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(a)	See “Fuel” for sources of fuels used in electric generation.

(b)	Net generation capacity is stated at proportionate ownership share. See ITEM 2. PROPERTIES—Generation for additional information.

(c)	Includes wind, hydroelectric and solar generating assets.

(d)	Electric supply procured under site specific agreements.

(e)	Includes EGTP generating assets that were deconsolidated from Generation's consolidated financial statements. See Note 4 — Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.

•	Mid-Atlantic represents operations in the eastern half of PJM, which includes Pennsylvania, New Jersey, Maryland, Virginia, West Virginia, Delaware, the District of Columbia and parts of North Carolina (approximately 33% of capacity).

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Midwest represents operations in the western half of PJM, which includes portions of Illinois, Indiana, Ohio, Michigan, Kentucky and Tennessee; and the United States footprint of MISO (excluding MISO’s Southern Region), which covers all or most of North Dakota, South Dakota, Nebraska, Minnesota, Iowa, Wisconsin and the remaining parts of Illinois, Indiana, Michigan and Ohio not covered by PJM; and parts of Montana, Missouri and Kentucky (approximately 34% of capacity).

•	New England represents the operations within ISO-NE covering the states of Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont (approximately 6% of capacity).

•	New York represents the operations within ISO-NY, which covers the state of New York in its entirety (approximately 6% of capacity).

•	ERCOT represents operations within Electric Reliability Council of Texas, covering most of the state of Texas (approximately 16% of capacity).

•	Other Power Regions is an aggregate of regions not considered individually significant (approximately 5% of capacity).

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(a)	Denotes year in which nuclear unit began commercial operations.

(b)	Although timing has been delayed, Generation currently plans to seek license renewal for Clinton and has advised the NRC that any license renewal application would not be filed until the first quarter of 2021.

(c)	Generation had previously announced and notified the NRC that it will permanently cease generation operations at Oyster Creek by the end of 2019. On February 2, 2018, Exelon announced that Generation will permanently cease generation operations at Oyster Creek at the end of its current operating cycle in October 2018.

(d)	On June 7, 2016, Generation announced that it will submit a second 20-year license renewal application to NRC for Peach Bottom Units 2 and 3 in 2018.

(e)	On May 30, 2017, Exelon announced that Generation will permanently cease generation operations at TMI on or about September 30, 2019 and has notified the NRC.

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(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).  Nuclear generation for 2017 and 2016 includes physical volumes of 34,761 GWh and 33,444 GWh, respectively, for CENG.

(b)	Includes wind, hydroelectric and solar generating assets.

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(a)	Includes approximately 2.7 million in the city of Chicago.

(b)	Includes approximately 1.6 million in the city of Philadelphia.

(c)	Includes approximately 0.6 million in the city of Baltimore.

(d)	Includes approximately 0.7 million in the District of Columbia.

(e)	Includes approximately 0.1 million in the city of Wilmington.

(f)	Includes approximately 0.1 million in the city of Atlantic City.

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(a)	Natural gas from underground storage represents approximately 28%, 46% and 34% of PECO's, BGE’s and DPL's 2017-2018 heating season planned supplies, respectively.

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(a)	A separate CBA between ComEd and IBEW Local 15 covers approximately 65 employees in ComEd’s System Services Group and was renewed in 2016. Generation’s and ComEd’s separate CBAs with IBEW Local 15 will expire in 2022.

(b)	PECO craft and call center employees in the Philadelphia service territory are covered by CBAs with IBEW Local 614, both expiring in 2021. Additionally, Exelon Power, an operating unit of Generation, has an agreement covering 97 employees, which was renewed in 2016 and expiring in 2019.

(c)

During 2017, Generation finalized CBAs with the Security Officer unions at LaSalle, Limerick and Quad Cities, which all will expire in 2020 and Dresden expiring in 2021. Additionally, during 2017, Generation acquired and combined two CBAs at FitzPatrick into one CBA covering both craft and security employees, which will expire in 2023. During 2016, Generation finalized its CBA with the Security Officer union at Oyster Creek, expiring in 2022 and New Energy IUOE Local 95-95A, which will expire in 2021. Also, during 2016, Generation finalized a 5-year agreement with the New England ENEH, UWUA Local 369, which will expire in 2022. During 2015, Generation finalized its CBA with Clinton Local 51 which will expire in 2020; its two CBAs with Local 369 at Mystic 7 and Mystic 8/9, both expiring in 2020; and four Security Officer unions at Braidwood, Byron, Clinton and TMI, all expiring between 2018 and 2021, respectively. During 2014, Generation finalized CBAs with TMI Local 777 and Oyster Creek Local 1289, expiring in 2019 and 2021, respectively and CENG finalized its CBA with Nine Mile Point which will expire in 2020. Additionally, during 2014, an agreement was negotiated with Las Vegas District Energy and IUOE Local 501, which will expire in 2018.

(d)	In January 2017, an election was held at BGE which resulted in union representation for 1,394 employees at the end of the year. BGE and IBEW Local 410 are negotiating an initial agreement which could result in some modifications to wages, hours and other terms and conditions of employment. No agreement has been finalized to date and management cannot predict the outcome of such negotiations.

(e)	PHI’s utility subsidiaries are parties to five CBAs with four local unions. CBAs are generally renegotiated every three to five years. All of these CBAs were renegotiated in 2014 and were extended through various dates ranging from October 2018 through June 2020.

(f)	Other includes shared services employees at BSC.

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•

Market and Financial Factors. Exelon’s and Generation’s results of operations are affected by price fluctuations in the energy markets. Power prices are a function of supply and demand, which in turn are driven by factors such as (1) the price of fuels, in particular the price of natural gas, which affects the prices that Generation can obtain for the output of its power plants, (2) the presence of other generation resources in the markets in which Generation’s output is sold, (3) the demand for electricity in the markets where the Registrants conduct their business, (4) the impacts of on-going competition in the retail channel and (5) emerging technologies.

•

Regulatory and Legislative Factors. The regulatory and legislative factors that affect the Registrants include changes to the laws and regulations that govern competitive markets and utility cost recovery, tax policy, zero emission credit programs and environmental policy. In particular, Exelon’s and Generation’s financial performance could be affected by changes in the design of competitive wholesale power markets or Generation’s ability to sell power in those markets. In addition, potential regulation and legislation, including regulation or legislation regarding climate change and renewable portfolio standards (RPS), could have significant effects on the Registrants. Also, returns for the Utility Registrants are influenced significantly by state regulation and regulatory proceedings.

•

Operational Factors. The Registrants’ operational performance is subject to those factors inherent in running the nation’s largest fleet of nuclear power reactors and large electric and gas distribution systems. The safe, secure and effective operation of the nuclear facilities and the ability to effectively manage the associated decommissioning obligations as well as the ability to maintain the availability, reliability, safety and security of its energy delivery systems are fundamental to Exelon’s ability to achieve value-added growth for customers, communities and shareholders. Additionally, the operating costs of the Registrants and the opinions of their customers, regulators and shareholders are affected by those companies’ ability to maintain the reliability, safety and efficiency of their energy delivery systems.

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•	Risks Related to the PHI Merger. Exelon is subject to additional risks related to the merger with PHI, which closed on March 23, 2016.

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(a)	All nuclear stations are boiling water reactors except Braidwood, Byron, Calvert Cliffs, Ginna, Salem and Three Mile Island, which are pressurized water reactors.

(b)	100%, unless otherwise indicated.

(c)

Base-load units are plants that normally operate to take all or part of the minimum continuous load of a system and, consequently, produce electricity at an essentially constant rate. Intermediate units are plants that normally operate to take load of a system during the daytime higher load hours and, consequently, produce electricity by cycling on and off daily. Peaking units consist of lower-efficiency, quick response steam units, gas turbines and diesels normally used during the maximum load periods.

(d)	For nuclear stations, capacity reflects the annual mean rating. Fossil stations reflect a summer rating. Wind and solar facilities reflect name plate capacity.

(e)

Generation had previously agreed to permanently cease generation operations at Oyster Creek by the end of 2019. On February 2, 2018, Exelon announced that Generation will permanently cease generation operations at Oyster Creek at the end of its current operating cycle in October 2018. See Note 28 — Subsequent Events of the Combined Notes to Consolidated Financial Statements for additional information regarding the early retirement of Oyster Creek.

(f)	Net generation capacity is stated at proportionate ownership share.

(g)	Reflects Generation’s 50.01% interest in CENG, a joint venture with EDF. For Nine Mile Point, the co-owner owns 18% of Unit 2. Thus, Exelon’s ownership is 50.01% of 82% of Nine Mile Point Unit 2.

(h)	Reflects the sale of 49% of ExGen Renewables Partners to a third party on July 6, 2017. See Note 2 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for additional information.

(i)	ExGen Renewables Partners owns 100% of the Class A membership interests and a tax equity investor owns 100% of the Class B membership interests of the entity that owns the Bluestem generating assets.

(j)	Generation directly owns a 50% interest in the Albany Green Energy station and an additional 49% through the consolidation of a Variable Interest Entity.

(k)	Generation has announced it will permanently cease generation operations at TMI on or about September 30, 2019. See Note 8 — Early Nuclear Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information regarding the early retirement of TMI.

(l)

As a result of the EGTP bankruptcy and deconsolidation on November 7, 2017, Generation deconsolidated EGTP's assets and liabilities from Generation's consolidated financial statements. As of December 31, 2017, these assets were still under Generation's ownership and included in the table. See Note 4 — Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.

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(a)	In addition, PECO has a 22.00% ownership interest in 127 miles of 500 kV lines located in Pennsylvania and a 42.55% ownership interest in 131 miles of 500 kV lines located in Delaware and New Jersey.

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(a)	DPL has a 10% undivided interest in approximately 8 miles of natural gas transmission mains located in Delaware which are used by DPL for its natural gas operations and by 90% owner for distribution of natural gas to its electric generating facilities.

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•	$100 invested on December 31, 2012 in Exelon common stock, in the S&P 500 Stock Index and in the S&P Utility Index; and

•	All dividends are reinvested.

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(a)	The 2016 financial results include the activity of PHI from the merger effective date of March 24, 2016 through December 31, 2016.

(b)	On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2014 financial results include CENG’s results of operations on a fully consolidated basis.

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(a)	On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2014 financial results include CENG’s results of operations on a fully consolidated basis.

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(a)	As a result of the PHI Merger in 2016, Exelon has elected to present PHI's selected financial data for the periods reflected above.

(a)	As a result of the PHI Merger in 2016, Exelon has elected to present Pepco's selected financial data for the periods reflected above.

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(a)	As a result of the PHI Merger in 2016, Exelon has elected to present DPL's selected financial data for the periods reflected above.

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(a)	As a result of the PHI Merger in 2016, Exelon has elected to present ACE's selected financial data for the periods reflected above.

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•	Generation, whose integrated business consists of the generation, physical delivery and marketing of power across multiple geographical regions through its customer-facing business, Constellation, which sells electricity and natural gas to both wholesale and retail customers. Generation also sells renewable energy and other energy-related products and services.

•	ComEd, whose business consists of the purchase and regulated retail sale of electricity and the provision of electricity transmission and distribution services in northern Illinois, including the City of Chicago.

•	PECO, whose business consists of the purchase and regulated retail sale of electricity and the provision of electricity distribution and transmission services in southeastern Pennsylvania, including the City of Philadelphia, and the purchase and regulated retail sale of natural gas and the provision of distribution services in the Pennsylvania counties surrounding the City of Philadelphia.

•	BGE, whose business consists of the purchase and regulated retail sale of electricity and natural gas and the provision of electricity distribution and transmission and gas distribution services in central Maryland, including the City of Baltimore.

•	Pepco, whose business consists of the purchase and regulated retail sale of electricity and the provision of electricity distribution and transmission in the District of Columbia and major portions of Prince George's County and Montgomery County in Maryland.

•	DPL, whose business consists of the purchase and regulated retail sale of electricity and the provision of electricity distribution and transmission services in portions of Maryland and Delaware, and the purchase and regulated retail sale of natural gas and the provision of natural gas distribution services in northern Delaware.

•	ACE, whose business consists of the purchase and regulated retail sale of electricity and the provision of electricity transmission and distribution services in southern New Jersey.

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(a)

The Registrants’ evaluate operating performance using the measure of revenues net of purchased power and fuel expense. The Registrant's believe that revenues net of purchased power and fuel expense is a useful measurement because it provides information that can be used to evaluate its operational performance. Revenues net of purchased power and fuel expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.

(b)	As a result of the PHI Merger, Exelon includes the consolidated results of PHI, Pepco, DPL and ACE from March 24, 2016 through December 31, 2016.

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•	Increase of $104 million at BGE primarily due to the impacts of the electric and natural gas distribution rate orders issued by the MDPSC in June 2016 and July 2016 and an increase in transmission formula rate revenues;

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Increase of $99 million at ComEd primarily due to increased electric distribution and transmission formula rate revenues (reflecting the impacts of increased capital investment and higher allowed electric distribution ROE), partially offset by lower revenues resulting from the change to defer and recover over time energy efficiency costs pursuant to FEJA and the impact of favorable weather conditions in 2016; and

•	Increase of $767 million in Revenue net of purchased power and fuel due to the inclusion of PHI's results for the year ended December 31, 2017 compared to the period March 24, 2016 to December 31, 2016, as well as distribution rate increases effective in 2016 and 2017.

•	Decrease of $134 million at Generation due to mark-to-market losses of $175 million in 2017 compared to mark-to-market losses of $41 million in 2016;

•	Decrease of $46 million at PECO primarily due to unfavorable weather conditions; and

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Decrease of $11 million at Generation primarily due to 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 impact of the New York CES, increased nuclear volumes primarily as a result of the acquisition of FitzPatrick, higher capacity prices, the addition of two combined-cycle gas turbines in Texas and lower nuclear fuel prices.

•	Increase of $307 million at Generation due to higher asset impairment charges;

•	Increase of $127 million at Generation primarily due to Generation’s decision in 2017 to early retire the TMI nuclear facility compared to the previous decision in 2016 to early retire the Clinton and Quad Cities nuclear facilities;

•	Increase of $104 million at Generation due to increased nuclear refueling outage costs;

•	Increase of $84 million at Generation due to the annual update of the Generation nuclear decommissioning obligation related to the non-regulatory units in 2017 versus 2016; and

•	Increase of $253 million at PHI due to the inclusion of PHI's results for the year ended December 31, 2017 compared to the period March 24, 2016 to December 31, 2016.

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•	Decrease of $665 million at Exelon due to merger commitment and other merger-related costs of $73 million in 2017 compared to $738 million in 2016;

•	Decrease of $85 million at ComEd due to the change to defer and recover over time energy efficiency costs pursuant to the Illinois Future Energy Jobs Act; and

•	Decrease of $21 million at BGE primarily due to certain disallowances contained in the June and July 2016 rate orders, partially offset by the impact of the favorable 2016 settlement of the Baltimore City conduit fee dispute.

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(a)	Reflects the impact of net gains and losses on Generation’s economic hedging activities. See Note 12 - Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional detail related to Generation’s hedging activities.

(b)	Reflects the impact of net unrealized gains on Generation’s NDT fund investments for Non-Regulatory Agreement Units. See Note 15 - Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional detail related to Generation’s NDT fund investments.

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

(d)	Primarily reflects certain costs incurred for the PHI acquisition in 2017 and 2016 and Generation's FitzPatrick acquisition in 2017, including professional fees, employee-related expenses and integration activities. See Note 4 - Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional detail related to merger and acquisition costs.

(e)

Represents costs incurred as part of the settlement orders approving the PHI acquisition, and in 2017, a decrease in reserves for uncertain tax positions related to the deductibility of certain merger commitments associated with the 2012 CEG and 2016 PHI acquisitions, and in 2016, a charge related to a 2012 CEG merger commitment. See Note 4 - Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional detail related to PHI Merger commitments.

