	1,925	2,077	1,142
New York	1	1	1	1	1
ERCOT	2,684	5,703	2,315	1,370	1,056
Other Power Regions(b)	1,213	2,149	2,084	1,423	1,935
Total Fossil and Renewables	6,045	10,586	7,641	6,125	5,018
Purchased Power
Mid-Atlantic	961	2,541	2,901	3,398	2,849
Midwest	355	217	413	388	400
New England	4,596	4,513	4,343	5,064	4,768
New York	—	—	—	28	—
ERCOT	1,622	1,199	1,871	2,655	3,189
Other Power Regions(b)	4,173	3,982	3,507	2,868	3,308
Total Purchased Power	11,707	12,452	13,035	14,401	14,514
Total Supply/Sales by Region
Mid-Atlantic(c)	17,616	19,617	19,046	20,779	19,701
Midwest(c)	24,707	24,797	23,422	23,274	24,585
New England	5,854	6,432	6,268	7,141	5,910
New York	7,411	6,906	6,228	4,520	4,682
ERCOT	4,306	6,902	4,186	4,025	4,245
Other Power Regions(b)	5,386	6,131	5,591	4,291	5,243
Total Supply/Sales by Region	65,280	70,785	64,741	64,030	64,366
	Three Months Ended
	December 31, 2017	September 30, 2017	June 30, 2017	March 31, 2017	December 31, 2016
Outage Days(d)
Refueling(e)	60	13	125	95	71
Non-refueling(e)	18	15	12	8	32
Total Outage Days	78	28	137	103	103

(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) 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) Outage days exclude Salem.

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

27

EXELON CORPORATION

Exelon Generation Statistics

Twelve Months Ended December 31, 2017 and 2016

	December 31, 2017	December 31, 2016
Supply (in GWhs)
Nuclear Generation
Mid-Atlantic(a)	64,466	63,447
Midwest	93,344	94,668
New York(a)(c)	25,033	18,684
Total Nuclear Generation	182,843	176,799
Fossil and Renewables
Mid-Atlantic	2,789	2,731
Midwest	1,482	1,488
New England	7,179	6,968
New York	3	3
ERCOT	12,072	6,785
Other Power Regions	6,869	8,179
Total Fossil and Renewables	30,394	26,154
Purchased Power
Mid-Atlantic	9,801	16,874
Midwest	1,373	2,255
New England	18,517	16,632
New York	28	—
ERCOT	7,346	10,637
Other Power Regions	14,530	13,589
Total Purchased Power	51,595	59,987
Total Supply/Sales by Region
Mid-Atlantic(b)	77,056	83,052
Midwest(b)	96,199	98,411
New England	25,696	23,600
New York	25,064	18,687
ERCOT	19,418	17,422
Other Power Regions	21,399	21,768
Total Supply/Sales by Region	264,832	262,940

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

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

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

28

EXELON CORPORATION

ComEd Statistics

Three Months Ended December 31, 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	6,128	6,052	1.3	%	(0.6	)%	$	637	$	578	10.2	%
Small Commercial & Industrial	7,698	7,527	2.3	%	2.2	%	326		310		5.2	%
Large Commercial & Industrial	6,755	6,784	(0.4	)%	(0.4	)%	109		112		(2.7	)%
Public Authorities & Electric Railroads	359	351	2.3	%	2.4	%	11		12		(8.3	)%
Total Retail	20,940	20,714	1.1	%	0.5	%	1,083		1,012		7.0	%
Other Revenue (b)							226		211		7.1	%
Total Electric Revenue (c)							$	1,309	$	1,223	7.0	%
Purchased Power							$	399	$	317	25.9	%

				% Change
Heating and Cooling Degree-Days	2017	2016	Normal	From 2016		From Normal
Heating Degree-Days	2,166	2,037	2,226	6.3	%	(2.7	)%
Cooling Degree-Days	29	27	11	7.4	%	163.6	%

Twelve Months Ended December 31, 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	26,292	27,790	(5.4	)%	(0.9	)%	$	2,746	$	$	2,597	5.7	%
Small Commercial & Industrial	31,332	31,975	(2.0	)%	(0.7	)%	1,376			1,316		4.6	%
Large Commercial & Industrial	27,467	27,842	(1.3	)%	(0.5	)%	461			462		(0.2	)%
Public Authorities & Electric Railroads	1,286	1,298	(0.9	)%	(0.3	)%	44			45		(2.2	)%
Total Retail	86,377	88,905	(2.8	)%	(0.7	)%	4,627			4,420		4.7	%
Other Revenue (b)							909			834		9.0	%
Total Electric Revenue (c)							$	5,536		$	5,254	5.4	%
Purchased Power							$	1,641		$	1,458	12.6	%

				% Change
Heating and Cooling Degree-Days	2017	2016	Normal	From 2016		From Normal
Heating Degree-Days	5,435	5,715	6,198	(4.9	)%	(12.3	)%
Cooling Degree-Days	991	1,157	893	(14.3	)%	11.0	%

Number of Electric Customers	2017	2016
Residential	3,624,372	3,595,376
Small Commercial & Industrial	378,345	374,644
Large Commercial & Industrial	1,959	2,007
Public Authorities & Electric Railroads	4,775	4,750
Total	4,009,451	3,976,777

(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 December 31, 2017 and 2016, respectively, and $15 million and $15 million for the twelve months ended December 31, 2017 and 2016, respectively.

29

EXELON CORPORATION

PECO Statistics

Three Months Ended December 31, 2017 and 2016

	Electric and Natural Gas Deliveries						Revenue (in millions)
	2017	2016	% Change		Weather- Normal % Change		2017		2016		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential	3,084	2,982	3.4	%	(3.3	)%	$	358	$	353	1.4	%
Small Commercial & Industrial	1,921	1,863	3.1	%	(1.2	)%	98		96		2.1	%
Large Commercial & Industrial	3,833	3,665	4.6	%	3.4	%	55		52		5.8	%
Public Authorities & Electric Railroads	190	218	(12.8	)%	(12.8	)%	7		7		—	%
Total Retail	9,028	8,728	3.4	%	(0.3	)%	518		508		2.0	%
Other Revenue (b)							55		52		5.8	%
Total Electric Revenue (d)							573		560		2.3	%
Natural Gas (in mmcfs)
Retail Deliveries and Sales
Retail Sales (c)	19,632	17,959	9.3	%	(2.0	)%	147		132		11.4	%
Transportation and Other	7,260	6,713	8.1	%	8.7	%	9		9		—	%
Total Natural Gas (d)	26,892	24,672	9.0	%	2.1	%	156		141		10.6	%
Total Electric and Natural Gas Revenues							$	729	$	701	4.0	%
Purchased Power and Fuel							$	250	$	238	5.0	%

				% Change
Heating and Cooling Degree-Days	2017	2016	Normal	From 2016		From Normal
Heating Degree-Days	1,512	1,425	1,629	6.1	%	(7.2	)%
Cooling Degree-Days	86	42	19	104.8	%	352.6	%

Twelve Months Ended December 31, 2017 and 2016

	Electric and Natural Gas Deliveries						Revenue (in millions)
	2017	2016	% Change		Weather- Normal % Change		2017		2016		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential	13,024	13,664	(4.7	)%	(1.8	)%	$	1,505	$	1,631	(7.7	)%
Small Commercial & Industrial	7,968	8,099	(1.6	)%	(1.1	)%	401		430		(6.7	)%
Large Commercial & Industrial	15,426	15,263	1.1	%	1.4	%	223		234		(4.7	)%
Public Authorities & Electric Railroads	809	890	(9.1	)%	(9.1	)%	30		32		(6.3	)%
Total Retail	37,227	37,916	(1.8	)%	(0.5	)%	2,159		2,327		(7.2	)%
Other Revenue (b)							216		204		5.9	%
Total Electric Revenue (d)							2,375		2,531		(6.2	)%
Natural Gas (in mmcfs)
Retail Deliveries and Sales
Retail Sales (c)	58,457	56,447	3.6	%	1.2	%	462		430		7.4	%
Transportation and Other	26,382	27,630	(4.5	)%	(2.3	)%	33		33		—	%
Total Natural Gas (d)	84,839	84,077	0.9	%	0.1	%	495		463		6.9	%
Total Electric and Natural Gas Revenues							$	2,870	$	2,994	(4.1	)%
Purchased Power and Fuel							$	969	$	1,047	(7.4	)%