(f)	Primarily reflects charges to earnings in 2017 related to impairments of EGTP assets and the PHI District of Columbia sponsorship intangible asset, and in 2016, impairments of Upstream assets and certain wind projects at Generation.

(g)

Primarily reflects 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. Primarily reflects 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.

(h)

Reflects 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, and 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.

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

(j)	Represents 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, and 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.

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

(l)	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.

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

(n)	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.

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

(p)	Reflects the 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.

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

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(a)	See Note 4 — Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for more information.

(a)	For Exelon, Generation, PHI, Pepco, DPL and ACE, includes the operations of the acquired businesses beginning on March 24, 2016.

(b)	External, third party costs paid to advisors, consultants, lawyers and other experts to assist in the due diligence and regulatory approval processes and in the closing of transactions.

(c)	Costs to integrate PHI processes and systems into Exelon. For the year ended December 31, 2017, also includes costs to integrate FitzPatrick processes and systems into Exelon.

(d)

For the year ended December 31, 2017, includes deferrals of previously incurred integration costs to achieve distribution synergies related to the PHI acquisition of $24 million, $8 million, $8 million, and $8 million incurred at PHI, Pepco, DPL, and ACE, respectively, that have been recorded as a regulatory asset for anticipated recovery. For the year ended December 31, 2016, includes deferrals of previously incurred integration costs to achieve distribution synergies related to the PHI acquisition of $8 million, $6 million, $11 million, and $4 million incurred at ComEd, BGE, Pepco, and DPL, respectively, that have been recorded as a regulatory asset for anticipated recovery. For the Successor period March 24, 2016 to December 31, 2016, includes deferrals of previously incurred integration costs to achieve distribution synergies related to the PHI acquisition of $16 million incurred at PHI that have been recorded as a regulatory asset for anticipated recovery. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for more information.

(e)	Costs primarily for employee severance, pension and OPEB expense and retention bonuses.

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(a)	Actual results may differ based on incremental future capital additions, actual units of production for nuclear fuel amortization, future revised ARO assumptions, etc.

(b)	Reflects incremental accelerated depreciation of plant assets, including any ARC.

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(a)	Includes the accelerated depreciation of plant assets including any ARC.

(b)	Actual results may differ based on incremental future capital additions, actual units of production for nuclear fuel amortization, future revised ARO assumptions, etc.

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(a)

Pursuant to EIMA, ComEd’s electric distribution rates are established through a performance-based formula through which ComEd is required to file an annual update on or before May 1, with resulting rates effective in January of the following year. ComEd’s annual electric distribution formula rate update is based on prior year actual costs and current year projected capital additions (initial year revenue requirement). The update also reconciles any differences between the revenue requirement in effect for the prior year and actual costs incurred for the year (annual reconciliation).

(b)	Reflects an increase of $78 million for the initial revenue requirement for 2017 and an increase of $18 million related to the annual reconciliation.

(c)

ComEd’s allowed ROE under its electric distribution formula rate is the annual average rate on 30-year treasury notes plus 580 basis points and is subject to reduction if ComEd does not deliver certain reliability and customer service benefits. The initial revenue requirement for 2017 reflects an allowed ROE of 8.40%, while the annual reconciliation reflects an allowed ROE of 8.34%, which is inclusive of a 6-basis-point performance penalty.

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(a)	On February 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.

(b)	By mid-February, Pepco and DPL will update their current distribution rate cases to reflect the TCJA impacts.

(c)

On December 18, 2017, a settlement agreement was filed with the MDPSC wherein DPL will be granted a rate increase of $13 million, and a ROE of 9.5% solely for purposes of calculating AFUDC and regulatory asset carrying costs.  On January 5, 2018, the MDPSC held a hearing on the settlement agreement.  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.

(a)	All rates are effective June 2017.

(b)	BGE's transmission revenues include a FERC approved dedicated facilities charge to recover the costs of providing transmission service to specifically designated load by BGE.

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

(d)

As part of the FERC-approved settlement of ComEd’s 2007 transmission rate case, the rate of return on common equity is 11.50%, inclusive of a 50-basis-point incentive adder for being a member of a RTO, and the common equity component of the ratio used to calculate the weighted average debt and equity return for the transmission formula rate is currently capped at 55%. As part of the FERC-approved settlement of the ROE complaint against BGE, Pepco, DPL and ACE, the rate of return on common equity is 10.50%, inclusive of a 50-basis-point incentive adder for being a member of a RTO.

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•	Exelon’s utilities provide a foundation for steadily growing earnings, which translates to a stable currency in our stock.

•	Generation’s competitive businesses provide free cash flow to invest primarily in the utilities and in long-term, contracted assets and to reduce debt.

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1.

DECON - a method of decommissioning shortly after the cessation of operation in which the equipment, structures, and portions of a facility and site containing radioactive contaminants are removed and safely buried in a LLRW landfill or decontaminated to a level that permits property to be released for unrestricted use. Spent fuel is transferred to dry cask storage as soon as possible until DOE acceptance for disposal.

2.	Delayed DECON - similar to the DECON scenario but with a delay to allow for spent fuel to be removed from the site prior to onset of decommissioning activities. Spent fuel is retained in existing location (either wet or dry storage) until DOE acceptance for disposal.

3.	Shortened SAFSTOR - similar to the DECON scenario but with generally a 30-year delay prior to onset of decommissioning activities. Spent fuel is transferred to dry cask storage as soon as possible until DOE acceptance for disposal.

4.	SAFSTOR - a method of decommissioning in which the nuclear facility is placed and maintained in such condition that the nuclear facility can be safely stored and subsequently decontaminated to levels that permit release for unrestricted use generally within 60 years after cessation of operations. Spent fuel is transferred to dry cask storage as soon as possible until DOE acceptance for disposal.

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(a)	Timing sensitivity does not include any sites for which an early plant retirement has been announced.

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(a)

In general, the discount rate will have a larger impact on the pension and other postretirement benefit cost and obligation as the rate moves closer to 0%. Therefore, the discount rate sensitivities above cannot necessarily be extrapolated for larger increases or decreases in the discount rate. Additionally, Exelon utilizes a liability-driven investment strategy for its pension asset portfolio. The sensitivities shown above do not reflect the offsetting impact that changes in discount rates may have on pension asset returns.

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(a)

Generation evaluates its operating performance using the measure of revenues net of purchased power and fuel expense. Generation believes that revenues net of purchased power and fuel expense is a useful measurement because it provides information that can be used to evaluate its operational performance. Revenues net of purchased power and fuel expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.

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

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Midwest represents operations in the western half of PJM, which includes portions of Illinois, Pennsylvania, Indiana, Ohio, Michigan, Kentucky and Tennessee, and the United States footprint of MISO excluding MISO’s Southern Region, which covers all or most of North Dakota, South Dakota, Nebraska, Minnesota, Iowa, Wisconsin, the remaining parts of Illinois, Indiana, Michigan and Ohio not covered by PJM, and parts of Montana, Missouri and Kentucky.

•	New England represents the operations within ISO-NE covering the states of Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont.

•	New York represents operations within ISO-NY, which covers the state of New York in its entirety.

•	ERCOT represents operations within Electric Reliability Council of Texas, covering most of the state of Texas.

•	Other Power Regions:

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South represents operations in the FRCC, MISO’s Southern Region, and the remaining portions of the SERC not included within MISO or PJM, which includes all or most of Florida, Arkansas, Louisiana, Mississippi, Alabama, Georgia, Tennessee, North Carolina, South Carolina and parts of Missouri, Kentucky and Texas. Generation’s South region also includes operations in the SPP, covering Kansas, Oklahoma, most of Nebraska and parts of New Mexico, Texas, Louisiana, Missouri, Mississippi and Arkansas.

•	West represents operations in the WECC, which includes California ISO, and covers the states of California, Oregon, Washington, Arizona, Nevada, Utah, Idaho, Colorado, and parts of New Mexico, Wyoming and South Dakota.

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

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(a)	Results of transactions with PECO and BGE are included in the Mid-Atlantic region. Results of transactions with Pepco, DPL, and ACE are included in the Mid-Atlantic region beginning on March 24, 2016, the day after the PHI merger was completed.

(b)	Results of transactions with ComEd are included in the Midwest region.

(c)

Other represents activities not allocated to a region. See text above for a description of included activities. Includes amortization of intangible assets related to commodity contracts recorded at fair value of a $54 million decrease to RNF, an $57 million decrease to RNF, and an $8 million increase to RNF for the years ended December 31, 2017, 2016, and 2015, respectively, and accelerated nuclear fuel amortization associated with announced early plant retirements, as discussed in Note 8 - Early Nuclear Plant Retirements of the Combined Notes to Consolidated Financial Statements, of $12 million and $60 million for the years ended December 31, 2017 and 2016, respectively.

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

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

(b)	Includes affiliate sales to PECO and BGE in the Mid-Atlantic region and affiliate sales to ComEd in the Midwest region. As a result of the PHI Merger, includes affiliate sales to Pepco, DPL and ACE in the Mid-Atlantic region beginning on March 24, 2016.

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

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(a)	Excludes Salem, which is operated by PSEG Nuclear, LLC. Reflects ownership percentage of stations operated by Exelon. Includes the ownership of the FitzPatrick nuclear facility from March 31, 2017.

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(a)	The 2017 financial results include Generation's acquisition of the FitzPatrick nuclear generating station from March 31, 2017.

(b)	Primarily reflects charges to earnings related to impairments as a result of the EGTP assets in 2017 and impairment of Upstream assets and certain wind projects in 2016.

(c)	Primarily reflects the non-cash benefit pursuant to the annual update of the Generation nuclear decommissioning obligation related to the non-regulatory units in 2017 compared to 2016.

(d)	Primarily represents the announcement of the early retirement of Generation's TMI nuclear facility in 2017 compared to the previous decision to early retire Generation's Clinton and Quad Cities nuclear facilities in 2016.

(e)	Reflects the impact of increased accretion expenses primarily due to the acquisition of FitzPatrick on March 31, 2017.

(f)	Primarily reflects an increase in the number of nuclear outage days during 2017 compared to 2016.

(g)	Primarily represents costs incurred as part of the settlement orders approving the PHI acquisition during 2016.

(h)	Reflects increased salaries, wages and contracting costs primarily related to the acquisition of the FitzPatrick nuclear facility beginning on March 31, 2017.

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

(j)	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.

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(a)	Reflects increased impairments in 2016 compared to 2015, primarily related to the impairments of certain Upstream assets and wind generating assets in 2016.

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

(c)	Reflects the favorable impact of higher pension and OPEB discount rates.

(d)	Reflects a decreased share of corporate allocated costs.

(e)	Reflects the impact of the Generation's previous decision to early retire the Clinton and Quad Cities nuclear facilities.

(f)	Reflects the favorable impacts of decreased nuclear outages in 2016.

(g)	Reflects an increase of labor, other benefits, contracting and materials costs primarily due to increased contracting costs related to energy efficiency projects and the inclusion of Pepco Energy Services results in 2016. Also includes cost of sales of our other business activities that are not allocated to a region.

(h)	Represents the 2016 severance expense and reorganization costs related to a cost management program.

(i)	Reflects the one-time recognition for 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.

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(a)

ComEd evaluates its operating performance using the measure of Revenue net of purchased power expense. ComEd believes that Revenue net of purchased power expense is a useful measurement because it provides information that can be used to evaluate its operational performance. In general, ComEd only earns margin based on the delivery and transmission of electricity. ComEd has included its discussion of Revenue net of purchased power expense below as a complement to the financial information provided in accordance with GAAP. However, Revenue net of purchased power expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.

(b)	For regulatory recovery mechanisms, including ComEd’s electric distribution and transmission formula rates, and riders, 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).

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(a)

For the year ended December 31, 2017, compared to the same period in 2016, the changes reflect the 2016 impacts of weather, volume and pricing and customer mix. As further described below, pursuant to the revenue decoupling provision in FEJA, ComEd began recording an adjustment to revenue in the first quarter of 2017 to eliminate the favorable or unfavorable impacts associated with variations in delivery volumes associated with above or below normal weather, number of customers or usage per customer.

(b)	Beginning on June 1, 2017, ComEd is deferring energy efficiency costs as a regulatory asset that will be recovered through the energy efficiency formula rate over the weighted average useful life of the related energy efficiency measures.

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(a)	Operating and maintenance expense for regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues.

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(a)	Primarily reflects the favorable impact of higher assumed pension and OPEB discount rates for the year ended December 31, 2016.

(b)

ComEd is allowed to recover from or refund to customers the difference between the utility’s annual uncollectible accounts expense and the amounts collected in rates annually through a rider mechanism. ComEd recorded a net decrease in 2017 and 2016 in Operating and maintenance expense related to uncollectible accounts due to the timing of regulatory cost recovery. An equal and offsetting amount has been recognized in Operating revenues for the periods presented.

(c)	Primarily reflects increased information technology support services from BSC in 2017 and 2016. For the year ended December 31, 2017, includes the $8 million write-off of a regulatory asset related to Constellation merger and integration costs for which recovery is no longer expected.

(d)	Beginning on June 1, 2017 ComEd is deferring energy efficiency costs as a regulatory asset that will be recovered through the energy efficiency over the weighted average useful life of the related energy efficiency measures.

(a)	Primarily reflects ongoing capital expenditures for the years ended December 31, 2017 and 2016.

(b)	Beginning in June 2017, includes amortization of ComEd's energy efficiency formula rate regulatory asset.

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(a)

Primarily reflects the recognition of after-tax interest related to the Tax Court's decision on Exelon's like-kind exchange tax position in the 2016. For the year ended December 31, 2017, the decrease was partially offset by additional interest recorded in 2017 related to Exelon's like-kind exchange tax position. See Note 14—Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.

(b)	Primarily reflects an increase in interest expense due to the issuance of First Mortgage Bonds for the years ended December 31, 2016. See Note 13—Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on ComEd's debt obligations.

(a)	Primarily reflects the recognition of the penalty related to the Tax Court's decision on Exelon's like-kind exchange tax position in 2016. See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.

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(a)	Reflects delivery revenue and volume 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 also includes rental revenue, revenue related to late payment charges, revenue from other utilities for mutual assistance programs and recoveries of remediation costs associated with MGP sites.

(c)	Includes operating revenues from affiliates totaling $15 million, $15 million, and $4 million for the years ended December 31, 2017, 2016, and 2015, respectively.

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(a)

PECO evaluates its operating performance using the measures of revenue net of purchased power expense for electric sales and revenue net of fuel expense for gas sales. PECO believes revenue net of purchased power expense and revenue net of fuel expense are useful measurements of its performance because they provide information that can be used to evaluate its net revenue from operations. PECO has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, revenue net of purchased power expense and revenue net of fuel expense figures are not a presentation defined under GAAP and may not be comparable to other companies’ presentations or more useful than the GAAP information provided elsewhere in this report.

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(a)	Operating and maintenance expenses for regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues.

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(a)	Reflects delivery volumes and revenue 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 revenue.

(c)	Total electric revenue includes operating revenues from affiliates totaling $6 million, $7 million and $1 million for the years ended December 31, 2017, 2016, and 2015, respectively.

(a)	Reflects delivery volumes and revenue 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.

(b)	Total natural gas revenue includes operating revenues from affiliates totaling $1 million for the years ended December 31, 2017, 2016 and 2015.

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(a)

BGE evaluates its operating performance using the measures of revenue net of purchased power expense for electric sales and revenue net of fuel expense for gas sales. BGE believes revenues net of purchased power and fuel expense are useful measurements of its performance because they provide information that can be used to evaluate its net revenue from operations. BGE has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, revenues net of purchased power and fuel expense figures are not a presentation defined under GAAP and may not be comparable to other companies’ presentations or more useful than the GAAP information provided elsewhere in this report.

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(a)	Operating and maintenance expense for regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues.

(a)	See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

(b)	See Note 23 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.

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(a)	Depreciation expense increased due to ongoing capital expenditures.

(b)

Regulatory asset amortization increased primarily due to an increase in regulatory asset amortization related to energy efficiency programs and the initiation of cost recovery of the AMI programs under the final electric and natural gas distribution rate case order issued by the MDPSC in June 2016. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.

(c)	Depreciation and amortization expenses for regulatory required programs are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues.

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(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 $5 million, $7 million and less than $1 million for the years ended 2017, 2016 and 2015, respectively.

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(a)	Reflects delivery volumes and revenue 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.

(b)	Transportation and other natural gas revenue includes off-system revenue of 3,615 mmcfs ($21 million), 5,977 mmcfs ($23 million), and 6,238 mmcfs ($35 million) for the years ended 2017, 2016 and 2015, respectively.

(c)	Includes operating revenues from affiliates totaling $11 million, $14 million, and $14 million for the years ended 2017, 2016 and 2015, respectively.

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(a)

PHI evaluates its operating performance using the measure of revenue net of purchased power and fuel expense for electric and natural gas sales. PHI believes revenue net of purchased power and fuel expense is a useful measurement because it provides information that can be used to evaluate its operational performance. PHI has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, Revenue net of purchased power and fuel expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.

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(a)

Pepco evaluates its operating performance using the measure of revenue net of purchased power expense for electric sales. Pepco believes revenue net of purchased power expense is a useful measurement because it provides information that can be used to evaluate its operational performance. Pepco has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, Revenue net of purchased power expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.

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(a)	Operating and maintenance expenses for regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues.

(a)	Related to a remeasurement of a regulatory asset for legacy meters recognized in 2016.

(b)	Primarily related to merger severance and compensation costs recognized in 2016

(c)	Primarily related to merger-related commitments for customer rate credits and charitable contributions recognized in 2016.

(d)	Primarily resulting from a review of capital projects during the fourth quarter of 2016.

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(a)	Depreciation expense increased primarily due to higher depreciation rates in Maryland effective November 2016 and ongoing capital expenditures.

(b)

Regulatory asset amortization increased for the year ended December 31, 2017 compared to the same period in 2016 primarily due to higher amortization of AMI-related regulatory assets, partially offset by lower amortization of MAPP abandonment costs. Regulatory asset amortization decreased for the year ended December 31, 2016 compared to the same period in 2015 primarily due to lower amortization of MAPP abandonment costs.

(c)

Regulatory required programs decreased for the year ended December 31, 2017 compared to the same period in 2016 primarily due to an EmPower Maryland surcharge rate decrease effective February 2016 and increased for the year ended December 31, 2016 compared to the same period in 2015 due to an EmPower Maryland surcharge rate increase effective February 2015. Depreciation and amortization expenses for regulatory required programs are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues and Operating and maintenance expense.

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(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 $6 million for the year ended December 31, 2017 and $5 million for the years ended December 31, 2016 and 2015, respectively.

(a)

DPL evaluates its operating performance using the measure of revenue net of purchased power expense for electric sales and revenue net of fuel expense for gas sales. DPL believes revenue net of purchased power expense and revenue net of fuel expense are useful measurements because they provide information that can be used to evaluate its operational performance. DPL has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, Revenue net of purchased power expense and Revenue net of fuel expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.

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(a)	Operating and maintenance expenses for regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues.

(a)	Primarily related to merger severance and compensation costs recognized in 2016.

(b)	Primarily related to merger-related commitments for customer rate credits and charitable contributions recognized in 2016.

(c)	Primarily resulting from a review of capital projects during the fourth quarter of 2016.

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(a)	Depreciation expense increased due to higher depreciation rates in Maryland effective February 2017 and due to ongoing capital expenditures.

(b)	Regulatory asset amortization decreased for the year ended December 31, 2016 compared to the same period in 2015 primarily due to lower amortization of MAPP abandonment costs.

(c)

Regulatory required programs decreased for the year ended December 31, 2017 compared to the same period in 2016 primarily due to an EmPower Maryland surcharge rate decrease effective February 2016 and increased for the year ended December 31, 2016 compared to the same period in 2015 due to an EmPower Maryland surcharge rate increase effective February 2015. Depreciation and amortization expenses for regulatory required programs are recoverable from customers on a full and current basis through approved regulated rates. A partially offsetting amount has been reflected in Operating revenues and Operating and maintenance expense.

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(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 $8 million, $7 million and $6 million for the years ended December 31, 2017, 2016 and 2015, respectively.

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(a)	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.

(b)	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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(a)

ACE evaluates its operating performance using the measure of revenue net of purchased power expense for electric sales. ACE believes Revenue net of purchased power expense is a useful measurement of its performance because it provides information that can be used to evaluate its operational performance. ACE has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, Revenue net of purchased power expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.

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(a)	Operating and maintenance expenses for regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues.

(a)	Primarily related to merger severance and compensation costs recognized in 2016.

(b)	Primarily related to merger-related commitments for customer rate credits and charitable contributions recognized in 2016.

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(a)	Depreciation expense increased due to ongoing capital expenditures.

(b)

Regulatory required programs decreased for the year ended December 31, 2017 compared to the same period in 2016 primarily as a result of lower revenue due to a rate decrease effective October 2016 for the ACE Transition Bond Charge and Market Transition Charge Tax. Required regulatory programs amortization decreased for the year ended December 31, 2016 compared to the same period in 2015 primarily as a result of lower revenue due to a rate decrease effective October 2015 for the ACE Market Transition charge tax. Depreciation and amortization expenses for regulatory required programs are recoverable from customers on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues and Operating and maintenance expense.

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(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.

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(a)

Represents depreciation, amortization, depletion and accretion, net fair value changes related to derivatives, deferred income taxes, provision for uncollectible accounts, pension and non-pension postretirement benefit expense, equity in earnings and losses of unconsolidated affiliates and investments, decommissioning-related items, stock compensation expense, impairment of long-lived assets, and other non-cash charges. See Note 24 —Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements for further detail on non-cash operating activity.

(b)	Changes in working capital and other noncurrent assets and liabilities exclude the changes in commercial paper, income taxes and the current portion of long-term debt.

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•	Pursuant to the TCJA, beginning in 2018 Generation is expected to have higher operating cash flows in the range of approximately $1.2 billion to $1.6 billion for the period from 2018 to 2021, reflecting the reduction in the corporate federal income tax rate and full expensing of capital investments.

(a)

Given the regulatory treatment of income tax benefits related to electric and gas distribution repairs, PECO remains in an overall net regulatory asset position as of December 31, 2017 after recording the impacts related to the TCJA. As a result, the amount of customer benefits resulting from the TCJA subject to the discretion of PECO's rate regulators are lower relative to the other Utility Registrants. Refer to Note 3 - Regulatory Matters for additional information.

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•

Exelon appealed the Tax Court’s like-kind exchange decision in the third quarter of 2017. In the fourth quarter of 2017, the IRS assessed the tax, penalties and interest of approximately $1.3 billion related to the like-kind exchange, including $300 million attributable to ComEd. While Exelon will receive a tax benefit of approximately $350 million associated with the deduction for the interest, Exelon currently has a net operating loss carryforward and thus does not expect to realize the cash benefit until 2018. After taking into account these interest deduction tax benefits, the total estimated net cash outflow for the like-kind exchange is approximately $950 million, of which approximately $300 million is attributable to ComEd after giving consideration to Exelon’s agreement to hold ComEd harmless from any unfavorable impacts on ComEd’s equity from the like-kind exchange position.

•

State and local governments continue to face increasing financial challenges, which may increase the risk of additional income tax, property taxes and other taxes or the imposition, extension or permanence of temporary tax increases. On July 6, 2017, Illinois enacted Senate Bill 9, which permanently increased Illinois’ total corporate income tax rate from 7.75% to 9.50% effective July 1, 2017. The rate increase is not expected to have a material ongoing

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•

Depending upon whether Generation is in a net mark-to-market liability or asset position, collateral may be required to be posted with or collected from its counterparties. In addition, the collateral posting and collection requirements differ depending on whether the transactions are on an exchange or in the OTC markets. During 2017, 2016 and 2015, Generation had net collections/(payments) of counterparty cash collateral of $(129) million, $923 million and $407 million, respectively, primarily due to market conditions that resulted in changes to Generation’s net mark-to-market position.

•	During 2017, 2016 and 2015, Generation had net collections/(payments) of approximately $28 million, $(66) million and $58 million, respectively, related to purchases and sales of options. The level of option activity in a given year may vary due to several factors, including changes in market conditions as well as changes in hedging strategy.

•

During 2017, 2016, and 2015 ComEd (posted)/received approximately $(27 million), $7 million, and $(31 million) of cash collateral with/from PJM, respectively. ComEd’s collateral posted with PJM has increased from 2017 to 2016, primarily due to an increase in ComEd’s RPM credit requirements and peak market activity with PJM.  The collateral posted with PJM decreased from 2016 to 2015 due to lower PJM billings.

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•

During 2017, Exelon had additional expenditures of $23 million and $178 million relating to the ConEdison Solutions and the acquisitions of the FitzPatrick nuclear generating station, respectively. During 2016, Exelon had expenditures of $6.6 billion, $235 million, and $58 million relating to the acquisitions of PHI, ConEdison Solutions and the acquisitions of the FitzPatrick nuclear generating station, respectively.

•	During 2017, Exelon had proceeds of $219 million from sales of long-lived assets.

•	During 2016, Exelon had proceeds of $360 million as a result of early termination of direct financing leases.

•

During 2017, Generation had additional expenditures of $23 million and $178 million relating to the ConEdison Solutions and the acquisitions of the FitzPatrick nuclear generating station, respectively. During 2016, Generation had expenditures of $235 million, and $58 million relating to the acquisitions of ConEdison Solutions and the acquisitions of the FitzPatrick nuclear generating station, respectively.

•	During 2017, Generation had proceeds of $218 million from sales of long-lived assets.

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(a)	Total projected capital expenditures do not include adjustments for non-cash activity.

(b)	Includes corporate operations, BSC and PHISCO rounded to the nearest $25 million.

(c)	The capital expenditures and 2018 projections include $86 million of expected incremental spending pursuant to EIMA, ComEd has committed to invest approximately $2.6 billion over a ten-year period to modernize and storm-harden its distribution system and to implement smart grid technology.

(d)	Includes PHISCO rounded to the nearest $25 million.

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(a)	For Energy Efficiency Project Financing, the maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt.

(b)	See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for discussion of nonrecourse debt.

(c)	As a result of the bankruptcy filing for EGTP on November 7, 2017, the nonrecourse debt was deconsolidated from Exelon's and Generation's consolidated financial statements. Refer to Note 4 — Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for further discussion.

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(a)	See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for discussion of nonrecourse debt.

(b)	For Energy Efficiency Project Financing, the maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt.

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(a)	See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for discussion of nonrecourse debt.

(b)	For Energy Efficiency Project Financing, the maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt.

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(a)	See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for discussion of nonrecourse debt.

(b)	As a result of the bankruptcy filing for EGTP on November 7, 2017, the nonrecourse debt was deconsolidated from Exelon's and Generation's consolidated financial statements. Refer to Note 4 — Mergers, Acquisitions and Dispositions for further discussion.

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(a)	See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for discussion of nonrecourse debt.

(b)	As a result of the bankruptcy filing for EGTP on November 7, 2017, the nonrecourse debt was deconsolidated from Exelon's and Generation's consolidated financial statements. Refer to Note 4 — Mergers, Acquisitions and Dispositions for further discussion.

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(a)	See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for discussion of nonrecourse debt.

(b)	As a result of the bankruptcy filing for EGTP on November 7, 2017, the nonrecourse debt was deconsolidated from Exelon's and Generation's consolidated financial statements. Refer to Note 4 — Mergers, Acquisitions and Dispositions for further discussion.

(c)	Represents Pepco Energy Services energy efficiency project financing. As of the date of the merger, PES financing was included with Generation.

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(a)	Includes dividends paid on BGE's preference stock during 2016 and 2015.

(a)	Exelon's Board of Directors approved an updated dividend policy providing an increase of 5% each year for the period covering 2018 through 2020, beginning with the March 2018 dividend.

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(a)	Additional contributions from parent or external debt financing may be required as a result of increased capital investment in infrastructure improvements and modernization pursuant to EIMA, transmission upgrades and expansions and Exelon's agreement to indemnify ComEd for any unfavorable after-tax impacts associated with ComEd's LKE tax matter.

(b)	Contribution paid by Exelon.

(c)	Contribution paid by PHI.

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(a)	Represents incremental collateral related to natural gas procurement contracts.

(a)

Includes approximately $389 million, $205 million and $184 million owed to unconsolidated affiliates of Exelon, ComEd, and PECO respectively. These special purpose entities were created for the sole purposes of issuing mandatorily redeemable trust preferred securities of ComEd and PECO. See Note 2 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for additional information regarding the authoritative guidance for VIEs.

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(a)	Generation currently has blanket financing authority it received from FERC in connection with its market-based rate authority.

(b)	ComEd had $1,140 million available in long-term debt refinancing authority and $243 million available in new money long term debt financing authority from the ICC as of December 31, 2017 and has an expiration date of June 1, 2019 and March 1, 2019, respectively.

(c)	Pepco and DPL are currently in the process of renewing their long-term financing authority with the MDPSC.

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(a)	Includes $390 million due after 2023 to ComEd and PECO financing trusts.

(b)	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2017 and do not reflect anticipated future refinancing, early redemptions or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2017. Includes estimated interest payments due to ComEd, PECO, BGE, PHI, Pepco, DPL and ACE financing trusts.

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(c)	Excludes Generation's contingent operating lease payments associated with contracted generation agreements. These amounts are included within purchase power obligations. Includes estimated cash payments for service fees related to PECO’s meter reading operating lease.

(d)

Purchase power obligations include contingent operating lease payments associated with contracted generation agreements. Amounts presented represent Generation’s expected payments under these arrangements at December 31, 2017, including those related to CENG. Expected payments include certain fixed capacity charges which may be reduced based on plant availability. Expected payments exclude renewable PPA contracts that are contingent in nature. Contained within Purchase power obligations are Net Capacity Purchases of $106 million, $99 million, $40 million, $31 million, $19 million and $171 million for 2018, 2019, 2020, 2021, 2022 and thereafter, respectively.

(e)	Represents commitments to purchase nuclear fuel, natural gas and related transportation, storage capacity and services, procure electric renewable energy and RECs, procure electric supply, and purchase AECs and curtailment services.

(f)

Primarily related to ComEd 20-year contracts for renewable energy and RECs beginning in June 2012. ComEd is permitted to recover its renewable energy and REC costs from retail customers with no mark-up. The commitments represent the earliest and maximum settlements with suppliers for renewable energy and RECs under the existing contract terms. See Note 3—Regulatory Matters of Combined Notes to Consolidated Financial Statements for additional information.

(g)

Represents the future estimated value at December 31, 2017 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between the Registrants and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.

(h)	Related to DC PLUG project costs for assets funded by the District of Columbia for which the District of Columbia has assessed a charge on Pepco. Pepco will recover this charge from customers through a volumetric distribution rider. See Note 3 — Regulatory Matters of Combined Notes to Consolidated Financial Statements for additional information.

(i)	Represents commitments for Generation's ongoing investments in new natural gas and biomass generation construction.

(j)

Under their operating agreements with PJM, ComEd, PECO, BGE, Pepco, DPL and ACE are committed to the construction of transmission facilities to maintain system reliability. These amounts represent ComEd, PECO, BGE, Pepco, DPL and ACE’s expected portion of the costs to pay for the completion of the required construction projects. See Note 3 — Regulatory Matters of Combined Notes to Consolidated Financial Statements for additional information.