				% Change
Heating and Cooling Degree-Days	2017	2016	Normal	From 2016		From Normal
Heating Degree-Days	3,949	4,041	4,603	(2.3	)%	(14.2	)%
Cooling Degree-Days	1,490	1,726	1,290	(13.7	)%	15.5	%

30

Number of Electric Customers	2017	2016	Number of Natural Gas Customers	2017	2016
Residential	1,469,916	1,456,585	Residential	477,213	472,606
Small Commercial & Industrial	151,552	150,142	Commercial & Industrial	43,892	43,668
Large Commercial & Industrial	3,112	3,096	Total Retail	521,105	516,274
Public Authorities & Electric Railroads	9,569	9,823	Transportation	771	790
Total	1,634,149	1,619,646	Total	521,876	517,064

(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 for both three months ended December 31, 2017 and 2016, respectively, and $6 million and $7 million for the twelve months ended December 31, 2017 and 2016, respectively.  Total natural gas revenue includes operating revenues from affiliates totaling less than $1 million for both three months ended December 31, 2017 and 2016 and $1 million for both twelve months ended December 31, 2017 and 2016.

31

EXELON CORPORATION

BGE Statistics

Three Months Ended December 31, 2017 and 2016

	Electric and Natural Gas Deliveries						Revenue (in millions)
	2017	2016	% Change		Weather- Normal % Change		2017		2016		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential	2,968	2,744	8.2	%	1.4	%	$	333	$	350	(4.9	)%
Small Commercial & Industrial	711	697	2.0	%	0.5	%	64		65		(1.5	)%
Large Commercial & Industrial	3,267	3,330	(1.9	)%	(0.9	)%	106		112		(5.4	)%
Public Authorities & Electric Railroads	64	67	(4.5	)%	(4.6	)%	8		9		(11.1	)%
Total Retail	7,010	6,838	2.5	%	0.1	%	511		536		(4.7	)%
Other Revenue (b)(c)							83		75		10.7	%
Total Electric Revenue							594		611		(2.8	)%
Natural Gas (in mmcfs)
Retail Deliveries and Sales (d)
Retail Sales	28,717	27,394	4.8	%	(1.4	)%	210		190		10.5	%
Transportation and Other (e)	1,152	1,898	(39.3	)%	n/a		9		11		(18.2	)%
Total Natural Gas (f)	29,869	29,292	2.0	%	(1.4	)%	219		201		9.0	%
Total Electric and Natural Gas Revenues							$	813	$	812	0.1	%
Purchased Power and Fuel							$	280	$	300	(6.7	)%

				% Change
Heating and Cooling Degree-Days	2017	2016	Normal	From 2016		From Normal
Heating Degree-Days	1,666	1,549	1,674	7.6	%	(0.5	)%
Cooling Degree-Days	63	32	25	96.9	%	152.0	%

Twelve Months Ended December 31, 2017 and 2016

	Electric and Natural Gas Deliveries						Revenue (in millions)
	2017	2016	% Change		Weather- Normal % Change		2017			2016		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential	12,094	12,740	(5.1	)%	(2.8	)%	$	1,428	$	$	1,554	(8.1	)%
Small Commercial & Industrial	2,921	3,040	(3.9	)%	(4.9	)%	266			277		(4.0	)%
Large Commercial & Industrial	13,688	13,957	(1.9	)%	(2.4	)%	450			449		0.2	%
Public Authorities & Electric Railroads	268	283	(5.3	)%	(3.0	)%	31			35		(11.4	)%
Total Retail	28,971	30,020	(3.5	)%	(2.8	)%	2,175			2,315		(6.0	)%
Other Revenue (b)(c)							314			294		6.8	%
Total Electric Revenue							2,489			2,609		(4.6	)%
Natural Gas (in mmcfs)
Retail Deliveries and Sales (d)
Retail Sales	89,337	96,808	(7.7	)%	(4.2	)%	655		$	593		10.5	%
Transportation and Other (e)	3,615	5,977	(39.5	)%	n/a		32			31		3.2	%
Total Natural Gas (f)	92,952	102,785	(9.6	)%	(4.2	)%	687			624		10.1	%
Total Electric and Natural Gas Revenues							$	3,176		$	3,233	(1.8	)%
Purchased Power and Fuel							$	1,133		$	1,294	(12.4	)%

				% Change
Heating and Cooling Degree-Days	2017	2016	Normal	From 2016		From Normal
Heating Degree-Days	4,190	4,427	4,666	(5.4	)%	(10.2	)%
Cooling Degree-Days	940	998	875	(5.8	)%	7.4	%

Number of Electric Customers	2017	2016	Number of Natural Gas Customers	2017	2016
Residential	1,160,783	1,150,096	Residential	629,690	623,647
Small Commercial & Industrial	113,594	113,230	Commercial & Industrial	44,247	44,255
Large Commercial & Industrial	12,155	12,053	Total Retail	673,937	667,902
Public Authorities & Electric Railroads	272	280	Transportation	—	—
Total	1,286,804	1,275,659	Total	673,937	667,902

32

(a) Reflects delivery volumes and revenue 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.

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

(c) Includes operating revenues from affiliates totaling $1 million for both the three months ended December 31, 2017 and 2016 and $5 million and $7 million for the twelve months ended December 31, 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 1,152 mmcfs ($6 million) and 1,898 mmcfs ($8 million) for the three months ended December 31, 2017 and 2016, respectively, and 3,615 mmcfs ($21 million) and 5,977 mmcfs ($23 million) for the twelve months ended December 31, 2017 and 2016, respectively.

(f) Includes operating revenues from affiliates totaling $4 million for both the three months ended December 31, 2017 and 2016 and $11 million and $14 million for the twelve months ended December 31, 2017 and 2016, respectively.

33

EXELON CORPORATION

Pepco Statistics

Three Months Ended December 31, 2017 and 2016

	Electric Deliveries							Revenue (in millions)
	2017		2016	% Change		Weather - Normal % Change		2017		2016		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential	1,793	1,608,000,000	1,720	4.2	%	(1.7	)%	$	212	$	209	1.4	%
Small Commercial & Industrial	304	321,000,000	335	(9.3	)%	(11.2	)%	34		34		—	%
Large Commercial & Industrial	3,682	3,592,000,000	3,669	0.4	%	(0.9	)%	202		190		6.3	%
Public Authorities & Electric Railroads	192	174,000,000	180	6.7	%	6.1	%	9		9		—	%
Total Retail	5,971		5,904	1.1	%	(1.6	)%	457		442		3.4	%
Other Revenue (b)								52		49		6.1	%
Total Electric Revenue (c)								509		491		3.7	%
Purchased Power								$	137	$	143	(4.2	)%

				% Change
Heating and Cooling Degree-Days	2017	2016	Normal	From 2016		From Normal
Heating Degree-Days	1,350	1,217	1,392	10.9	%	(3.0	)%
Cooling Degree-Days	88	64	42	37.5	%	109.5	%

Twelve Months Ended December 31, 2017 and 2016

	Electric Deliveries							Revenue (in millions)
	2017		2016	% Change		Weather - Normal % Change		2017		2016		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential	7,831	8,452,000,000	8,372	(6.5	)%	(2.5	)%	$	956	$	1,000	(4.4	)%
Small Commercial & Industrial	1,303	1,471,000,000	1,459	(10.7	)%	(9.0	)%	147		150		(2.0	)%
Large Commercial & Industrial	14,988	15,351,000,000	15,559	(3.7	)%	(2.5	)%	810		803		0.9	%
Public Authorities & Electric Railroads	734	714,000,000	724	1.4	%	1.4	%	33		32		3.1	%
Total Retail	24,856		26,114	(4.8	)%	(2.8	)%	1,946		1,985		(2.0	)%
Other Revenue (b)								212		201		5.5	%
Total Electric Revenue (c)								2,158		2,186		(1.3	)%
Purchased Power								$	614	$	706	(13.0	)%