(k)	See Note 23 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for further information regarding SNF obligations.

(l)

These amounts represent Exelon’s expected contributions to its qualified pension plans. The projected contributions reflect a funding strategy of contributing the greater of $300 million (which has been updated for the inclusion of PHI) until the qualified plans are fully funded on an accumulated benefit obligation basis, and the minimum amounts under ERISA to avoid benefit restrictions and at-risk status thereafter. The remaining qualified pension plans’ contributions are generally based on the estimated minimum pension contributions required under ERISA and the Pension Protection Act of 2006, as well as contributions necessary to avoid benefit restrictions and at-risk status. These amounts represent estimates that are based on assumptions that are subject to change. Qualified pension contributions for years after 2023 are not included. See Note 16 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for further information regarding estimated future pension benefit payments.

(a)	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2017 and do not reflect anticipated future refinancing, early redemptions or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2017.

(b)	Excludes Generation's contingent operating lease payments associated with contracted generation agreements. These amounts are included within purchase power obligations.

(c)	Purchase power obligations include contingent operating lease payments associated with contracted generation agreements. Amounts presented represent Generation’s expected payments under these arrangements at December 31, 2017. Expected

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(d)	Represents commitments to purchase fuel supplies for nuclear and fossil generation, including those related to CENG.

(e)

Represents the future estimated value at December 31, 2017 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between the Registrants and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.

(f)	Represents commitments for Generation's ongoing investments in new natural gas generation construction.  As of December 31, 2017, the commitments relate to the construction of a new dual fuel, natural peaking facility in Massachusetts.  Achievement of commercial operation related to this project is expected in 2018.

(g)	See Note 23 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for further information regarding SNF obligations.

(a)	Includes $206 million due after 2023 to a ComEd financing trust.

(b)	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2017 and do not reflect anticipated future refinancing, early redemptions or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2017. Includes estimated interest payments due to the ComEd financing trust.

(c)	Amounts related to certain real estate leases and railroad licenses effectively have indefinite payment periods. As a result, ComEd, has excluded these payments from the remaining years as such amounts would not be meaningful. ComEd’s average annual obligation for these arrangements, included in each of the years 2018-2022, was $2 million.

(d)

Primarily related to ComEd 20-year contracts for renewable energy and RECs beginning in June 2012. ComEd is permitted to recover its renewable energy and REC costs from retail customers with no mark-up. The commitments represent the maximum and earliest settlements with suppliers for renewable energy and RECs under the existing contract terms. See Note 3—Regulatory Matters of Combined Notes to Consolidated Financial Statements for additional information.

(e)

Represents the future estimated value at December 31, 2017 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between the Registrants and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.

(f)	Under its operating agreement with PJM, ComEd is committed to the construction of transmission facilities to maintain system reliability. These amounts represent ComEd’s expected portion of the costs to pay for the completion of the required construction projects. See Note 3 — Regulatory Matters of Combined Notes to Consolidated Financial Statements for additional information.

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(a)	Annual ZEC commitment amounts will be published by the IPA each May prior to the start of the subsequent planning year. Amounts presented in the table represent management's estimate of ComEd's obligation based on forward energy prices and load forecasts. ComEd is permitted to recover its ZEC costs from retail customers with no mark-up.

(a)	Includes $184 million due after 2023 to PECO financing trusts.

(b)	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2017 and do not reflect anticipated future refinancing, early redemptions or debt issuances.

(c)

Includes estimated cash payments for service fees related to PECO’s meter reading operating lease. Amounts related to certain real estate leases and railroad licenses effectively have indefinite payment periods. As a result, PECO has excluded these payments from the remaining years as such amounts would not be meaningful. PECO’s average annual obligation for these arrangements, included in each of the years 2018-2022, was $5 million.

(d)	Represents commitments to purchase natural gas and related transportation, storage capacity and services, procure electric supply, and purchase AECs.

(e)

Represents the future estimated value at December 31, 2017 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between the Registrants and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.

(f)	Under its operating agreement with PJM, PECO is committed to the construction of transmission facilities to maintain system reliability. These amounts represent PECO’s expected portion of the costs to pay for the completion of the required construction projects. See Note 3 — Regulatory Matters of Combined Notes to Consolidated Financial Statements for additional information.

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(a)	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2017 and do not reflect anticipated future refinancing, early redemptions or debt issuances.

(b)	Amounts related to certain real estate leases and railroad licenses effectively have indefinite payment periods. As a result, BGE has excluded these payments from the remaining years as such amounts would not be meaningful. BGE’s average annual obligation for these arrangements, included in each of the years 2018—2022, was $1 million, respectively.

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

(d)	The BGE column above includes minimum future lease payments associated with a 6-year lease for the Baltimore City conduit system that became effective during the fourth quarter of 2016. BGE's total commitments under the lease agreement are $25 million, $26 million, $28 million , $28 million and $14 million related to years 2018, 2019, 2020, 2021and 2022, respectively.

(e)	Represents commitments to purchase natural gas and related transportation, storage capacity and services, procure electric supply, and curtailment services.

(f)

Represents the future estimated value at December 31, 2017 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between the BGE and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.

(g)	Under its operating agreement with PJM, BGE is committed to the construction of transmission facilities to maintain system reliability. These amounts represent BGE’s expected portion of the costs to pay for the completion of the required construction projects. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements.

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(a)	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2017 and do not reflect anticipated future refinancing, early redemptions or debt issuances.

(b)	Represents commitments to purchase natural gas and related transportation, storage capacity and services, procure electric renewable energy and RECs, procure electric supply, and curtailment services.

(c)

Represents the future estimated value at December 31, 2017 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between the Registrants and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.

(d)	Related to DC PLUG project costs for assets funded by the District of Columbia for which the District of Columbia has assessed a charge on Pepco. Pepco will recover this charge from customers through a volumetric distribution rider. See Note 3 — Regulatory Matters of Combined Notes to Consolidated Financial Statements for additional information.

(e)	Under its operating agreement with PJM, PHI is committed to the construction of transmission facilities to maintain system reliability. These amounts represent PHI’s expected portion of the costs to pay for the completion of the required construction projects. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements.

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(a)	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2017 and do not reflect anticipated future refinancing, early redemptions or debt issuances.

(b)	Represents commitments to purchase procure electric supply and curtailment services.

(c)

Represents the future estimated value at December 31, 2017 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between the Registrants and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.

(d)	Related to DC PLUG project costs for assets funded by the District of Columbia for which the District of Columbia has assessed a charge on Pepco. Pepco will recover this charge from customers through a volumetric distribution rider. See Note 3 — Regulatory Matters of Combined Notes to Consolidated Financial Statements for additional information.

(e)	Under its operating agreement with PJM, Pepco is committed to the construction of transmission facilities to maintain system reliability. These amounts represent Pepco’s expected portion of the costs to pay for the completion of the required construction projects. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements.

(a)	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2017 and do not reflect anticipated future refinancing, early redemptions or debt issuances.

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(b)	Amounts related to certain real estate leases and railroad licenses effectively have indefinite payment periods. As a result, DPL has excluded these payments from the remaining years as such amounts would not be meaningful. DPL's average annual obligation for these arrangements, included in each of the years 2018-2022, was $2 million.

(c)	Represents commitments to purchase natural gas and related transportation, storage capacity and services, procure electric renewable energy and RECs, procure electric supply, and curtailment services.

(d)

Represents the future estimated value at December 31, 2017 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between the Registrants and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.

(e)	Under its operating agreement with PJM, DPL is committed to the construction of transmission facilities to maintain system reliability. These amounts represent DPL’s expected portion of the costs to pay for the completion of the required construction projects. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements.

(a)	Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2017 and do not reflect anticipated future refinancing, early redemptions or debt issuances.

(b)	Represents commitments to procure electric supply and curtailment services.

(c)

Represents the future estimated value at December 31, 2017 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between the Registrants and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.

(d)	Under its operating agreement with PJM, ACE is committed to the construction of transmission facilities to maintain system reliability. These amounts represent ACE’s expected portion of the costs to pay for the completion of the required construction projects. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements.

•	commercial paper, see Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements.

•	long-term debt, see Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements.

•	liabilities related to uncertain tax positions, see Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements.

•	capital lease obligations, see Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements.

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•	operating leases and rate relief commitments, see Note 23 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements.

•	the nuclear decommissioning and SNF obligations, see Notes 15 — Asset Retirement Obligations and 23 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements.

•	regulatory commitments, see Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements.

•	variable interest entities, see Note 2 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements.

•	nuclear insurance, see Note 23 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements.

•	new accounting pronouncements, see Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements.

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(a)	Amounts are shown net of collateral paid to and received from counterparties.

(b)	Includes fair value from contracts received at acquisition of ConEdison Solutions of $(59) million.

(c)

For ComEd and DPL, the changes in fair value are recorded as a change in regulatory assets or liabilities. As of December 31, 2016, ComEd recorded a regulatory liability of $258 million, respectively, related to its mark-to-market derivative liabilities with Generation and unaffiliated suppliers. ComEd recorded $29 million of decreases in fair value and an increase for realized losses due to settlements of $18 million in purchased power expense associated with floating-to-fixed energy swap suppliers for the year ended December 31, 2016.

(d)	Includes derivative contracts acquired or sold by Generation through upfront payments or receipts of cash, excluding option premiums, and the associated amortizations.

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(a)	Amounts are shown net of collateral paid to and received from counterparties.

(b)	Includes derivative contracts acquired or sold by Generation through upfront payments or receipts of cash, excluding option premiums, and the associated amortizations.

(c)

For ComEd and DPL, the changes in fair value are recorded as a change in regulatory assets or liabilities. As of December 31, 2017, ComEd recorded a regulatory liability of $256 million, related to its mark-to-market derivative liabilities with Generation and unaffiliated suppliers. For the year ended December 31, 2017, ComEd also recorded $18 million of decreases in fair value and realized losses due to settlements of $20 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2017.

(d)	As a result of the bankruptcy filing for EGTP on November 7, 2017, the net mark-to-market commodity contracts were deconsolidated from Exelon’s and Generation consolidated financial statements.

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(a)	Mark-to-market gains and losses on other economic hedge and trading derivative contracts that are recorded in results of operations.

(b)	Amounts are shown net of collateral paid to and received from counterparties (and offset against mark-to-market assets and liabilities) of $466 million at December 31, 2017.

(c)	Includes ComEd’s net assets (liabilities) associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.

(a)	Mark-to-market gains and losses on other economic hedge and trading derivative contracts that are recorded in the results of operations.

(b)	Amounts are shown net of collateral paid to and received from counterparties (and offset against mark-to-market assets and liabilities) of $466 million at December 31, 2017.

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(a)	Represents ComEd’s net liabilities associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.

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(a)	As of December 31, 2017, credit collateral held from counterparties where Generation had credit exposure included $8 million of cash and $19 million of letters of credit.

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(a)

Exelon’s consolidated assets include $9,565 million and $8,893 million at December 31, 2017 and December 31, 2016, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $3,612 million and $3,356 million at December 31, 2017 and December 31, 2016, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 2–Variable Interest Entities.

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(a)

Generation’s consolidated assets include $9,524 million and $8,817 million at December 31, 2017 and 2016, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $3,510 million and $3,170 million at December 31, 2017 and 2016, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 2–Variable Interest Entities.

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(a)

BGE’s consolidated assets include $26 million at December 31, 2016 of BGE’s consolidated VIE that can only be used to settle the liabilities of the VIE. BGE’s consolidated liabilities include $42 million at December 31, 2016 of BGE’s consolidated VIE for which the VIE creditors do not have recourse to BGE. BGE no longer has interests in any VIEs as of December 31, 2017. See Note 2 - Variable Interest Entities.

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(a)

PHI’s consolidated total assets include $41 million and $49 million at December 31, 2017 and 2016, respectively, of PHI's consolidated VIE that can only be used to settle the liabilities of the VIE. PHI’s consolidated total liabilities include $102 million and $143 million at December 31, 2017 and 2016, respectively, of PHI's consolidated VIE for which the VIE creditors do not have recourse to PHI. See Note 2 - Variable Interest Entities.

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(a)	At March 23, 2016 and December 31, 2015, PHI's (predecessor) shareholders' equity included $3,835 million and $3,829 million of other paid-in capital, and $3 million and $3 million of common stock, respectively.

(b)	The March 24, 2016, beginning balance differs from the PHI Merger total purchase price by $59 million related to an acquisition accounting adjustment recorded at Exelon Corporate to reflect unitary state income tax consequences of the merger.

(c)	Distribution to member includes $235 million of net assets associated with PHI's unregulated business interests and $165 million of cash, each of which were distributed by PHI to Exelon.

(d)	The liabilities assumed include $29 million for PHI stock-based compensation awards and $33 million for a merger related obligation, each assumed by PHI from Exelon. See Note 4 — Mergers, Acquisitions and Dispositions.

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(a)

ACE’s consolidated assets include $29 million and $32 million at December 31, 2017 and 2016, respectively, of ACE’s consolidated VIE that can only be used to settle the liabilities of the VIE. ACE’s consolidated liabilities include $90 million and $126 million at December 31, 2017 and 2016, respectively, of ACE’s consolidated VIE for which the VIE creditors do not have recourse to ACE. See Note 2 - Variable Interest Entities.

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•	requires an entity to qualitatively assess whether it should consolidate a VIE based on whether the entity has a controlling financial interest, meaning (1) has the power to direct the activities that most significantly impact the VIE's economic performance, and (2) has the obligation to absorb losses or the right to receive benefits of the VIE that could potentially be significant to the VIE,

•	requires an ongoing reconsideration of this assessment instead of only upon certain triggering events, and

•	requires the entity that consolidates a VIE (the primary beneficiary) to disclose (1) the assets of the consolidated VIE, if they can be used to only settle specific obligations of the consolidated VIE, and (2) the liabilities of a consolidated VIE for which creditors do not have recourse to the general credit of the primary beneficiary.

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(a)	Includes interest expense to affiliates.

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•	The Utility Registrants’ tariff sale contracts, including those with lower credit quality customers, are generally deemed to be probable of collection under the guidance and, thus, the timing of revenue recognition will continue to be concurrent with the delivery of electricity or natural gas, consistent with current practice;

•

Consistent with current industry practice, revenues recognized from sales of bundled energy commodities (i.e., contracts involving the delivery of multiple energy commodities such as electricity, capacity, ancillary services, etc.) are generally expected to be recognized upon delivery to the customer in an amount based on the invoice price given that it corresponds directly with the value of the commodities transferred to the customer; and

•	Contributions in aid of construction are outside of the scope of the standard and, therefore, will continue to be accounted for as a reduction to Property, Plant, and Equipment.

•	Costs to acquire certain contracts (e.g., sales commissions associated with retail power contracts) will be deferred and amortized ratably over the term of the contract rather than being expensed as incurred; and

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•	Variable consideration within certain contracts (e.g., performance bonuses) will be estimated and recognized as revenue over the term of the contract rather than being recognized when realized.

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•	Developing a complete lease inventory and abstracting the required data attributes into a lease accounting system that supports the Registrants' lease portfolios and integrates with existing systems.

•	Evaluating the transition practical expedients available under the guidance.

•	Identifying, assessing and documenting technical accounting issues, policy considerations and financial reporting implications. Includes completing a detailed contract assessment for a sample of transactions to determine whether they are leases under the new guidance.

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•	Identifying and implementing changes to processes and controls to ensure all impacts of the new guidance are effectively addressed.

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

(b)	Includes certain purchase accounting adjustments not pushed down to the BGE standalone entity.

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under power purchase agreements with CENG, Generation purchased or will purchase 50.01% of the available output generated by the CENG nuclear plants not subject to other contractual agreements from January 2015 through the end of the operating life of each respective plant. However, pursuant to amendments dated March 31, 2015, the energy obligations under the Ginna Nuclear Power Plant (Ginna) PPAs were suspended during the term of the Reliability Support Services Agreement (RSSA), through the end of March 31, 2017. With the expiration of the RSSA, the PPA was reinstated beginning April 1, 2017. (see Note 3 — Regulatory Matters for additional details),

•	Generation provided a $400 million loan to CENG. As of December 31, 2017, the remaining obligation is $333 million, including accrued interest, which reflects the principal payment made in January 2015,

•	Generation executed an Indemnity Agreement pursuant to which Generation agreed to indemnify EDF against third-party claims that may arise from any future nuclear incident (as defined in the Price-Anderson Act) in connection with the CENG nuclear plants or their

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•	Generation and EDF share in the $637 million of contingent payment obligations for the payment of contingent retrospective premium adjustments for the nuclear liability insurance, and

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

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

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

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

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

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

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

(b)	Includes certain purchase accounting adjustments not pushed down to the BGE standalone entity.

(c)	Includes the CNEG retail gas pension obligation, which is presented as a net asset balance within the Prepaid pension asset line item on Generation’s balance sheet. See Note 16 - Retirement Benefits for additional details.

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

(b)

These items represent amounts on Exelon’s and Generation’s Consolidated Balance Sheets related to the asset sale agreement with ZionSolutions, LLC. The net assets pledged for Zion Station decommissioning includes gross pledged assets of $39 million and $113 million as of December 31, 2017 and December 31, 2016, respectively; offset by payables to ZionSolutions LLC of $37 million and $104 million as of December 31, 2017 and December 31, 2016, respectively. These items are included to provide information regarding the relative size of the ZionSolutions LLC unconsolidated VIE.

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(a)	On March 22, 2017, the ICC issued an order approving ComEd's proposal to reduce the 2016 revenue requirement by $18 million, which was reflected in customer rates beginning in April 2017. This reduction is not reflected in the 2016 revenue requirement amounts above.

(b)	Includes a reduction of 6 basis points in 2017 and 5 basis points in 2016 and 2015 for a reliability performance metric penalty.

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(a)	Reflects higher projected PJM capacity revenues compared to projected energy efficiency costs.

(b)	An ICC order on the annual reconciliation of any differences between the revenue requirement in effect and the revenue requirement based on actual costs for 2017 and 2018 is expected in December 2018 and December 2019, respectively.

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(a)	The time period for any challenges to the annual transmission formula rate update flings expired with no challenges submitted.

(b)	BGE's transmission revenues include a FERC approved dedicated facilities charge to recover the costs of providing transmission service to specifically designated load by BGE.

(c)	In 2012, PJM terminated the MAPP transmission line construction project planned for the Pepco and DPL service territories. Pursuant to a FERC approved settlement agreement, the abandonment costs associated with MAPP were being recovered in transmission rates over a three-year period that ended in May 2016.

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

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(e)

As part of the FERC-approved settlement of ComEd’s 2007 transmission rate case, the rate of return on common equity is 11.50%, inclusive of a 50-basis-point incentive adder for being a member of a RTO, and the common equity component of the ratio used to calculate the weighted average debt and equity return for the transmission formula rate is currently capped at 55%. As part of the FERC-approved settlement of the ROE complaint against BGE, Pepco, DPL and ACE, the rate of return on common equity is 10.50%, inclusive of a 50-basis-point incentive adder for being a member of a RTO.

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(a)	Reflects ComEd's unrecognized equity returns earned for ratemaking purposes on its under-recovered distribution services costs regulatory assets.

(b)	BGE's authorized amounts capitalized for ratemaking purposes primarily relate to earnings on shareholders' investment on its AMI programs

(c)	Pepco's and DPL's authorized amounts capitalized for ratemaking purposes relate to earnings on shareholders' investment on their respective AMI Programs and Energy Efficiency and Demand Response Programs. The earnings on energy efficiency are on Pepco DC and DPL DE programs only.

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(a)	For ComEd, BGE, Pepco and DPL, reflects the incremental allowance for uncollectible accounts recorded, which is in addition to the purchase discount. For ComEd, the incremental uncollectible accounts expense is recovered through its Purchase of Receivables with Consolidated Billing tariff.

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(a)	Includes a $110 million asset associated with a contractual right to reimbursement from the New York Power Authority (NYPA), a prior owner of FitzPatrick, associated with the DOE one-time fee obligation. See Note 23-Commitments and Contingencies for additional background regarding SNF obligations to the DOE.

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(a)

PHI’s unvested time-based restricted stock units and performance-based restricted stock units issued prior to April 29, 2014 were immediately vested and paid in cash upon the close of the merger.  PHI’s remaining unvested time-based restricted stock units as of the close of the merger were cancelled.  There were no remaining unvested performance-based restricted stock units as of the close of the merger.

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(a)	Amounts shown reflect the final purchase price allocation and the correction of a reporting error identified and corrected in the second quarter of 2016. The error had resulted in a gross up of certain assets and liabilities related to legacy PHI intercompany and income tax receivable and payable balances.

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(a)	The costs incurred are classified primarily within Operating and maintenance expense in the Registrants’ respective Consolidated Statements of Operations and Comprehensive Income, with the exception of the financing costs, which are included within Interest expense. Costs do not include merger commitments discussed above.

(b)

For the year ended December 31, 2017, includes deferrals of previously incurred integration costs to achieve distribution synergies related to the PHI acquisition of $24 million, $8 million, $8 million, and $8 million incurred at PHI, Pepco, DPL, and ACE, respectively, that have been recorded as a regulatory asset for anticipated recovery. For the year ended December 31, 2016, includes deferrals of previously incurred integration costs to achieve distribution synergies related to the PHI acquisition of $8 million, $6 million, $11 million, and $4 million incurred at ComEd, BGE, Pepco, and DPL, respectively, that have been recorded as a regulatory asset for anticipated recovery. For the Successor period March 24, 2016 to December 31, 2016, includes deferrals of previously incurred integration costs to achieve distribution synergies related to the PHI acquisition of $16 million incurred at PHI that have been recorded as a regulatory asset for anticipated recovery. See Note 3 - Regulatory Matters for more information.

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(a)	The amounts above exclude non-recurring costs directly related to the merger of $680 million and intercompany revenue of $171 million for the year ended December 31, 2016.

(b)	The amounts above exclude non-recurring costs directly related to the merger of $92 million and intercompany revenue of $559 million for the year ended December 31, 2015.

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(a)	Represents unbilled portion of retail receivables estimated under Exelon’s unbilled critical accounting policy.

(b)	Includes the estimated allowance for uncollectible accounts on billed customer and other accounts receivable.

(c)	Excludes the non-current allowance for uncollectible accounts of $15 million and $23 million at December 31, 2017 and 2016, respectively, related to PECO’s current installment plan receivables described below.

(d)

At December 31, 2016, as explained in Note 1 — Significant Accounting Policies, PHI, Pepco, DPL and ACE estimated the allowance for uncollectible accounts on customer receivables by applying loss rates to the outstanding receivable balance by risk segment. The change in estimate resulted in an overall increase of $30 million, $14 million, $8 million, and $8 million in the allowance for uncollectible accounts with $20 million, $8 million, $4 million, and $8 million deferred as a regulatory asset on PHI's, Pepco's, DPL's and ACE's Consolidated Balance Sheets at December 31, 2016, respectively. This also resulted in a $10 million, $6 million, and $4 million pre-tax charge to provision for uncollectible accounts expense for the year ended December 31, 2016, which is included in Operating and maintenance expense on PHI's, Pepco's and DPL's Consolidated Statements of Operations and Comprehensive Income, respectively.

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(a)	Includes nuclear fuel that is in the fabrication and installation phase of $1,196 million and $1,326 million at December 31, 2017 and 2016, respectively.

(b)

Includes Generation’s buildings under capital lease with a net carrying value of $7 million and $10 million at December 31, 2017 and 2016, respectively. The original cost basis of the buildings was $47 million and $52 million, and total accumulated amortization was $40 million and $42 million, as of December 31, 2017 and 2016, respectively. Also includes ComEd’s buildings under capital lease with a net carrying value at both December 31, 2017 and 2016, of $7 million. The original cost basis of the buildings was $8 million and total accumulated amortization was $1 million as of both December 31, 2017 and 2016. Includes land held for future use and non-utility property at ComEd, PECO, BGE, Pepco, DPL and ACE of $44 million, $21 million, $26 million, $59 million, $15 million and $27 million, respectively, at December 31, 2017. Includes the original cost and progress payments associated with Generation’s turbine equipment held for future use with a carrying value of $0 million and $17 million as of December 31, 2017 and 2016, respectively. Generation's turbine equipment was impaired by $11 million and the remaining $6 million was moved to the assets held for sale account at December 31, 2017.

(c)	Includes accumulated amortization of nuclear fuel in the reactor core at Generation of $3,159 million and $3,186 million as of December 31, 2017 and 2016, respectively.

(a)	See Note 8 — Early Nuclear Plant Retirements for additional information on the accelerated net depreciation and amortization of Clinton, Quad Cities and TMI.

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(a)	Includes nuclear fuel that is in the fabrication and installation phase of $1,196 million and $1,326 million at December 31, 2017 and 2016, respectively.

(b)

Includes buildings under capital lease with a net carrying value of $7 million and $10 million at December 31, 2017 and 2016, respectively. The original cost basis of the buildings was $47 million and $52 million, and total accumulated amortization was $40 million and $42 million, as of December 31, 2017 and 2016, respectively. Includes the original cost and progress payments associated with Generation’s turbine equipment held for future use with a carrying value of $0 million and $17 million as of December 31, 2017 and 2016, respectively. Generation's turbine equipment was impaired by $11 million and the remaining $6 million was moved to the assets held for sale account at December 31, 2017.

(c)	Includes accumulated amortization of nuclear fuel in the reactor core of $3,159 million and $3,186 million as of December 31, 2017 and 2016, respectively.

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(a)	Includes buildings under capital lease with a net carrying value at both December 31, 2017 and 2016 of $7 million. The original cost basis of the buildings was $8 million and total accumulated amortization was $1 million as of both December 31, 2017 and 2016.

(b)	Includes land held for future use and non-utility property.

(a)	Represents land held for future use and non-utility property.

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(a)	Represents land held for future use and non-utility property.

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(a)	Represents plant held for future use and non-utility property. Utility plant is generally subject to a first mortgage lien.

(a)	Represents plant held for future use and non-utility property. Utility plant is generally subject to a first mortgage lien.

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(a)	Represents plant held for future use and non-utility property. Utility plant is generally subject to a first mortgage lien.

(a)	Represents plant held for future use and non-utility property. Utility plant is generally subject to a first mortgage lien.

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(a)	Reflects incremental charges for TMI including incremental accelerated depreciation and amortization from May 30, 2017 through December 31, 2017.

(b)

Reflects incremental charges for Clinton and Quad Cities including incremental accelerated depreciation and amortization from June 2, 2016 through December 6, 2016. In December 2016, as a result of reversing its retirement decision for Clinton and Quad Cities, Exelon and Generation updated the expected economic useful life for both facilities, to 2027 for Clinton, commensurate with the end of the Illinois ZES, and to 2032 for Quad Cities, the end of its current operating license. Depreciation was therefore adjusted beginning December 7, 2016, to reflect these extended useful life estimates.

(c)	Reflects incremental accelerated depreciation of plant assets, including any ARC.

(d)	Primarily includes materials and supplies inventory reserve adjustments, employee related costs and CWIP impairments.

(e)	In June 2016, as a result of the retirement decision for Clinton and Quad Cities, Exelon and Generation recognized one-time charges of $146 million. In December 2016, as a result of reversing its retirement decision for Clinton and Quad Cities, Exelon and Generation reversed approximately $120 million of these one-time charges initially recorded in June 2016.

(f)

For Quad Cities based on the regulatory agreement with the Illinois Commerce Commission, decommissioning-related activities are offset within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. The offset results in an equal adjustment to the noncurrent payables to ComEd at Generation and an adjustment to the regulatory liabilities at ComEd. Likewise, ComEd has recorded an equal noncurrent affiliate receivable from Generation and corresponding regulatory liability.

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(a)	Generation also owns a proportionate share in the fossil-fuel combustion turbine at Salem, which is fully depreciated. The gross book value was $3 million at December 31, 2017 and 2016.

(b)	PECO, BGE, Pepco, DPL and ACE own a 22%, 7%, 27%, 9% and 8% share, respectively, in 127 miles of 500kV lines located in Pennsylvania as well as a 20.72%, 10.56%, 9.72%, 3.72% and 3.83% share, respectively, of a 500kV substation immediately outside of the Conemaugh fossil-generating station which supplies power to the 500kV lines including, but not limited to, the lines noted above.

(c)	PECO, DPL and ACE own a 42.55%, 1% and 13.9% share, respectively in 151.3 miles of 500kV lines located in New Jersey and Delaware Station. PECO, DPL and ACE also own a 42.55%, 7.45% and 7.45% share, respectively, in 2.5 miles of 500kV line located over the Delaware River. ACE also has a 21.78% share in a 500kV New Freedom Switching

(d)	Generation, DPL and ACE own a 44.24%, 4.83% and 11.91% share, respectively in assets located at Merrill Creek Reservoir located in New Jersey. Pepco, DPL and ACE own a 11.9%, 7.4% and 6.6% share, respectively, in Valley Forge Corporate Center.

(e)	Excludes asset retirement costs.

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(a)	Reflects goodwill recorded in 2000 from the PECO/Unicom (predecessor parent company of ComEd) merger net of amortization, resolution of tax matters and other non-impairment-related changes as allowed under previous authoritative guidance.

(b)	Represents various measurement period adjustments to the valuation of the fair value of the PHI assets acquired and liabilities assumed as a result of the merger.

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(a)	On May 31, 2015, Exelon entered into a long-term software license agreement.  Exelon is required to make payments starting August 2015 through May 2024.  The intangible asset recognized as a result of these payments is being amortized on a straight-line basis over the contract term.

(b)	Includes unamortized energy contract assets and liabilities on Exelon's, Generations and PHI's Consolidated Balance Sheets.

(c)	In March 1999 and February 2003, ComEd entered into separate agreements with the City of Chicago and Midwest Generation, LLC. Under the terms of the settlement, ComEd agreed to make payments to the City of Chicago. The intangible asset recognized as a result of the settlement agreement is being amortized ratably over the remaining term of the City of Chicago franchise agreement.

(d)	PHI entered into a sponsorship agreement with the District of Columbia for future sponsorship rights associated with public property within the District of Columbia. In December 2017, the asset was written off. See Note 7 - Impairment of Long-Lived Assets and Intangibles for additional information.

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(a)

Includes unamortized debt issuance costs which are not fair valued of $201 million, $60 million, $52 million, $17 million, $17 million, $6 million, $32 million, $11 million and $5 million for Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE respectively, as of December 31, 2017. Includes unamortized debt issuance costs which are not fair valued of $200 million, $64 million, $46 million, $15 million, $15 million, $2 million, $30 million, $11 million and $6 million for Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE respectively, as of December 31, 2016.

(b)	Includes unamortized debt issuance costs which are not fair valued of $1 million and $1 million for Exelon and ComEd, respectively, as of December 31, 2017. Includes unamortized debt issuance costs which are not fair valued of $7 million, $1 million, and $6 million for Exelon, ComEd and BGE, respectively, as of December 31, 2016.