				% Change
Heating and Cooling Degree-Days	2017	2016	Normal	From 2016		From Normal
Heating Degree-Days	3,312	3,624	3,869	(8.6	)%	(14.4	)%
Cooling Degree-Days	1,767	1,936	1,653	(8.7	)%	6.9	%

Number of Electric Customers	2017	2016
Residential	792,211	780,652
Small Commercial & Industrial	53,489	53,529
Large Commercial & Industrial	21,732	21,391
Public Authorities & Electric Railroads	144	130
Total	867,576	855,702

(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 $2 million and $1 million for the three months ended December 31, 2017 and 2016, respectively, and $6 million and $5 million for the twelve months ended December 31, 2017 and 2016, respectively.

34

EXELON CORPORATION

DPL Statistics

Three Months Ended December 31, 2017 and 2016

	Electric and Natural Gas Deliveries						Revenue (in millions)
	2017	2016	% Change		Weather - Normal % Change		2017		2016		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential	1,167	1,115	4.7	%	(1.2	)%	$	154	$	147	4.8	%
Small Commercial & Industrial	544	544	—	%	(1.8	)%	47		45		4.4	%
Large Commercial & Industrial	1,145	1,131	1.2	%	0.2	%	24		24		—	%
Public Authorities & Electric Railroads	9	12	(25.0	)%	(18.2	)%	3		3		—	%
Total Retail	2,865	2,802	2.2	%	(0.8	)%	228		219		4.1	%
Other Revenue (b)							46		38		21.1	%
Total Electric Revenue (c)							274		257		6.6	%
Natural Gas (in mmcfs)
Retail Deliveries and Sales (d)
Retail Sales	4,428	4,086	8.4	%	2.3	%	49		40		22.5	%
Transportation and Other (e)	1,848	1,748	5.7	%	4.2	%	7		6		16.7	%
Total Natural Gas	6,276	5,834	7.6	%	2.8	%	56		46		21.7	%
Total Electric and Natural Gas Revenues							$	330	$	303	8.9	%
Purchased Power and Fuel							$	133	$	135	(1.5	)%

Electric Service Territory				% Change
Heating and Cooling Degree-Days	2017	2016	Normal	From 2016		From Normal
Heating Degree-Days	1,601	1,507	1,586	6.2	%	0.9	%
Cooling Degree-Days	72	43	26	67.4	%	176.9	%

Gas Service Territory				% Change
Heating Degree-Days	2017	2016	Normal	From 2016		From Normal
Heating Degree-Days	1,632	1,542	1,677	5.8	%	(2.7	)%

Twelve Months Ended December 31, 2017 and 2016

	Electric and Natural Gas Deliveries							Revenue (in millions)
	2017		2016	% Change		Weather - Normal % Change		2017		2016		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential	5,010		5,181	(3.3	)%	(0.3	)%	$	660	$	668	(1.2	)%
Small Commercial & Industrial	2,237		2,290	(2.3	)%	(0.9	)%	185		187		(1.1	)%
Large Commercial & Industrial	4,585		4,623	(0.8	)%	0.3	%	102		98		4.1	%
Public Authorities & Electric Railroads	44		46	(4.3	)%	(8.3	)%	14		13		7.7	%
Total Retail	11,876		12,140	(2.2	)%	(0.2	)%	961		966		(0.5	)%
Other Revenue (b)								178		163		9.2	%
Total Electric Revenue (c)								1,139		1,129		0.9	%
Natural Gas (in mmcfs)
Retail Deliveries and Sales (d)
Retail Sales	13,107		13,341	(1.8	)%	5.2	%	136		127		7.1	%
Transportation and Other (e)	6,538	—	6,201	5.4	%	6.9	%	25		21		19.0	%
Total Natural Gas	19,645		19,542	0.5	%	5.7	%	161		148		8.8	%
Total Electric and Natural Gas Revenues								$	1,300	$	1,277	1.8	%
Purchased Power and Fuel								$	532	$	583	(8.7	)%