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

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

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

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(a)

Generation excludes cash of $259 million and $252 million at December 31, 2017 and 2016 and restricted cash of $127 million and $157 million at December 31, 2017 and 2016.  Exelon excludes cash of $389 million and $360 million at December 31, 2017 and 2016 and restricted cash of $145 million and $180 million at December 31, 2017 and 2016 and includes long-term restricted cash of $85 million and $25 million at December 31, 2017 and 2016, which is reported in Other deferred debits on the Consolidated Balance Sheets.

(b)	Includes $77 million and $29 million of cash received from outstanding repurchase agreements at December 31, 2017 and 2016, respectively, and is offset by an obligation to repay upon settlement of the agreement as discussed in (d) below.

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(c)

Includes derivative instruments of less than $1 million and $(2) million, which have a total notional amount of $811 million and $933 million at December 31, 2017 and 2016, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do not represent the amount of the company's exposure to credit or market loss.

(d)

Excludes net liabilities of $82 million and $31 million at December 31, 2017 and 2016, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, repurchase agreement obligations, and payables related to pending securities purchases. The repurchase agreements are generally short-term in nature with durations generally of 30 days or less.

(e)

Collateral posted/(received) from counterparties totaled $65 million, $320 million and $81 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2017. Collateral posted/(received) from counterparties totaled $71 million, $197 million and $61 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2016.

(f)	Of the collateral posted/(received), $(117) million and $(158) million represents variation margin on the exchanges as of December 31, 2017 and 2016, respectively.

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(a)

ComEd excludes cash of $45 million and $36 million at December 31, 2017 and 2016 and restricted cash of $2 million at December 31, 2016 and includes long-term restricted cash of $62 million at December 31, 2017, which is reported in Other deferred debits on the Consolidated Balance Sheets.  PECO excludes cash of $47 million and $22 million at December 31, 2017 and 2016.  BGE excludes cash of $17 million and $13 million at December 31, 2017 and 2016 and restricted cash of $1 million at December 31, 2017 and includes long-term restricted cash of $2 million at December 31, 2016, which is reported in Other deferred debits on the Consolidated Balance Sheets.

(b)	The Level 3 balance consists of the current and noncurrent liability of $21 million and $235 million, respectively, at December 31, 2017, and $19 million and $239 million, respectively, at December 31, 2016, related to floating-to-fixed energy swap contracts with unaffiliated suppliers.

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(a)

PHI excludes cash of $12 million and $19 million at December 31, 2017 and 2016 and includes long term restricted cash of $23 million at both December 31, 2017 and 2016 which is reported in Other deferred debits on the Consolidated Balance Sheets.  Pepco excludes cash of $4 million and $9 million at December 31, 2017 and 2016. DPL excludes cash of $2 million and $4 million at December 31, 2017 and 2016. ACE excludes cash of $2 million and $3 million at December 31, 2017 and 2016 and includes long-term restricted cash of $23 million at both December 31, 2017 and 2016 which is reported in Other deferred debits on the Consolidated Balance Sheets.

(b)	Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC.

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(a)	Includes a reduction for the reclassification of $352 million and $677 million of realized gains due to the settlement of derivative contracts for the years ended December 31, 2017 and 2016, respectively.

(b)

Includes $18 million of decreases in fair value and an increase for realized losses due to settlements of $20 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2017. Includes $29 million of decreases in fair value and an increase for realized losses due to settlements of $18 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2016.

(c)	Exelon includes the settlement value for any open contracts that were net settled prior to their scheduled maturity within this line item.

(d)	As a result of the bankruptcy filing for EGTP on November 7, 2017, the net mark-to-market commodity contracts were deconsolidated from Exelon's and Generation's consolidated financial statements.

(e)	Includes $168 million of fair value from contracts acquired as a result of portfolio acquisitions.

(f)	Successor period represents activity from March 24, 2016 to December 31, 2016. See tables below for PHI's predecessor periods, as well as activity for Pepco for the years ended December 31, 2017 and 2016.

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(a)	Other, net activity consists of realized and unrealized gains (losses) included in income for the NDT funds held by Generation, accrued interest on a convertible promissory note at Generation and the life insurance contracts held by PHI and Pepco.

(b)	Successor period represents activity from March 24, 2016 to December 31, 2016. See the subsequent table for PHI's predecessor periods, as well as activity for Pepco for the year ended December 31, 2017 and 2016.

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

(b)	The fair values do not include cash collateral posted on level three positions of $81 million as of December 31, 2017.

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

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

(b)	The fair values do not include cash collateral posted on level three positions of $61 million as of December 31, 2016

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

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(a)

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

(b)	Current and noncurrent assets are shown net of collateral of $169 million and $53 million, respectively, and current and noncurrent liabilities are shown net of collateral of $167 million and $77 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $466 million at December 31, 2017.

(c)	Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.

(d)	Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC.

(e)	Of the collateral posted/(received), $(117) million represents variation margin on the exchanges.

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(a)

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

(b)	Current and noncurrent assets are shown net of collateral of $100 million and $72 million, respectively, and current and noncurrent liabilities are shown net of collateral of $95 million and $62 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $329 million at December 31, 2016.

(c)	Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.

(d)	Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC.

(e)	Of the collateral posted/(received), $(158) million represents variation margin on the exchanges.

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(a)

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

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(a)

Generation enters into interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions. The characterization of the interest rate derivative contracts between the proprietary trading activity in the above table is driven by the corresponding characterization of the underlying commodity position that gives rise to the interest rate exposure. Generation does not utilize proprietary trading interest rate derivatives with the objective of benefiting from shifts or changes in market interest rates.

(b)

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

(a)	For the year ended December 31, 2015, the loss on Generation swaps included $(1) million realized in earnings with an immaterial amount excluded from hedge effectiveness testing.

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(a)	Amount is net of related income tax expense of $1 million for the year ended December 31, 2017.

(b)	Amount is net of related income tax expense of $5 million for the year ended December 31, 2016.

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(a)	As of December 31, 2017, credit collateral held from counterparties where Generation had credit exposure included $8 million of cash and $19 million of letters of credit. The credit collateral does not include non-liquid collateral.

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

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

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

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(a)	Excludes $480 million and $500 million in bilateral credit facilities that do not back Generation's commercial paper program at December 31, 2017 and 2016, respectively.

(b)

Excludes additional credit facility agreements for Generation, ComEd, PECO, BGE, Pepco, DPL and ACE with aggregate commitments of $49 million, $34 million, $34 million, $5 million, $2 million, $2 million and $2 million, respectively, arranged with minority and community banks located primarily within utilities' service territories. These facilities expire on October 12, 2018. These facilities are solely utilized to issue letters of credit. As of December 31, 2017, letters of credit issued under these facilities totaled $5 million and $2 million for Generation and BGE, respectively.

(c)

Pepco, DPL and ACE's revolving credit facility is subject to available borrowing capacity. The borrowing capacity may be increased or decreased during the term of the facility, except that (i) the sum of the borrowing capacity must equal the total amount of the facility, and (ii) the aggregate amount of credit used at any given time by each of Pepco, DPL or ACE may not exceed $900 million or the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the borrowing reallocations may not exceed eight per year during the term of the facility.

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(a)

Excludes additional credit facility agreements for Generation, ComEd, PECO, BGE, Pepco, DPL and ACE with aggregate commitments of $49 million, $34 million, $34 million, $5 million, $2 million, $2 million and $2 million, respectively, arranged with minority and community banks located primarily within utilities' service territories. These facilities expire on October 12, 2018. These facilities are solely utilized to issue letters of credit. As of December 31, 2017, letters of credit issued under these facilities totaled $5 million and $2 million for Generation and BGE, respectively.

(b)

Pepco, DPL and ACE's revolving credit facility is subject to available borrowing capacity. The borrowing capacity may be increased or decreased during the term of the facility, except that (i) the sum of the borrowing capacity must equal the total amount of the facility, and (ii) the aggregate amount of credit used at any given time by each of Pepco, DPL or ACE may not exceed $900 million or the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the borrowing reallocations may not exceed eight per year during the term of the facility.

(c)	Excludes nonrecourse debt letters of credit, see discussion below on Antelope Valley Solar Ranch One and Continental Wind.

(d)	Excludes $480 million in bilateral credit facilities that do not back Generation’s commercial paper program.

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(a)	Substantially all of ComEd’s assets other than expressly excepted property and substantially all of PECO’s, Pepco's, DPL's and ACE's assets are subject to the liens of their respective mortgage indentures.

(b)	Includes capital lease obligations of $53 million and $69 million at December 31, 2017 and 2016, respectively. Lease payments of $18 million, $20 million, $5 million, $1 million, $1 million and $8 million will be made in 2018, 2019, 2020, 2021, 2022 and thereafter, respectively.

(c)	Includes financing related to Albany Green Energy, LLC (AGE). During the third quarter of 2017, Generation retired $228 million of its outstanding debt balance. As of December 31, 2016, $198 million was outstanding.

(d)	Amounts owed to these financing trusts are recorded as Long-term debt to financing trusts within Exelon’s Consolidated Balance Sheets.

(a)	Includes Generation’s capital lease obligations of $18 million and $22 million at December 31, 2017 and 2016, respectively. Generation will make lease payments of $5 million, $6 million, $5 million, $1 million and $1 million in 2018, 2019, 2020, 2021 and 2022 respectively. The capital lease matures in 2022.

(b)	Includes financing related to Albany Green Energy, LLC (AGE). During the third quarter of 2017, Generation retired $228 million of its outstanding debt balance. As of December 31, 2016, $198 million was outstanding.

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(a)	Substantially all of ComEd’s assets, other than expressly excepted property, are subject to the lien of its mortgage indenture.

(b)	Includes ComEd’s capital lease obligations of $8 million at both December 31, 2017 and 2016, respectively. Lease payments of less than $1 million annually will be made from 2018 through expiration at 2053.

(c)	Amount owed to this financing trust is recorded as Long-term debt to financing trust within ComEd’s Consolidated Balance Sheets.

(a)	Substantially all of PECO’s assets are subject to the lien of its mortgage indenture.

(b)	Amounts owed to this financing trust are recorded as Long-term debt to financing trusts within PECO’s Consolidated Balance Sheets.

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(a)

Amounts owed to this financing trust are recorded as Long-term debt to financing trusts within BGE’s Consolidated Balance Sheets. On August 28, 2017, BGE redeemed all of the outstanding shares of BGE Capital Trust II 6.20% Preferred Securities (“Securities”), pursuant to the optional redemption provisions of the Indenture under which the Securities were issued. The redemption price per share was $25.19, which equaled the stated value per share plus accrued and unpaid dividends to, but excluding, the redemption date. No dividends on the Securities redeemed were accrued on or after the redemption date, nor did any interest accrue on amounts held to pay the redemption price.

(a)	Substantially all of Pepco's, DPL's, and ACE's assets are subject to the lien of its respective mortgage indenture.

(b)	Transition bonds are recorded as part of Long-term debt within ACE's Consolidated Balance Sheets.

(c)	Includes Pepco's capital lease obligations of $27 million and $39 million at December 31, 2017 and 2016, respectively.

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(a)	Substantially all of Pepco's assets are subject to the lien of its respective mortgage indenture.

(b)	Includes capital lease obligations of $27 million and $39 million at December 31, 2017 and 2016, respectively. Lease payments of $13 million and $14 million will be made in 2018 and 2019, respectively.

(a)	Substantially all of DPL's assets are subject to the lien of its respective mortgage indenture.

(a)	Substantially all of ACE's assets are subject to the lien of its respective mortgage indenture.

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(b)	Maturities of ACE's Transition Bonds outstanding at December 31, 2017 are $31 million in 2018, $18 million in 2019, $20 million in 2020 and $21 million in 2021.

(a)	Includes $390 million due to ComEd and PECO financing trusts.

(b)	Includes $206 million due to ComEd financing trust.

(c)	Includes $184 million due to PECO financing trusts.

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(a)	Reflects the net regulatory liabilities recorded on a pre-tax basis before taking into consideration the income tax benefits associated with the ultimate settlement with customers.

(b)	Amounts do not sum across due to deferred tax adjustments recorded at the Exelon Corporation parent company, primarily related to certain employee compensation plans.

(c)	Given the regulatory treatment of income tax benefits related to electric and gas distribution repairs, PECO remains in an overall net regulatory asset position as of December 31, 2017 after recording the impacts related to the TCJA. Refer to Note 3 - Regulatory Matters for additional information.

(a)

Given the regulatory treatment of income tax benefits related to electric and gas distribution repairs, PECO remains in an overall net regulatory asset position as of December 31, 2017 after recording the impacts related to the TCJA. As a result, the amount of customer benefits resulting from the TCJA subject to the discretion of PECO's rate regulators are lower relative to the other Utility Registrants. Refer to Note 3 - Regulatory Matters for additional information.

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(a)	Includes the charges related to the transmission-related income tax regulatory asset for Exelon, ComEd, BGE, PHI, Pepco, DPL, and ACE of $35 million, $3 million, $5 million, $27 million, $14 million, $6 million, and $7 million, respectively (See Footnote 3 - Regulatory Matters).

(b)	Included are impacts for TJCA other than the corporate rate change, including revisions further limiting tax deductions for compensation of certain highest paid executives, the write-off of foreign tax credit carryforwards, and loss of a 2015 domestic production activities deduction due to an NOL carryback.

(c)	DPL and ACE recognized a loss before income taxes for the year ended December 31, 2016, and PHI recognized a loss before income taxes for the period of March 24, 2016, through December 31, 2016. As a result, positive percentages represent an income tax benefit for the periods presented.

(d)	Includes a remeasurement of uncertain state income tax positions for Pepco and DPL.

(e)	At PECO, includes a cumulative adjustment related to an anticipated gas repairs tax return accounting method change. The method change request was filed and accepted in 2017. No change to the results recorded as of December 31, 2016.

(f)	Includes impacts of the PHI Global Settlement for Pepco, DPL, ACE and PHI.

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(a)	Exelon's federal net operating loss will begin expiring in 2034.

(b)	Exelon’s federal general business credit carryforwards will begin expiring in 2033.

(c)	Exelon’s and Generation's state net operating losses and credit carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2018.

(d)	BGE's state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2026.

(e)	PECO's state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2031.

(f)	PHI's state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2036.

(g)	Pepco's state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2028.

(h)	DPL's state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2027.

(i)	ACE's state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2031.

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(a)	Change in balance attributable to Like-Kind Exchange interest payments, see Other Tax Matters for further discussion.

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(a)	Includes $13 million and $10 million as the current portion of the ARO at December 31, 2017 and 2016, respectively, which is included in Other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets.

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(a)	Net unrealized gains (losses) related to Generation’s NDT funds associated with Regulatory Agreement Units are included in Regulatory liabilities on Exelon’s Consolidated Balance Sheets and Noncurrent payables to affiliates on Generation’s Consolidated Balance Sheets.

(b)

Excludes $(10) million, $(1) million and $7 million of net unrealized gains (losses) related to the Zion Station pledged assets in 2017, 2016 and 2015, respectively. Net unrealized gains related to Zion Station pledged assets are included in the Other current liabilities and Payable for Zion Station decommissioning on Exelon’s and Generation’s Consolidated Balance Sheets in 2017 and 2016, respectively.

(c)	Net unrealized gains (losses) related to Generation’s NDT funds with Non-Regulatory Agreement Units are included within Other, net in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

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(a)	Included in Other current assets within Exelon’s and Generation’s Consolidated Balance Sheets in 2017.

(b)	Excludes a liability recorded within Exelon’s and Generation’s Consolidated Balance Sheets related to the tax obligation on the unrealized activity associated with the Zion Station NDT Funds. The NDT Funds will be utilized to satisfy the tax obligations as gains and losses are realized.

(c)	Included in Other current liabilities within Exelon’s and Generation’s Consolidated Balance Sheets.

(d)	Includes project expenses to decommission Zion Station and estimated tax payments on Zion Station NDT fund earnings.

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(a)	Following the completion of the PHI merger on March 23, 2016, PHI's AROs related to its unregulated business interests were transferred to Exelon and Generation.

(b)

During the year ended December 31, 2017, ComEd recorded a decrease of $1 million in Operating and maintenance expense. Generation, PECO, BGE, Pepco, DPL and ACE did not record any adjustments in Operating and maintenance expense for the year ended December 31, 2017. During the year ended December 31, 2016, Generation recorded a increase of $1 million in Operating and maintenance expense. ComEd, PECO, BGE, Pepco, DPL and ACE did not record any adjustments in Operating and maintenance expense for the year ended December 31, 2016.

(c)	Relates to new AROs recorded due to the construction of solar, wind and other non-nuclear generating sites.

(d)	For ComEd, PECO and BGE, the majority of the accretion is recorded as an increase to a regulatory asset due to the associated regulatory treatment.

(e)	Reflects a reduction to the ARO resulting primarily from the sales of the New Boston generating site and Upstream business in 2016. See Note 4—Mergers, Acquisitions and Dispositions for further information.

(f)	Excludes the current portion of the ARO at December 31, 2017 for Generation, ComEd and BGE of $1 million, $2 million and $2 million, respectively. Excludes the current portion of the ARO at December 31, 2016 for Generation, ComEd and BGE of $1 million, $2 million and $3 million, respectively. This is included in Other current liabilities on the Registrants' respective Consolidated Balance Sheets.

(g)	For PHI, the successor period includes activity for the year ended December 31, 2017 and the period of March 24, 2016 through December 31, 2016. The PHI predecessor periods include activity for the period of January 1, 2016 through March 23, 2016.

(h)	See Note 4—Mergers, Acquisitions and Dispositions for additional information.

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(a)	These plans are collectively referred to as the legacy Exelon plans.

(b)	These plans are collectively referred to as the legacy Constellation Energy Group (CEG) Plans.

(c)	These plans are collectively referred to as the legacy CENG plans.

(d)	These plans are collectively referred to as the legacy PHI plans.

(e)	Employees generally remain in their legacy benefit plans when transferring between operating companies.

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(a)	2016 amounts include PHI for the period of March 24, 2016 through December 31, 2016.

(b)	Exelon recorded pension and OPEB obligations associated with its acquisition of Fitzpatrick on March 31, 2017. Effective March 23, 2016, Exelon became the sponsor of PHI's defined benefit pension and other postretirement benefit plans.

(a)	Effective March 23, 2016, Exelon became the sponsor of PHI's defined benefit pension and other postretirement benefit plans, and assumed PHI's benefit plan obligations and related assets.

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(a)	FitzPatrick net benefit costs are included for the period after acquisition.

(b)	PHI net periodic benefit costs for the period prior to the merger are not included in the table above.

(c)	2016 amount includes an additional termination benefit for PHI.

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(a)	2016 amounts include PHI for the period of March 24, 2016 through December 31, 2016.

(a)	Effective March 23, 2016, Exelon became the sponsor of PHI's defined benefit pension and other postretirement benefit plans, and assumed PHI's benefit plan obligations and related assets.

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(a)	Of the $642 million related to pension benefits at December 31, 2017, $317 million and $325 million are expected to be amortized from AOCI and regulatory assets in 2018, respectively. Of the $(120) million related to other postretirement benefits at December 31, 2017, $(65) million and $(55) million are expected to be amortized from AOCI and regulatory assets (liabilities) in 2018, respectively.

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(a)	The discount rates above represent the blended rates used to determine the majority of Exelon’s pension and other postretirement benefits obligations as of December 31, 2017. Certain benefit plans used individual rates ranging from 3.49% - 3.65% and 3.57% - 3.68% for pension and other postretirement plans, respectively.

(b)	The discount rates above represent the blended rates used to determine the majority of Exelon’s pension and other postretirement benefits obligations as of December 31, 2016. Certain benefit plans used individual rates ranging from 3.66% - 4.11% and 4.00% - 4.17% for pension and other postretirement plans, respectively.

(c)	The discount rates above represent the blended rates used to determine the majority of Exelon’s pension and other postretirement benefits obligations as of December 31, 2015. Certain benefit plans used individual rates ranging from 3.68% - 4.14% and 4.32% - 4.43% for pension and other postretirement plans, respectively.

(d)	3.25% through 2019 and 3.75% thereafter.

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(e)	The legacy Exelon, CEG and CENG pension and other postretirement plans used a rate of compensation increase of 3.25% through 2019 and 3.75% thereafter, while the legacy PHI pension and other postretirement plans used a weighted-average rate of compensation increase of 5% for all periods.

(f)	Obligation was not remeasured during this period.

(g)	The discount rate for the qualified and non-qualified pension plans was 4.65% and 4.55%, respectively.

(a)	The discount rates above represent the blended rates used to establish the majority of Exelon’s pension and other postretirement benefits costs for the year ended December 31, 2017. Certain benefit plans used individual rates ranging from 3.66%-4.11% and 4.00%-4.17% for pension and other postretirement plans, respectively.

(b)	The discount rates above represent the blended rates used to establish the majority of Exelon's pension and other postretirement benefits costs for the year ended December 31, 2016. Certain benefit plans used individual rates ranging from 3.68%-4.14% and 4.32%-4.43% for pension and other postretirement plans, respectively.

(c)	The discount rates above represent the blended rates used to establish the majority of Exelon’s pension and other postretirement benefits costs for the year ended December 31, 2015. Certain benefit plans used the individual rates ranging from 3.29%-3.82% and 3.99%-4.06% for pension and other postretirement plans, respectively.

(d)	Not applicable to pension and other postretirement benefit plans that do not have plan assets.

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(e)	The legacy Exelon, CEG and CENG pension and other postretirement plans used a rate of compensation increase of 3.25% through 2019 and 3.75% thereafter, while the legacy PHI pension and other postretirement plans used a weighted-average rate of compensation increase of 5% for all periods.

(f)	The discount rate for the qualified and non-qualified pension plans was 4.65% and 4.55%, respectively.

(g)	Expected return on other postretirement benefit plan assets is pre-tax.

(a)	Exelon's and Generation's pension contributions include $21 million, $25 million and $36 million related to the legacy CENG plans that was funded by CENG as provided in an Employee Matters Agreement (EMA) between Exelon and CENG for the years ended December 31, 2017, 2016 and 2015, respectively.

(b)	Includes $4 million, $6 million, and $5 million of pension contributions funded by Exelon Corporate, for the years ended December 31, 2017, 2016, and 2015, respectively.

(c)	PHISCO’s pension contributions for the year ended December 31, 2016 include $4 million of contributions made prior to the closing of Exelon’s merger with PHI on March 23, 2016.

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(a)	FitzPatrick net benefit costs are included for the period after acquisition.

(b)	These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO, BGE, PHI, Pepco, DPL or ACE amounts above.

(c)	Pepco's, DPL's, ACE's and PHISCO's pension and postretirement benefit costs for the year ended December 31, 2016 include $7 million, $4 million, $3 million and $9 million, respectively, of costs incurred prior to the closing of Exelon’s merger with PHI on March 23, 2016.

(d)	These amounts represent amounts billed to Pepco, DPL and ACE through intercompany allocations. These amounts are not included in Pepco, DPL or ACE amounts above.

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(a)	Alternative investments include private equity, hedge funds, real estate, and private credit.

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(a)	See Note 11—Fair Value of Financial Assets and Liabilities for a description of levels within the fair value hierarchy.

(b)	Effective March 31, 2017, Exelon became sponsor of FitzPatrick's defined benefit pension and other postretirement benefit plans, and assumed FitzPatrick's benefit plan obligations.

(c)

Includes derivative instruments of $6 million and $1 million, which have a total notional amount of $3,606 million and $2,918 million at December 31, 2017 and 2016, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do not represent the amount of the company’s exposure to credit or market loss.

(d)	Excludes net assets of $2 million and net liabilities of $28 million at December 31, 2017 and 2016, respectively, which are required to reconcile to the fair value of net plan assets. These items consist primarily of receivables related to pending securities sales, interest and dividends receivable, and payables related to pending securities purchases.

(e)	Effective March 23, 2016, Exelon became sponsor of PHI's defined benefit pension and other postretirement benefit plans, and assumed PHI's benefit plan obligations and related assets.

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(a)	Represents cash settlements only.

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(a)	Includes $13 million and $9 million related to CENG for the years ended December 31, 2016 and December 31, 2015.

(b)	These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These costs are not included in the Generation, ComEd, PECO, BGE, PHI, Pepco, DPL or ACE amounts above.

(c)	Pepco's, DPL's and PHISCO's matching contributions include $1 million, $1 million and $1 million, respectively, of costs incurred prior to the closing of Exelon's merger with PHI on March 23, 2016, which is not included in Exelon's matching contributions for the year ended December 31, 2016.

(d)	These amounts primarily represent amounts billed to Pepco, DPL, and ACE through intercompany allocations. These amounts are not included in Pepco, DPL or ACE amounts above.

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(a)	The amounts above for Generation, ComEd, PECO, BGE, and PHI include immaterial amounts billed by BSC for the years ended December 31, 2017 and 2016. Pepco, DPL, and ACE include immaterial amounts billed by PHISCO for the year ended December 31, 2017. Pepco, DPL, and ACE did not have any ongoing severance plans for the year ended December 31, 2016.

(a)	The amounts for Generation, ComEd, PECO, and BGE include $(4) million, $(2) million, $(1) million, and $(1) million, respectively, for amounts billed by BSC through intercompany allocations for the year ended December 31, 2017.

(b)	The amounts above for Generation, ComEd, PECO and BGE include $7 million, $3 million, $1 million, and $1 million, respectively, for amounts billed by BSC through intercompany allocations for the year ended December 31, 2016.

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(a)	The amounts above for Generation, ComEd, PECO, BGE, Pepco, DPL, and ACE include $8 million, $2 million, $1 million, $1 million, $20 million, $12 million and $10 million, respectively, for amounts billed by BSC and/or PHISCO through intercompany allocations for the year ended December 31, 2016.

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(a)	Includes salary continuance and health and welfare severance benefits.

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(a)	2016 amounts include expense related to stock-based compensation granted to eligible PHI employees since the merger date of March 23, 2016.

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(a)	These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO, BGE or PHI amounts above.

(b)	Pepco's, DPL's and ACE's stock-based compensation expense for the years ended December 31, 2017 and 2016 was not material.

(c)	These amounts primarily represent amounts billed to PHI’s subsidiaries through PHISCO intercompany allocations.

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(a)	Includes stock options issued to retirement eligible employees.

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(a)	The difference between the market value on the date of exercise and the option exercise price.

(a)	Excludes 1,488,383 and 1,319,372 of restricted stock units issued to retirement-eligible employees as of December 31, 2017 and 2016, respectively, as they are fully vested.

(b)	Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2017.

(c)	2016 amounts include activity related to stock-based compensation granted to eligible PHI employees since the merger date of March 23, 2016.

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(a)	Excludes 2,723,440 and 2,443,409 of performance share awards issued to retirement-eligible employees as of December 31, 2017 and 2016, respectively, as they are fully vested.

(b)	Represents performance share awards that vested but were not distributed to retirement-eligible employees during 2017.

(c)	2016 amounts include activity related to stock-based compensation granted to eligible PHI employees since the merger date of March 23, 2016.

(a)	As of December 31, 2017, $41 million of total unrecognized compensation costs related to nonvested performance shares are expected to be recognized over the remaining weighted-average period of 1.5 years.

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(a)	Represents the current liability related to performance share awards expected to be settled in cash.

(b)	Represents the long-term liability related to performance share awards expected to be settled in cash.

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

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

(c)	As a result of the PHI Merger, the PHI predecessor balances at March 23, 2016 were reduced to zero on March 24, 2016 due to purchase accounting adjustments applied to PHI.

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

(b)	This AOCI component is included in the computation of net periodic pension and OPEB cost (see Note 16 — Retirement Benefits for additional details).

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

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

(c)

Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $56 million, $16 million of which is a guarantee by Pepco, $23 million by DPL and $15 million by ACE. The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.

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

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

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

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

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

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

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(a)

Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $56 million. The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.

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

(b)

Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $16 million. The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.

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

(b)

Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $23 million. The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.

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(a)

Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $15 million. The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.

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

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

(c)

Amounts related to certain real estate leases and railroad licenses effectively have indefinite payment periods. As a result, ComEd, PECO, BGE and DPL have excluded these payments from the remaining years as such amounts would not be meaningful. ComEd’s, PECO’s, BGE’s and DPL's average annual obligation for these arrangements, included in each of the years 2018—2022, was $2 million, $5 million, $1 million and $2 million, respectively. Also includes amounts related to shared use land arrangements.

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

(e)	The BGE column above includes minimum future lease payments associated with a 6-year lease for the Baltimore City conduit system that became effective during the fourth quarter of 2016. BGE's total commitments under the lease agreement are $25 million, $26 million, $28 million , $28 million and $14 million related to years 2018, 2019, 2020, 2021and 2022, respectively.

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(a)

Includes contingent operating lease payments associated with contracted generation agreements that are not included in the minimum future operating lease payments table above. Payments made under Generation’s contracted generation lease agreements totaled $508 million, $604 million and $798 million during 2017, 2016 and 2015, respectively. Excludes contract amortization associated with purchase accounting and contract acquisitions.

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

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

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(a)	Recorded in Accounts receivable, other.

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

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

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•	ComEd has identified 42 sites, 19 of which have been remediated and approved by the Illinois EPA or the U.S. EPA and 23 that are currently under some degree of active study and/or remediation. ComEd expects the majority of the remediation at these sites to continue through at least 2022.

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

•

BGE has identified 13 former gas manufacturing or purification sites, 11 of which the remediation has been completed and approved by the MDE and 2 that require some level of remediation and/or ongoing monitoring. BGE has determined that a loss associated with these sites is probable and has recorded an estimated liability, which is included in the table below. However, it is reasonably possible that BGE’s cost of remediation for one of its sites could be up to $13 million.

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

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(a)

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

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(a)	Includes investment income and realized gains and losses on sales of investments within the nuclear decommissioning trust funds.

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

(c)	See Note 14—Income Taxes for discussion of the penalty related to the Tax Court’s decision on Exelon’s like-kind exchange tax position.

(d)

In January 2015, in connection with Generation's $750 million issuance of five-year Senior Unsecured Notes, Exelon terminated certain floating-to-fixed interest rate swaps. As the original forecasted transactions were a series of future interest payments over a ten-year period, a portion of the anticipated interest payments are probable not to occur. As a result, $26 million of anticipated payments were reclassified from AOCI to Other, net in Exelon's Consolidated Statements of Operations and Comprehensive Income.

(e)	See Note 13—Debt and Credit Agreements and Note 4—Mergers, Acquisitions and Dispositions for additional information on the PHI merger related debt exchange.

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

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

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

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

(b)	Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations.

(c)	See Note 4 - Mergers, Acquisitions and Dispositions for more information.

(d)	Reflects the change in ComEd's distribution and energy efficiency formula rates . See Note 3 — Regulatory Matters for more information.

(e)

On December 1, 2017, Exelon adopted a single, standard vacation accrual policy for all non-represented, non-craft (represented and craft policies remained unchanged) employees effective January 1, 2018.  To reflect the new policy, Exelon recorded a one-time, $68 million pre-tax credit to expense to reverse 2018 vacation cost originally accrued throughout 2017 that will now be accrued ratably over the year in 2018.

(f)	See Note 14 — Income Taxes for discussion of the like-kind exchange tax position.

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

(b)	Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations.

(c)	See Note 4 - Mergers, Acquisitions and Dispositions for more information.

(d)	Excludes $5 million of forgiveness of Accounts receivable related to merger commitments recorded in connection with the PHI Merger, the balance is included within Provision for uncollectible accounts.