Electric Service Territory				% Change
Heating and Cooling Degree-Days	2017	2016	Normal	From 2016		From Normal
Heating Degree-Days	4,077	4,319	4,519	(5.6	)%	(9.8	)%
Cooling Degree-Days	1,300	1,453	1,210	(10.5	)%	7.4	%

Gas Service Territory				% Change
Heating Degree-Days	2017	2016	Normal	From 2016		From Normal
Heating Degree-Days	4,203	4,454	4,739	(5.6	)%	(11.3	)%

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Number of Electric Customers	2017	2016	Number of Natural Gas Customers	2017	2016
Residential	459,389	456,181	Residential	122,347	120,951
Small Commercial & Industrial	60,697	60,173	Commercial & Industrial	9,853	9,801
Large Commercial & Industrial	1,400	1,411	Total Retail	132,200	130,752
Public Authorities & Electric Railroads	629	643	Transportation	154	156
Total	522,115	518,408	Total	132,354	130,908

(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 $1 million for the three months ended December 31, 2017 and 2016, respectively, and $8 million and $7 million for the twelve months ended December 31, 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.

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EXELON CORPORATION

ACE Statistics

Three Months Ended December 31, 2017 and 2016

	Electric Deliveries						Revenue (in millions)
	2017	2016	% Change		Weather - Normal % Change		2017			2016		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential	811	826	(1.8	)%	(6.9	)%	$	136		$	134	1.5	%
Small Commercial & Industrial	294	457	(35.7	)%	(36.9	)%	37			50		(26.0	)%
Large Commercial & Industrial	842	697	20.8	%	19.5	%	46			43		7.0	%
Public Authorities & Electric Railroads	14	14	—	%	—	%	3			3		—	%
Total Retail	1,961	1,994	(1.7	)%	(4.5	)%	222			230		(3.5	)%
Other Revenue (b)							50			45		11.1	%
Total Electric Revenue (c)							272			275		(1.1	)%
Purchased Power							$	128	155,000,000	$	133	(3.8	)%

				% Change
Heating and Cooling Degree-Days	2017	2016	Normal	From 2016		From Normal
Heating Degree-Days	1,598	1,549	1,611	3.2	%	(0.8	)%
Cooling Degree-Days	75	36	23	108.3	%	226.1	%

Twelve Months Ended December 31, 2017 and 2016

	Electric Deliveries						Revenue (in millions)
	2017	2016	% Change		Weather - Normal % Change		2017		2016		% Change
Electric (in GWhs)
Retail Deliveries and Sales (a)
Residential	3,853	4,153	(7.2	)%	(6.2	)%	$	619	$	664	(6.8	)%
Small Commercial & Industrial	1,286	1,455	(11.6	)%	(11.1	)%	166		183		(9.3	)%
Large Commercial & Industrial	3,399	3,402	(0.1	)%	0.4	%	189		201		(6.0	)%
Public Authorities & Electric Railroads	47	49	(4.1	)%	(4.1	)%	13		13		—	%
Total Retail	8,585	9,059	(5.2	)%	(4.5	)%	987		1,061		(7.0	)%
Other Revenue (b)							199		196		1.5	%
Total Electric Revenue (c)							1,186		1,257		(5.6	)%
Purchased Power							$	570	$	651	(12.4	)%

				% Change
Heating and Cooling Degree-Days	2017	2016	Normal	From 2016		From Normal
Heating Degree-Days	4,206	4,487	4,713	(6.3	)%	(10.8	)%
Cooling Degree-Days	1,228	1,303	1,115	(5.8	)%	10.1	%

Number of Electric Customers	2017	2016
Residential	487,168	484,240
Small Commercial & Industrial	61,013	61,008
Large Commercial & Industrial	3,684	3,763
Public Authorities & Electric Railroads	636	610
Total	552,501	549,621

(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 December 31, 2017 and 2016, respectively, and $2 million and $3 million for the twelve months ended December 31, 2017 and 2016, respectively.

37