(e)	Reflects the change in distribution rates pursuant to EIMA, which allows for the recovery of costs by a utility through a pre-established performance-based formula rate. See Note 3 — Regulatory Matters for more information.

(f)	Immediately following closing of the PHI Merger, the net assets associated with PHI’s unregulated business interests were distributed by PHI to Exelon. Exelon contributed a portion of such net assets to Generation.

(g)	See Note 14 — Income Taxes for discussion of the like-kind exchange tax position.

(h)	Reflects the transfer of nuclear fuel to Entergy under the cost reimbursement provisions of the FitzPatrick acquisition agreements. See Note 4 - Mergers, Acquisitions and Dispositions for more information.

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

(b)	Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations.

(c)	Reflects the change in distribution rates pursuant to EIMA, which allows for the recovery of costs by a utility through a pre-established performance-based formula rate. See Note 3 — Regulatory Matters for more information.

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(d)	Relates to the nuclear fuel procurement contracts for the purchase of fixed quantities of uranium, which was delivered to Generation in 2015. Generation is required to make payments starting September 30, 2018, with the final payment being due no later than September 30, 2020.

(e)	See Note 14 — Income Taxes for discussion of the like-kind exchange tax position.

(f)	Relates to a long-term software license agreement entered into on May 30, 2015. Exelon is required to make payments starting August of 2015 through May of 2024. See Note 13 - Debt and Credit Agreements.

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(a)	Includes investments in affiliated financing trusts, which were not consolidated within the financial statements of Exelon and are shown as investments on the Consolidated Balance Sheets. See Note 1 — Significant Accounting Policies for additional information.

(b)	The Registrants’ investments in these marketable securities are recorded at fair market value.

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

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

•

Midwest represents operations in the western half of PJM, which includes portions of Illinois, Pennsylvania, Indiana, Ohio, Michigan, Kentucky and Tennessee, and the United States footprint of MISO, excluding MISO’s Southern Region, which covers all or most of North Dakota, South Dakota, Nebraska, Minnesota, Iowa, Wisconsin, the remaining parts of Illinois, Indiana, Michigan and Ohio not covered by PJM, and parts of Montana, Missouri and Kentucky.

•	New England represents the operations within ISO-NE covering the states of Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont.

•	New York represents operations within ISO-NY, which covers the state of New York in its entirety.

•	ERCOT represents operations within Electric Reliability Council of Texas, covering most of the state of Texas.

•	Other Power Regions:

•

South represents operations in the FRCC, MISO’s Southern Region, and the remaining portions of the SERC not included within MISO or PJM, which includes all or most of Florida, Arkansas, Louisiana, Mississippi, Alabama, Georgia, Tennessee, North Carolina, South Carolina and parts of Missouri, Kentucky and Texas. Generation’s South region also includes operations in the SPP, covering Kansas, Oklahoma, most of Nebraska and parts of New Mexico, Texas, Louisiana, Missouri, Mississippi and Arkansas.

•	West represents operations in the WECC, which includes California ISO, and covers the states of California, Oregon, Washington, Arizona, Nevada, Utah, Idaho, Colorado and parts of New Mexico, Wyoming and South Dakota.

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

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(a)

Generation includes the six reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions. For the year ended December 31, 2017, intersegment revenues for Generation include revenue from sales to PECO of $138 million, sales to BGE of $388 million, sales to Pepco of $255 million, sales to DPL of $179 million and sales to ACE of $29 million in the Mid-Atlantic region, and sales to ComEd of $121 million in the Midwest region, which eliminate upon consolidation. For the year ended December 31, 2016, intersegment revenues for Generation include revenue from sales to PECO of $290 million and sales to BGE of $608 million in the Mid-Atlantic region, and sales to ComEd of $47 million in the Midwest region, which eliminate upon consolidation. For the Successor period of March 24, 2016 to December 31, 2016, intersegment revenues for Generation include revenue from sales to Pepco of $295 million, sales to DPL of $154 million and sales to ACE of $37 million in the Mid-Atlantic region, which eliminate upon consolidation. For the year ended December 31, 2015, intersegment revenues for Generation include revenue from sales to PECO of $224 million and sales to BGE of $502 million in the Mid-Atlantic region, and sales to ComEd of $18 million in the Midwest region, which eliminate upon consolidation.

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

(c)	Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses on the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 24 — Supplemental Financial Information for total utility taxes for the years ended December 31, 2017, 2016 and 2015.

(d)

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

(e)	Amounts included represent activity for PHI's successor period, March 24, 2016 through December 31, 2017. PHI includes the three reportable segments: Pepco, DPL and ACE. See tables below for PHI's predecessor periods, including Pepco, DPL and ACE, for January 1, 2016 to March 23, 2016 and for the year ended December 31, 2015.

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(a)	Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses on the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 24 — Supplemental Financial Information for total utility taxes for the years ended December 31, 2017, 2016 and 2015.

(b)	Other primarily includes PHI’s corporate operations, shared service entities and other financing and investment activities.  For the predecessor periods presented, Other includes the activity of PHI’s unregulated businesses which were distributed to Exelon and Generation as a result of the PHI Merger.

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

(b)

Other represents activities not allocated to a region. See text above for a description of included activities. Also includes a $38 million decrease to revenues, a $52 million decrease to revenues, and a $7 million increase to revenues for the amortization of intangible assets related to commodity contracts recorded at fair value for the years ended December 31, 2017, 2016, and 2015, respectively, unrealized mark-to-market losses of $131 million, losses of $500 million, and gains of $203 million for the years ended December 31, 2017, 2016, and 2015, respectively, and elimination of intersegment revenues.

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

(b)

Other represents activities not allocated to a region. See text above for a description of included activities. Includes a $54 million decrease in RNF, a $57 million decrease in RNF, and a $8 million increase in RNF for the amortization of intangible assets and liabilities related to commodity contracts for the years ended December 31, 2017, 2016, and 2015, respectively, unrealized mark-to-market losses of $175 million, losses of $41 million, and gains of $257 million for the years ended December 31, 2017, 2016, and 2015, respectively, accelerated nuclear fuel amortization associated with the announced early retirement decision for Clinton and Quad Cities as discussed in Note 8 - Early Nuclear Plant Retirements of $12 million and $60 million for the year ended December 31, 2017 and 2016, and the elimination of intersegment revenues net of purchased power and fuel expense.

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(a)

The intersegment profit associated with the sale of certain products and services by and between Exelon’s segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in operating revenues in the Consolidated Statements of Operations. See Note 3—Regulatory Matters for additional information.

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(a)	Generation has an ICC-approved RFP contract with ComEd to provide a portion of ComEd’s electricity supply requirements. Generation also sells RECs to ComEd. In addition, Generation had revenue from ComEd associated with the settled portion of the financial swap contract established as part of the Illinois Settlement. See Note 3—Regulatory Matters for additional information.

(b)	Generation provides electric supply to PECO under contracts executed through PECO’s competitive procurement process. In addition, Generation has a ten-year agreement with PECO to sell solar AECs. See Note 3—Regulatory Matters for additional information.

(c)	Generation provides a portion of BGE’s energy requirements under its MDPSC-approved market-based SOS and gas commodity programs. See Note 3—Regulatory Matters for additional information.

(d)	Generation provides electric supply to Pepco under contracts executed through Pepco's competitive procurement process approved by the MDPSC and DCPSC. See Note 3—Regulatory Matters for additional information.

(e)	Generation provides a portion of DPL's energy requirements under its MDPSC and DPSC approved market based SOS and gas commodity programs. See Note 3—Regulatory Matters for additional information.

(f)	Generation provides electric supply to ACE under contracts executed through ACE's competitive procurement process. See Note 3—Regulatory Matters for additional information.

(g)	Generation requires electricity for its own use at its generating stations. Generation purchases electricity and distribution and transmission services from PECO and BGE and only distribution and transmission services from ComEd for the delivery of electricity to its generating stations.

(h)	Generation receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.

(i)	The balance consists of interest owed to Exelon Corporation related to the senior unsecured notes, as well as, expense related to certain invoices Exelon Corporation processed on behalf of Generation.

(j)	Generation has long-term payables to ComEd and PECO as a result of the nuclear decommissioning contractual construct whereby, to the extent NDT funds are greater than the underlying ARO at the end of decommissioning, such amounts are due back to ComEd and PECO, as applicable, for payment to their respective customers. See Note 15—Asset Retirement Obligations.

(k)

In connection with the debt obligations assumed by Exelon as part of the Constellation merger, Exelon and subsidiaries of Generation (former Constellation subsidiaries) assumed intercompany loan agreements that mirror the terms and amounts of the third-party debt obligations of Exelon, resulting in intercompany notes payable included in Long-term Debt to affiliate on Generation’s Consolidated Balance Sheets and intercompany notes receivable at Exelon Corporate, which are eliminated in consolidation on Exelon’s Consolidated Balance Sheets.

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(a)	ComEd procures a portion of its electricity supply requirements from Generation under an ICC-approved RFP contract. ComEd also purchases RECs from Generation. In addition, purchased power expense includes the settled portion of the financial swap contract with Generation, which expired in 2013. See Note 3—Regulatory Matters and Note 12—Derivative Financial Instruments for additional information.

(b)	ComEd receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.

(c)

The voluntary employee benefit association trusts covering active employees are included in corporate operations and are funded by the Registrants. A prepayment to the active welfare plans has accumulated due to actuarially determined contribution rates, which are the basis for ComEd’s contributions to the plans, being higher than actual claim expense incurred by the plans over time. The prepayment is included in other current assets.

(d)	Represents indemnification from Exelon Corporate related to the like-kind exchange.

(e)	ComEd has a long-term receivable from Generation as a result of the nuclear decommissioning contractual construct for generating facilities previously owned by ComEd. To the extent the assets associated with decommissioning are greater than the applicable ARO at the end of decommissioning, such amounts are due back to ComEd for payment to ComEd’s customers.

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(a)	PECO provides energy to Generation for Generation’s own use.

(b)	PECO purchases electric supply from Generation under contracts executed through its competitive procurement process. In addition, PECO has five-year and ten-year agreements with Generation to purchase non-solar and solar AECs, respectively. See Note 3—Regulatory Matters for additional information on AECs.

(c)	PECO receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.

(d)	The voluntary employee beneficiary association trusts covering active employees are included in corporate operations and are funded by the Registrants. A prepayment to the active welfare plans has accumulated due to actuarially determined contribution rates, which are the basis for PECO’s contributions to the plans, being higher than actual claim expense incurred by the plans over time.

(e)	PECO has a long-term receivable from Generation as a result of the nuclear decommissioning contractual construct, whereby, to the extent the assets associated with decommissioning are greater than the applicable ARO at the end of decommissioning, such amounts are due back to PECO for payment to PECO’s customers.

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(a)	BGE provides energy to Generation for Generation’s own use.

(b)	BGE procures a portion of its electricity and gas supply requirements from Generation under its MDPSC-approved market-based SOS and gas commodity programs. See Note 3—Regulatory Matters for additional information.

(c)	BGE receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.

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(a)	PHI receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.

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(a)	Pepco provides energy to Generation for Generation’s own use.

(b)	Pepco procures a portion of its electricity and gas supply requirements from Generation under its MDPSC and DPSC approved market based SOS and gas commodity programs. See Note 3—Regulatory Matters for additional information.

(c)	Pepco receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.

(d)	PES performs underground transmission, distribution construction and maintenance services, including services that are treated as capital costs, for Pepco.

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(a)	DPL procures a portion of its electricity and gas supply requirements from Generation under its MDPSC and DPSC approved market based SOS and gas commodity programs. See Note 3—Regulatory Matters for additional information.

(b)	DPL receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.

(c)	PES performs underground transmission construction services, including services that are treated as capital costs, for DPL.

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(a)	ACE purchases electric supply from Generation under contracts executed through its competitive procurement process. See Note 3—Regulatory Matters for additional information.

(b)	ACE receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.

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(a)	Amounts for March 31, 2016 reflect the PHI Successor activity for the period March 24, 2016 to March 31, 2016.

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(a)	Includes the accelerated depreciation of plant assets including any ARC.

(b)	Actual results may differ based on incremental future capital additions, actual units of production for nuclear fuel amortization, future revised ARO assumptions, etc.

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(1)

Balance includes stock options, unvested performance shares, and unvested restricted shares granted under the Exelon LTIP or predecessor company plans including shares awarded under those plans and deferred into the stock deferral plan, and deferred stock units granted to directors as part of their compensation. For performance shares granted in 2015, 2016 and 2017, the total includes the number of shares that could be granted, if the performance and total shareholder return modifier metrics were both at maximum, representing a total of 9,546,000 shares. If the performance and total shareholder return modifier metrics were at target, the number of securities to be issued for such awards would be 4,773,000. The deferred stock units granted to directors includes 384,900 shares to be issued upon the conversion of deferred stock units awarded to members of the Exelon Board of Directors, and 109,200 shares to be issued upon the conversion of stock units held by members of the Exelon Board of Directors that were earned under a legacy Constellation Energy Group plan. Conversion of the deferred stock units to shares will occur after the director terminates service to the Exelon board or the board of any of its subsidiary companies. See Note 20—Stock-Based Compensation Plans of the Combined Notes to Consolidated Financial Statements for additional information about the material features of the plans.

(2)	Includes outstanding restricted stock units and performance shares that can be exercised for no consideration. Without such instruments, the weighted-average price of outstanding options, warrants and rights shown in column [C] would be $47.69.

(3)	Includes 19,737,600 shares available for issuance from the company’s employee stock purchase plan.

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(a)	The following documents are filed as a part of this report:

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(a)	Senior unsecured notes include mirror debt that is held on both Generation and Exelon Corporation's balance sheets.

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(a)	Exelon Corporate receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead.

(b)	Exelon Energy Delivery Company, LLC consists of ComEd, PECO, BGE, PHI, Pepco, DPL and ACE.

(c)

In connection with the debt obligations assumed by Exelon as part of the Constellation merger, Exelon and subsidiaries of Generation (former Constellation subsidiaries) assumed intercompany loan agreements that mirror the terms and amounts of the third-party debt obligations of Exelon, resulting in intercompany notes payable included in Long-Term Debt to affiliate on Generation’s Consolidated Balance Sheets and intercompany notes receivable at Exelon Corporate, which are eliminated in consolidation on Exelon’s Consolidated Balance Sheets.

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(a)	Excludes the non-current allowance for uncollectible accounts related to PECO’s installment plan receivables of $15 million, $23 million, and $8 million for the years ended December 31, 2017, 2016, and 2015, respectively.

(b)	Primarily represents the addition of PHI's results as of March 23, 2016, the date of the merger

(c)	Includes charges for late payments and non-service receivables.

(d)	Write-off of individual accounts receivable.

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(a)	Primarily charges for late payments and non-service receivables.

(b)	Write-off of individual accounts receivable.

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(a)	Excludes the non-current allowance for uncollectible accounts related to PECO’s installment plan receivables of $15 million, $23 million, and $8 million for the years ended December 31, 2017, 2016, and 2015, respectively.

(b)	Primarily charges for late payments.

(c)	Write-off of individual accounts receivable.

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(a)	Write-off of individual accounts receivable.

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(a)	Primarily charges for late payments.

(b)	Write-off of individual accounts receivable.

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(a)	Primarily charges for late payments.

(b)	Write-off of individual accounts receivable.

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(a)	Primarily charges for late payments.

(b)	Write-off of individual accounts receivable.

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(a)	Primarily charges for late payments.

(b)	Write-off of individual accounts receivable.

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*	Compensatory plan or arrangements in which directors or officers of the applicable registrant participate and which are not available to all employees.

(a)	These filings are not available electronically on the SEC website as they were filed in paper previous to the electronic system that is currently in place.

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